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Filed Pursuant to Rule 424(b)(3)
Registration No. 333-89725
PROSPECTUS
[AES EARSTERN ENERGY, L.P. LOGO]
AES EASTERN ENERGY, L.P.
EXCHANGE OFFER
PASS THROUGH TRUST CERTIFICATES, SERIES 1999
------------------------
The Exchange Offer and
the Consent
Solicitation We are offering to exchange pass through trust
certificates registered with the Securities and Exchange
Commission for existing pass through trust certificates
that we previously offered in an offering exempt from the
SEC's registration requirements. We are also soliciting
consents from the holders of the existing pass through
trust certificates to a waiver of our obligation to file
a shelf registration statement under the registration
rights agreement as a result of our failure to complete
the exchange offer on or prior to November 10, 1999,
which is 180 days after the original issue date of the
existing pass through trust certificates. The terms and
conditions of the exchange offer and the consent
solicitation are summarized below and more fully
described in this prospectus.
Expiration Date 5:00 p.m. (New York City time) on March 20, 2000.
Withdrawal Rights Any time before 5:00 p.m. (New York City time) on
expiration date.
Integral Multiples Old certificates may only be tendered in integral
multiples of $1,000.
Expenses Paid for by AES Eastern Energy, L.P.
New Certificates The new pass through trust certificates will represent
the same fractional undivided interest in two pass
through trusts as the existing pass through trust
certificates they are replacing. The new pass through
trust certificates will have the same material financial
terms as the existing pass through trust certificates,
which are summarized below and described more fully in
this prospectus. The new pass through trust certificates
will not contain terms with respect to transfer
restrictions or interest rate increases.
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PASS THROUGH PRINCIPAL INTEREST INITIAL PRINCIPAL FINAL PRINCIPAL INTEREST DISTRIBUTION
CERTIFICATES AMOUNT RATE DISTRIBUTION DATE DISTRIBUTION DATE DATES
- --------------------------------------------------------------------------------------------------------------------------------
Series 1999-A........ $282,000,000 9.00% July 2, 2003 January 2, 2017 January 2 and July 2
Series 1999-B........ 268,000,000 9.67% January 2, 2018 January 2, 2029 January 2 and July 2
-------------------
Total................ $550,000,000
- --------------------------------------------------------------------------------------------------------------------------------
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CONSIDER CAREFULLY THE RISK FACTORS BEGINNING ON PAGE 14 OF THIS
PROSPECTUS.
The pass through trust certificates represent interests in one of two pass
through trusts only and do not represent interests in or obligations of The AES
Corporation, AES Eastern Energy, L.P. or any other affiliate of The AES
Corporation.
We are relying on the position of the SEC staff in certain interpretive
letters to third parties to remove the transfer restrictions on the new pass
through trust certificates.
NEITHER THE SEC NOR ANY STATE SECURITIES COMMISSION HAS APPROVED THESE PASS
THROUGH TRUST CERTIFICATES OR DETERMINED THAT THIS PROSPECTUS IS ACCURATE OR
COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
February 18, 2000
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IMPORTANT NOTICE ABOUT INFORMATION PRESENTED IN THIS PROSPECTUS
You should rely only on the information provided in this prospectus. We
have not authorized anyone to provide you with different information. We are not
offering the pass through trust certificates in any state where the offer is not
permitted. We do not claim the accuracy of the information in this prospectus as
of any date other than the date stated on the cover.
We include cross-references in this prospectus to captions where you can
find further related discussions. The following Table of Contents provides the
pages on which these captions are located. You can find a listing of the pages
where capitalized terms used in this prospectus are defined under the caption
"INDEX OF DEFINED TERMS" and a glossary of technical terms used in this
prospectus under the caption "GLOSSARY OF CERTAIN ELECTRIC INDUSTRY TERMS," both
of which are at the end of this prospectus.
AVAILABLE INFORMATION
We are filing with the SEC a Registration Statement on Form S-4 relating to
the new pass through trust certificates. This prospectus is a part of the
Registration Statement, but the Registration Statement includes additional
information and also includes exhibits that are referenced in this prospectus.
You can review a copy of the Registration Statement through the SEC's "EDGAR"
System (Electronic Data Gathering, Analysis and Retrieval) that is available on
the SEC's web site (http://www.sec.gov).
After our Registration Statement becomes effective, we will be required to
file publicly certain information under the Securities Exchange Act of 1934, as
amended. All of our public filings will also be available on EDGAR, including
annual and quarterly reports and other information. You may also read and copy
all of our public filings at the SEC's public reference room in Washington, D.C.
or at their facilities in New York and Chicago. Please call the SEC at (800)
732-0330 for further information on the operation of the public reference rooms.
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TABLE OF CONTENTS
Available Information....................................... i
Prospectus Summary.......................................... 1
AES Eastern Energy........................................ 1
This Exchange Offer....................................... 1
Summary of Terms of the New Pass Through Trust
Certificates........................................... 5
Summary Financial Data.................................... 10
Projected Financial Data.................................. 11
Independent Engineer's Conclusions Regarding Financial
Projections............................................ 12
Risk Factors................................................ 14
The market in which our business will be concentrated is
being deregulated and there is no historical price data
that shows we will be able to sell our electric energy,
installed capacity and ancillary services at prices
that will permit us to pay our expenses................ 14
We will be required to make substantial payments under our
leases and other contracts and we may have difficulty
responding to unforeseen requirements.................. 14
We may have difficulty meeting our payment obligations if
our operations are not as successful as we have
projected.............................................. 15
Operation of our stations might be disrupted.............. 15
Our electricity generating stations are not new and will
require careful maintenance if they are to operate
efficiently............................................ 16
Our financial projections assume that we will be able to
operate our electricity generating stations nearly
continually and we may have trouble meeting our
obligations if we are not successful................... 16
Our financial projections assume that the real price of
coal will continue to drop in the future; an increase
in the real price of coal will negatively affect our
operating results...................................... 16
We have only a limited operating history and we have not
demonstrated that we can operate our electricity
generating stations in a profitable manner............. 16
Our business is extensively regulated and new regulations
may impose requirements that we are unable to meet or
that require us to make additional expenditures........ 17
We will have responsibility for pre-existing environmental
liabilities and will incur expenses as a result; these
expenses may exceed our projections.................... 17
We will be subject to significant new restrictions on
emissions which may force us to restrict our operations
or incur significant expenses.......................... 19
The financial projections and the underlying assumptions
that we have presented to help you to evaluate the
merits of an investment in the pass through trust
certificates are inherently imprecise and actual
results are expected to differ......................... 19
Under the asset purchase agreement with NYSEG, we have
assumed liabilities of NYSEG that could result in
unexpected expenses and we have given up the right to
make claims for problems we may discover later......... 20
We or our affiliates may have to defend lawsuits relating
to asbestos exposure at our electricity generating
stations while they were owned by NYSEG and damages in
those suits or the cost of defending them could be
material............................................... 20
If we enter bankruptcy proceedings, sufficient funds to
make distributions under the pass through trust
certificates might not be available.................... 20
If we default under the leases, the value of the
collateral for the secured lease obligation notes might
not be sufficient to provide for all scheduled payments
under the pass through trust certificates.............. 21
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If we default under the leases, the indenture trustee may
have difficulty continuing the operation of our
electricity generating plants, which will reduce their
collateral value....................................... 21
We are effectively subordinated to creditors of two of our
electricity generating stations........................ 22
We are controlled by The AES Corporation and The AES
Corporation may pursue its own interests to the
detriment of holders of pass through trust
certificates........................................... 22
The AES Corporation is not obligated to provide further
funding to us if we are unable to pay our
obligations............................................ 22
We expect that two senior members of our management team
will devote a portion of their time to other projects
for The AES Corporation................................ 22
In the future we might compete with other electricity
generating stations owned by The AES Corporation....... 22
A liquid and deep public market for the pass through trust
certificates may never develop and it may be difficult
to sell the pass through trust certificates at
favorable prices....................................... 23
We intend to suspend reporting under the Exchange Act as
soon as we are able to do so........................... 23
Ratings assigned to the pass through trust certificates
are not investment recommendations and do not assure
market value........................................... 23
This Exchange Offer......................................... 24
Ratio of Earnings to Fixed Charges.......................... 33
Use of Proceeds............................................. 34
Capitalization.............................................. 35
Discussion and Analysis of Financial Condition and Results
of Operations............................................. 36
Forward Looking Statements.................................. 41
Our Company and The AES Corporation......................... 43
Business.................................................... 46
The Lease Transactions...................................... 71
Regulation.................................................. 82
Management.................................................. 91
Relationships with Affiliates and Related Transactions...... 94
Description of the Pass Through Trust Certificates.......... 95
Description of the Working Capital Credit Facility.......... 155
U.S. Federal Income Tax Consequences........................ 157
ERISA Considerations........................................ 163
Plan of Distribution........................................ 165
Experts..................................................... 166
Legal Matters............................................... 167
Financial Statements........................................ F-1
Glossary of Certain Electric Industry Terms................. G-1
Index of Defined Terms...................................... I-1
Schedule I -- Amortization Schedule of Secured Lease
Obligation Notes.......................................... S-1
Appendix A -- Independent Engineer's Report................. A-1
Appendix B -- Independent Market Consultant's Report........ B-1
Appendix C -- Coal Market Study............................. C-1
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PROSPECTUS SUMMARY
This summary highlights selected information from this prospectus. Because
this is a summary, it does not contain all of the information that may be
important to you. You should carefully read the entire prospectus to understand
fully the terms of the exchange offer and the new pass through trust
certificates, as well as the tax and other considerations that are important to
you in making your investment decision and participating in the exchange offer.
You should pay special attention to the "Risk Factors" section beginning on page
14 of this prospectus.
For your convenience, a glossary of the technical terms used in this
prospectus and an index of defined terms used in this prospectus appear at the
end of this prospectus.
AES EASTERN ENERGY
We were formed in 1998 as an indirect wholly owned subsidiary of The AES
Corporation to take part in the acquisition by subsidiaries of The AES
Corporation of six coal-fired electricity generating stations and related assets
located in the western and west central part of New York State. AES NY, L.L.C.
is the sole general partner of our company and AES NY2, L.L.C. is the sole
limited partner of our company. The AES Corporation owns indirectly all of the
member interests in both AES NY, L.L.C. and AES NY2, L.L.C. The mailing address
of our principal executive offices is 1001 North 19th Street, Arlington,
Virginia 22209, telephone no. (703) 522-1315.
New York State Electric & Gas Corporation and its affiliate NGE Generation,
Inc. (whom we refer to collectively as "NYSEG") sold these six electricity
generating stations and related assets as part of NYSEG's overall plan to divest
itself of electricity generating assets. NYSEG and many other integrated
electric utilities in New York and elsewhere in the United States have announced
plans to sell electricity generating assets in response to state regulatory
initiatives which favor more decentralized ownership of electricity generating,
transmission and distribution assets. The purchase of these assets from NYSEG is
an element of The AES Corporation's overall strategy to be a major participant
in the newly competitive and deregulated markets for electricity, principally
through the purchase of strategically significant regional generating assets.
On May 14, 1999, twelve special purpose business trusts formed by three
institutional investors that are not affiliated with us or with The AES
Corporation acquired from NYSEG and leased to us the assets constituting the
Kintigh Generating Station and the Milliken Generating Station, excluding the
real property on which they are located. On that date, we acquired from NYSEG
the real property on which the Kintigh Generating Station and the Milliken
Generating Station are located and two additional coal-fired electricity
generating stations, the Goudey Generating Station and the Greenidge Generating
Station (together with the real property upon which they are located). We leased
a portion of the real property on which the Kintigh Generating Station and the
Milliken Generating Station are located and a selective catalytic reduction
system, which reduces emissions of nitrogen oxides, that was then being
installed at the Kintigh Generating Station to the special purpose business
trusts, which subleased them back to us. As part of the transaction, another
subsidiary of The AES Corporation that we do not control acquired the stock of
the Somerset Railroad Corporation, which owns short line railroad assets used to
transport coal to the Kintigh Generating Station. Somerset Railroad entered into
a coal hauling agreement with us to transport coal. Another subsidiary of The
AES Corporation that we do not control acquired the balance of the assets that
were purchased from NYSEG, consisting of two older, coal-fired electricity
generating stations, the Jennison Generating Station and the Hickling Generating
Station. These two stations are expected to be used primarily to generate
revenues from ancillary services rather than power generation.
THIS EXCHANGE OFFER
On May 14, 1999, we completed an offering of $550 million principal amount
of pass through trust certificates that was exempt from the SEC's registration
requirements. In connection with that offering, we agreed, among other things,
to deliver to you this prospectus and to use our best efforts to complete the
exchange offer by November 10, 1999.
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SUMMARY OF THIS EXCHANGE OFFER AND CONSENT SOLICITATION
This Exchange Offer........... We are offering to exchange:
-- $1,000 principal amount of Series 1999-A
pass through trust certificates which have been
registered under the Securities Act for each
outstanding $1,000 principal amount of Series
1999-A pass through trust certificates, and
-- $1,000 principal amount of Series 1999-B
pass through trust certificates which have been
registered under the Securities Act for each
outstanding $1,000 principal amount of Series
1999-B pass through trust certificates.
The form and terms of the pass through trust
certificates that we are offering in the
exchange offer are identical in all material
respects to the form and terms of the existing
pass through trust certificates which were
issued on May 14, 1999 in an offering that was
exempt from the SEC's registration
requirements, except that the pass through
trust certificates that we are offering in the
exchange offer have been registered under the
Securities Act. The pass through trust
certificates that we are offering in the
exchange offer will evidence the same
obligations as, and will replace, the existing
pass through trust certificates and will be
issued under the same pass through trust
agreements.
If you wish to exchange an outstanding pass
through trust certificate, you must properly
tender it in accordance with the terms
described in this prospectus. As a condition to
a valid tender, you will be required to give
your consent to the proposed waiver of our
obligation to file a shelf registration
statement under certain circumstances as set
forth in the registration rights agreement. We
will exchange all outstanding pass through
trust certificates that are validly tendered
and are not validly withdrawn.
As of this date, there are $282 million
principal amount of existing Series 1999-A pass
through trust certificates and $268 million
principal amount of existing Series 1999-B pass
through trust certificates outstanding. The
exchange offer is not contingent upon any
minimum aggregate principal amount of existing
pass through trust certificates being tendered
for exchange. We will arrange for the pass
through trustee to issue the registered pass
through trust certificates on or promptly after
the expiration of the exchange offer.
Consent Solicitation.......... In connection with the exchange offer, we are
seeking the consent of the holders of the
existing pass through trust certificates to a
waiver of our obligation to file a shelf
registration statement as a result of our
failure to complete the exchange offer on or
prior to November 10, 1999, which is 180 days
after the original issue date of the existing
pass through trust certificates. We are seeking
these consents because the holders of existing
pass through trust certificates who would
benefit from this shelf registration statement
will not need it to resell the new pass through
trust certificates they will receive if they
participate in this exchange offer. See
"-- RESALES OF NEW PASS THROUGH TRUST
CERTIFICATES." By properly tendering
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your existing pass through trust certificates,
you will be deemed to consent to the proposed
waiver of our obligation to file a shelf
registration statement as described above. The
proposed waiver will become effective with
respect to all holders of existing pass through
trust certificates if the holders of a majority
of the principal amount of the existing pass
through trust certificates tender their
certificates.
Registration Rights
Agreement..................... We are making this exchange offer in order to
satisfy our obligation under the registration
rights agreement, entered into on May 11, 1999,
to cause our registration statement to become
effective under the Securities Act. You are
entitled to exchange your pass through trust
certificates for registered pass through trust
certificates with substantially identical
terms. After the exchange offer is complete,
you will generally no longer be entitled to any
registration rights with respect to your pass
through trust certificates.
Resales of the New Pass
Through Trust Certificates.... Based on an interpretation by the staff of the
SEC set forth in no-action letters issued to
third parties, we believe that the new pass
through trust certificates may be offered for
resale, resold and otherwise transferred by you
without compliance with the registration and
prospectus delivery requirements of the
Securities Act provided that:
- you acquire any new pass through trust
certificate in the ordinary course of your
business;
- you are not participating, do not intend to
participate, and have no arrangement or
understanding with any person to
participate, in the distribution of the new
pass through trust certificates;
- you are not a broker-dealer who purchased
existing pass through trust certificates
for resale pursuant to Rule 144A or any
other available exemption under the
Securities Act; and
- you are not an "affiliate" (as defined in
Rule 405 under the Securities Act) of our
company.
If our belief is inaccurate and you transfer
any new pass through trust certificate without
delivering a prospectus meeting the
requirements of the Securities Act or without
an exemption from registration of your pass
through trust certificates from such
requirements, you may incur liability under the
Securities Act. We do not assume or indemnify
you against this liability.
Each broker-dealer that is issued new pass
through trust certificates for its own account
in exchange for pass through trust certificates
must acknowledge that it will deliver a
prospectus meeting the requirements of the
Securities Act in connection with any resale of
the new pass through trust certificates. The
letter of transmittal states that, by making
this acknowledgment and by delivering a
prospectus, a broker-dealer will not be deemed
to admit that it is an "underwriter" within the
meaning of the Securities Act. A broker-dealer
who acquired existing pass through trust
certificates for its own account as a result of
market-making
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or other trading activities may use this
prospectus for an offer to resell, resale or
other retransfer of the new pass through trust
certificates. We have agreed that, for a period
of 120 days following the completion of this
exchange offer, we will make this prospectus
and any amendment or supplement to this
prospectus available to any broker-dealers for
use in connection with these resales. We
believe that no registered holder of the
existing pass through trust certificates is an
affiliate (as the term is defined in Rule 405
of the Securities Act) of our company.
Expiration Date............... Both this exchange offer and the consent
solicitation will expire at 5:00 p.m., New York
City time, March 20, 2000, unless we decide to
extend the expiration date.
Conditions to this Exchange
Offer......................... This exchange offer is not subject to any
conditions other than that it does not violate
applicable law or any applicable interpretation
of the staff of the SEC.
Withdrawal Rights............. You may withdraw the tender of your pass
through trust certificates at any time prior to
5:00 p.m. New York City time on March 20, 2000.
If you withdraw your tender of existing pass
through trust certificates, your consent to the
proposed waiver will also be deemed withdrawn.
You may not withdraw your consent without
withdrawing your tender of existing pass
through trust certificates.
U.S. Federal Income Tax
Consequences................ The exchange of pass through trust certificates
will not constitute a taxable exchange for
United States federal income tax purposes. For
a discussion of other U.S. federal income tax
consequences resulting from the exchange,
acquisition, ownership and disposition of the
new pass through trust certificates, see "U.S.
FEDERAL INCOME TAX CONSEQUENCES."
Use of Proceeds............... We will not receive any proceeds from the
issuance of pass through trust certificates in
this exchange offer. We will pay all
registration expenses incident to this exchange
offer. Each holder of pass through trust
certificates will pay all underwriting
discounts and commissions and transfer taxes
incurred in the sale or disposition of the pass
through trust certificates issued in this
exchange offer.
Exchange Agent................ Bankers Trust Company is serving as exchange
agent in connection with the exchange offer.
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SUMMARY OF TERMS OF THE NEW PASS THROUGH TRUST CERTIFICATES
The form and terms of the new pass through trust certificates are the same
as the form and terms of the existing pass through trust certificates except
that the new pass through trust certificates will be registered under the
Securities Act and, therefore, will not bear legends restricting their transfer
and, in general, will not be entitled to registration under the Securities Act.
The new pass through trust certificates will evidence the same obligations as
the existing pass through trust certificates and both the existing pass through
trust certificates and the new pass through trust certificates are governed by
the same pass through trust agreements.
The pass through trust certificates are not our direct obligation. Each
pass through trust certificate represents a fractional undivided interest in one
of two pass through trusts formed pursuant to two separate pass through trust
agreements between us and Bankers Trust Company, as pass through trustee under
each pass through trust agreement. The pass through trusts were formed for the
benefit of the holders of the pass through trust certificates.
The property of the pass through trusts consists solely of secured lease
obligation notes issued on a non-recourse basis by twelve separate special
purpose business trusts. These secured lease obligation notes were issued in a
leveraged lease transaction with respect to each special purpose business
trust's undivided interest in the assets constituting either the Kintigh
Generating Station or the Milliken Generating Station. The amount
unconditionally payable by us for our leases of the special purpose business
trusts' interests in the Kintigh Generating Station and the Milliken Generating
Station will be at least sufficient to pay in full when due all payments of
principal of, premium, if any, and interest on, the secured lease obligation
notes issued by the special purpose business trusts. The secured lease
obligation notes issued by the special purpose business trusts were issued in
two series under lease indentures between the special purpose business trusts
and Bankers Trust Company, as lease indenture trustee. Each pass through trust
purchased one series of the secured lease obligation notes issued by the special
purpose business trusts so that all of the secured lease obligation notes held
in each pass through trust have an interest rate and maturity date corresponding
to the interest rate and final distribution date applicable to the pass through
trust certificates issued by that pass through trust. The pass through trustee
will generally distribute any amounts paid by the special purpose business
trusts in respect of the secured lease obligation notes to the holders of the
pass through trust certificates promptly after receipt. Distributions on the
pass through trust certificates therefore depend on the rental and other
payments that we make under the leases of the Kintigh Generating Station and the
Milliken Generating Station. The AES Corporation has no obligation for and has
not guaranteed our lease obligations, the pass through trust certificates or the
secured lease obligation notes issued by the special purpose business trusts
which are held by the pass through trusts.
SECURITIES OFFERED............ $550,000,000 aggregate principal amount of Pass
Through Trust Certificates, Series 1999-A and
Series 1999-B.
LESSEE........................ AES Eastern Energy, L.P.
PASS THROUGH TRUSTS........... Each of the two pass through trusts were formed
by separate pass through trust agreements
between us and Bankers Trust Company, as the
pass through trustee.
PRINCIPAL AMOUNT..............
PRINCIPAL
CERTIFICATE AMOUNT
----------- ------------
Series 1999-A....................... $282,000,000
Series 1999-B....................... 268,000,000
------------
$550,000,000
INTEREST...................... Interest will accrue on the principal amount of
the secured lease obligation notes issued by
the special purpose business trusts at the
applicable rate per annum listed below.
Additional interest has
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been accruing at the rate of 0.50% per annum
since November 10, 1999 as a result of our
failure to complete this exchange offer on or
prior to November 10, 1999 and will accrue
until we complete this exchange offer. Interest
will be payable on the secured lease obligation
notes semiannually on January 2 and July 2 of
each year and will be paid with respect to the
semiannual period then ended. Additional
interest will be paid at the same times. The
first interest payment date is January 2, 2000.
The pass through trustee will then distribute
interest payments to holders of the pass
through trust certificates.
CERTIFICATE INTEREST RATE
----------- -------------
Series 1999-A........................ 9.00%
Series 1999-B........................ 9.67%
PRINCIPAL DISTRIBUTION
DATES......................... With respect to each series of pass through
trust certificates, the initial principal
distribution date and the final principal
distribution date are as follows:
INITIAL PRINCIPAL FINAL PRINCIPAL
CERTIFICATE DISTRIBUTION DATE DISTRIBUTION DATE
----------- ----------------- -----------------
Series 1999-A........ July 2, 2003 January 2, 2017
Series 1999-B........ January 2, 2018 January 2, 2029
AVERAGE LIFE.................. The average life of each series of pass through
trust certificates is as follows:
CERTIFICATE AVERAGE LIFE
----------- ------------
Series 1999-A........................ 13.1 years
Series 1999-B........................ 22.5 years
RATINGS....................... Standard & Poor's Ratings Services, Moody's
Investors Service, Inc. and Fitch IBCA, Inc.
have assigned ratings to the pass through trust
certificates of BBB-, Ba1 and BBB-,
respectively.
RANKING....................... Our obligation to make lease rental payments is
a senior unsecured obligation of our company
and ranks equally in right of payment with all
of our other existing and future senior
unsecured indebtedness and our future senior
secured indebtedness, and senior in right of
payment to all of our existing and future
indebtedness that is designated as subordinate
or junior in right of payment to the lease
rental payments. We have a $50 million secured
working capital credit facility with Credit
Suisse First Boston which has priority over our
obligation to make lease rental payments. No
amounts are currently outstanding under this
facility. See "DESCRIPTION OF THE WORKING
CAPITAL CREDIT FACILITY." See "DESCRIPTION OF
THE PASS THROUGH TRUST
CERTIFICATES -- COVENANTS" for a description of
restrictions on our ability to incur
indebtedness and liens.
PASS THROUGH TRUST PROPERTY... The property of each pass through trust
consists solely of secured lease obligation
notes issued on a non-recourse basis by each of
the special purpose business trusts in twelve
separate lease transactions. Each pass through
trust purchased one series of the secured
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lease obligation notes issued by each of the
special purpose business trusts so that all of
the notes held in each pass through trust have
an interest rate, amortization schedule and
maturity date corresponding to the interest
rate, amortization schedule and final
distribution date applicable to the pass
through trust certificates issued by each pass
through trust.
COLLATERAL FOR THE SECURED
LEASE OBLIGATION NOTES........ The secured lease obligation notes issued by
each special purpose business trust are secured
by a lien on and first priority security
interest in the rights and interests of the
special purpose business trust (other than
customary excepted payments and excepted rights
reserved to the special purpose business trust
and the institutional investor who formed that
special purpose business trust) in the related
lease, including the right to receive payments
of periodic rent, the special purpose business
trust's undivided interest in either the
Kintigh Generating Station or the Milliken
Generating Station and the special purpose
business trust's rights and interests in the
agreements relating to the lease transactions.
See "DESCRIPTION OF THE PASS THROUGH TRUST
CERTIFICATES -- THE SECURED LEASE OBLIGATION
NOTES."
DEPOSIT AND DISBURSEMENT
AGREEMENT..................... Our company, each subsidiary of our company,
Bankers Trust Company, as the lease indenture
trustee, other lease transaction participants
and Bankers Trust Company, as depositary and
disbursement agent, entered into a deposit and
disbursement agreement pursuant to which all of
our revenues and the revenues of each
subsidiary of ours will be deposited with the
depositary and disbursement agent. The deposit
and disbursement agreement establishes a
hierarchy for the distribution of revenues
produced by our company and our subsidiaries.
Under this hierarchy, our operations and
maintenance expenses (including capital
expenditures) are to be paid prior to the
rental payments under the leases for the
Kintigh Generating Station and the Milliken
Generating Station. Amounts we borrow under the
working capital credit facility between us and
Credit Suisse First Boston, which will be used
to fund these expenses, as necessary, are to be
paid after our operations and maintenance
expenses but prior to the rental payments under
the leases for the Kintigh Generating Station
and the Milliken Generating Station. See
"DESCRIPTION OF THE PASS THROUGH TRUST
CERTIFICATES -- THE DEPOSIT AND DISBURSEMENT
AGREEMENT."
REDEMPTION.................... The secured lease obligation notes may be
redeemed in certain circumstances, and
distributions to the holders of pass through
trust certificates issued by each pass through
trust related to the notes being redeemed will
be made on the date and in the amount paid in
respect of the redemption of these notes. See
"DESCRIPTION OF THE PASS THROUGH TRUST
CERTIFICATES -- REDEMPTION OF SECURED LEASE
OBLIGATION NOTES."
COVENANTS..................... The agreements relating to our leases of the
Kintigh Generating Station and the Milliken
Generating Station include covenants that
limit, among other things, our ability and the
ability of our
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subsidiaries to incur debt, sell assets, create
liens and make distributions and other
payments, and our ability to merge or
consolidate or transfer, assign or sublease our
interest in the Kintigh Generating Station and
the Milliken Generating Station.
GOVERNING LAW................. The pass through trust certificates, the pass
through trust agreements, the lease indentures
and the secured lease obligation notes are
governed by the laws of the State of New York.
BOOK-ENTRY, DELIVERY AND
FORM.......................... Pass through trust certificates were issued in
denominations of $100,000 or any integral
multiple of $1,000 in excess of $100,000. Pass
through trust certificates are issued in
registered form, without interest coupons, and
have been deposited with the pass through
trustee as custodian for, and registered in the
name of, The Depository Trust Company or Cede &
Co., its nominee, in each case for credit to an
account of a direct or indirect participant of
The Depository Trust Company. See "DESCRIPTION
OF THE PASS THROUGH TRUST
CERTIFICATES -- BOOK-ENTRY; DELIVERY AND FORM."
INDENTURE AND PASS THROUGH
TRUSTEE....................... Bankers Trust Company will act as trustee,
paying agent and registrar for the pass through
trust certificates to be issued by each pass
through trust. Bankers Trust Company will also
act as the lease indenture trustee for the
secured lease obligation notes issued by the
special purpose business trusts.
INDEPENDENT ENGINEER.......... Stone & Webster Management Consultants, Inc.
and its affiliated company, Stone & Webster
Engineering Corporation, as Independent
Engineer, has produced the report set forth in
Appendix A to this prospectus and provided the
summary of that report appearing under
"BUSINESS -- SUMMARY OF INDEPENDENT ENGINEER'S
REPORT" below.
INDEPENDENT MARKET
CONSULTANT.................... London Economics, Inc., as Independent Market
Consultant, has produced the report set forth
in Appendix B to this prospectus and provided
the summary of that report appearing under
"BUSINESS -- SUMMARY OF INDEPENDENT MARKET
CONSULTANT'S REPORT" below.
INDEPENDENT COAL MARKET
CONSULTANT.................... John T. Boyd Company, as Independent Coal
Market Consultant , has produced the report set
forth in Appendix C to this prospectus and
provided the summary of that report appearing
under "BUSINESS -- SUMMARY OF COAL MARKET
STUDY" below.
RISK FACTORS.................. An investment in the pass through trust
certificates involves risks, including, without
limitation, risks related to the uncertainties
associated with the competitive market in which
we will operate, environmental liabilities,
risks related to the structure of the lease
transactions and operational risks associated
with our electricity generating stations. See
"RISK FACTORS."
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The following diagram illustrates aspects of the ongoing payment flows in
the lease transactions among us, the indenture trustee, the special purpose
business trusts, the institutional investors, the pass through trustee and the
pass through trust certificate holders.
[Energy Flow Chart]
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SUMMARY FINANCIAL DATA
Set forth below is summary financial data of our company as of September
30, 1999 and for the period from May 14, 1999 to September 30, 1999. This
summary financial data has been extracted from our audited financial statements
which are included in this prospectus.
SUMMARY BALANCE SHEET DATA (in millions):
Total Assets................................................ $1,144
Long-Term Liabilities..................................... 691
Partners' Capital......................................... 384
SUMMARY STATEMENT OF INCOME DATA (in millions):
Operating Revenues........................................ $ 121
Operating Income.......................................... 48
Net Income................................................ $ 30
We engaged in no operations between our formation in 1998 and May 14, 1999.
There are no separate financial statements available with regard to our
electricity generating stations prior to May 14, 1999 because their operations
were fully integrated with, and therefore results of operations were
consolidated into, NYSEG.
No financial statements of the pass through trusts are included in this
prospectus since the property of the pass through trusts consists solely of the
secured lease obligation notes and because distributions by the pass through
trusts depend on the rental and other payments that we make under the leases of
the Kintigh Generating Station and the Milliken Generating Station.
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PROJECTED FINANCIAL DATA
The following table sets forth summary projected cash flow statement data
of our company. We prepared the financial projections and they are included in
the Independent Engineer's Report. Data for 1999 was prepared on the basis that
our operations and ownership of our electricity generating stations would begin
on May 1, 1999. Revenues are based on cash receipts collected from customers.
Expenses are based on cash disbursements to vendors, suppliers, employees and
others, excluding rent payments under the leases. Cash Available for Fixed
Charges is equal to revenues less expenses, capital expenditures and net
interest expense (income). Fixed charges consist of rent payments under the
leases equal to principal and interest on the pass through trust certificates
and non-deferrable rent. Net Cash Provided by Operating Activities is equal to
the difference between Cash Available for Fixed Charges and Total Rent Payment.
The Fixed Charge Coverage Ratio is equal to Cash Available for Fixed Charges
divided by fixed charges.
Our financial projections consist of a base case and six sensitivity cases.
The base case represents our opinion of the most probable specific amounts for
our revenue, operating costs, capital expenditures, interest we will earn on
reserves we are required to maintain in connection with the leases for the
Kintigh Generating Station and the Milliken Generating Station, and interest we
will pay under our working capital credit facility with Credit Suisse First
Boston. The sensitivity cases show how the base case is affected by variations
in important market, operating cost and capital expenditure assumptions. We do
not intend to provide holders of pass through trust certificates with any
revised or updated financial projections or analysis of the differences between
the financial projections and actual operating results.
Our financial projections are subject to all of the assumptions,
qualifications and limitations described in the Independent Engineer's Report
attached as Appendix A to this prospectus. Financing assumptions, including the
interest rates, debt amortization schedule and lease payments are based on the
terms of the agreements relating to the lease of the Kintigh Generating Station
and the Milliken Generating Station. Market price projections for electricity
and installed capacity are based on the Independent Market Consultant's Report
prepared by London Economics and attached as Appendix B to this prospectus.
Market projections for coal prices are based on the base case pricing forecast
contained in the Coal Market Study prepared by John T. Boyd Company, Independent
Coal Market Consultant, which is attached as Appendix C to this prospectus. We
have assumed that cash receipts will be received 30 days after revenue is earned
and cash disbursements will be paid 30 days after the payment obligation is
incurred. We treated the semiannual rent payments that are due on January 2 of
each year as though they will be paid in the preceding year. Our financial
projections incorporate an assumed inflation rate of 2% per year for the years
1999 through 2032. Our ability to make distributions to the partners of our
company is restricted by the terms of the agreements governing the leases for
the Kintigh Generating Station and the Milliken Generating Station. We may make
distributions only on or within five days after a semiannual rent payment date
and only if all rent on the leases has been paid, the reserve accounts for lease
payments that we are required to maintain are fully funded and other conditions
are satisfied. See "DESCRIPTION OF THE PASS THROUGH TRUST
CERTIFICATES -- RESTRICTED PAYMENTS." Although we expect to make distributions
to our partners if we are permitted to do so, we have not included distributions
in our financial projections because distributions are effectively subordinated
to our obligations to pay rent and other expenses.
Our actual results may differ materially from those presented in our
financial projections. No one is representing that the results contained in our
financial projections will be achieved. We do not, as a matter of course, make
public projections as to future revenues, earnings or other results. We did not
prepare our financial projections with a view toward complying with the
guidelines established by the American Institute of Certified Public Accountants
with respect to prospective financial information. Therefore, our financial
projections may not be comparable to financial projections of others. Neither
Deloitte & Touche LLP, our independent auditors, nor any other independent
accountants, have examined, compiled or performed any procedures with respect to
our financial projections nor have they expressed any opinion or any other form
of assurance with respect to our financial projections or their achievability,
and assume no responsibility for, and disclaim any association with, our
financial projections. You should read the information set forth below in
conjunction with the discussion under "RISK FACTORS -- THE FINANCIAL PROJECTIONS
AND THE UNDERLYING ASSUMPTIONS THAT WE HAVE PRESENTED TO HELP YOU EVALUATE THE
MERITS OF AN INVESTMENT IN THE PASS THROUGH
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TRUST CERTIFICATES ARE INHERENTLY IMPRECISE AND ACTUAL RESULTS ARE EXPECTED TO
DIFFER" and "DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS."
YEAR ENDING DECEMBER 31,
----------------------------------------------------
1999 2000 2001 2002 2003
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT RATIOS)
BASE CASE PROJECTED CASH FLOW STATEMENT
DATA:
Revenues................................ $188,370 $308,831 $337,793 $364,309 $368,840
Expenses.............................. 124,838 187,814 197,860 196,114 204,490
Capital Expenditures.................. 10,609 12,249 7,177 17,003 15,604
Cash Available for Fixed Charges...... 54,403 110,628 134,132 152,556 150,110
Rent for Principal and Interest on
Certificates....................... 32,487 51,296 51,296 51,296 58,149
Deferrable Rent....................... 4,000 8,454 9,204 9,204 2,351
-------- -------- -------- -------- --------
Total Rent Payment.................... $ 36,487 $ 59,750 $ 60,500 $ 60,500 $ 60,500
-------- -------- -------- -------- --------
Net Cash Provided by Operating
Activities......................... $ 17,916 $ 50,878 $ 73,632 $ 92,056 $ 89,610
Fixed Charge Coverage Ratio........... 1.67x 2.16x 2.61x 2.97x 2.58x
Ten-Year Average FCCR (2000-2009)..... 2.44x
Average FCCR Over Term of
Certificates....................... 3.38x
INDEPENDENT ENGINEER'S CONCLUSIONS REGARDING FINANCIAL PROJECTIONS
Stone & Webster, as Independent Engineer, reviewed our financial
projections. Stone & Webster is an international engineering and consulting firm
in the electric power industry. We retained Stone & Webster because of its
reputation in that field. Stone & Webster is not affiliated with us. We retained
Stone & Webster on behalf of the institutions that initially purchased the
existing pass through trust certificates to provide an independent technical
assessment of our electricity generating stations. Stone & Webster is also
acting as independent engineer for purposes of making required technical
certifications to the special purpose business trusts that own the Kintigh
Generating Station and the Milliken Generating Station and to the institutional
investors that formed the special purpose business trusts. We pay Stone &
Webster's fees and expenses for performing those services. We and other
affiliates of The AES Corporation may in the future retain Stone & Webster and
its affiliated companies for other professional engineering and consulting
services.
The scope of Stone & Webster's independent technical review included design
and equipment, operating history, projected performance, technical, logistical,
operations and maintenance and environmental considerations, as described in the
Independent Engineer's Report attached as Appendix A to this prospectus.
Stone & Webster also reviewed the technical and commercial assumptions and
the calculation methodology of our financial projections as well as the
projected performance, revenue and expenses. Set forth below is a summary of
their conclusions with respect to analyses they performed on the fixed charge
coverage ratios shown in our financial projections to determine their
sensitivity to changes in the assumptions we made in preparing them. Stone &
Webster's conclusions are based on the financial analysis set forth in the
Independent Engineer's Report attached as Appendix A to this prospectus. The
foregoing description of the services provided by Stone & Webster should be read
in conjunction with the full text of the Independent Engineer's Report.
Stone & Webster performed several sensitivity analyses on the base case
assumptions set forth in our financial projections, including analyses based on:
- the downside scenarios of London Economics, the Independent Market
Consultant, for energy and capacity prices and reduced capacity factors;
- reduction of capacity factors by 10%;
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- increase of fuel costs (including coal transportation) by 10%;
- increase of operations and maintenance ("O&M") costs of 25%;
- increase in capital expenditures by 50%; and
- increase of heat rates at each unit by 500 Btu/kWh.
Set forth below is a summary showing minimum fixed charge coverage ratios
and average fixed charge coverage ratios for the life of the leases. The fixed
charge coverage ratios for the base case and each of the sensitivity cases are
presented in the table below and have been calculated on a pre-tax basis. The
minimum fixed charge coverage ratios in the base case and in the six sensitivity
cases all occurred in 1999.
MINIMUM
POST-1999 AVERAGE
1999 FCCR FCCR FCCR
--------- --------- -------
Base Case............................................ 1.67x 2.13x 3.38x
Sensitivity 1: London Economics' Downside
Scenarios............................................ 1.28x 1.61x 2.66x
Sensitivity 2: Reduced Capacity Factors.............. 1.48x 1.93x 3.12x
Sensitivity 3: Increased Fuel Costs.................. 1.41x 1.87x 3.04x
Sensitivity 4: Increased O&M Costs................... 1.34x 1.87x 3.07x
Sensitivity 5: Increased Capital Expenditures........ 1.51x 2.04x 3.26x
Sensitivity 6: Increased Heat Rates.................. 1.52x 1.99x 3.19x
THE INDEPENDENT MARKET CONSULTANT
London Economics is a specialized economics consulting organization. We
retained London Economics because of its reputation in that field. London
Economics is not affiliated with us. We retained London Economics on behalf of
the institutions that initially purchased the existing pass through trust
certificates to conduct an independent market study of the New York region and
to forecast detailed prices for the New York power market. We pay the fees and
expenses of London Economics for performing those services. We and other
affiliates of The AES Corporation may in the future retain London Economics for
other economics consulting services.
London Economics used its proprietary power markets simulation model to
model pricing outcomes in the New York energy market based on input assumptions
that are described in the Independent Market Consultant's Report attached as
Appendix B to this prospectus. The method used by London Economics to forecast
prices for installed capacity is also described in that report. The foregoing
description of the services provided by London Economics should be read in
conjunction with the full text of the Independent Market Consultant's Report.
THE INDEPENDENT COAL MARKET CONSULTANT
John T. Boyd Company is a mining and geological consulting organization. We
retained John T. Boyd Company because of its reputation in that field. John T.
Boyd Company is not affiliated with us. We retained John T. Boyd Company on
behalf of the institutions that initially purchased the existing pass through
trust certificates to conduct an independent analysis of the market for coals
supplied to northeastern U.S. utilities from Maryland, eastern Ohio,
Pennsylvania and northern West Virginia. We pay the fees and expenses of John T.
Boyd Company for performing those services. We and other affiliates of The AES
Corporation may in the future retain John T. Boyd Company for other mining and
geological consulting services.
John T. Boyd Company's report states that its market analysis was based on
its extensive knowledge of the coal industry within the regional study areas and
its numerous databases of published information on coal production, coal
reserves, coal prices and other matters. The foregoing description of the
services provided by John T. Boyd Company should be read in conjunction with the
full text of the Independent Coal Market Consultant's Report.
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RISK FACTORS
In addition to the information contained elsewhere in this prospectus, you
should carefully consider the following risk factors before making an investment
decision and participating in the exchange offer.
THE MARKET IN WHICH OUR BUSINESS WILL BE CONCENTRATED IS BEING DEREGULATED
AND THERE IS NO HISTORICAL PRICE DATA THAT YOU CAN USE TO ASSESS WHETHER WE WILL
BE ABLE TO SELL OUR ELECTRIC ENERGY, INSTALLED CAPACITY AND ANCILLARY SERVICES
AT PRICES THAT WILL PERMIT US TO PAY OUR EXPENSES
With the exception of revenue generated by our agreements with NYSEG, our
revenues and results of operations will depend on the prices we can obtain for
energy, installed capacity and ancillary services in the recently deregulated
New York power pool and adjacent markets. Because the deregulated markets for
wholesale energy, installed capacity and ancillary services have only recently
come into effect, there is no historical price data that you can use to assess
the likelihood that those prices will be sufficient to permit us to pay our
expenses. See "BUSINESS -- INDUSTRY OVERVIEW" and "BUSINESS -- OUR PLAN AND
STRATEGY." Among the factors that will influence such prices (all of which
factors are beyond our control) are:
- existing and projected generating capacity surpluses which could have the
effect of driving prices down;
- a decrease in natural gas prices, which would make gas-fired electricity
generating facilities more competitive with our coal-fired electricity
generating stations;
- prevailing market prices for coal;
- additional supplies of electric energy, installed capacity and ancillary
services becoming available from our current competitors or new market
entrants, including the development of new generation facilities that may
be able to produce energy less expensively than our coal-fired
electricity generating stations;
- newly adopted regulations of the new independent system operator system
in the New York power pool;
- additional supplies of energy or energy-related services becoming
available if there is an increase in physical transmission capacity into
the New York power pool;
- the extended operation of nuclear generating plants located in the New
York power pool and adjacent markets beyond their presently expected
dates of decommissioning, or the resumption of generation by nuclear
facilities in Ontario, Canada that are currently out of service;
- weather conditions prevailing in New York State from time to time;
- the possibility of a reduction in the projected rate of growth in
electricity usage as a result of factors such as regional economic
conditions and the implementation of conservation programs;
- our ability to negotiate successfully and enter into advantageous
bilateral contracts for sales of our electric energy, installed capacity
and ancillary services; and
- export power transmission constraints, which would limit our ability to
sell energy, installed capacity and ancillary services in adjacent
markets in which prices are expected to be higher than in the western New
York power pool.
WE WILL BE REQUIRED TO MAKE SUBSTANTIAL PAYMENTS UNDER OUR LEASES AND OTHER
CONTRACTS AND WE MAY HAVE DIFFICULTY RESPONDING TO UNFORESEEN REQUIREMENTS
Our ratio of earnings to fixed charges for the period from May 14, 1999 to
September 30, 1999 was 2.04. See "RATIO OF EARNINGS TO FIXED CHARGES." The level
of our fixed charges and debt obligations could have important consequences to
holders of the pass through trust certificates. See "DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL
RESOURCES" and "BUSINESS -- THE
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ACQUISITION OF OUR ENERGY GENERATING STATIONS -- ACQUISITION-RELATED CONTRACTS."
These consequences include, but are not limited to, the following:
- a substantial portion of our cash flow from operations must be dedicated
to lease payments, payments of the principal of and interest on amounts
borrowed under the working capital credit facility with Credit Suisse
First Boston and payments pursuant to the coal hauling agreement with
Somerset Railroad and will not be available for other purposes;
- our future ability to obtain additional debt financing for working
capital, capital expenditures or other purposes is limited by financial
covenants restricting our ability to incur debt and liens contained in
the agreements governing the leases of the Kintigh Generating Station and
the Milliken Generating Station; and
- our fixed charges and level of indebtedness could limit our flexibility
to react to changes in the electricity generating industry, the New York
power pool and general economic conditions.
Some of our competitors currently operate with lower fixed charges and have
greater operating and financing flexibility than we have.
WE MAY HAVE DIFFICULTY MEETING OUR PAYMENT OBLIGATIONS IF OUR OPERATIONS ARE NOT
AS SUCCESSFUL AS WE HAVE PROJECTED
Cash flow from our operations was sufficient to cover aggregate rental
payments under the leases of the Kintigh Generating Station and the Milliken
Generating Station on the first rent payment date, January 2, 2000. If we are
unable to make lease payments, service our indebtedness and meet our operating
expenses, we will be forced to adopt an alternative strategy that may include
actions such as reducing or delaying our ongoing plans and strategies. We might
not succeed in effecting any of these strategies. See "DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL
RESOURCES" and "BUSINESS -- OUR PLAN AND STRATEGY."
OPERATION OF OUR STATIONS MIGHT BE DISRUPTED
As with all power generation facilities, operation of our electricity
generating stations will involve risks, including:
- our possible inability to achieve the output and efficiency levels for
our electricity generating stations that we have projected;
- interruptions in fuel supply;
- disruptions in the delivery of electricity;
- facility shutdown due to a breakdown or failure of equipment or
processes, violation of permit requirements (whether through operations
or change in law), operator error or catastrophic events such as fires,
explosions, floods or other similar occurrences affecting us, our
electricity generating stations or third parties upon which our business
may depend; and
- disputes with labor unions in which certain personnel involved in the
operation of our electricity generating stations are members and disputes
under various collective bargaining agreements applicable to our
electricity generating stations.
The occurrence of one or more of these events could significantly reduce
revenues generated by our electricity generating stations or significantly
increase the expenses of our electricity generating stations, thereby adversely
affecting our ability to make lease payments.
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OUR ELECTRICITY GENERATING STATIONS ARE NOT NEW AND WILL REQUIRE CAREFUL
MAINTENANCE IF THEY ARE TO OPERATE EFFICIENTLY
The generating equipment at our electricity generating stations is between
15 and 61 years old. While we think that this generating equipment has generally
been well maintained, we will have to make additional capital expenditures to
keep it operating at optimal levels. The average capital expenditures we expect
to make in our electricity generating stations are $11.9 million per year. The
terms of the leases and the related agreements and the working capital credit
facility with Credit Suisse First Boston contain financial covenants that
restrict our ability to incur indebtedness for these or other unexpected capital
expenditures.
OUR FINANCIAL PROJECTIONS ASSUME THAT WE WILL BE ABLE TO OPERATE OUR ELECTRICITY
GENERATING STATIONS NEARLY CONTINUALLY AND WE MAY HAVE TROUBLE MEETING OUR
OBLIGATIONS IF WE ARE NOT SUCCESSFUL
We will need to achieve high levels of availability and dispatch for our
electricity generating stations to operate profitably. We assumed that we will
achieve high levels of availability and dispatch in developing the revenue
figures included in our financial projections.
Developments that could affect the dispatch rate of our electricity
generating stations include:
- equipment problems or other problems which affect the availability of our
electricity generating stations to operate;
- non-utility generators continuing to be placed before our electricity
generating stations in the New York power pool dispatch sequence of
generating plants because they continue to be subject to power purchase
agreements with utilities that require that they be dispatched; we expect
that these non-utility generators will restructure their power purchase
agreements and that they will be placed in the dispatch sequence in a
position appropriate for their production costs, which position would
follow our electricity generating stations in the dispatch sequence;
- extended operation of nuclear generating plants, currently before our
electricity generating stations in the dispatch sequence, beyond their
presently expected dates of decommissioning or resumption of generation
by nuclear facilities in Ontario, Canada, that are currently out of
service;
- implementation of additional or more stringent environmental compliance
measures; or
- the construction of new generating plants which may be more efficient and
cost effective than our electricity generating stations.
OUR FINANCIAL PROJECTIONS ASSUME THAT THE REAL PRICE OF COAL WILL CONTINUE TO
DROP IN THE FUTURE; AN INCREASE IN THE REAL PRICE OF COAL WILL NEGATIVELY AFFECT
OUR OPERATING RESULTS
Based on the coal price forecast of the Independent Coal Market Consultant,
we have projected that the inflation adjusted or real price of coal will
continue to drop through 2010. Actual prices may not decline in real terms
throughout this period. Upward pressure on coal prices could result from
increased demand for coal, increased consolidation in the coal industry, more
stringent environmental restrictions and a resulting increase in the demand for
relatively more expensive low-sulfur coal, increased costs of developing new
reserves as the current reserves are exhausted or other factors. The Independent
Engineer performed a sensitivity analysis on our base case financial projections
showing the effects of a 10% increase in the coal prices we assumed which showed
that our fixed charge coverage ratios would decrease. See "BUSINESS -- OUR PLAN
AND STRATEGY -- FUEL SUPPLY STRATEGY," "APPENDIX A -- INDEPENDENT ENGINEER'S
REPORT" and "APPENDIX C -- COAL MARKET STUDY."
WE HAVE ONLY A LIMITED OPERATING HISTORY AND WE HAVE NOT DEMONSTRATED THAT WE
CAN OPERATE OUR ELECTRICITY GENERATING STATIONS IN A PROFITABLE MANNER
Although our electricity generating stations have a significant operating
history, we have only a limited history of owning or leasing and operating our
electricity generating stations. In addition, all of our electricity generating
stations have been operated as an integrated part of a regulated utility prior
to their acquisition
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from NYSEG and as such, their output of electricity was sold by NYSEG based upon
rates set by regulatory authorities at levels intended to permit NYSEG to
recover its capital and operating costs and to earn a profit. While owned by
NYSEG, our electricity generating stations were generally operated at lower
capacity factors than we plan to operate them. We may not be successful in
operating our electricity generating stations in a competitive environment in
which electricity rates will be set by the operation of market forces or our
electricity generating stations may not perform as expected. Additionally, the
revenues generated by our electricity generating stations may not support the
costs of operating them, the capital expenditures needed to maintain them, our
obligation to make rental payments under the leases, our obligation to pay the
principal amount of and interest on our indebtedness and our obligations under
the coal hauling agreement with Somerset Railroad. As a result of our having
only a limited operating history, the only historical financial data for our
company is the data for the period beginning May 14, 1999.
OUR BUSINESS IS EXTENSIVELY REGULATED AND NEW REGULATIONS MAY IMPOSE
REQUIREMENTS THAT WE ARE UNABLE TO MEET OR THAT REQUIRE US TO MAKE ADDITIONAL
EXPENDITURES
Our activities, including the operation of our electricity generating
stations, will be subject to extensive energy and environmental regulation by
federal, state and local authorities. In addition, we and the other parties to
the lease transactions have obtained numerous regulatory approvals related to
the lease transactions. Several types of regulatory developments may adversely
affect us, such as:
- existing regulations may be revised or reinterpreted;
- new laws and regulations may be adopted or become applicable to us or to
the operation of our electricity generating stations;
- the technology and equipment we have selected to comply with current and
future regulatory requirements may not be implemented in a timely fashion
or may not meet these requirements upon implementation;
- we may not be able to comply with current and future laws and
regulations; or
- third parties may initiate proceedings to challenge our compliance with
then-existing regulatory requirements in effect from time to time or to
subject us or the operation of our electricity generating stations to new
or different regulatory requirements.
Delay in obtaining or failure to obtain and maintain in full force and effect
any of these regulatory approvals, or delay or failure to satisfy any applicable
regulatory requirements, could prevent operation of our electricity generating
stations or the sale of their electric energy, installed capacity or ancillary
services, or could result in potential civil or criminal liability or in
additional costs to us. See "REGULATION."
WE WILL HAVE RESPONSIBILITY FOR PRE-EXISTING ENVIRONMENTAL LIABILITIES AND WILL
INCUR EXPENSES AS A RESULT; THESE EXPENSES MAY EXCEED OUR PROJECTIONS
We agreed to assume responsibility for losses resulting from or arising out
of any environmental condition or violation of environmental law relating to our
electricity generating stations while our electricity generating stations were
owned by NYSEG. However, we did not assume responsibility for losses related to
the disposal, storage, transportation, treatment, release or recycling of
hazardous substances and the remediation of these hazardous substances at any
off-site location other than an ash disposal site known as the Lockwood ash
disposal site, for which we assumed responsibility. If we incur costs with
respect to a pre-existing environmental condition, we may not be able to seek
indemnification from NYSEG. Prior to the acquisition of our electricity
generating stations, we performed due diligence but not independent, on-site
testing and we relied on Phase I and Phase II evaluations of our electricity
generating stations by an independent environmental consulting firm commissioned
by NYSEG. Based on this information, we and our environmental consultants, TRC
Environmental Corporation, have concluded that historical on-site releases of
hazardous materials have occurred in some areas and that some environmental
cleanup obligations may exist. TRC has estimated that our liability for the
historic environmental liabilities identified in the Phase I and Phase II
evaluations (excluding possible closure and post-closure costs at the Lockwood
ash disposal sites) will be in
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the range of approximately $4 million to $10 million. This maximum cost estimate
has been included in our financial projections. We also included in our
financial projections approximately $6 million for closure and post-closure
(monitoring and maintenance) expenses for the Lockwood ash disposal site and
approximately $2 million for the share of closure and post-closure expenses that
AEE2, L.L.C., one of our subsidiaries, has agreed to bear in respect of a second
ash disposal site known as the Weber ash disposal site, based solely on amounts
previously budgeted for these activities by NYSEG. As part of its estimate, TRC
reported that approximately 500 to 700 drums of abrasives were disposed in the
early 1970s and covered with ash in an area adjacent to the Lockwood ash
disposal site. TRC projected that the most probable costs to conduct a site
investigation and remove the drums is approximately $520,000. These costs have
been included in our financial projections. In addition, groundwater sampling in
this area and around the Lockwood ash disposal site indicates that some
monitoring wells have parameters which exceed state regulatory limits.
In October 1999, AES Creative Resources, L.P. entered into a consent order
with the New York State Department of Environmental Conservation to resolve
alleged violations of the water quality standards in the groundwater
downgradient of the Weber ash disposal site. The consent order includes a
suspended $5,000 civil penalty and a requirement to submit a work plan to
initiate closure of the landfill by October 8, 2000. The consent order also
calls for a site investigation and there is a possibility that some groundwater
remediation at the site may be required. AEE2, L.L.C. will contribute two-thirds
of the costs to close the landfill, which are anticipated to be approximately $3
million, as well as additional costs for long term groundwater monitoring. While
the actual closure costs may exceed $3 million, we do not expect any added
closure costs to be material. Nevertheless, if a groundwater remediation is
required, these costs have not been budgeted, and AEE2, L.L.C. may be
responsible for a portion of such costs.
These projected environmental costs are merely estimates. We may incur
additional environmental liabilities, and it is possible that the actual costs
could be significantly higher. It is also possible that contamination may be
present that was not found in the reports commissioned by NYSEG. Still other
environmental occurrences or conditions may arise or be discovered in the
future, which could be costly for us to remedy and for which we would be unable
to seek indemnification from NYSEG. See "BUSINESS -- THE ACQUISITION OF OUR
ELECTRICITY GENERATING STATIONS."
On October 14, 1999, we received an information request letter from the New
York Attorney General which seeks detailed operating and maintenance history for
the Goudey and Greenidge Generating Stations. On January 13, 2000, we received a
subpoena from the New York State Department of Environmental Conservation
seeking similar operating and maintenance history for all four of our
electricity generating stations. This information is being sought in connection
with the Attorney General's and the Department of Environmental Conservation's
investigations of several electricity generating stations in New York which are
suspected of undertaking modifications in the past (as far back as 1977) without
undergoing an air permitting review. If the Attorney General or the Department
of Environmental Conservation does file an enforcement action against the
Kintigh, Milliken, Goudey or Greenidge Generating Stations, then penalties may
be imposed and further emission reductions may be necessary at these electricity
generating stations.
We recently received a draft consent order from the New York State
Department of Environmental Conservation that alleges violations of the opacity
emission limitations in the air permits for the Milliken, Goudey, and Greenidge
Generating Stations. The draft consent order would require us to prepare an
opacity compliance plan and would impose penalties for opacity violations
occurring after the date of the acquisition of our electricity generating
stations, May 14, 1999. We expect to enter a final consent order with the
Department of Environmental Conservation early in 2000. AES NY L.L.C. also
recently received notice from NYSEG that NYSEG has received a draft consent
order from the Department of Environmental Conservation seeking penalties
primarily for opacity violations occurring prior to May 14, 1999. In the notice,
NYSEG asserts that it will seek indemnification from AES NY L.L.C. for any
penalties, attorney fees, and related costs that it incurs in connection with
the consent order. We and AES NY L.L.C. have denied liability for the
pre-closing violations and intend to vigorously defend this claim if NYSEG
pursues litigation or arbitration.
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WE WILL BE SUBJECT TO SIGNIFICANT NEW RESTRICTIONS ON EMISSIONS WHICH MAY FORCE
US TO RESTRICT OUR OPERATIONS OR INCUR SIGNIFICANT EXPENSES
Our electricity generating stations will be subject to significant new
restrictions on the emissions of sulfur dioxide which are expected to take
effect in January 2000 and on NO(x) which took effect in May 1999. Even more
stringent NO(x) restrictions are expected to take effect in 2003, although the
ultimate standards and their implications have not been finalized.
A new initiative was recently announced by New York Governor Pataki on
October 14, 1999 which directs the New York State Department of Environmental
Conservation to issue regulations requiring electric generators to reduce SO(2)
emissions by another 50% below federal standards. The Governor's initiative also
seeks to impose stringent NO(x) reduction requirements on a year-round basis,
rather than just during the summertime ozone season for which current NO(x)
reduction requirements apply. The Governor is calling for the new regulations to
be phased in starting on January 1, 2003 with implementation completed by
January 1, 2007.
If our proposed strategies for meeting these restrictions are not
successful, we might be required to reduce the expected levels of operation of
our electricity generating stations or we might incur increased costs. Some of
our proposed strategies for meeting these restrictions are evolving and may
entail installing new emissions control equipment, increasing the efficiency of
existing equipment, trading emissions allowances among the various units
included in our electricity generating stations and purchasing emissions
allowances in the open market. Any strategies adopted are likely to rely on our
continued ability to demonstrate compliance based on averaging the emissions of
several plants or based on the aggregate emissions of all of our electricity
generating stations rather than on a plant-by-plant basis. The New York State
Department of Environmental Conservation has recently approved our use of an
emissions rate averaging strategy to comply with certain NO(x) requirements. If
we purchase SO(2) and/or NO(x) allowances to achieve compliance, we will be
exposed to changes in market prices for these allowances. If any of the final
strategies require the installation of additional emissions control equipment,
the leases for the Kintigh Generating Station and the Milliken Generating
Station and the related agreements and the working capital credit facility with
Credit Suisse First Boston impose restrictions on debt incurrences which may
limit our ability to finance the additional equipment. In addition, both the
Governor's initiative and the Attorney General's and the Department of
Environmental Conservation's investigations discussed above have the potential
of requiring further emissions reductions at our electricity generating stations
beyond the existing SO(2) and NO(x) requirements, which might require us to
install additional emissions control equipment. See "REGULATION -- ENVIRONMENTAL
REGULATORY MATTERS -- AIR EMISSIONS."
THE FINANCIAL PROJECTIONS AND THE UNDERLYING ASSUMPTIONS THAT WE HAVE PRESENTED
TO HELP YOU TO EVALUATE THE MERITS OF AN INVESTMENT IN THE PASS THROUGH TRUST
CERTIFICATES ARE INHERENTLY IMPRECISE AND ACTUAL RESULTS ARE EXPECTED TO DIFFER
The assumptions upon which our financial projections are based are
inherently subject to significant uncertainties and actual results are expected
to differ, perhaps materially, from those projected. We prepared our financial
projections on the basis of assumptions that we, the Independent Market
Consultant and the Independent Engineer believe to be reasonable. We do not
intend to provide holders of pass through trust certificates with any revised or
updated financial projections or analysis of the differences between the
financial projections and actual operating results.
The financial projections are not necessarily indicative of future
performance and we, the Independent Market Consultant, the Independent Engineer
or any other person cannot provide you any assurances that we will attain the
projected results. Therefore, no representation is made or intended, nor should
any be inferred, with respect to the likely existence of any particular future
set of facts or circumstances. If actual results are less favorable than those
shown or if the assumptions used in formulating the base case and the
sensitivity cases included in the financial projections prove to be incorrect,
we may not be able to pay our operating expenses, make rental payments under the
leases, pay the principal amount of and interest on our indebtedness and pay our
obligations under the coal hauling agreement with Somerset Railroad.
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UNDER THE ASSET PURCHASE AGREEMENT WITH NYSEG, WE HAVE ASSUMED LIABILITIES OF
NYSEG THAT COULD RESULT IN UNEXPECTED EXPENSES AND WE HAVE GIVEN UP THE RIGHT TO
MAKE CLAIMS FOR PROBLEMS WE MAY DISCOVER LATER
The asset purchase agreement with NYSEG contains provisions that (a) shift
responsibility for certain actions and occurrences during NYSEG's ownership of
our electricity generating stations to us and (b) give us no recourse against
NYSEG after the date of acquisition of our electricity generating stations for
breaches of many of the representations and warranties of NYSEG. See
"BUSINESS -- THE ACQUISITION OF OUR ELECTRICITY GENERATING STATIONS." Some of
the liabilities that AES NY, L.L.C. agreed to assume under the asset purchase
agreement with NYSEG were assumed by us and some were assumed by AES Creative
Resources, L.P. and other affiliates of AES NY, L.L.C. We expect that none of
the assumed liabilities will have a material adverse effect on the operation of
our electricity generating stations; however, these liabilities may nevertheless
turn out to be material. In addition, NYSEG or another creditor of AES Creative
Resources, L.P. or such other affiliate may challenge this allocation and seek
to assert liabilities against us that were assumed by AES Creative Resources,
L.P. or another affiliate.
WE OR OUR AFFILIATES MAY HAVE TO DEFEND LAWSUITS RELATING TO ASBESTOS EXPOSURE
AT OUR ELECTRICITY GENERATING STATIONS WHILE THEY WERE OWNED BY NYSEG AND
DAMAGES IN THOSE SUITS OR THE COST OF DEFENDING THEM COULD BE MATERIAL
AES Creative Resources, L.P., another subsidiary of The AES Corporation
that we do not control and that does not control us, assumed from NYSEG
responsibility for asbestos-related personal injury lawsuits in which plaintiffs
claim they were exposed to asbestos while employed by independent contractors
providing services at the electricity generating stations acquired from NYSEG.
As of December 1, 1999, 24 of these lawsuits were pending. While we cannot
quantify the potential liability arising from these suits given the early stage
of the proceedings and the large number of named defendants, the plaintiffs have
claimed substantial compensatory and punitive damages. AES NY, L.L.C., the
general partner of our company and of AES Creative Resources, L.P., and AES NY2,
L.L.C., the limited partner of our company and of AES Creative Resources, L.P.,
guaranteed the obligations of AES Creative Resources, L.P. If AES Creative
Resources, L.P., as NYSEG's successor, is held responsible for all or a
substantial part of any judgments granted to the plaintiffs and not covered
under liability insurance, such amounts could be material and could require AES
NY, L.L.C. and AES NY2, L.L.C. to satisfy these judgments as guarantors. If they
were unable to satisfy these judgments, then judgment creditors might seek to
attach the membership interests owned by AES NY, L.L.C. and AES NY2, L.L.C. in
our company, which would be a Lease Event of Default, as defined under the
caption "DESCRIPTION OF THE PASS THROUGH TRUST CERTIFICATES -- THE LEASE, THE
FACILITY SITE LEASES, THE FACILITY SITE SUBLEASES -- LEASE EVENT OF DEFAULT." We
or our affiliates may also become subject to additional suits based on similar
allegations. The costs of defending, settling or paying adverse judgments in
such additional suits could, collectively, have an adverse impact on us even if
these amounts were not individually material. See "BUSINESS -- LEGAL
PROCEEDINGS."
IF WE ENTER BANKRUPTCY PROCEEDINGS, SUFFICIENT FUNDS TO MAKE DISTRIBUTIONS UNDER
THE PASS THROUGH TRUST CERTIFICATES MIGHT NOT BE AVAILABLE
The pass through trust certificates are not our direct obligations. If we
were to become a debtor in a liquidation or reorganization case under the
federal bankruptcy code, we, as debtor, or a bankruptcy trustee appointed for
us, could reject the leases as "executory" contracts. If the leases were
rejected, rental payments under the leases would terminate and leave the special
purpose business trusts without regular rent payments and with a claim for
damages for breach of the leases. In this case, while the special purpose
business trusts could file claims for damages, the amount of any recovery on
those claims and the amount of time that would pass between the commencement of
the bankruptcy case and the receipt of any recovery cannot be determined. If we
were to become a debtor in a bankruptcy case, a violation of the terms of the
lease indentures would occur. See "DESCRIPTION OF THE PASS THROUGH TRUST
CERTIFICATES -- THE SECURED LEASE OBLIGATION NOTES."
Under New York law, it is likely that the leases will be viewed as leases
of real, rather than personal, property. If the leases are rejected, the federal
bankruptcy code limits the claims of lessors under unexpired leases of real
property. If a bankruptcy court concluded that the leases are leases of real
property, damages for
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the rejection of a lease would be limited to the greater of one year's rent
under the lease or 15% of the remaining rent under the lease (not to exceed
three years' rent). These damages would be insufficient to cover debt service on
the secured lease obligation notes and, accordingly, the pass through trust
certificates. However, the leases would not be subject to the foregoing
limitations if a court determined that they constitute "financing leases." This
issue has not been definitively addressed by the courts, and resolution would
depend on a bankruptcy court's analysis of the particular facts and
circumstances associated with the lease transactions. Therefore, we cannot
predict with any degree of certainty as to whether or not a court would conclude
that the leases constitute "financing leases." Rejection of one or more of the
leases by us or a bankruptcy trustee would not deprive the indenture trustee of
its liens on the collateral for the secured lease obligation notes issued by the
special purpose business trusts.
It is also possible that we could, in a bankruptcy proceeding, elect to
cure defaults under the leases and to assume and assign the leases, in which
event the ultimate source of payments under the leases (and thus on the pass
through trust certificates) would be an entity other than us. While this
assignee would have to demonstrate its ability to perform under the assumed
leases, the assignee might not be able to satisfy our obligations under the
leases.
IF WE DEFAULT UNDER THE LEASES, THE VALUE OF THE COLLATERAL FOR THE SECURED
LEASE OBLIGATION NOTES MIGHT NOT BE SUFFICIENT TO PROVIDE FOR ALL SCHEDULED
PAYMENTS UNDER THE PASS THROUGH TRUST CERTIFICATES
The secured lease obligation notes issued by the special purpose business
trusts are secured by an assignment by the special purpose business trusts to
the indenture trustee of the rights and interests of these special purpose
business trusts (other than customary excepted payments and excepted rights
reserved to the applicable special purpose business trusts and the institutional
investors that formed these trusts) in the Kintigh Generating Station and the
Milliken Generating Station and the agreements related to the lease
transactions. If a default occurs with respect to the secured lease obligation
notes, an exercise of remedies, including foreclosure on the related collateral,
might not provide sufficient funds to repay all amounts due on the secured lease
obligation notes and, accordingly, the pass through trust certificates.
In addition, the leases and the other agreements relating to the lease
transactions do not contain cross-collateralization provisions. Accordingly, the
indenture trustee's security interests in the Kintigh Generating Station and the
Milliken Generating Station and the rights and interests in each of these
electricity generating stations are separate and secure separate amounts. The
amounts secured are, in the aggregate, at least equal to the aggregate amounts
due under the secured lease obligation notes. If the indenture trustee exercises
its right to foreclose on and sell the rights and interests in each of these
electricity generating stations, the proceeds from the sale of each of the
Kintigh Generating Station and the Milliken Generating Station and the rights
and interests in each of these electricity generating stations would be
separately applied against the amount secured by that particular generating
station and could not be used to satisfy any deficiency in the proceeds from the
sale of the other electricity generating station and the rights and interests in
that electricity generating station. By operation of law, any excess of sale
proceeds relating to a particular electricity generating station would be
remitted to the special purpose business trusts that owned undivided interests
in the electricity generating station. As a result, the amount of sale proceeds
from the foreclosure of the rights and interests related to a particular
generating station available to the indenture trustee for distribution to the
pass through trusts might not be sufficient to pay all principal, premium if
any, and interest due upon the pass through trust certificates even though
aggregate sale proceeds were sufficient for this purpose.
IF WE DEFAULT UNDER THE LEASES, THE INDENTURE TRUSTEE MAY HAVE DIFFICULTY
CONTINUING THE OPERATION OF OUR ELECTRICITY GENERATING PLANTS, WHICH WILL REDUCE
THEIR COLLATERAL VALUE
If we default under the leases and the indenture trustee exercises its
right to foreclose on the rights and interests in each of these electricity
generating stations as these rights and interests relate to the Kintigh
Generating Station or the Milliken Generating Station, transferring required
government approvals to, or obtaining new approvals by, a purchaser or new
operator of that electricity generating station may require additional
governmental approvals or proceedings, with consequent delays.
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If we default under the leases as they relate to the Kintigh Generating
Station or the Milliken Generating Station and the indenture trustee exercises
its right to foreclose on the rights and interests in each of these electricity
generating stations, the indenture trustee will need to rely on an agreement
made by us to supply essential services in order to operate the electricity
generating station. In a bankruptcy proceeding, our agreement might be regarded
as an executory contract that could be rejected by us, as debtor, or by a
bankruptcy trustee. If that were to occur, the indenture trustee might not be
able to operate the electricity generating station in order to provide revenues
for payments of lease rentals or might incur significant additional costs in
doing so.
WE ARE EFFECTIVELY SUBORDINATED TO CREDITORS OF TWO OF OUR ELECTRICITY
GENERATING STATIONS
Our wholly owned subsidiary, AEE2, L.L.C., owns the Goudey Generating
Station and the Greenidge Generating Station and will distribute to us the
earnings from those electricity generating stations. The claims of creditors of
AEE2, L.L.C. arising from the business conducted at the Goudey Generating
Station and the Greenidge Generating Station would have priority over our
interests, as the sole equity owner of AEE2, L.L.C., in any bankruptcy or
insolvency proceeding involving AEE2, L.L.C. as debtor.
WE ARE CONTROLLED BY THE AES CORPORATION AND THE AES CORPORATION MAY PURSUE ITS
OWN INTERESTS TO THE DETRIMENT OF HOLDERS OF PASS THROUGH TRUST CERTIFICATES
The AES Corporation has the power to control us. In circumstances involving
a conflict of interest between The AES Corporation, as the sole indirect equity
owner, on the one hand, and the holders of the pass through trust certificates,
effectively as our creditors on the other, The AES Corporation might exercise
its power to control us in a manner that would benefit The AES Corporation to
the detriment of the holders of the pass through trust certificates. See
"RELATIONSHIPS WITH AFFILIATES AND RELATED TRANSACTIONS."
THE AES CORPORATION IS NOT OBLIGATED TO PROVIDE FURTHER FUNDING TO US IF WE ARE
UNABLE TO PAY OUR OBLIGATIONS
We are an indirect, wholly owned subsidiary of The AES Corporation. Since
our formation, The AES Corporation has provided all of our equity funding for
our business and operations. Our only other sources of funding will be our
internally generated cash flow from our electricity generating stations and
amounts available under the working capital credit facility with Credit Suisse
First Boston. In the event of a shortfall between the amount of our commitments
and the foregoing sources of funds, The AES Corporation is not obligated to
provide, and may decide not to provide, any loans or equity contributions to
make up this shortfall. See "DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL RESOURCES."
WE EXPECT THAT TWO SENIOR MEMBERS OF OUR MANAGEMENT TEAM WILL DEVOTE A PORTION
OF THEIR TIME TO OTHER PROJECTS FOR THE AES CORPORATION
We expect that John Ruggirello, our Assistant General Manager, will devote
approximately 10% of his time to the affairs of our company and that Dan
Rothaupt, our General Manager, will devote approximately 50% of his time to the
affairs of our company. See "MANAGEMENT -- DUAL STATUS OF TWO MEMBERS OF
MANAGEMENT." The remaining portions of their working time will be devoted to
other projects for The AES Corporation, including other electricity generating
stations in and around the New York power pool. In the future we may compete
with these projects. See "-- IN THE FUTURE WE MIGHT COMPETE WITH OTHER
ELECTRICITY GENERATING STATIONS OWNED BY THE AES CORPORATION," and
"RELATIONSHIPS WITH AFFILIATES AND RELATED TRANSACTIONS."
IN THE FUTURE WE MIGHT COMPETE WITH OTHER ELECTRICITY GENERATING STATIONS OWNED
BY THE AES CORPORATION
The existing plants in and around the New York power pool of The AES
Corporation, like AES Thames in Uncasville, Connecticut, and AES Beaver Valley
in Monaco, Pennsylvania, do not currently compete with our electricity
generating stations because their entire outputs are committed for sale under
existing power purchase agreements. Upon expiration or early termination of
these contracts, the operations of these other electricity generating stations
may compete with our electricity generating stations. In addition, The AES
Corporation may undertake future projects that could ultimately compete with our
electricity generating stations in the New York power pool.
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A LIQUID AND DEEP PUBLIC MARKET FOR THE PASS THROUGH TRUST CERTIFICATES MAY
NEVER DEVELOP AND IT MAY BE DIFFICULT TO SELL THE PASS THROUGH TRUST
CERTIFICATES AT FAVORABLE PRICES
Following completion of the exchange offer, the pass through trust
certificates will be freely tradable by most holders. See "THIS EXCHANGE
OFFER -- RESALES OF THE NEW PASS THROUGH TRUST CERTIFICATES." We do not intend
to apply for listing of the pass through trust certificates on any securities
exchange or on the Nasdaq National Market. Any market that may develop for the
pass through trust certificates may not be liquid or deep and you may not be
able to sell your pass through trust certificates or sell them at prices which
you consider favorable. Future trading prices of the pass through trust
certificates will depend on many factors including, among other things,
prevailing interest rates, our operating results and the market for similar
securities.
Morgan Stanley & Co. Incorporated, Credit Suisse First Boston Corporation
and CIBC World Markets Corp., the initial purchasers in the offering of the
existing pass through trust certificates, have informed us that they intend to
make a market in the pass through trust certificates. However, they are not
obligated to do so and they may terminate any market-making activity at any time
without notice to holders of pass through trust certificates. In addition, this
market-making activity will be subject to the limits imposed by federal
securities law. If a market for the pass through trust certificates does not
develop, holders may be unable to resell the pass through trust certificates for
an extended period of time, if at all. Consequently, a holder of a pass through
trust certificate may not be able to liquidate its investment readily, and the
pass through trust certificates may not be readily accepted as collateral for
loans.
WE INTEND TO SUSPEND REPORTING UNDER THE EXCHANGE ACT AS SOON AS WE ARE ABLE TO
DO SO
Upon completion of the exchange offer, we will be subject to the reporting
requirements of the Exchange Act. However, we currently contemplate suspending
our Exchange Act reporting obligations at the beginning of the calendar year
following the year in which the registration statement of which this prospectus
is a part becomes effective, if there are fewer than 300 holders of record of
the pass through trust certificates at the beginning of that calendar year. If
that condition is not met at the beginning of the calendar year following the
year in which the registration statement becomes effective, we would suspend our
reporting obligations at the beginning of the first year in which that condition
is met. If we suspend our reporting obligations, the pass through certificates
will continue to be freely transferable by holders who are not affiliates of
ours, but we will no longer prepare and file the reports and other information
required by the Exchange Act. Investors might not view this suspension favorably
and it might become more difficult to sell the pass through trust certificates
or to sell them at prices which you consider favorable. The pass through trust
agreements provide that if we are not subject to Exchange Act reporting
requirements we will provide the pass through trustee and the holders of the
pass through trust certificates reports containing financial statements and a
discussion and analysis thereof substantially conforming to the requirements of
Form 10-K promulgated under the Exchange Act on an annual basis and the
requirements of Form 10-Q promulgated under the Exchange Act on a quarterly
basis.
RATINGS ASSIGNED TO THE PASS THROUGH TRUST CERTIFICATES ARE NOT INVESTMENT
RECOMMENDATIONS AND DO NOT ASSURE MARKET VALUE
S&P, Moody's and Fitch have assigned ratings to the pass through trust
certificates of BBB-, Ba1 and BBB-, respectively. A rating is not a
recommendation to purchase, hold or sell pass through trust certificates,
inasmuch as this rating does not address market price or suitability for a
particular investor. At any time, a rating may be lowered or withdrawn entirely
by a rating agency if, in its judgment, circumstances in the future so warrant,
including the downgrading of its assessment of our credit. The rating of the
pass through trust certificates is based primarily on the risk that we will
default under the leases.
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THIS EXCHANGE OFFER
PURPOSE AND TERMS OF THIS EXCHANGE OFFER
The existing pass through trust certificates were originally sold on May
14, 1999 in an offering that was exempt from the registration requirements of
the Securities Act. As of the date of this prospectus, $282 million aggregate
principal amount of existing pass through trust certificates Series 1999-A and
$268 million aggregate principal amount of existing pass through trust
certificates Series 1999-B are outstanding. In connection with the sale of the
existing pass through trust certificates, we entered into a registration rights
agreement in which we agreed to file with the SEC a registration statement with
respect to the exchange of existing pass through trust certificates for new pass
through trust certificates and to use our best efforts to cause the registration
statement to become effective by October 11, 1999. Under the registration rights
agreement, we also agreed to pay additional interest at a rate of 0.50% per
annum on the existing pass through trust certificates if we failed to complete
the exchange offer on or prior to November 10, 1999. As a result of our failure
to complete the exchange offer as agreed, we are obligated to pay additional
interest accruing from November 10, 1999 until the exchange offer is completed.
The additional interest is payable on the existing pass through trust
certificates on the regular interest payment dates. We filed a copy of the
registration rights agreement as an exhibit to the registration statement of
which this prospectus is a part. This exchange offer satisfies our contractual
obligations under the registration rights agreement.
We are offering, upon the terms and subject to the conditions set forth in
this prospectus and in the accompanying letter of transmittal, to exchange up to
$282 million aggregate principal amount of existing pass through trust
certificates Series 1999-A for $282 million aggregate principal amount of pass
through trust certificates Series 1999-A which have been registered under the
Securities Act and up to $268 million aggregate principal amount of existing
pass through trust certificates Series 1999-B for $268 million aggregate
principal amount of pass through trust certificates Series 1999-B which have
been registered under the Securities Act. We will accept for exchange existing
pass through trust certificates that you properly tender prior to the expiration
date and do not withdraw in accordance with the procedures described below. You
may tender your existing pass through trust certificates in whole or in part in
integral multiples of $1,000 principal amount.
This exchange offer is not conditioned upon the tender for exchange of any
minimum aggregate principal amount of existing pass through trust certificates.
We reserve the right in our sole discretion to purchase or make offers for any
existing pass through trust certificates that remain outstanding after the
expiration date or, as detailed under the caption "-- CONDITIONS TO THIS
EXCHANGE OFFER," to terminate this exchange offer and, to the extent permitted
by applicable law, purchase existing pass through trust certificates in the open
market, in privately negotiated transactions or otherwise. The terms of any of
these purchases or offers could differ from the terms of this exchange offer.
There will be no fixed record date for determining the registered holders of the
existing pass through trust certificates entitled to participate in the exchange
offer.
Only a registered holder of the existing pass through trust certificates
(or the holder's legal representative or attorney-in-fact) may participate in
the exchange offer. Holders of existing pass through trust certificates do not
have any appraisal or dissenters' rights in connection with this exchange offer.
Existing pass through trust certificates which are not tendered in, or are
tendered but not accepted in connection with, this exchange offer will remain
outstanding. We intend to conduct this exchange offer in accordance with the
provisions of the registration rights agreement and the applicable requirements
of the Securities Act and SEC rules and regulations.
If we do not accept any existing pass through trust certificates that you
tender for exchange because of an invalid tender, the occurrence of other events
set forth in this prospectus or otherwise, we will return the certificates for
any unaccepted existing pass through trust certificates to you, without expense,
after the expiration date.
If you tender existing pass through trust certificates in connection with
this exchange offer, you will not be required to pay brokerage commissions or
fees or, subject to the instructions in the letter of transmittal, transfer
taxes with respect to the exchange of existing pass through trust certificates
in connection with this
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exchange offer. We will pay all charges and expenses, other than certain
applicable taxes described below, in connection with this exchange offer. See
"-- FEES AND EXPENSES."
Unless the context requires otherwise, the term "holder" with respect to
this exchange offer means any person in whose name the existing pass through
trust certificates are registered on the pass through trustee's books or any
other person who has obtained a properly completed bond power from the
registered holder, or any participant in The Depository Trust Company whose name
appears on a security position listing as a holder of existing pass through
trust certificates. For purposes of this exchange offer, a participant includes
beneficial interests in the existing pass through trust certificates held by
direct or indirect participants and existing pass through trust certificates
held in definitive form.
WE MAKE NO RECOMMENDATION TO YOU AS TO WHETHER YOU SHOULD TENDER OR REFRAIN
FROM TENDERING ALL OR ANY PORTION OF YOUR EXISTING PASS THROUGH TRUST
CERTIFICATES INTO THIS EXCHANGE OFFER. IN ADDITION, NO ONE HAS BEEN AUTHORIZED
TO MAKE THIS RECOMMENDATION. YOU MUST MAKE YOUR OWN DECISION WHETHER TO TENDER
INTO THIS EXCHANGE OFFER AND, IF SO, THE AGGREGATE AMOUNT OF EXISTING PASS
THROUGH TRUST CERTIFICATES TO TENDER AFTER READING THIS PROSPECTUS AND THE
LETTER OF TRANSMITTAL AND CONSULTING WITH YOUR ADVISORS, IF ANY, BASED ON YOUR
FINANCIAL POSITION AND REQUIREMENTS.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
The term "expiration date" means 5:00 p.m., New York City time, on March
20, 2000 unless we extend this exchange offer, in which case the term
"expiration date" shall mean the latest date and time to which we extend this
exchange offer and the consent solicitation.
We expressly reserve the right, at any time or from time to time, so long
as applicable law allows,
(1) to delay our acceptance of existing pass through trust certificates for
exchange;
(2) to terminate or amend this exchange offer if, in the opinion of our
counsel, completing the exchange offer would violate any applicable
law, rule or regulation or any SEC staff interpretation; and
(3) to extend the expiration date and retain all existing pass through
trust certificates tendered into this exchange offer, subject, however,
to your right to withdraw your tendered existing pass through trust
certificates as described under "-- WITHDRAWAL RIGHTS."
If this exchange offer is amended in a manner that we think constitutes a
material change, or if we waive a material condition of this exchange offer, we
will promptly disclose the amendment by means of a prospectus supplement that
will be distributed to the registered holders of the existing pass through trust
certificates, and we will extend this exchange offer to the extent required by
Rule 14e-1 under the Exchange Act.
We will promptly follow any delay in acceptance, termination, extension or
amendment by oral or written notice of the event to the exchange agent followed
promptly by oral or written notice to the registered holders. Should we choose
to delay, extend, amend or terminate the exchange offer, we will have no
obligation to publish, advertise or otherwise communicate this announcement,
other than by making a timely release to an appropriate news agency.
CONSENT SOLICITATION
As part of this exchange offer, we are soliciting consents from the holders
of the existing pass through trust certificates to a waiver of our obligation
under the registration rights agreement to file a shelf registration statement
as a result of our failure to consummate the exchange offer on or prior to
November 10, 1999. We are seeking these consents because the holders of existing
pass through trust certificates who would benefit from this shelf registration
statement will not need it to resell the new pass through trust certificates
they will receive if they participate in this exchange offer. See "-- RESALES OF
THE NEW PASS THROUGH TRUST CERTIFICATES." If we obtain the consent of the
holders of a majority of the aggregate principal amount of the existing pass
through trust certificates, we will not file a shelf registration statement
unless otherwise required by the registration rights agreement. If we obtain the
necessary consents, each holder of existing pass through trust certificates that
does not exchange its existing pass through trust certificates will be bound by
the proposed waiver even though this holder did not consent to it.
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PROCEDURES FOR TENDERING THE EXISTING PASS THROUGH TRUST CERTIFICATES
Upon the terms and the conditions of this exchange offer, we will exchange,
and we will arrange for the pass through trusts to issue to the exchange agent,
new pass through trust certificates for existing pass through trust certificates
that have been validly tendered and not validly withdrawn promptly after the
expiration date. The tender by a holder of any existing pass through trust
certificates and our acceptance of that holder's pass through trust certificates
will constitute a binding agreement between us and that holder subject to the
terms and conditions set forth in this prospectus and the accompanying letter of
transmittal. By signing or agreeing to be bound by the letter of transmittal,
you will be consenting to the proposed waiver of our obligation under the
registration rights agreement to file a shelf registration statement as a result
of our failure to complete the exchange offer on or prior to November 10, 1999.
Valid Tender
We will deliver new pass through trust certificates in exchange for
existing pass through trust certificates that have been validly tendered and
accepted for exchange pursuant to this exchange offer. Except as set forth
below, you will have validly tendered your existing pass through trust
certificates pursuant to this exchange offer if the exchange agent receives
prior to the expiration date at the address listed under the caption
"-- EXCHANGE AGENT":
(1) a properly completed and duly executed letter of transmittal, with any
required signature guarantees, including all documents required by the
letter of transmittal; or
(2) if the pass through trust certificates are tendered in accordance with
the book-entry procedures set forth below, the tendering pass through
trust certificate holder may transmit an agent's message (described
below) instead of a letter of transmittal.
In addition, on or prior to the expiration date:
(1) the exchange agent must receive the certificates for the pass through
trust certificates along with the letter of transmittal; or
(2) the exchange agent must receive a timely book-entry confirmation of a
book-entry transfer of the tendered pass through trust certificates
into the exchange agent's account at The Depository Trust Company
according to the procedure for book-entry transfer described below,
along with a letter of transmittal or an agent's message in lieu of the
letter of transmittal; or
(3) the holder must comply with the guaranteed delivery procedures
described below.
Accordingly, we may not make delivery of new pass through trust
certificates to all tendering holders at the same time since the time of
delivery will depend upon when the exchange agent receives the existing pass
through trust certificates, book-entry confirmations with respect to existing
pass through trust certificates and the other required documents.
The term "book-entry confirmation" means a timely confirmation of a
book-entry transfer of existing pass through trust certificates into the
exchange agent's account at The Depository Trust Company. The term "agent's
message" means a message, transmitted by The Depository Trust Company to and
received by the exchange agent and forming a part of a book-entry confirmation,
which states that The Depository Trust Company has received an express
acknowledgment from the tendering participant stating that the participant has
received and agrees to be bound by the letter of transmittal and that we may
enforce the letter of transmittal against the participant.
If you tender less than all of your existing pass through trust
certificates, you should fill in the amount of existing pass through trust
certificates you are tendering in the appropriate box on the letter of
transmittal or, in the case of a book-entry transfer, so indicate in an agent's
message if you have not delivered a letter of transmittal. The entire amount of
existing pass through trust certificates delivered to the exchange agent will be
deemed to have been tendered unless otherwise indicated.
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If any letter of transmittal, endorsement, bond power, power of attorney,
or any other document required by the letter of transmittal is signed by a
trustee, executor, administrator, guardian, attorney-in-fact, officer of a
corporation or other person acting in a fiduciary or representative capacity,
that person should so indicate when signing, and, unless waived by us, you must
submit evidence satisfactory to us, in our sole discretion, of that person's
authority to so act.
If you are a beneficial owner of existing pass through trust certificates
that are held by or registered in the name of a broker, dealer, commercial bank,
trust company or other nominee or custodian, we urge you to contact this entity
promptly if you wish to participate in this exchange offer.
THE METHOD OF DELIVERY OF EXISTING PASS THROUGH TRUST CERTIFICATES, THE
LETTER OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS IS AT YOUR OPTION AND AT
YOUR SOLE RISK, AND DELIVERY WILL BE DEEMED MADE ONLY WHEN ACTUALLY RECEIVED BY
THE EXCHANGE AGENT. INSTEAD OF DELIVERY BY MAIL, WE RECOMMEND THAT YOU USE AN
OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT
TIME TO ASSURE TIMELY DELIVERY AND YOU SHOULD OBTAIN PROPER INSURANCE. DO NOT
SEND ANY LETTER OF TRANSMITTAL OR EXISTING PASS THROUGH TRUST CERTIFICATES TO
AES EASTERN ENERGY. YOU MAY REQUEST YOUR BROKER, DEALER, COMMERCIAL BANK, TRUST
COMPANY OR NOMINEE TO EFFECT THESE TRANSACTIONS FOR YOU.
Book-Entry Transfer
Holders who are participants in The Depository Trust Company tendering by
book-entry transfer must execute the exchange through the Automated Tender Offer
Program of The Depository Trust Company on or prior to the expiration date. The
Depository Trust Company will verify this acceptance and execute a book-entry
transfer of the tendered Certificates into the exchange agent's account at The
Depository Trust Company. The Depository Trust Company will then send to the
exchange agent a book-entry confirmation including an agent's message confirming
that The Depository Trust Company has received an express acknowledgment from
the holder that the holder has received and agrees to be bound by the letter of
transmittal and that the exchange agent and we may enforce the letter of
transmittal against such holder. The book-entry confirmation must be received by
the exchange agent in order for the exchange to be effective.
The exchange agent will make a request to establish an account with respect
to the existing pass through trust certificates at The Depository Trust Company
for purposes of this exchange offer within two business days after the date of
this prospectus unless the exchange agent already has established an account
with The Depository Trust Company suitable for this exchange offer.
Any financial institution that is a participant in The Depository Trust
Company's book-entry transfer facility system may make a book-entry delivery of
the existing pass through trust certificates by causing The Depository Trust
Company to transfer these existing pass through trust certificates into the
exchange agent's account at The Depository Trust Company in accordance with The
Depository Trust Company's procedures for transfers.
If the tender is not made through the Automated Tender Offer Program, you
must deliver the existing pass through trust certificates and the applicable
letter of transmittal, or a facsimile of the letter of transmittal, properly
completed and duly executed, with any required signature guarantees, or an
agent's message in lieu of a letter of transmittal, and any other required
documents to the exchange agent at its address listed under the caption
"-- EXCHANGE AGENT" prior to the expiration date, or you must comply with the
guaranteed delivery procedures set forth below in order for the tender to be
effective.
Delivery of documents to The Depository Trust Company does not constitute
delivery to the exchange agent and book-entry transfer to The Depository Trust
Company in accordance with its procedures does not constitute delivery of the
book-entry confirmation to the exchange agent.
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Signature Guarantees
Signature guarantees on a letter of transmittal or a notice of withdrawal,
as the case may be, are only required if:
(1) a certificate for existing pass through trust certificates is
registered in a name other than that of the person surrendering the
certificate; or
(2) a registered holder completes the box entitled "Special Issuance
Instructions" or "Special Delivery Instructions" in the letter of
transmittal. See "Instructions" in the letter of transmittal.
In the case of (1) or (2) above, you must duly endorse these certificates for
existing pass through trust certificates or they must be accompanied by a
properly executed bond power, with the endorsement or signature on the bond
power and on the letter of transmittal or the notice of withdrawal, as the case
may be, guaranteed by a firm or other entity identified in Rule 17Ad-15 under
the Exchange Act as an "eligible guarantor institution" that is a member of a
medallion guarantee program, unless these pass through trust certificates are
surrendered on behalf of that eligible guarantor institution. An "eligible
guarantor institution" includes the following:
- a bank;
- a broker, dealer, municipal securities broker or dealer or government
securities broker or dealer;
- a credit union;
- a national securities exchange, registered securities association or
clearing agency; or
- a savings association.
Guaranteed Delivery
If you desire to tender existing pass through trust certificates into this
exchange offer and:
(1) the certificates for the existing pass through trust certificates are
not immediately available;
(2) time will not permit delivery of the existing pass through trust
certificates and all required documents to the exchange agent on or
prior to the expiration date; or
(3) the procedures for book-entry transfer cannot be completed on a timely
basis;
you may nevertheless tender the existing pass through trust certificates,
provided that you comply with all of the following guaranteed delivery
procedures:
(1) tender is made by or through an eligible guarantor institution;
(2) prior to the expiration date, the exchange agent receives from the
eligible guarantor institution a properly completed and duly executed
Notice of Guaranteed Delivery, substantially in the form accompanying
the letter of transmittal. This eligible guarantor institution may
deliver the Notice of Guaranteed Delivery by hand or by facsimile or
deliver it by mail to the exchange agent and must include a guarantee
by this eligible guarantor institution in the form in the Notice of
Guaranteed Delivery; and
(3) within three New York Stock Exchange trading days after the date of
execution of the Notice of Guaranteed Delivery, the exchange agent must
receive:
(a) the certificates, or book-entry confirmation, representing all
tendered existing pass through trust certificates, in proper form
for transfer;
(b) a properly completed and duly executed letter of transmittal or
facsimile of the letter of transmittal or, in the case of a
book-entry transfer, an agent's message in lieu of the letter of
transmittal, with any required signature guarantees; and
(c) any other documents required by the letter of transmittal.
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Determination of Validity
- We have the right, in our sole discretion, to determine all questions as
to the form of documents, validity, eligibility, including time of
receipt, and acceptance for exchange of any tendered existing pass
through trust certificates. Our determination will be final and binding
on all parties.
- We reserve the absolute right, in our sole and absolute discretion, to
reject any and all tenders of existing pass through trust certificates
that we determine are not in proper form.
- We reserve the absolute right, in our sole and absolute discretion, to
refuse to accept for exchange a tender of existing pass through trust
certificates if our counsel advises us that the tender is unlawful.
- We also reserve the absolute right, so long as applicable law allows, to
waive any of the conditions of this exchange offer or any defect or
irregularity in any tender of existing pass through trust certificates of
any particular holder whether or not similar defects or irregularities
are waived in the case of other holders.
- Our interpretation of the terms and conditions of this exchange offer,
including the letter of transmittal and the instructions relating to it,
will be final and binding on all parties.
- We will not consider the tender of existing pass through trust
certificates to have been validly made until all defects or
irregularities with respect to the tender have been cured or waived.
- We, our affiliates, the exchange agent, and any other person will not be
under any duty to give any notification of any defects or irregularities
in tenders and will not incur any liability for failure to give this
notification.
ACCEPTANCE FOR EXCHANGE FOR THE NEW PASS THROUGH TRUST CERTIFICATES
Upon satisfaction or waiver of all of the conditions of this exchange
offer, we will accept, promptly after the expiration date, all existing pass
through trust certificates properly tendered and will arrange for the pass
through trusts to issue the new pass through trust certificates promptly after
acceptance of the existing pass through trust certificates. See "-- CONDITIONS
TO THIS EXCHANGE OFFER." Subject to the terms and conditions of this exchange
offer, we will be deemed to have accepted for exchange, and exchanged, existing
pass through trust certificates validly tendered and not withdrawn as, if and
when we give oral or written notice to the exchange agent, with any oral notice
promptly confirmed in writing by us, of our acceptance of these existing pass
through trust certificates for exchange in this exchange offer. The exchange
agent will act as our agent for the purpose of receiving tenders of existing
pass through trust certificates, letters of transmittal and related documents,
and as agent for tendering holders for the purpose of receiving existing pass
through trust certificates, letters of transmittal and related documents and
transmitting new pass through trust certificates to holders who validly tendered
existing pass through trust certificates. The exchange agent will make the
exchange promptly after the expiration date. If for any reason whatsoever:
- the acceptance for exchange or the exchange of any existing pass through
trust certificates tendered in this exchange offer is delayed, whether
before or after our acceptance for exchange of existing pass through
trust certificates;
- we extend this exchange offer; or
- we are unable to accept for exchange or exchange existing pass through
trust certificates tendered in this exchange offer;
then, without prejudice to our rights set forth in this prospectus, the exchange
agent may, nevertheless, on our behalf and subject to Rule 14e-1(c) under the
Exchange Act, retain tendered existing pass through trust certificates and these
existing pass through trust certificates may not be withdrawn unless tendering
holders are entitled to withdrawal rights as described under "-- WITHDRAWAL
RIGHTS."
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INTEREST
For each existing pass through trust certificate that we accept for
exchange, the existing pass through trust certificate holder will receive a new
pass through trust certificate having a principal amount and final distribution
date equal to that of the surrendered existing pass through trust certificate.
Interest on the new pass through trust certificates will accrue from May 14,
1999, the original issue date of the existing pass through trust certificates or
from any later interest distribution date preceding completion of this exchange
offer on which all scheduled interest was distributed in respect of the existing
pass through trust certificates tendered for exchange. January 2, 2000 is the
first scheduled interest distribution date.
RESALES OF THE NEW PASS THROUGH TRUST CERTIFICATES
Based on interpretations by the staff of the SEC set forth in no-action
letters issued to third parties, we believe that the new pass through trust
certificates may be offered for resale, resold and otherwise transferred by you
without compliance with the registration and prospectus delivery requirements of
the Securities Act provided that:
- you acquire any new pass through trust certificate in the ordinary course
of your business;
- you are not participating, do not intend to participate, and have no
arrangement or understanding with any person to participate, in the
distribution of the new pass through trust certificates;
- you are not a broker-dealer who purchased outstanding pass through trust
certificates directly from us for resale pursuant to Rule 144A or any
other available exemption under the Securities Act; and
- you are not an "affiliate" (as defined in Rule 405 under the Securities
Act) of our company.
If our belief is inaccurate and you transfer any new pass through trust
certificate without delivering a prospectus meeting the requirements of the
Securities Act or without an exemption from registration of your pass through
trust certificates from these requirements, you may incur liability under the
Securities Act. We do not assume any liability or indemnify you against any
liability under the Securities Act.
Each broker-dealer that is issued new pass through trust certificates for
its own account in exchange for pass through trust certificates must acknowledge
that it will deliver a prospectus meeting the requirements of the Securities Act
in connection with any resale of the new pass through trust certificates. A
broker-dealer that acquired existing pass through trust certificates for its own
account as a result of market-making or other trading activities may use this
prospectus for an offer to resell, resale or other retransfer of the new pass
through trust certificates.
WITHDRAWAL RIGHTS
Except as otherwise provided in this prospectus, you may withdraw your
tender of existing pass through trust certificates at any time prior to the
expiration date. If you withdraw your tender of existing pass through trust
certificates, your consent to the proposed waiver will also be deemed withdrawn.
You may not withdraw your consent without withdrawing your tender of existing
pass through trust certificates.
- In order for a withdrawal to be effective, you must deliver a written,
telegraphic or facsimile transmission of a notice of withdrawal to the
exchange agent at any of its addresses listed under the caption
"-- EXCHANGE AGENT" prior to the expiration date.
- Each notice of withdrawal must specify:
(1) the name of the person who tendered the existing pass through trust
certificates to be withdrawn;
(2) the aggregate principal amount of existing pass through trust
certificates to be withdrawn; and
(3) if certificates for these existing pass through trust certificates
have been tendered, the name of the registered holder of the
existing pass through trust certificates as set forth on the
existing
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pass through trust certificates, if different from that of the person who
tendered these existing pass through trust certificates.
- If you have delivered or otherwise identified to the exchange agent
certificates for existing pass through trust certificates, the notice of
withdrawal must specify the serial numbers on the particular certificates
for the existing pass through trust certificates to be withdrawn and the
signature on the notice of withdrawal must be guaranteed by an eligible
guarantor institution, except in the case of existing pass through trust
certificates tendered for the account of an eligible guarantor
institution.
- If you have tendered existing pass through trust certificates in
accordance with the procedures for book-entry transfer listed in
"-- PROCEDURES FOR TENDERING THE EXISTING PASS THROUGH TRUST
CERTIFICATES -- BOOK-ENTRY TRANSFER," the notice of withdrawal must
specify the name and number of the account at The Depository Trust
Company to be credited with the withdrawal of existing pass through trust
certificates and must otherwise comply with the procedures of The
Depository Trust Company.
- You may not rescind a withdrawal of your tender of existing pass through
trust certificates.
- We will not consider existing pass through trust certificates properly
withdrawn to be validly tendered for purposes of this exchange offer.
However, you may retender existing pass through trust certificates at any
subsequent time prior to the expiration date by following any of the
procedures described above in "-- PROCEDURES FOR TENDERING THE EXISTING
PASS THROUGH TRUST CERTIFICATES."
- We, in our sole discretion, will determine all questions as to the
validity, form and eligibility, including time of receipt, of any
withdrawal notices. Our determination will be final and binding on all
parties. We, our affiliates, the exchange agent and any other person have
no duty to give any notification of any defects or irregularities in any
notice of withdrawal and will not incur any liability for failure to give
any such notification.
- We will return to the holder any existing pass through trust certificates
which have been tendered but which are withdrawn promptly after the
withdrawal.
CONDITIONS TO THIS EXCHANGE OFFER
Notwithstanding any other provisions of this exchange offer or any
extension of this exchange offer, we will not be required to accept for
exchange, or to exchange, any existing pass through trust certificates. We may
terminate this exchange offer, whether or not we have previously accepted any
existing pass through trust certificates for exchange, or we may waive any
conditions to or amend this exchange offer, if we determine in our sole and
absolute discretion that the exchange offer would violate applicable law or any
applicable interpretation of the staff of the SEC.
EXCHANGE AGENT
We have appointed Bankers Trust Company of New York as exchange agent for
this exchange offer. You should direct all deliveries of the letters of
transmittal and any other required documents, questions, requests
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for assistance and requests for additional copies of this prospectus or of the
letters of transmittal to the exchange agent as follows:
By Mail: By Overnight Mail or Courier: By Hand:
BT Services Tennessee, Inc. BT Services Tennessee, Inc. Bankers Trust Company
Reorganization Unit Corporate Trust & Agency Services Corporate Trust & Agency Services
P.O. Box 292737 Reorganization Unit Attn: Reorganization Department
Nashville, TN 37229-2737 648 Grassmere Park Road Receipt & Delivery Window
By Facsimile: Nashville, TN 37211 123 Washington Street, 1st Floor
(615) 835-3701 New York, NY 10006
Confirm by telephone:
(615) 835-3572
Information: (800) 735-7777
DELIVERY TO OTHER THAN THE ABOVE ADDRESS OR FACSIMILE NUMBER WILL NOT
CONSTITUTE A VALID DELIVERY.
FEES AND EXPENSES
We will bear the expenses of soliciting tenders of the existing pass
through trust certificates. We will make the initial solicitation by mail;
however, we may decide to make additional solicitations personally or by
telephone or other means through our officers, agents, directors or employees.
We have not retained any dealer-manager or similar agent in connection with
this exchange offer and we will not make any payments to brokers, dealers or
others soliciting acceptances of this exchange offer. We have agreed to pay the
exchange agent and pass through trustee reasonable and customary fees for its
services and will reimburse it for its reasonable out-of-pocket expenses in
connection with this exchange offer. We will also pay brokerage houses and other
custodians, nominees and fiduciaries the reasonable out-of-pocket expenses they
incur in forwarding copies of this prospectus and related documents to the
beneficial owners of existing pass through trust certificates, and in handling
or tendering for their customers.
TRANSFER TAXES
Holders who tender their existing pass through trust certificates will not
be obligated to pay any transfer taxes in connection with the exchange, except
that if:
(1) you want us to deliver new pass through trust certificates to any
person other than the registered holder of the existing pass through
trust certificates tendered;
(2) you want the pass through trusts to issue the new pass through trust
certificates in the name of any person other than the registered holder
of the existing pass through trust certificates tendered; or
(3) a transfer tax is imposed for any reason other than the exchange of
existing pass through trust certificates in connection with this
exchange offer;
then you will be liable for the amount of any transfer tax, whether imposed on
the registered holder or any other person. If you do not submit satisfactory
evidence of payment of such transfer tax or exemption from such transfer tax
with the letter of transmittal, the amount of this transfer tax will be billed
directly to the tendering holder.
CONSEQUENCES OF EXCHANGING OR FAILING TO EXCHANGE EXISTING PASS THROUGH TRUST
CERTIFICATES
Holders of existing pass through trust certificates who do not exchange
their existing pass through trust certificates for new pass through trust
certificates in this exchange offer will continue to be subject to the
provisions of the pass through trust agreements regarding transfer and exchange
of the existing pass through trust certificates and the restrictions on transfer
of the existing pass through trust certificates set forth on the legend on the
existing pass through trust certificates. In general, the existing pass through
trust certificates may not be offered or sold, unless registered under the
Securities Act, except under an exemption from, or in a
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transaction not subject to, the registration requirements of the Securities Act
and applicable state securities laws. If we obtain the necessary consents to the
proposed waiver of our obligation under the registration rights agreement to
file a shelf registration statement as a result of our failure to complete the
exchange offer on or prior to November 10, 1999, we will not file a shelf
registration statement unless otherwise required by the registration rights
agreement. In that case, each non-exchanging holder of existing pass through
trust certificates will be bound by the proposed waiver even though that holder
did not consent to the proposed waiver.
Based on interpretations by the staff of the SEC, as detailed in no-action
letters issued to third parties, we believe that new pass through trust
certificates issued in this exchange offer in exchange for existing pass through
trust certificates may be offered for resale, resold or otherwise transferred by
the holders (other than any holder that is an "affiliate" of our company within
the meaning of Rule 405 under the Securities Act) without compliance with the
registration and prospectus delivery provisions of the Securities Act, provided
that the new pass through trust certificates are acquired in the ordinary course
of the holders' business and the holders have no arrangement or understanding
with any person to participate in the distribution of these new pass through
trust certificates. However, we do not intend to request the SEC to consider,
and the SEC has not considered, the exchange offer in the context of a no-action
letter and we cannot guarantee that the staff of the SEC would make a similar
determination with respect to the exchange offer.
Each holder must acknowledge that it is not engaged in, and does not intend
to engage in, a distribution of new pass through trust certificates and has no
arrangement or understanding to participate in a distribution of new pass
through trust certificates. If any holder is an affiliate of our company, is
engaged in or intends to engage in or has any arrangement or understanding with
respect to the distribution of the new pass through trust certificates to be
acquired pursuant to the exchange offer, the holder:
- could not rely on the applicable interpretations of the staff of the SEC,
and
- must comply with the registration and prospectus delivery requirements of
the Securities Act.
Each broker-dealer that receives new pass through trust certificates for
its own account in exchange for outstanding pass through trust certificates must
acknowledge that it will deliver a prospectus in connection with any resale of
the new pass through trust certificates. See "PLAN OF DISTRIBUTION."
In addition, to comply with state securities laws, the new pass through
trust certificates may not be offered or sold in any state unless they have been
registered or qualified for sale in the state or an exemption from registration
or qualification is available and is complied with. The offer and sale of the
new pass through trust certificates to "qualified institutional buyers" (as
defined under Rule 144A of the Securities Act) is generally exempt from
registration or qualification under the state securities laws. We currently do
not intend to register or qualify the sale of the new pass through trust
certificates in any state where an exemption from registration or qualification
is required and not available.
RATIO OF EARNINGS TO FIXED CHARGES
For the period from May 14, 1999 to September 30, 1999, the ratio of our
earnings to fixed charges was 2.04. Because we began operations on May 14, 1999,
we cannot calculate a ratio of earnings to fixed charges for any prior periods.
For the purposes of calculating the ratio of earnings available to cover fixed
charges:
- earnings consist of income from continuing operations and fixed charges
excluding capitalized interest, and
- fixed charges consist of interest on borrowings (whether expensed or
capitalized), related amortization and the interest component of rent
expense.
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USE OF PROCEEDS
We will not receive any cash proceeds from the issuance of the new pass
through trust certificates offered in this exchange offer. In consideration for
issuing the new pass through trust certificates as contemplated in this
prospectus, we will receive in exchange existing pass through trust certificates
in like principal amount.
The existing pass through trust certificates surrendered in exchange for
new pass through trust certificates will be retired and canceled and cannot be
reissued. Accordingly, issuance of the new pass through trust certificates will
not result in a change in our lease rental obligations.
The existing pass through trust certificates were issued and sold in order
to provide the debt portion of the lease transactions we entered into with
respect to the Kintigh Generating Station and the Milliken Generating Station.
The proceeds from the sale of the existing pass through trust certificates were
$550 million and were used by the pass through trustee to purchase the secured
lease obligation notes that were issued by the special purpose business trusts
that acquired the Kintigh Generating Station and the Milliken Generating
Station. The special purpose business trusts used the proceeds of the issuance
of the secured lease obligation notes, together with the proceeds of equity
investments made in the special purpose business trusts by the institutional
investors that formed the trusts, to finance the purchase of their interests in
the Kintigh Generating Station or the Milliken Generating Station and for lease
related transaction expenses, including the underwriting fees for the pass
through trust certificates.
The aggregate purchase price of our electricity generating stations was
$914 million. In addition, aggregate transaction expenses of the acquisition of
our electricity generating stations and the lease transactions were $26 million.
The special purpose business trusts paid an aggregate of $666 million to acquire
their interests in the Kintigh Generating Station and the Milliken Generating
Station and to fund transaction costs (approximately $448 million in respect of
the Kintigh Generating Station, approximately $202 million in respect of the
Milliken Generating Station and approximately $16 million in respect of
transaction costs). The institutional investors that formed the special purpose
business trusts made equity contributions to the special purpose business trusts
equal to $116 million (17.4% of the total cost of the interests in the Kintigh
Generating Station and the Milliken Generating Station purchased by the special
purpose business trusts and the transaction costs funded by the special purpose
business trusts) and the balance of the amount paid by the special purpose
business trusts, $550 million (82.6% of such cost), was financed through the
issuance by each special purpose business trust of secured lease obligation
notes. We paid the balance of the purchase price of our electricity generating
stations and the balance of the transaction expenses using equity contributions
that we received from The AES Corporation.
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CAPITALIZATION
The capitalization of our company as of September 30, 1999 consisted of
Partners' Capital of $383,589,000.
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DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
GENERAL
We were formed on December 2, 1998 to acquire, lease and, through our
wholly owned subsidiaries, operate and improve our electricity generating
stations. We and the special purpose business trusts acquired our electricity
generating stations on May 14, 1999 for a purchase price of $914 million. In
order to fund the acquisition of our electricity generating stations (including
some adjustments and plus improvement costs, working capital and transaction
costs) and pay transaction expenses relating to the acquisition and the lease
transactions, The AES Corporation made an equity contribution of $354 million to
us (net of costs advanced by The AES Corporation for which we will reimburse
it), the institutional investors made an equity contribution of $116 million
through the special purpose business trusts and we realized $550 million from
the sale of the pass through trust certificates.
All four of our electricity generating stations operate as merchant plants,
which means that we will sell their output in power pool spot market
transactions or in transactions negotiated from time to time directly with
another party rather than selling the output under a long-term power sales
contract. As merchant plants, our electricity generating stations generally will
be dispatched, that is, they will supply electricity, whenever the market price
of electricity exceeds their variable cost of generating electricity. Our
revenue and income will be directly affected by the price of electricity, which
is usually highest during the summer and winter peak seasons.
The economics of any electric power facility are primarily a function of
the price of electricity, the quantity of electricity which is purchased and the
level of operating expenses. The greater the percentage of time a unit is
dispatched, the greater the revenues associated with that unit.
We expect to concentrate our business activities in the New York power pool
for the foreseeable future. The markets for wholesale electric energy, installed
capacity and ancillary services in the New York power pool were largely
deregulated in November 1999. In a competitive market where the order in which
electricity generating plants are directed to run will be based on bids for the
sale of electric energy made by owners of generating assets in the region, we
expect that owners of lower marginal cost facilities will bid lower prices and
therefore those facilities will be directed to run more often than higher
marginal cost facilities.
According to data compiled by London Economics, our electricity generating
stations are among the lowest variable cost facilities in the New York power
pool. During 1998, the average production costs for the Kintigh Generating
Station, the Milliken Generating Station, the Goudey Generating Station and the
Greenidge Generating Station were $16.55/MWh, $16.82/MWh, $18.88/MWh and
$17.99/MWh, respectively. We believe that our electricity generating stations
are among the most efficient coal units in the region. London Economics believes
that our electricity generating stations will almost always be directed to run
under London Economics' modeling assumptions. London Economics noted that the
dispatch rates of the least efficient units among our electricity generating
stations (the non-reheat units at the Goudey Generating Station (Unit 7) and the
Greenidge Generating Station (Unit 3)) are most sensitive to unfavorable changes
in the model inputs while the most efficient units (the Kintigh Generating
Station and the Milliken Generating Station) are likely not to be sensitive to
these unfavorable changes. The efficiency of our electricity generating stations
provides several important advantages: a stable pricing structure, the ability
to benefit from energy price spikes in the market and relatively little risk
that our generating stations will be idle while other generating stations are
directed to run. Also, the Goudey Generating Station and the Greenidge
Generating Station provide economically valuable flexibility because they can be
used to provide ancillary services when they are not fully dispatched.
Our electricity generating stations have historically been available to run
a high percentage of the time due to the regulated utility-grade nature of their
design and construction. In 1998, the stations had a weighted average (based on
capacity) equivalent availability factor of 92.1%. Over the five-year period
ended in 1998,
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the weighted average (based on capacity) equivalent availability factor was
94.1% (excluding years in which major maintenance was performed). Based upon the
historical experience of The AES Corporation, we believe that we can maintain or
improve the availability of our electricity generating stations. The AES
Corporation's generating facilities around the world had a combined availability
of 92% during 1998.
At the Milliken Generating Station, we are currently planning major
maintenance outages of approximately 21 days each for Unit 2 in 2002 and Unit 1
in 2003. We will schedule these outages to avoid expected seasonal peaks in
demand for electric energy and we will schedule these outages to coincide with
normal, annual 10 to 14 day maintenance outages. We expect that there will be no
significant impact on our results of operations from these major maintenance
outages.
We believe that we will also have opportunities to derive revenue from
sales of installed capacity and ancillary services. Under the terms of the
capacity purchase agreement with NYSEG, NYSEG will purchase all of our 1,268MW
of installed capacity at a price of $68 per MW-day until April 30, 2001. During
the term of the capacity purchase agreement, the rules of the New York power
pool will require us to offer to sell our electric energy in the New York power
pool day-ahead energy market. We will be permitted to sell electric energy into
other pools only when the energy is not needed in the New York power pool. See
"BUSINESS -- OUR PLAN AND STRATEGY -- ELECTRICITY MARKETING PLAN."
We are currently being sued by NYSEG for allegedly refusing to cooperate in
NYSEG's efforts to perform an appraisal of the Kintigh Generating Station. See
"BUSINESS -- LEGAL PROCEEDINGS." We believe that NYSEG desires to perform this
appraisal in connection with a proceeding that NYSEG has brought to obtain a
refund of real estate taxes it paid in connection with the Kintigh Generating
Station while NYSEG owned it. NYSEG had little incentive to contest the tax
valuation of its electricity generating stations while it owned them because the
real property taxes it paid were included among the expenses it was permitted to
recover through regulated electricity rates and were therefore passed along to
its customers. We had identified real estate taxes as a potential area for cost
savings. If NYSEG is successful in obtaining substantial refunds of prior real
estate taxes, our potential savings may be to some extent nullified because the
local governments may be forced to raise real estate tax rates to bring revenues
into balance with expenditures. It is too early to tell what impact, if any,
this will have on our financial condition and results of operations.
AES Creative Resources, L.P., another subsidiary of The AES Corporation
that we do not control and that does not control us, assumed from NYSEG
responsibility for asbestos-related personal injury lawsuits in which plaintiffs
claim they were exposed to asbestos while employed by independent contractors
providing services at the electricity generating stations acquired from NYSEG.
As of December 1, 1999, 24 of these lawsuits were pending. While we cannot
quantify the potential liability arising from these suits given the early stage
of the proceedings and the large number of named defendants, the plaintiffs have
claimed substantial compensatory and punitive damages. AES NY, L.L.C., the
general partner of our company and of AES Creative Resources, L.P., and AES NY2,
L.L.C., the limited partner of our company and of AES Creative Resources, L.P.,
guaranteed the obligations of AES Creative Resources, L.P. We or our affiliates
may also become subject to additional suits based on similar allegations. The
costs of defending, settling or paying adverse judgments in such additional
suits could, collectively, have an adverse impact on us even if these amounts
were not individually material. See "RISK FACTORS -- WE OR OUR AFFILIATES MAY
HAVE TO DEFEND LAWSUITS RELATING TO ASBESTOS EXPOSURE AT OUR ELECTRICITY
GENERATING STATIONS WHILE THEY WERE OWNED BY NYSEG AND DAMAGES IN THOSE SUITS OR
THE COST OF DEFENDING THEM COULD BE MATERIAL" and "BUSINESS -- LEGAL
PROCEEDINGS."
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SOURCES AND USES OF FUNDS
The sources and uses of funds related to the acquisition of our electricity
generating stations and the lease transactions are as follows:
(IN MILLIONS) %
Sources of Funds:
Pass Through Trust Certificates......................... $ 550 53.9
Lease Equity(1)......................................... 116 11.4
Partners' Capital(2).................................... 354 34.7
------ -----
$1,020 100.0
Use of Funds:
Purchase of Electricity Generating Stations............. $ 914 89.6
Kintigh Selective Catalytic Reduction System Cost....... 31 3.0
Working Capital......................................... 20 2.0
Initial Rent Reserve.................................... 29 2.8
Transaction Costs....................................... 26 2.6
------ -----
$1,020 100.0
- ---------------
(1) Contributed by institutional investors.
(2) Contributed by The AES Corporation.
RESULTS OF OPERATIONS
We engaged in no operations between our formation in December 1998 and May
14, 1999. There are no separate financial statements available with regard to
our electricity generating stations prior to May 14, 1999 because their
operations were fully integrated with, and therefore results of operations were
consolidated into, NYSEG. In addition, the electric output of our electricity
generating stations was sold based on rates set by regulatory authorities while
they were owned by NYSEG. As a result and because electricity rates will now be
set by the operation of market forces, the historical financial data with
respect to our electricity generating stations for periods prior to May 14, 1999
is not meaningful or indicative of our future results. Our results of operations
in the future will depend primarily on revenues from the sale of electric
energy, installed capacity and ancillary products, and the level of our
operating expenses.
Energy revenue results from sales of electricity into the New York power
pool and adjoining power pools. Capacity revenue results from our commitment of
our generating capacity to NYSEG under the capacity purchase agreement that we
entered into with NYSEG to satisfy NYSEG's requirement to procure capacity
commitments sufficient to meet its forecasted peak demand plus a reserve
requirement. Other revenue in the period ended September 30, 1999 resulted
mainly from the sale of credits for the emission of nitrogen oxides.
During the period from May 14, 1999 to September 30, 1999, we generated
revenues of $107.2 million from sales of electricity and $10.0 million from the
capacity purchase agreement with NYSEG. Operating expenses totaled $73.2 million
primarily due to fuel cost for electric generation of $42.4 million. Net
interest expense for the period was $18.5 million. Our net income during this
period was $29.8 million.
The Kintigh Generating Station was taken out of service from May 14, 1999
to June 28, 1999 to complete the installation of a selective catalytic reduction
system and to make other improvements to the station's turbine and boiler.
During the period from May 14 to June 28, 1999, net costs directly related to
the construction at the Kintigh Generating Station were capitalized and are
included in electric generation assets on our balance sheet. Our revenues and
our energy generation costs were lower than usual during the period from May 14,
1999 to June 28, 1999 because the Kintigh Generating Station was not in service
for almost the entire period. Our revenues from sales of electricity during the
summer months were positively affected by the abnormally high temperatures
experienced in the northeastern United States and the resulting high demand for
electricity. As a consequence, our results of operations during the period from
May 14, 1999 to
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September 30, 1999 may not be comparable with our results of operations during
future periods or indicative of our future results of operations.
The existing pass through trust certificates have been accruing additional
interest at the rate of 0.50% per annum since November 10, 1999 as a result of
our failure to complete this exchange offer on or prior to November 10, 1999.
The existing pass through trust certificates will accrue this additional
interest until the exchange offer is completed. We will therefore pay
approximately $229,000 additional interest per month until we complete this
exchange offer.
LIQUIDITY AND CAPITAL RESOURCES
The leases for the Kintigh Generating Station and the Milliken Generating
Station require that we make fixed semiannual payments of rent on each January 2
and July 2 during the terms of the leases commencing on January 2, 2000 in
amounts calculated to be sufficient (1) to pay principal and interest when due
on the secured lease obligation notes issued by the special purpose business
trusts that own and lease to us the Kintigh Generating Station and the Milliken
Generating Station and (2) to pay the economic return of the institutional
investors that formed the special purpose business trusts. Our minimum rent
obligation under the leases is $36.5 million for 1999, $59.8 million for 2000,
$60.5 million for 2001, $60.5 million for 2002, $60.5 million for 2003 and a
total of $1,467.4 million for the years thereafter. For purposes of our
financial projections and the minimum rent obligations described in the
preceding sentence, we treated the semiannual rent payments that are due on
January 2 of each year as though they would be paid in the preceding year. You
can find information concerning our minimum rental obligations that treats rent
payments as obligations for the years in which they are due in the notes to our
audited financial statements which are included in this prospectus. Through
January 2, 2017 and so long as no Lease Event of Default exists, we may defer
payment of rent obligations under each lease in excess of the amount required to
pay principal and interest on the secured lease obligation notes secured by the
lease until after the final scheduled payment date of the secured lease
obligation notes. In addition, we are required to maintain a rent reserve
account equal to the maximum semiannual payment with respect to the sum of basic
rent (other than deferrable basic rent) and fixed charges expected to become due
on any one basic rent payment date in the immediately succeeding three-year
period. The amount of the rent reserve account required currently is $29
million. We will also be obligated to make payments under the coal hauling
agreement with Somerset Railroad in an amount sufficient, when added to funds
available from other sources, to enable Somerset Railroad to pay, when due, all
of its operating expenses and other expenses, including interest on and
principal of outstanding indebtedness. Somerset Railroad currently has a 364-day
term loan of up to $26 million from an affiliate of CIBC World Markets. See
"BUSINESS -- THE ACQUISITION OF OUR ELECTRICITY GENERATING
STATIONS -- ACQUISITION-RELATED CONTRACTS." As a result of these obligations, we
must dedicate a substantial portion of our cash flow from operations to payments
of rent under the leases, payment of the principal amount outstanding from time
to time under our working capital credit facility with Credit Suisse First
Boston and interest on this principal amount and payments under the coal hauling
agreement with Somerset Railroad.
We incurred approximately $56.7 million in capital expenditures with regard
to our assets through December 31, 1999, including approximately $31 million
that we paid to AES NY, L.L.C. on May 14, 1999 for work in progress on a
selective catalytic reduction system at the Kintigh Generating Station and
including expenditures made in connection with the construction of that
selective catalytic reduction system that we capitalized. We will make capital
expenditures thereafter according to the life extension program to be
implemented at our electricity generating stations. We have included the amounts
to be expended under the life extension program in our financial projections.
The average capital expenditures to be made under the program are $11.9 million
per year. We have budgeted capital expenditures in our financial projections
totaling $12.2 million for 2000, $7.1 million for 2001, $17 million for 2002,
$15.6 million for 2003, $6.6 million for 2004 and a total of $335 million for
the remaining years through 2032. These amounts include approximately $14
million to install a selective catalytic reduction system to reduce NO(x)
emissions at the Milliken Generating Station during scheduled outages in 2002
and 2003, although we are also considering other compliance strategies, such as
the addition of a selective non-catalytic reduction system. For specific
information concerning projected capital expenditures for the years 2005 through
2032, please refer to our
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financial projections, which are included in Appendix A -- Independent
Engineer's Report. In addition to capital requirements associated with the
ownership and operation of our electricity generating stations, we will have
significant fixed charge obligations in the future, principally with respect to
the leases.
Compliance with environmental standards will continue to be reflected in
our capital expenditures and operating costs. Based on the current status of
regulatory requirements and, other than the expenditures for a selective
catalytic reduction system at the Kintigh Generating Station, including the
construction of new landfill space to manage ash from selective catalytic
reduction system operations, and possible expenditures for a selective catalytic
reduction system at the Milliken Generating Station, we do not anticipate that
any capital expenditures or operating expenses associated with our compliance
with current laws and regulations will have a material effect on our results of
operations or our financial condition. See "REGULATION -- ENVIRONMENTAL
REGULATORY MATTERS."
Our net working capital at September 30, 1999 was $47.8 million. No amounts
were borrowed under our working capital credit facility with Credit Suisse First
Boston at September 30, 1999. During the period from May 14, 1999 to December
31, 1999, we made only one borrowing under our working capital credit facility.
This borrowing was from August 25, 1999 to September 13, 1999 in the amount of
$5 million and bore interest at the rate of 9.25% per annum. See "DESCRIPTION OF
THE WORKING CAPITAL CREDIT FACILITY." The outage at the Kintigh Generating
Station for almost the entire period from May 14, 1999 to June 30, 1999 did not
impair our ability to meet our obligations during this period. Subsequent to
this outage, our four electricity generating stations are all available for
service and are being dispatched to generate electricity when market conditions
warrant.
Cash flow from our operations was sufficient to cover aggregate rental
payments under the leases for the Kintigh Generating Station and the Milliken
Generating Station on the first rent payment date, January 2, 2000. We believe
that cash flow from our operations will be sufficient to cover aggregate rental
payments on each rent payment date thereafter. We also believe that our cash
flow from operations, together with amounts we can borrow under our $50 million
working capital credit facility with Credit Suisse First Boston (or renewals or
refinancings), will be sufficient to cover expected capital requirements over
the terms of the leases. If we are required to make unanticipated capital
expenditures, our cash flow from operations and operating income in the period
incurred might be reduced. In the event of a shortfall between the amount of our
commitments and the foregoing sources of funds, the shortfall may be made up by
loans or equity contributions from The AES Corporation, but there can be no
assurances that The AES Corporation would decide to provide a loan or equity
contribution.
The working capital credit facility with Credit Suisse First Boston permits
us to borrow up to $50 million for operating and maintenance expenses. Loans
under the working capital credit facility with Credit Suisse First Boston will
be available on a revolving basis, provided that the aggregate principal amount
available under the working capital credit facility will be reduced by the
outstanding principal amount under any secured borrowings permitted by the terms
of the working capital credit facility. During each 12-month period, borrowings
under the working capital credit facility must be repaid, and cannot be
reborrowed, during a 30-day period preceding at least one semiannual lease
rental payment date. Amounts outstanding under the working capital credit
facility also must be reduced to zero prior to any rental payment under the
leases. The working capital credit facility is secured by a pledge of our
membership interest in AEE2, L.L.C., our wholly owned subsidiary that owns the
Greenidge Generating Station and the Goudey Generating Station, and by a
security interest in equipment and personal property of AEE2, L.L.C. See
"DESCRIPTION OF THE WORKING CAPITAL CREDIT FACILITY."
Our ability to make distributions to the partners of our company is
restricted by the terms of the agreements governing the leases for the Kintigh
Generating Station and the Milliken Generating Station. We may make
distributions only on or within five days after a semiannual rent payment date
and only if all rent on the leases has been paid, the reserve accounts for lease
payments that we are required to maintain are fully funded and other conditions
are satisfied. See "DESCRIPTION OF THE PASS THROUGH TRUST CERTIFICATES --
RESTRICTED PAYMENTS."
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FINANCIAL PROJECTIONS
Our financial projections are included in the Independent Engineer's
Report. They are predicated upon certain assumptions and forecasts of the
revenue generating capacity of our electricity generating stations and the
associated costs. The assumptions that we made with respect to future market
prices for electric energy and installed capacity and the level of dispatch
(volume) for our electricity generating stations are based upon a comprehensive
market analysis prepared by London Economics. This market forecast served as a
basis for both the dispatch and pricing assumptions incorporated in our
financial projections and employed by the Independent Engineer in its review of
our financial projections. The Independent Engineer has reviewed the technical
operating parameters of our electricity generating stations. The Independent
Engineer has also evaluated the operations and maintenance budgets for our
electricity generating stations and the related assumptions and forecasts
contained therein based on a review of certain technical, environmental,
economic and permitting aspects of our electricity generating stations. The
Independent Engineer's Report contains a discussion of the principal assumptions
and considerations we utilized in preparing our financial projections, which you
should review carefully. See "BUSINESS -- SUMMARY OF INDEPENDENT ENGINEER'S
REPORT" and "APPENDIX A -- INDEPENDENT ENGINEER'S REPORT."
YEAR 2000 COMPLIANCE
We have experienced no adverse effects from the expected year 2000 issue,
which is the failure of computers to recognize the year 2000 and later years. We
do not anticipate any adverse effects from the year 2000 issue.
Under the asset purchase agreement between NYSEG and us, NYSEG expressly
disclaimed liability for losses stemming from the failure of computers to
recognize dates in the year 2000 and later years. NYSEG developed and
implemented a year 2000 compliance program for all of its facilities pursuant to
which NYSEG assessed the potential impact of this issue on its operations. NYSEG
evaluated (a) the vulnerability of its facility operations for the supply of
power, (b) its business software and hardware including those systems developed
internally and those purchased from third parties and (c) other systems and
products used internally that were purchased from third parties. The plan
covered the evaluation of imbedded systems, control systems and computer systems
at the component level for potential year 2000 impact. NYSEG agreed to deliver
to us all materials relating to NYSEG's year 2000 compliance efforts. In
addition, we met with the NYSEG personnel responsible for NYSEG's year 2000
compliance efforts and we are familiar with all aspects of these efforts.
As part of its assessment, NYSEG evaluated all date sensitive systems
necessary to generate energy at each of our electricity generating stations and
tested these systems during scheduled maintenance outages. At the Kintigh
Generating Station and the Milliken Generating Station, these tests included
rolling the date forward to December 31, 1999. To the extent that compliance
problems existed at any of our electricity generating stations, a replacement
option was put into place. NYSEG spent approximately $80,000 in the aggregate in
1998 for testing and upgrades, $70,000 of which was spent at the Kintigh
Generating Station and the Milliken Generating Station. During 1999, the
combined expenditures by us and NYSEG were approximately $300,000 for testing
and upgrades at the Kintigh Generating Station and the Milliken Generating
Station. New business systems software and hardware, including software for
accounting, inventory management, work management and payroll, which are year
2000 compliant, were put in place at each of our electricity generating
stations. In addition, the continuous emission monitoring systems at each of our
electricity generating stations were upgraded during 1999 at an aggregate cost
of $240,000.
In addition, NYSEG and we surveyed all of the third parties with which we
deal to determine the extent of these third parties' year 2000 compliance
efforts and requested compliance certificates from all equipment vendors. NYSEG
and we received certifications that the third parties with which we conduct
business were year 2000 compliant.
FORWARD LOOKING STATEMENTS
CERTAIN STATEMENTS CONTAINED IN THIS PROSPECTUS ARE FORWARD-LOOKING
STATEMENTS. THESE FORWARD-LOOKING STATEMENTS CAN BE IDENTIFIED BY THE USE OF
FORWARD-LOOKING TERMINOLOGY SUCH AS "BELIEVES," "EXPECTS," "MAY," "INTENDS,"
"WILL," "SHOULD" OR "ANTICIPATES" OR THE NEGATIVE FORMS OR OTHER VARIATIONS OF
THESE TERMS OR COMPARABLE TERMINOLOGY, OR BY DISCUSSIONS OF STRATEGY. FUTURE
RESULTS COVERED BY THE FORWARD-LOOKING STATEMENTS MAY NOT BE ACHIEVED.
FORWARD-LOOKING STATEMENTS ARE SUBJECT TO RISKS, UNCERTAINTIES AND OTHER
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FACTORS WHICH COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM FUTURE
RESULTS EXPRESSED OR IMPLIED BY SUCH FORWARD-LOOKING STATEMENTS. THE MOST
SIGNIFICANT RISKS, UNCERTAINTIES AND OTHER FACTORS ARE DISCUSSED UNDER THE
HEADING "RISK FACTORS" IN THIS PROSPECTUS, AND YOU ARE URGED TO CONSIDER
CAREFULLY SUCH FACTORS. YOU SHOULD READ AND UNDERSTAND THE DESCRIPTION OF THE
ASSUMPTIONS AND UNCERTAINTIES UNDERLYING OUR FINANCIAL PROJECTIONS THAT ARE SET
FORTH IN APPENDIX A OF THIS PROSPECTUS. WE DO NOT INTEND TO PROVIDE HOLDERS OF
PASS THROUGH TRUST CERTIFICATES WITH ANY REVISED OR UPDATED FINANCIAL
PROJECTIONS OR ANALYSIS OF THE DIFFERENCE BETWEEN THE FINANCIAL PROJECTIONS AND
ACTUAL OPERATING RESULTS.
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OUR COMPANY AND THE AES CORPORATION
Our company is a Delaware limited partnership. Our company was formed on
December 2, 1998 for the purpose of leasing the Kintigh Generating Station and
the Milliken Generating Station and acquiring the Goudey Generating Station and
the Greenidge Generating Station from NYSEG. We operate our electricity
generating stations through our wholly owned subsidiaries. The Goudey Generating
Station and the Greenidge Generating Station are owned by a wholly owned
subsidiary, AEE2, L.L.C. Our other subsidiaries do not own any of our
electricity generating stations but operate them pursuant to operations and
maintenance agreements with us.
A diagram of the corporate structure of The AES Corporation as it relates
to the transactions described in this prospectus is included below:
[AES Corporation Flow Chart]
THE AES CORPORATION
The AES Corporation, incorporated under the laws of Delaware in 1981 and
headquartered in Arlington, Virginia, is a global power company committed to
supplying electricity to customers worldwide in a socially responsible way. In
addition to marketing power principally from generating facilities that it
develops, builds, owns, and operates, The AES Corporation also has interests in
electric distribution companies. These distribution companies sell electricity
directly to commercial, industrial, governmental and residential customers. The
AES Corporation currently has assets in excess of $10 billion and employs
approximately 40,000 people around the world.
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Over the last six years, The AES Corporation has experienced significant
growth. This growth has resulted primarily from the development and construction
of new plants and also from the acquisition of existing generating plants and
distribution companies, through competitively bid privatization initiatives
outside of the United States or negotiated acquisitions. In particular, The AES
Corporation has been interested in acquiring existing businesses or assets in
electricity markets that are promoting competition and eliminating rate of
return regulation. This growth has resulted in The AES Corporation's total
revenues increasing at a compound annual growth rate of 35%, from $401 million
in 1992 to $2.4 billion in 1998, while net income (before extraordinary item)
has increased at a compound annual growth rate of 33%, from $56 million to $307
million over the same period.
The AES Corporation and its affiliates, other than our company, will not be
liable for any obligations under the leases, the pass through trust certificates
or the secured lease obligation notes issued by the special purpose business
trusts.
Generation
The AES Corporation operates and owns (entirely or in part) a diverse
portfolio of 111 electric power plants with a total capacity of 38,852MW. This
represents more than a tenfold increase from The AES Corporation's total
generating capacity in 1992. The AES Corporation is also in the process of
adding approximately 6,314MW to its operating portfolio by constructing 10 new
plants. As a result, The AES Corporation's total of 121 power plants in
operation or under construction represents approximately 43,166MW, of which net
equity ownership is approximately 27,046MW. These plants are located in the
United States, the United Kingdom, Argentina, China, Hungary, Brazil,
Kazakhstan, the Dominican Republic, Canada, Pakistan, the Netherlands,
Australia, Panama, India and Mexico, and generally utilize natural gas, coal,
oil, hydro power or combinations of these fuels or power sources.
Distribution
Beginning in 1996, The AES Corporation began acquiring interests in
electric distribution companies. The AES Corporation has majority ownership in
one distribution company in the United States, three in Argentina, one in
Brazil, one in El Salvador, one in the Dominican Republic, one in the Republic
of Georgia (operational control acquired in 1999) and a heat and electricity
distribution business in Kazakhstan. The AES Corporation has less than majority
ownership in three additional companies in Brazil. These 10 companies serve a
total of approximately 13.2 million customers with sales exceeding 63,000GWh. On
a net equity basis, The AES Corporation's ownership represents approximately 3
million customers with sales exceeding 22,000GWh.
Strategy
The AES Corporation's strategy of helping meet the world's needs for
electricity includes the following elements:
- Supplying energy to customers at the lowest cost possible, taking into
account factors such as reliability and environmental performance;
- Constructing or acquiring projects of a relatively large size (generally
larger than 100MW);
- Whenever possible, entering into power sales contracts with electric
utilities or other customers with significant credit strength, or
alternatively pursuing methods to hedge costs and revenues to provide as
much assurance as possible to the project's profitability; and
- Participating in electric power distribution and retail supply markets
that grant concessions with long-term pricing arrangements.
The AES Corporation also strives for operating excellence as a key element
of its strategy, which it believes is accomplished by minimizing organizational
layers and maximizing company-wide participation in decision-making. The AES
Corporation has attempted to create an operating environment that results in
safe,
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clean and reliable electricity generation. Because of this emphasis, The AES
Corporation (through its subsidiaries and affiliates) prefers to operate all
facilities which it develops or acquires.
The AES Corporation attempts to finance each domestic and foreign plant
primarily under loan agreements and related documents which require the loans to
be repaid solely from the project's revenues and provide that the repayment of
the loans (and interest on the loans) is secured solely by the capital stock,
physical assets, contracts and cash flow of that plant subsidiary and affiliate.
The lenders under these financing structures cannot look to The AES Corporation
or its other projects for repayment.
Principles and Practices
A core part of The AES Corporation's corporate culture is a commitment to
"shared principles." These principles describe how The AES Corporation people
endeavor to behave, recognizing that they don't always live up to these
standards. The principles are:
Integrity -- The AES Corporation strives to act with integrity, or
"wholeness." The AES Corporation seeks to honor its commitments. The goal
is that the things The AES Corporation people say and do in all parts of
The AES Corporation should fit together with truth and consistency.
Fairness -- The AES Corporation wants to treat fairly its people, its
customers, its suppliers, its stockholders, governments and the communities
in which it operates. Defining what is fair is often difficult, but The AES
Corporation believes it is helpful to routinely question the relative
fairness of alternative courses of action.
Fun -- The AES Corporation desires that people employed by The AES
Corporation and those people with whom The AES Corporation interacts have
fun in their work. The AES Corporation's goal has been to create and
maintain an environment in which each person can flourish in the use of his
or her gifts and skills and thereby enjoy the time spent at The AES
Corporation.
Social Responsibility -- The AES Corporation believes that it has a
responsibility to be involved in projects that provide social benefits,
such as lower costs to customers, a high degree of safety and reliability,
increased employment and a cleaner environment.
The AES Corporation recognizes that most companies have standards and
ethics by which they operate and that business decisions are based, at least in
part, on these principles. The AES Corporation believes that an explicit
commitment to a particular set of standards is a useful way to encourage
ownership of those values among its people. While the people at The AES
Corporation acknowledge that they won't always live up to these standards, they
believe that being held accountable to these shared values will help them behave
more consistently with these principles.
The AES Corporation makes an effort to support these principles in ways
that acknowledge a strong corporate commitment and encourage people to act
accordingly. For example, The AES Corporation conducts annual surveys, both
company-wide and at each location, designed to measure how well its people are
doing in supporting these principles -- through interactions within The AES
Corporation and with people outside The AES Corporation. These surveys are
perhaps most useful in revealing failures, and helping to deal with those
failures. The AES Corporation's principles are relevant because they help
explain how The AES Corporation people approach The AES Corporation's business.
The AES Corporation seeks to adhere to these principles, not as a means to
achieve economic success but because adherence is a worthwhile goal in and of
itself.
In order to create a fun working environment for its people and implement
its strategy of operational excellence, The AES Corporation has adopted
decentralized organizational principles and practices. For example, The AES
Corporation works to minimize the number of supervisory layers in its
organization. Most of The AES Corporation's plants operate without shift
supervisors. The project subsidiaries are responsible for all major
facility-specific business functions, including financing and capital
expenditures. The AES Corporation's criteria for hiring new people include a
person's willingness to accept responsibility and The AES Corporation's
principles as well as a person's experience and expertise. The AES Corporation
has generally organized itself into multi-skilled teams to develop projects,
rather than forming "staff" groups (such as a human resources department or an
engineering staff) to carry out specialized functions.
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BUSINESS
INDUSTRY OVERVIEW
The United States electric industry, including companies engaged in
providing generation, transmission, distribution, and ancillary services, has
undergone significant change over the last several years, leading to significant
deregulation and increased competition. The Federal Energy Regulatory Commission
requires the owners and operators of electric transmission facilities to make
those facilities available on a nondiscriminatory basis to all wholesale
generators, sellers and buyers of electricity. In addition, there have been an
increasing number of proposals throughout the United States to allow retail
customers to choose their electricity suppliers, with incumbent utilities
required to deliver that electricity over their transmission and distribution
systems. Numerous electric utilities nationwide are in the process of divesting
all or a portion of their electricity generating business or are expected to
commence this process in the foreseeable future, as legislative and regulatory
developments drive the industry to disaggregate.
The restructuring of New York's vertically integrated utility industry
began in May 1996 as a result of an order of the Public Service Commission of
the State of New York requiring each investor owned utility to file a
restructuring plan. The Public Service Commission order called for wholesale
competition commencing in 1997, retail competition starting in 1998 and the
creation of an independent system operator. In the order, the Public Service
Commission expressed a preference for the divestiture of generation assets and
indicated that it would allow utilities to recover prudent and verifiable
stranded costs, which are costs that represent losses in the economic value of
existing generation-related utility assets. Restructuring agreements for all of
New York State's investor owned utilities have now been approved and are being
implemented. In the Upstate region of New York, customers other than those in
the service area of Rochester Gas & Electric Corporation were able to choose
their electricity providers by the end of 1999; in the service area of Rochester
Gas & Electric Corporation and in the Downstate region other than the service
area of the Long Island Power Authority, customers will be able to choose their
electricity providers by the end of 2001. Customers in the service area of the
Long Island Power Authority will be able to choose their electricity providers
by the end of 2003. Most investor owned utilities are divesting their generating
assets and becoming primarily distribution companies, resulting in fragmentation
of ownership of New York State's generation assets.
Pursuant to the approved restructurings, transmission lines will be
controlled by an independent system operator and market prices for power will be
set through one or more power exchanges. We anticipate that separate markets
will develop for installed capacity, electric energy and ancillary services
(including services which provide system reliability) and that prices will be
determined competitively. As most New York State utilities have divested, or are
expected to divest, some or all of their generating assets, power suppliers will
need to purchase power from other generators. The transmission of electricity
between regions is constrained by physical limits on transmission capacity and
limits on the amount of electricity that may be imported into a power pool
imposed by power pools to enhance reliability. Therefore, the purchasers of
generating assets in any given region will have a competitive advantage in that
region over generators not in the region. There is an existing natural market
for the installed capacity and the electric energy of our electricity generating
stations in Western New York, which includes the retail service territories of
NYSEG, Niagara Mohawk Power Corporation and Rochester Gas & Electric
Corporation. The existing transmission infrastructure also permits us to access
neighboring markets. However, our ability to sell electric energy into
neighboring markets is limited by constraints imposed by transmission capacity
limitations and limits imposed by power pools in those markets for reliability
considerations. Our ability to sell electric energy into neighboring markets may
also be limited because we are required to offer to sell our electric energy in
the New York power pool market for the delivery of electric energy on the
following day during the term of the capacity purchase agreement with NYSEG.
As required by the Public Service Commission, NYSEG filed a restructuring
plan in October 1997, which was approved, with minor modifications, by the
Public Service Commission in January 1998. In accordance with the restructuring
plan, NYSEG put its fossil fueled generating assets up for auction. In August
1998, it accepted two bids, first, from an affiliate of Edison Mission Energy
for NYSEG's 50% interest
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in the Homer City Generating Station and, second, from The AES Corporation for
the other fossil fueled generating assets.
After the divestiture of its generating assets, NYSEG is still regulated as
a transmission and distribution utility and continued to supply all required
power to its service territory until August 1999, when full retail competition
began. NYSEG is still the power supplier for those customers who did not
actively choose a different power supplier. To fulfill its commitments to
deliver this power, NYSEG is required to obtain installed capacity commitments
to satisfy the projected demand of its customers and to purchase electric energy
in the open market or enter into bilateral power purchase agreements. The
capacity purchase agreement that we have signed with NYSEG addresses NYSEG's
need to obtain commitments of installed capacity through April 2001. See
"BUSINESS -- THE ACQUISITION OF OUR ELECTRICITY GENERATING
STATIONS -- ACQUISITION-RELATED CONTRACTS."
NEW YORK POWER POOL
The New York power pool is an association of the investor owned utilities
in the state, the New York Power Authority and the Long Island Power Authority.
Historically, the New York power pool has operated a centrally dispatched pool
to minimize member production costs and to maintain statewide reliability. It
has also coordinated the operation of the bulk power transmission facilities in
the state. The New York power pool system transformed into the new independent
system operator system in November 1999. The new independent system operator
system consists of three new entities, the independent system operator, the New
York State Reliability Council and New York Power Exchange. The independent
system operator is a non-profit New York corporation under the Federal Energy
Regulatory Commission's jurisdiction. It is governed by a board of directors
with 10 members and three committees, the management committee, the operating
committee, and the business issues committee, which are composed of
representatives from all market participants, including buyers of power, sellers
of power, consumer groups and transmission owners. The New York State
Reliability Council has the primary responsibility to preserve the reliability
of electricity service on the bulk power system within New York State and sets
the reliability standards to be used by the independent system operator. The New
York Power Exchange is one of many possible power exchanges in New York State
which will be formed to facilitate competition in the power markets, and to
operate the actual markets for installed capacity, energy and ancillary services
which will be maintained for the offer and sale of those commodities for
delivery on the following day and on an immediate basis.
The new independent system operator system only recently began operations.
The rules may change based on recommendations by the committees to the board of
directors. We entered into an interim arrangement with NYSEG to sell energy into
the New York power pool during the period preceding commencement of operations
by the independent system operator system. See "-- OUR PLAN AND
STRATEGY -- INTERIM AGREEMENT."
The New York power pool member systems serve over 99% of New York State's
electric power requirements. In addition, over 8,000MW of capacity is owned by
non-utility generators, who sell the bulk of their output to the investor-owned
utilities under long-term contracts. The New York power pool is interconnected
with New England power pool to the northeast, Hydro Quebec and Ontario Hydro to
the north, and Pennsylvania-New Jersey-Maryland power pool to the south.
Transmission System Market. Transmission access is available to all market
participants on a comparable and non-discriminatory basis. The party
transmitting electric energy pays the independent system operator a transmission
service charge to cover the revenue requirements of the transmission owner. In
addition to the transmission service charges, electric energy under a bilateral
contract is subject to a congestion charge. The congestion charge reflects the
differences between the marginal power price at the source and destination on
the transmission system. Parties can hedge their exposure to congestion charges
through transmission congestion contracts which are auctioned biannually.
New York Power Pool Wholesale Market. Electric energy generators sell
electric energy, installed capacity and ancillary services at the wholesale
level to regulated distribution utilities, municipalities and energy supply
companies. Electric energy generators may also sell electric energy, installed
capacity and
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ancillary services in the centralized wholesale market coordinated by the
independent system operator. Competition in wholesale and retail markets will
lead to unbundling of and distinct markets for electric energy, installed
capacity and ancillary services.
Electric Energy Markets. Any generator in the state can sell its output of
electric energy to any wholesale customer statewide including utilities,
municipalities, and energy supply companies. Generators can sell electric energy
under bilateral contracts, with pricing and other provisions determined by
two-party negotiation, or they can bid into either or both of two centralized
markets for electric energy, a market for delivery on the following day or a
market for delivery on an immediate basis, which is intended primarily to ensure
that actual loads and resources match up. The system pricing is based upon
market clearing price, which is the price at which sufficient electric energy is
supplied to satisfy all demand for which bids have been submitted. If a
generator's bid is equal to or less than the market clearing price, the
generator will be paid the market clearing price, rather than its bid price, at
the point it supplies electric energy to the system and the purchaser will pay
the market clearing price at the point it receives electric energy from the
system.
Installed Capacity Market. A market in which electricity generators can
sell commitments of their installed generating capacity has been established to
ensure there is enough generation capacity to meet retail demand and ancillary
service requirements. Any load serving entity, i.e., an entity selling electric
energy to consumers of electric energy, including regulated distribution
utilities, municipalities and energy supply companies, is required to procure
capacity commitments sufficient to meet its capacity requirements for the next
year based on its forecasted annual requirements at times of maximum usage plus
a reserve requirement. Initially, each load serving entity is required to
purchase installed capacity commitments equal to 118% of its forecasted annual
maximum usage (which translates into a 22% control area reserve margin). The
load serving entity can secure these capacity commitments through a bilateral
contract or through installed capacity auctions. Any capacity commitment which
is not procured locally needs to satisfy the requirement that, as an import, it
does not violate transmission constraints. Any load serving entity that fails to
satisfy its installed capacity requirements is subject to a deficiency payment
of $52.50 per KW-year in the first year escalating to $62.50 per KW-year in the
third year, which is well above forecasted capacity prices. The deficiency
payments are higher for New York City and Long Island.
Suppliers of installed capacity are not required to supply the associated
electric energy to the load serving entity with whom they have a contract to
provide installed capacity. However, if the load serving entity does not
purchase electric energy from its installed capacity supplier, the installed
capacity supplier is required to submit an offer to sell its electric energy
into the electric energy market for delivery on the following day. If the
installed capacity supplier's offer in the electric energy market for delivery
on the following day is not accepted, the installed capacity supplier, for the
next day, will be free either to offer to sell its electric energy in the market
for delivery on an immediate basis or to sell electric energy to any customer,
including out-of-state customers.
Ancillary Services Market. The independent system operator will procure
various ancillary services required for reliability from generators as needed.
Services to be procured on a market basis include operating reserves and
regulation and frequency support. Generators will be compensated for other
services, including voltage support and black start capability, on a cost basis.
Generation. The existing generation mix in New York is fairly diverse. As
of January 1, 1999, nuclear and coal facilities made up only 28% of the
installed capacity. Non-utility generators, which are predominantly gas-fired,
formed another 23% of installed capacity. The remaining 49% of installed
capacity, comprised of oil, gas and seasonal hydro plants, is considered to be
economically viable at times of peak demand. Even though the nuclear and coal
facilities comprise 28% of the installed capacity, they produced 41% of the
electric energy in 1998.
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NET CAPACITY (SUMMER) BY FUEL TYPE IN
NEW YORK (1998)
- -------------------------------------
Oil/Dual -- fuel.................. 33%
NUGs.............................. 23%
Coal.............................. 14%
Nuclear........................... 14%
Conventional Hydro................ 12%
Pumped Storage Hydro.............. 3%
Natural Gas....................... 1%
---
100%
NET GENERATION BY FUEL TYPE IN
NEW YORK (1998)
- ------------------------------
NUGs........................... 25%
Nuclear........................ 21%
Coal........................... 20%
Conventional Hydro............. 17%
Natural Gas.................... 10%
Oil............................ 6%
Pumped Storage Hydro........... 1%
---
100%
- ---------------
Source: New York Power Pool, 1999 Load and Capacity Data.
Regions. New York State has regional transmission constraints which divide
the state's power market into distinct regions. The most significant
transmission constraints impede the transmission of electricity going west to
east. As a result, the most significant regional differences in the power market
are between the western and eastern regions. The eastern region includes the
service areas of the Long Island Power Authority, Key Span Energy Corporation,
Consolidated Edison Company of New York, Inc., Orange & Rockland Utilities, Inc.
and Central Hudson Gas & Electric Corporation. The western region includes
service areas of Niagara Mohawk Power Corporation, Rochester Gas & Electric
Corporation, the New York Power Authority and most of NYSEG.
The western region is dominated by low cost nuclear and coal and hydro
facilities which, together with non-utility generators that must be permitted to
run under their power purchase agreements with local utilities, form 83% of
installed capacity. The eastern region has a predominance of facilities which
are economically viable only at periods of peak demand, which form 80% of its
installed capacity. Even though the western region has only 40% of the New York
power market's generation capacity, power normally flows from the west into the
east. The flow of power from the lower priced western region to the higher
priced eastern region is limited to approximately 5,000MW by transmission limits
and reliability considerations. When this limit is reached, higher cost units in
the New York City area are directed to run even when lower cost units in the
western region are available.
Demand. In 1998, the New York power pool summer peak was 28,160MW and
electric energy demand totaled 151,420GWh. The statewide summer peak demand grew
by an average of 2.2% per year from 1992 to 1998, while electric energy demand
grew by an average of 0.9% annually during that same period. Current New York
power pool forecasts call for a continued capacity surplus until 2003, except
for 2001 when an external purchase is required. After 2003, new capacity will be
required in order to maintain system reserve margin requirements. PG&E
Generating and Sithe Energies, Inc. have recently announced new projects that,
if completed, will extend the forecasted capacity surplus beyond 2008.
Interconnection. Western and central New York are relatively unattractive
markets for the transmission of imported power due to the low generation costs
of existing facilities and low on-peak electric energy prices relative to the
area's adjacent markets, the New England power pool, the Pennsylvania-New
Jersey-Maryland power pool and eastern New York. On the export side, the New
England power pool and the Pennsylvania-New Jersey-Maryland power pool forecast
higher demand growth for their markets. Furthermore, the existing transmission
infrastructure permits us to access these neighboring markets, subject to
constraints imposed by capacity limitations and reliability considerations and
subject to our obligation to offer to sell our electric energy in the New York
power pool market for the delivery of electric energy on the following day
during the term of the capacity purchase agreement with NYSEG in accordance with
the rules of the New York power pool.
The Pennsylvania-New Jersey-Maryland power pool is a market characterized
by high price volatility where peak hour pricing is set by inefficient
diesel-fired facilities. The Pennsylvania-New Jersey-Maryland power pool
forecasts summer peak demand to grow 1.6% per year over the next ten years and
projects that a capacity shortage will occur by 2000. The New England power
pool, where energy prices are among the
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highest in the U.S., relies heavily on relatively inefficient oil and gas-fueled
steam power plants. The New England power pool is currently experiencing
capacity shortfalls primarily due to nuclear outages and retirements. New
capacity is required in the New England power pool to meet increasing demand,
which may increase installed capacity prices in the near term. The New York
power pool has transfer capacity to the New England power pool of 1,675MW
through two 345KV interconnections and transfer capacity to the Pennsylvania-New
Jersey-Maryland power pool of 725MW.
[POWER POOL MAP]
OUR PLAN AND STRATEGY
Introduction
Consistent with the corporate philosophy of The AES Corporation, our
strategy for the long-term profitable operation of our electricity generating
stations is to continue to operate the stations in a low cost, environmentally
responsible way. We expect to reduce these stations' current operating costs by
implementing the decentralized operating philosophy of The AES Corporation.
In general, we plan to sell the electric energy generated by our
electricity generating stations directly into the spot market. We entered into a
two-year agreement for energy marketing services with Merchant Energy Group of
the Americas, Inc. ("MEGA"), an Annapolis, Maryland-based subsidiary of Gener
S.A., a Chilean independent power producer listed on the New York Stock
Exchange. MEGA will be responsible for marketing our electric energy, installed
capacity and ancillary services in the deregulated New York power market. We
entered into the capacity purchase agreement with NYSEG pursuant to which we
agreed to make the installed capacity of our electricity generating stations
available to NYSEG for $68 per MW-day through April 2001. The capacity purchase
agreement permits us to sell our electric energy and ancillary services to NYSEG
or any other purchaser. During the term of the capacity purchase agreement, the
rules of the New York power pool will require us to offer to sell our electric
energy in the New York power pool market for the delivery of electric energy on
the following day. It is possible that we will enter into additional bilateral
sales
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contracts for installed capacity or electric energy from our electricity
generating stations in the future. We expect that strategic opportunities to
enter into long-term contracts will occur over the next few years as New York
electric utilities complete their divestiture programs and any transitional
capacity and energy sales contracts they may sign at the time of divestiture
expire, and full retail competition for electric energy develops.
We believe that we have a number of advantages that will help us implement
this strategy. First, our ultimate parent, The AES Corporation, has several
plants in the northeast region that are currently operating, under construction,
or in advanced stages of development. These assets give The AES Corporation
familiarity with the operating environment in the region and offer possibilities
for achieving economies of scale, particularly with respect to coal purchases.
Second, our electricity generating stations utilize coal as their primary fuel.
The inflation adjusted or real price of coal has declined historically and we
expect that trend to continue at least until 2010. This may allow us to offer
fixed price electric energy contracts that are responsive to our customers'
desire to insulate themselves from potential volatility in the electric energy
spot market. However, our assumption that the real price of coal will decline
until at least 2010 may not be correct. See "RISK FACTORS -- OUR FINANCIAL
PROJECTIONS ASSUME THAT THE REAL PRICE OF COAL WILL CONTINUE TO DROP IN THE
FUTURE; AN INCREASE IN THE REAL PRICE OF COAL WILL NEGATIVELY AFFECT OUR
OPERATING RESULTS." We may be unable to meet our operating expenses if we enter
into fixed price electric energy contracts and the price of coal rises to levels
higher than those we projected. We may attempt to hedge these contracts with
matching coal contracts. Third, The AES Corporation has acquired older plants
throughout the world and has been able to operate them efficiently, reliably and
in a cost effective manner. The AES Corporation also has made capital
investments in older plants to extend the operational lives of the plants.
For example, AES Beaver Valley in Pennsylvania was approximately 50 years
old when The AES Corporation acquired it in August 1985, and its 1998
availability was 95%. In Argentina, The AES Corporation acquired Central Termica
San Nicolas, an older facility operating at approximately 60% availability that
The AES Corporation operated at 72% availability in 1998. In Hungary, The AES
Corporation acquired Borsod, Tiszapalkonya, and Tisza 2, three plants that The
AES Corporation operated at availability factors between 86% and 100% in 1998,
which represent significant increases over previous levels. The AES Corporation
managed each of these improvements with existing unionized labor forces using
its decentralized operating philosophy.
Electricity Marketing Plan
Competitive markets for electric energy, installed capacity and various
ancillary services in the New York power market will allow us to enter into both
bilateral and bid-based energy transactions. Additionally, New York is pursuing
a statewide retail access schedule that is among the most aggressive in the
country. New York power markets currently operate near capacity and the New York
power pool projects a capacity deficit for New York beginning in 2003. Central
and western New York is a source of low-cost generation, giving us potential to
export electric energy to neighboring power pools with higher costs and prices.
These opportunities are subject to constraints imposed by transmission capacity
limitations and reliability considerations and subject to our obligation to
offer to sell our electric energy in the New York power pool market for delivery
of electric energy on the following day during the term of the capacity purchase
agreement with NYSEG in accordance with the rules of the New York power pool.
The New York power pool is interconnected with the higher cost neighboring
regions, the New England power pool and the Pennsylvania-New Jersey-Maryland
power pool. The projected low and stable production costs of our electric energy
should provide us with an attractive competitive position in a dynamic and
increasingly volatile environment.
We entered into a Capacity, Energy and Ancillary Services Agreement, dated
as of April 9, 1999, with MEGA. Under this agreement, we gave MEGA exclusive
rights to market our electricity generating stations' available electric energy,
installed capacity and ancillary services through direct pool transactions with
the New York power pool, indirect pool transactions as a satellite New York
power pool member through NYSEG, bilateral transactions and other physical and
financial transactions. MEGA will have full authority to manage marketing,
trading and hedging activities with respect to the available electric energy,
installed capacity and ancillary services of our electricity generating
stations, except to the extent that MEGA's
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authority is limited by risk policies and procedures specified in the agreement.
The risk policies and procedures stipulate the commodities MEGA is authorized to
trade, the volume limits of MEGA's authority, limits on the length of contracts
MEGA is authorized to enter into and stop-loss and aggregate exposure limits. We
may change the risk policies and procedures at any time. The risk policies and
procedures are administered by a committee made up of two representatives of
each of us and MEGA.
The agreement with MEGA provides that MEGA will remit to us the sum of all
revenues received minus MEGA's costs in connection with sales of our electricity
generating stations' available electric energy, installed capacity and ancillary
services, provided these costs are incurred in accordance with practices
generally followed by the electric utility industry. We will pay MEGA $88,500
per month in advance for services provided under the agreement. In addition, we
will compensate MEGA for any transaction extending one year beyond the term of
the agreement as negotiated on a case by case basis up to a maximum of 5% of the
gross margin of the transaction. MEGA's minimum compensation for all of the
transactions extending one year beyond the term of the agreement in the
aggregate is $0.10/MWh, provided that the minimum compensation cannot exceed the
lesser of (a) $2,500,000 or (b) $125,000 multiplied by the total number of
months the agreement remains in effect, provided the agreement remains in effect
for at least 12 months. MEGA also is obligated to provide space and training for
two of our employees in MEGA's office. The financial obligations of MEGA under
the agreement are guaranteed by its parent company, Gener S.A.
The initial term of the agreement with MEGA ends on March 31, 2001.
Beginning August 1, 1999, we may terminate the agreement upon 90 days written
notice to MEGA and, beginning August 1, 2000, MEGA may terminate the agreement
upon 120 days written notice to us. After the initial term, the agreement will
be extended automatically each year until terminated in accordance with these
notice requirements.
We decided to arrange for marketing of electricity in the near term through
our agreement with MEGA rather than to create our own marketing infrastructure.
As our personnel gain expertise in this process or as we enter into longer term
bilateral markets for electric energy, this function may be managed increasingly
by our personnel. The development of our business and the business of other
affiliates of The AES Corporation will determine whether or not we will
eventually market electricity without the assistance of MEGA or other third
parties. We will develop an independent marketing infrastructure, either alone
or with other affiliates of The AES Corporation that may in the future engage in
market sales of wholesale electricity, if the level of activity justifies the
necessary investment and we are unable to obtain satisfactory marketing services
from third parties at a reasonable price.
Energy Revenues. We plan to sell directly into the spot market and will
focus on operating our electricity generating stations at high volume on a
cost-effective basis. It is possible that on occasion we will enter into
bilateral sales contracts for our electricity generating stations' electric
energy in the future.
Our electricity generating stations' revenues may increase over time if we
are able to gain access to export markets. Historically, NYSEG has successfully
exported to the Pennsylvania-New Jersey-Maryland power pool at a premium over
western New York prices. During the term of the capacity purchase agreement with
NYSEG, the rules of the New York power pool will require us to offer to sell our
electric energy in the New York power pool market for the delivery of electric
energy on the following day. We will be permitted to sell electric energy into
other pools only when the electricity is not needed in the New York power pool.
Installed Capacity Revenues. The long-term value of installed capacity is
based on the long run marginal costs of new entrants net of the potential energy
revenues earned by these new entrants. However, over the short term, installed
capacity value is based on the minimal fixed costs required to keep marginal
plant in service to meet system reliability. London Economics used this approach
in their analysis of the New York installed capacity market. Their analysis
shows that a capacity payment is necessary to maintain the financial viability
of sufficient capacity to meet system reserve margins. They estimate the payment
to maintain the availability of marginal producers to be approximately $27 per
KW-year in the short term, moving to $59 per KW-year over the long term. See
"APPENDIX B -- INDEPENDENT MARKET CONSULTANT'S REPORT."
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For reliability reasons, the New York power pool will require that
electricity generators that sell installed capacity into that pool must make
their electric energy available in the event of a system emergency. This
prevents generators from entering into firm contracts to sell electric energy
into one pool and installed capacity into another. Thus, we must make our choice
of market for installed capacity sales in conjunction with expected electric
energy sales. We will be monitoring installed capacity and electric energy
prices in the New York power pool and surrounding markets in the normal course
of conducting business. Depending on the evolution of installed capacity and
electric energy pricing over the next several years, following expiration of the
capacity purchase agreement with NYSEG, we may choose to:
- Lock in pricing by signing a long-term follow-on agreement for installed
capacity with NYSEG or another load serving entity in the New York power
pool or a surrounding pool.
- Hedge installed capacity prices by negotiating collars with NYSEG or
another load serving entity in the New York power pool or a surrounding
pool. A collar is an agreement with a counterparty that would permit us
to put installed capacity to the counterparty at an agreed price and that
would permit the counterparty to call our installed capacity at an agreed
price.
- Arrange some short-term installed capacity sales in the New York power
pool or a surrounding pool.
Interim Agreement
We entered into a Scheduling and Settlement Agreement with NYSEG which
provides for the sale of electric energy by us into the New York power pool
during the period prior to full implementation of the New York independent
system operator system. Under this agreement, NYSEG acts as our agent and
arranges for the sale and purchase of our electric energy or installed capacity
in the New York power pool. We paid NYSEG a one-time fee of $15,000 for
providing billing and energy control services during the term of this agreement.
We are responsible for the performance of our electricity generating stations.
If NYSEG is required to pay a performance penalty by the New York power pool, we
will cover the cost. If NYSEG receives a performance bonus, NYSEG will pass the
bonus on to us. This agreement was terminated due to our being able to schedule
and settle energy sales directly with the New York independent system operator
system.
Fuel Supply Strategy
We believe we have significant competitive advantages in relation to our
coal supply that will help us maintain low operating costs relative to our
competitors. Our electricity generating stations are located in close proximity
to important coal producers. In addition, both the Kintigh Generating Station
and the Milliken Generating Station are equipped with flue gas desulfurization
systems which allow the plant to burn less expensive medium- and high-sulfur
coal while staying within SO(2) emission regulation requirements. We and The AES
Corporation's facilities in the adjacent New England power pool and
Pennsylvania-New Jersey-Maryland power pool may have opportunities to pool our
buying power when negotiating prices and terms with coal suppliers. We are
projecting total coal usage of approximately 3.5 million tons per year.
Coal mines in the Pittsburgh Seam coal formation near our electricity
generating stations include some of the lowest cost coal supply sources
producing at volume. Although more expensive low-sulfur coals are available for
units without flue gas desulfurization systems, the high sulfur content of the
coals from the Pittsburgh Seam have historically made coal-fired generating
stations equipped with flue gas desulfurization systems the primary market for
Pittsburgh Seam producers. Since both the Kintigh Generating Station and the
Milliken Generating Station have installed flue gas desulfurization systems and
are capable of burning higher sulfur coals, we expect to maintain a fuel cost
advantage over competitors without flue gas desulfurization systems. John T.
Boyd Company, Independent Coal Market Consultant, has prepared a Pittsburgh Seam
Market Study. The Pittsburgh Seam Market Study evaluates the regional market for
coal, including supply sources, availability, demand and the impacts of
environmental regulations and is set forth in Appendix C hereto.
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Approximately 100% of the Kintigh Generating Station's and approximately
70% of the Milliken Generating Station's coal requirements initially will be
supplied under a contract with Consolidation Coal Company ("Consol"), under
which Consol will provide coal at least through 2002. In the year 2000, the
average price at which Consol will provide us coal is estimated by us to be
$22.57 per ton. Thereafter, we and Consol will periodically attempt to negotiate
the price of the separate lots of coal delivered under the contract. See "-- THE
ACQUISITION OF OUR ELECTRICITY GENERATING STATIONS -- ACQUISITION-RELATED
CONTRACTS -- COAL SALES AGREEMENT." Additionally, the Greenidge Generating
Station and the Goudey Generating Station have or are in the process of
negotiating short-term, fixed-price coal supply agreements expiring at the end
of 2000 and thereafter we expect that the Greenidge Generating Station and the
Goudey Generating Station will rely on spot market purchases of medium-sulfur
coal. It is possible that our electric energy revenues may not keep pace with
our coal costs if market prices for purchases of fuel escalate more rapidly than
market prices for sales of electric energy and energy-related products. See
"RISK FACTORS -- OUR FINANCIAL PROJECTIONS ASSUME THAT THE REAL PRICE OF COAL
WILL CONTINUE TO DROP IN THE FUTURE; AN INCREASE IN THE REAL PRICE OF COAL WILL
NEGATIVELY AFFECT OUR OPERATING RESULTS."
Each of our electricity generating stations typically receives coal through
conventional rail delivery. The Kintigh Generating Station is served by Somerset
Railroad, a single track railroad owned by a wholly-owned subsidiary of The AES
Corporation that delivers coal from a rail junction located in Lockport, New
York. The rail cars of Somerset Railroad are used to transport coal to the
Milliken Generating Station over tracks owned by another railroad. In addition,
the Milliken Generating Station can receive coal delivery via truck and barge.
Operations and Maintenance Plan
Consistent with the philosophy of The AES Corporation regarding other
affiliates and subsidiaries, we will be a decentralized organization with few
organizational layers. To the extent permitted by the agreements relating to the
lease of the Kintigh Generating Station and the Milliken Generating Station and
by prudent utility practice, we entered into an operations and maintenance
contract for each electricity generating station with a different wholly owned
subsidiary. The purpose of this arrangement is to create an organizational
structure that reflects the decentralized philosophy of The AES Corporation.
Decision making will, as much as possible, be vested at the individual plant
level, as will accountability for meeting financial, plant performance and other
objectives. In the experience of The AES Corporation, this approach increases
the motivation of employees to maximize revenues, to minimize overall facility
production costs and to manage risks effectively.
We implemented a life extension program at our electricity generating
stations. Stone & Webster, as Independent Engineer, prepared an independent life
extension study to compare against our life extension program. The two budgets
were within approximately 10% of each other for the 38 years of projections.
Stone & Webster therefore concluded that the life extension program prepared by
us is adequate and reasonable.
Operations and maintenance of the electricity generating stations as well
as fuel procurement and environmental compliance will be managed internally.
In general, the specific market for each unit's output will drive our view
on operations and maintenance expense at the individual units. Subject to the
requirements of the agreements relating to the lease of the Kintigh Generating
Station and the Milliken Generating Station, plant managers and team leaders at
each plant will respond to market signals in determining appropriate levels of
plant spending in order to maintain and enhance plant profitability.
At the Kintigh Generating Station, the installation of a $31 million
selective catalytic reduction system, with Babcock & Wilcox as the turnkey
contractor and Hitachi as the supplier of the catalyst, was completed in June
1999. See "-- THE KINTIGH ELECTRICITY GENERATING STATION -- ENVIRONMENTAL." In
addition, we completed a turbine overhaul at the Kintigh Generating Station in
June 1999.
At the Milliken Generating Station, we are currently planning major
maintenance outages for Unit 2 in 2002 and Unit 1 in 2003. As at the Kintigh
Generating Station, the efforts are designed to protect and improve
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the station's reliability and efficiency. We may also install a selective
catalytic reduction system at the Milliken Generating Station to comply with the
likely more stringent Phase III NO(X) regulations, which will take effect in May
2003. We will also consider lower cost alternative compliance strategies such as
the addition of a selective non-catalytic reduction system. See
"REGULATION -- ENVIRONMENTAL REGULATORY MATTERS."
At the Goudey Generating Station and the Greenidge Generating Station, we
believe that our planned maintenance budgets are sufficient to extend the
current availability performance of the units. We may repower or pursue other
development options at these electricity generating stations.
Environmental Compliance
Our electricity generating stations are designed and operated in
substantial compliance with currently applicable environmental laws and
regulations of the United States Environmental Protection Agency and the New
York State Department of Environmental Protection. All of the applicable
environmental permits for our electricity generating stations have been
transferred to us or to affiliates of ours that own and operate the electricity
generating stations. See "REGULATION -- ENVIRONMENTAL REGULATORY MATTERS."
THE ELECTRICITY GENERATING STATIONS
We believe that our two principal coal-fired electricity generating
stations, the Kintigh Generating Station and the Milliken Generating Station,
are operated currently at or near operating costs at which they can be run
economically even at times of minimum demand for electric energy, and we expect
them to be fully directed to generate when available in the soon to be
deregulated and competitive New York power market. As a means of further
enhancing the competitive position of our electricity generating stations in the
New York power market, we expect to use expertise gained by The AES Corporation
as a major operator of coal-fired facilities on a worldwide basis. We also
intend to make appropriate investments of capital to maintain our electricity
generating stations and to extend their service lives. The Kintigh, Milliken,
Goudey and Greenidge Generating Stations have an aggregate net generating
capacity of 1,268MW. They are low cost facilities (weighted average (based on
capacity) 1998 production costs were $17.03/MW) with high availability (weighted
average (based on capacity) 1998 equivalent availability was 92.1%).
THE KINTIGH GENERATING STATION
Overview
The Kintigh Generating Station is the largest and newest of our electricity
generating stations and is located northeast of Niagara Falls, alongside the
southern shore of Lake Ontario near Barker, New York. There is a single
operating unit at the Kintigh Generating Station, which began generating
electricity in 1984. The maximum net generating capacity of the Kintigh
Generating Station is 675MW. The Kintigh Generating Station is comprised of a
steam turbine generator manufactured by General Electric and is supplied steam
from a Babcock & Wilcox coal-fired steam generator. The Kintigh Generating
Station presently occupies a site of approximately 1,722 acres, of which
approximately 1,062 acres are used for plant operations.
The Kintigh Generating Station currently operates at operating costs at
which it can be run economically even at times of minimum demand for electric
energy. The Kintigh Generating Station also is capable of burning low cost
medium- and high-sulfur coal as a result of being equipped with a flue gas
desulfurization system. When the Kintigh Generating Station is not being
dispatched at maximum load, its periodic load can be varied to both meet system
load demand and provide transmission system support and the plant can provide
both operating reserves that are available immediately or on ten minutes notice.
In 1998, the Kintigh Generating Station produced 4,920GWh of net generation,
accounting for over half of NYSEG's total annual New York-based production.
Major plant systems are oversized and the plant's design contains
substantial operating redundancy allowing certain equipment to be bypassed in
the event of failure. Additionally, the Kintigh Generating Station benefited
from NYSEG's historic policy to emphasize maintenance and invest in new
equipment. Finally, the
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Kintigh Generating Station maintains a good inventory of spare parts, including
large components such as spare motors for major pumps and fans, and spare rotors
for its large axial fans.
The Kintigh Generating Station is one of the two newest utility coal-fired
electricity generating stations in the northeast and the newest in the New York
power pool. The Kintigh Generating Station is the most significant generating
facility among our electricity generating stations, accounting for approximately
55.5% of the 1998 aggregate net generation of our electricity generating
stations.
The turbine generator at the Kintigh Generating Station developed an
unusual vibration following a maintenance outage conducted by NYSEG in September
1998, although the unit was operating at full load at the time the Kintigh
Generating Station was acquired from NYSEG. We performed maintenance during the
previously scheduled major turbine overhaul in May and June 1999.
We and NYSEG entered into an agreement pursuant to which NYSEG agreed to
bear the costs of repair and to reimburse us for a defined measure of lost
revenues resulting from any lost production caused by the vibration condition
resulting from anything other than
(a) repair and maintenance to the turbine generator consistent with a
ten-year wear and tear factor (from baseline data contained in a
mutually acceptable report), or
(b) normal "wear and tear" of the turbine generator.
We have made demand on NYSEG, by letter dated October 5, 1999, for payment of
approximately $852,000 in costs incurred by us to satisfactorily address the
vibration condition and which costs are not attributable to either factor
enumerated in the preceding sentence. NYSEG has asserted, by letter dated
October 13, 1999, that it is not responsible for such costs because
(a) NYSEG maintains that the actions taken by us that generated such costs
were not necessary to address the vibration condition,
(b) NYSEG maintains the activities that generated these costs were either
(1) part of the repair and maintenance to the turbine generator
consistent with a ten-year wear and tear factor, or (2) repair and
maintenance necessary to address normal wear and tear,
(c) NYSEG maintains that the turbine outage extension component of the
costs incurred by us resulted from activities undertaken by us without
NYSEG's consent and we are therefore outside the scope of the
above-referenced agreement, and
(d) we, in NYSEG's view, breached the provisions of the above-referenced
agreement and therefore we should not be entitled to assert rights
under such agreement.
We are currently considering our options for the recovery of these costs. One of
our options is to pursue the dispute resolution procedure incorporated into this
agreement from the Asset Purchase Agreement, which first provides for
consultation by senior people of The AES Corporation and NYSEG and, if that
fails, for binding arbitration.
Performance
Because of its design and experienced workforce, the Kintigh Generating
Station has been a reliable generator of electricity. During the eleven years
ended in 1998 (excluding 1990 when major maintenance was performed), the
station's average equivalent availability was 95.7%. An aggressive monitoring
program has resulted in low lifetime outages, as potential problems are detected
well before they pose a serious threat to operations. In 1996, the station
achieved 100% equivalent availability and ran 9,191 consecutive hours through
the 13 months ending January 17, 1997. Since 1989, the station has experienced
only 59 days of forced outage. Nearly all of the causes of these forced outages
were detected in advance and were addressed during low revenue weekend periods.
The Kintigh Generating Station is one of the lowest cost coal-fired
electricity producers in the northeastern United States. In data compiled by
London Economics, the Kintigh Generating Station's
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weighted average total production costs during the five-year period from
1993-1997 were the seventh lowest out of 48 utility coal plants in the
northeast. During the five-year period ended in 1998, the Kintigh Generating
Station's annual production costs have ranged between $15.73 per MWh and $17.02
per MWh and have averaged $16.40 per MWh. We believe that the Kintigh Generating
Station currently is among the most efficient plants (as measured by heat rate)
in the country equipped with a flue gas desulfurization system. In the New York
power pool, only the Milliken Generating Station and the Kintigh Generating
Station have flue gas desulfurization systems. As such, the Kintigh Generating
Station is expected to improve its ranking over the next five years as
facilities without flue gas desulfurization systems incur required compliance
costs for new SO(2) emissions regulation.
A summary of the Kintigh Generating Station's recent performance is
included below:
KINTIGH PERFORMANCE SUMMARY
EQUIVALENT
NET AVAILABILITY NET CAPACITY FORCED NET PRODUCTION
GENERATION FACTOR FACTOR OUTAGE RATE HEAT RATE COSTS
YEAR (GWH) (%) (%) (%) (BTU/KWH) ($/MWH)(1)
- ---- ---------- ------------ ------------ ----------- --------- ----------
1998........................... 4,920 94.8 83.3 3.5 9,266 16.55
1997........................... 4,479 93.3 75.8 2.1 9,464 17.02
1996........................... 4,456 100.0 75.2 0.0 9,426 16.19
1995........................... 4,573 92.2 77.3 4.1 9,312 16.52
1994........................... 5,109 98.5 86.4 1.4 9,262 15.73
1993........................... 5,131 95.6 86.1 0.7 9,254 16.51
1992........................... 5,386 96.5 89.0 0.4 9,222 17.21
- ---------------
(1) The components of production costs are: operations, maintenance, fuel and
flue gas desulfurization system plant expenses.
Capital Expenditures
NYSEG spent over $20 million at the Kintigh Generating Station over the
last ten years on plant betterment and environmental improvement projects. These
improvements include a mix zone duct relining of its flue gas desulfurization
system, a landfill liner extension, a fly ash silo addition and a plant
monitoring computer network.
During May and June of 1999, Babcock & Wilcox installed a selective
catalytic reduction system to reduce NO(x) emissions at a turnkey cost of $31
million. While the facility was shut down from May 1999 through June 1999 for
the installation of the selective catalytic reduction system, we performed $11
million of major improvements, including an overhaul of the turbine generator
and replacement of the leading boiler elements of the reheat and superheat
sections.
Employees
As of December 1999, we employed 144 people at the Kintigh Generating
Station, of which 40 were salaried and 104 were paid hourly. All hourly
employees are represented by The International Brotherhood of Electrical Workers
("IBEW"). Key personnel have worked at the plant since its startup in 1983 and
many of those individuals have held multiple positions during their tenure. The
Kintigh Generating Station employees have an average of 15 years of service. In
order to maintain continuity in the Kintigh Generating Station's operations, we
retained a substantial majority of the existing NYSEG workforce at the Kintigh
Generating Station.
Environmental
The Kintigh Generating Station was the first unit in New York to be fitted
with flue gas desulfurization technology. The Kintigh Generating Station's flue
gas desulfurization system presently operates at less than
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85% SO(2) reduction. The plant has the potential to consume significantly fewer
SO(2) allowances with minimal additional costs by operating the flue gas
desulfurization system at greater than 90% reduction.
The Kintigh Generating Station's selective catalytic reduction system began
operation in June 1999. The selective catalytic reduction system will generate
excess NO(X) allowances that we believe we will be able to sell or to transfer
to our other electricity generating stations to allow all of our electricity
generating stations to operate at planned capacity factors under more
restrictive regulations governing NO(X) emissions in the May-September ozone
season that took effect in May 1999.
The selective catalytic reduction system will work in conjunction with
existing NO(X) control equipment and procedures at the Kintigh Generating
Station. Originally, the plant was designed with low NO(X) burners. In response
to 1995 requirements for ozone season compliance, various methods to improve the
combustion NO(X) control capability beyond the original burner design were
implemented. We anticipate that the combination of these NO(X) mitigation
measures will result in a NO(X) rate of 0.04 lbs. per MMBtu, which is
significantly below all current permit levels. In addition, this low emission
rate will play an important role in bringing the overall average NO(X) emissions
rate from the former NYSEG plants below the rate required under the NO(X)
averaging plan approved by the New York Department of Environmental
Conservation.
The Kintigh Generating Station's additional environmental features include
electrostatic precipitators, a completely lined coal handling facility and a
continuous emissions monitoring system.
Transmission
The Kintigh Generating Station is interconnected to the New York power pool
bulk transmission system via two 345KV transmission lines.
THE MILLIKEN GENERATING STATION
Overview
The Milliken Generating Station is located alongside the east shore of
Cayuga Lake, near the town of Lansing, New York. There are two operating units
at the Milliken Generating Station, Unit 1 and Unit 2, which began generating
electricity in 1955 and 1958, respectively. The maximum net generating capacity
of both units is 306MW in aggregate.
Milliken Unit 1 currently has a net generating capacity of 150MW. It is
comprised of a steam turbine generator manufactured by Westinghouse Electric. It
is supplied steam from a Combustion Engineering coal-fired steam generator with
reheat steam capability. Unit 2 currently has a net generating capacity of
156MW. It utilizes a steam turbine generator manufactured by General Electric
and is supplied steam from the same type of boiler as Unit 1.
The Milliken Generating Station historically has been operated at operating
costs at which it can be run economically even at times of minimum demand for
electric energy. The Milliken Generating Station also is capable of burning low
cost medium- and high-sulfur coal as a result of being equipped with a flue gas
desulfurization system. When the Milliken Generating Station is not being
dispatched at maximum load, its periodic load can be varied to meet both system
load demand and provide transmission system support, and the plant can provide
both operating reserves that are available immediately or on ten minutes notice.
The plant is also equipped with Automatic Generation Controls enabling it to
provide regulation, frequency support, and, due to the existence of backup
diesel generators, the capability to start operating from a shutdown condition
without external assistance. In 1998, the Milliken Generating Station produced
2,223GWh of net generation, accounting for approximately one-fourth of NYSEG's
total annual New York-based production.
Performance
The Milliken Generating Station's two units have a history of reliable
performance. Except for 1993 and 1995 when substantial capital improvements were
undertaken, Unit 1 has an eleven-year (period ending 1998)
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average equivalent availability factor of 92.4%. During this period, excluding
1988 and 1994 when major capital projects were performed, Unit 2 had an average
equivalent availability factor of 92.0%.
In data compiled by London Economics for the five-year period from 1993 to
1997, Milliken's total production costs were the tenth lowest overall out of 48
utility coal plants in the northeast and were the third lowest in the New York
power pool. For the five-year period ended in 1998, the Milliken Generating
Station's annual production costs have ranged between $16.82 per MWh and $17.73
per MWh and have averaged $17.31 per MWh.
A summary of the Milliken Generating Station units' recent performance is
included below:
MILLIKEN GENERATING STATION PERFORMANCE SUMMARY
UNIT 1
- --------------------------------------------------------------------------------------
EQUIVALENT
NET AVAILABILITY NET CAPACITY FORCED NET PRODUCTION
GENERATION FACTOR FACTOR OUTAGE RATE HEAT RATE COSTS
YEAR (GWH) (%) (%) (%) (BTU/KWH) ($/MWH)(1)
- ---- ---------- ------------ ------------ ----------- --------- ----------
1998 1,205 91.9 84.6 0.0 9,805 16.82
1997 1,010 91.1 77.3 1.4 9,707 17.24
1996 931 90.8 71.7 2.8 9,706 17.35
1995 927 80.8 69.3 0.9 9,709 17.73
1994 1,187 95.5 86.3 1.5 9,318 17.40
1993 769 61.3 55.9 3.5 9,381 19.32(2)
1992 1,188 93.8 86.2 0.0 9,429 16.20
UNIT 2
- --------------------------------------------------------------------------------------
EQUIVALENT
NET AVAILABILITY NET CAPACITY FORCED NET PRODUCTION
GENERATION FACTOR FACTOR OUTAGE RATE HEAT RATE COSTS
YEAR (GWH) (%) (%) (%) (BTU/KWH) ($/MWH)(1)
- ---- ---------- ------------ ------------ ----------- --------- ----------
1998 1,194 88.0 83.5 0.9 9,716 16.82
1997 1,068 91.2 78.6 0.9 9,636 17.24
1996 994 92.8 75.4 1.8 9,779 17.35
1995 1,060 90.2 78.2 6.9 9,644 17.73
1994 600 49.3 42.6 1.6 9,470 17.40
1993 1,144 93.4 81.1 0.5 9,485 19.32(2)
1992 1,153 92.6 81.5 0.8 9,381 16.20
- ---------------
(1) Production costs are average costs for both Unit 1 and Unit 2. The
components of production costs are: operations, maintenance, fuel and flue
gas desulfurization system.
(2) The higher cost of production in 1993 ($19.32 per MWh) was the result of
higher maintenance charges due to major plant overhauls which occurred
during the year.
Capital Expenditures
At the Milliken Generating Station, NYSEG spent approximately $100 million
over the last ten years on plant betterment and approximately $100 million on
environmental improvement projects. In 1995, the Milliken Generating Station was
retrofitted with an advanced flue gas desulfurization system. Other major
expenditures include a low NO(X) burner system, improvements to various systems
including fuel delivery, demineralization, coal pile leachate and treatment, an
all new electrical system, retubing of the condenser, precipitator modernization
and a new control system.
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Employees
As of December 1999, we employed 92 people at the Milliken Generating
Station, of which 21 were salaried and 71 were paid hourly. All hourly employees
are represented by the IBEW. Milliken Generating Station employees have an
average of 17 years of service. In order to maintain continuity in the Milliken
Generating Station's operations, we retained a substantial majority of the
existing NYSEG workforce at the Milliken Generating Station.
Environmental
The Milliken Generating Station benefited from NYSEG's selection to
participate in the United States Department of Energy ("DOE") Clean Coal
Technology Round IV demonstration program, which was designed to develop
advanced, more efficient and environmentally-responsive coal combustion
technologies. As a result of this program, the Milliken Generating Station was
retrofitted in 1995 with an advanced flue gas desulfurization system. For NO(X)
reduction, a Low NO(X) Concentric Firing System was installed to achieve up to a
45% reduction in NO(X) emissions.
In addition to the Low NO(X) Concentric Firing System project, a 2MW
selective catalytic reduction reactor and a test scale ABB Air Preheater heat
pipe were installed at the Milliken Generating Station on Unit 2 in 1994. During
the test period, the Milliken Generating Station burned medium- and high-sulfur
coal with sulfur levels ranging from 1.5% to 2.6%, with a reduction of SO(2)
emissions by 97-98%. The flue gas desulfurization system also produces
wallboard-quality gypsum.
NYSEG instituted water treatment programs to protect lakes and groundwater
supplies nearby the Milliken Generating Station. NYSEG installed or upgraded
facilities to collect and treat water from yard, roof and in-plant drains,
maintenance cleaning washes and coal-pile runoff.
Exceedences of state groundwater standards at the Milliken Generating
Station were reported in the vicinity of the on-site coal pile, coal pile runoff
pond and the ash disposal site. In 1997, a new coal pile liner was installed.
Based on data provided by NYSEG, TRC Environmental Corporation, our
environmental consultant, estimated monitoring and investigation costs of
approximately $270,000 for the coal pile runoff pond area and approximately
$163,000 for the ash disposal area. We have included these costs in our
financial projections.
NYSEG has been actively selling fly ash from the Milliken Generating
Station since 1983. Its new coal pulverization system provides flexibility in
coal fineness adjustment for firing under low NO(X) conditions. Coal pulverized
and burned in this manner results in fly ash that can be sold to the New York
Department of Transportation.
Transmission
The Milliken Generating Station is centrally located in the New York State
electric system, connected through three 115KV lines and three 34.5KV lines to
the New York power pool bulk transmission system. Additionally, the Milliken
Generating Station is located in the only area in NYSEG's service territory that
NYSEG has identified as requiring voltage support. We entered into an agreement
with NYSEG which permits NYSEG to require the dispatch of the Milliken
Generating Station under some circumstances for up to seven years. See "-- THE
ACQUISITION OF OUR ELECTRICITY GENERATING STATIONS -- ACQUISITION-RELATED
CONTRACTS."
OTHER FACILITIES
Goudey Generating Station
The Goudey Generating Station is located alongside the Susquehanna River
near Johnson City, New York, and began generating electricity in the early
1900's. Units 1 through 6 have been retired and physically removed. The Goudey
Generating Station presently consists of two pulverized coal units, Unit 7 and
Unit 8,
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with a combined maximum net generating capacity of 126MW. In 1998, the Goudey
Generating Station's net generation was 778GWh.
The Goudey Generating Station is capable of providing both operating
reserves that are available immediately or on ten minutes notice. The station is
equipped with Automatic Generation Controls, which connect it to the New York
independent system operator power control center and enable it to provide
regulation, frequency support, and when directed by the independent system
operator, voltage support.
Goudey Unit 7 is a non-reheat unit which came online in 1943 and currently
has a net generating capacity of 43MW. It is comprised of a steam turbine
generating unit manufactured by Westinghouse Electric, which is supplied steam
by two Foster-Wheeler coal-fired steam generators.
In 1994 and 1995, Unit 7 was modified to operate as a synchronous
condenser, which enables the unit to provide system regulation, a revenue
producing ancillary service. Since then, it has been reconverted to a generator
and is presently operated intermittently to meet load demand.
Goudey Unit 8 is a reheat unit which came online in 1951 and currently has
a net generating capacity of 83MW. It is comprised of a steam turbine generating
unit manufactured by Westinghouse Electric, which is supplied steam from a
Combustion Engineering coal-fired steam generator. Unit 8 operates to meet
system load demands and to provide transmission support. Steam from the facility
is sold to Lockheed-Martin, a national defense contractor having a facility
located adjacent to the site. Steam sales in 1998 were approximately $250,000.
Goudey Unit 7 and Unit 8 had average equivalent availability factors of
approximately 92.6% and 91.4%, respectively, in the eleven years ended in 1998,
and production costs were below $20 per MWh in the most recent four years ended
in 1998. A summary of the Goudey Generating Station's recent performance is
included below:
GOUDEY PERFORMANCE SUMMARY
UNIT 7
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EQUIVALENT
NET AVAILABILITY NET CAPACITY FORCED NET PRODUCTION
GENERATION FACTOR FACTOR OUTAGE RATE HEAT RATE COSTS
YEAR (GWH) (%) (%) (%) (BTU/KWH) ($/MWH)(1)
- ---- ---------- ------------ ------------ ----------- --------- ----------
1998(2) 197 99.7 52.0 0.1 12,659 18.88
1997 168 96.9 45.0 0.1 12,959 19.22
1996 54 99.5 14.6 0.0 13,205 19.53
1995(3) (2) 100.0 0.0 0.0 0.0 19.79
1994(3) 54 99.4 14.4 1.5 12,868 20.13
1993 215 94.5 54.9 1.7 12,655 21.58
1992 186 73.9 47.2 0.3 12,723 23.47
UNIT 8
- --------------------------------------------------------------------------------------
EQUIVALENT
NET AVAILABILITY NET CAPACITY FORCED NET PRODUCTION
GENERATION FACTOR FACTOR OUTAGE RATE HEAT RATE COSTS
YEAR (GWH) (%) (%) (%) (BTU/KWH) ($/MWH)(1)
- ---- ---------- ------------ ------------ ----------- --------- ----------
1998 581 94.3 79.0 0.1 10,281 18.88
1997 574 95.5 79.7 0.4 10,298 19.22
1996 529 92.2 75.2 0.8 10,309 19.53
1995 551 92.0 74.8 1.0 10,195 19.79
1994 571 97.6 77.8 1.5 10,127 20.13
1993 545 93.3 73.4 0.2 10,102 21.58
1992 587 93.8 79.3 0.0 10,073 23.47
- ---------------
(1) Production costs are average costs for both Unit 7 and Unit 8. The
components of production costs are: operations, maintenance and fuel.
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(2) NYSEG shut down Unit 7 for 2,139 hours between February and May 1998 due to
market conditions and to assure compliance with NO(X) emission reduction
requirements. If this had been treated as a forced outage, equivalent
availability would have been 51.0% and forced outage rate would have been
25.0%.
(3) Unit 7 was used as a synchronous condenser only and generated no electric
energy from the spring of 1994 through the fall of 1995.
Capital Expenditures
NYSEG spent over $30 million at the Goudey Generating Station over the last
ten years on plant betterment and environmental improvement projects. These
expenditures include chimney rehabilitation and repair and redesign of various
boiler components at Unit 8. Expenditures at Unit 7 include steam pipe
replacement, condenser retubing, improvement to systems for coal pile leachate
collection and treatment, and coal and bottom ash handling.
Employees
As of December 1999, we employed a workforce of 39 at the Goudey Generating
Station, of which 5 were salaried and 34 were paid hourly. All hourly employees
are represented by the IBEW. Goudey employees have an average of 19 years of
service. We retained a substantial majority of the existing NYSEG workforce at
the Goudey Generating Station.
Environmental
During 1998, NYSEG shut down Goudey Unit 7 for 2,139 hours between February
and May due to market conditions and to assure compliance with NO(x) emission
reduction requirements. We believe that the installation of a selective
catalytic reduction system at the Kintigh Generating Station will generate
sufficient NO(x) allowances and sufficient NO(x) emissions rate reductions to
permit us to run the Goudey Generating Station at all times.
In 1988, NYSEG began a water treatment and control program in response to
tightened permit limitations under New York State environmental laws. NYSEG
installed or upgraded facilities to collect and treat water from yard, roof and
in-plant drains, maintenance cleaning washes and coal-pile runoff. A new coal
pile liner was installed in 1989 which has decreased leachate derived
concentrations of several metals in downgradient wells. While continued
groundwater monitoring will be required in the coal pile area, our environmental
consultant, TRC Environmental Corporation, concluded that no additional
investigation or mitigation will be needed.
In addition to the water treatment program, NO(x) software was installed at
Goudey Unit 8 to predict the NO(x) emissions and maintain plant heat rates under
various operating conditions.
Fly ash, bottom ash and pulverizer mill rejects from the Goudey Generating
Station were in the past disposed at the Weber ash disposal site in the Town of
Fenton, New York. We expect that the Weber ash disposal site will be required to
stop accepting ash in 2000 and will be closed in 2001 in accordance with a
consent order that AES Creative Resources entered into in October 1999 with the
New York State Department of Environmental Conservation. We plan to evaluate
other options for disposing of ash in the future, including disposal at other
landfills in the area. Our subsidiary, AEE2, L.L.C., has agreed to contribute
two-thirds of the closure costs for the Weber ash disposal site (approximately
$2 million) based on the amount of ash disposed at the site from AEE2, L.L.C.'s
facilities compared to the amount disposed from the facilities acquired by AES
Creative Resources, L.P., which is a subsidiary of The AES Corporation but not
of us.
Transmission
The Goudey Generating Station is interconnected to the New York power pool
bulk transmission system via six 115kV transmission lines and twelve 34.5kV
lines.
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Greenidge Generating Station
The Greenidge Generating Station is located on the west shore of Seneca
Lake adjacent to the village of Dresden, New York, and began generating
electricity in 1938. Units 1 and 2 have been retired and physically removed. The
Greenidge Generating Station presently consists of two coal-fired units, Unit 3
and Unit 4, with a combined maximum net generating capacity of 161MW. In 1998,
the Greenidge Generating Station produced 939GWh of net generation.
The Greenidge Generating Station is capable of providing both operating
reserves available immediately and on ten minutes notice. The station is
equipped with Automatic Generating Controls, which connect it to the New York
independent system operator power control center and enable it to provide
regulation, frequency support, and, when directed by the independent system
operator, voltage support.
Unit 3 utilizes two Babcock & Wilcox coal-fired steam generators, supplying
steam to a non-reheat steam turbine generator manufactured by General Electric
that came online in 1950 and currently has a net generating capacity of 56MW.
Unit 4 is a reheat steam turbine generator manufactured by General Electric
which came online in 1953 and currently has a net generating capacity of 105MW.
It is supplied steam from a single Combustion Engineering coal-fired steam
generator.
Performance
A summary of recent performance for the Greenidge Generating Station is
presented below:
GREENIDGE PERFORMANCE SUMMARY
UNIT 3
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EQUIVALENT
NET AVAILABILITY NET CAPACITY FORCED NET PRODUCTION
GENERATION FACTOR FACTOR OUTAGE RATE HEAT RATE COSTS
YEAR (GWH) (%) (%) (%) (BTU/KWH) ($/MWH)(1)
- ---- ---------- ------------ ------------ ----------- --------- ----------
1998(2).............. 161 72.8 34.0 0.0 13,078 17.99
1997(2).............. 0 NA NA NA NA NA
1996(2).............. 72 92.7 15.2 3.7 12,733 22.76
1995(2).............. 42 99.5 9.0 0.0 12,854 19.10
1994(2).............. 67 98.0 14.2 0.0 12,732 21.53
1993................. 226 73.1 47.0 22.6 12,565 21.66
1992................. 329 88.9 68.0 2.3 12,380 20.67
UNIT 4
- -----------------------------------------------------------------------------------------------------------
EQUIVALENT
NET AVAILABILITY NET CAPACITY FORCED NET PRODUCTION
GENERATION FACTOR FACTOR OUTAGE RATE HEAT RATE COSTS
YEAR (GWH) (%) (%) (%) (BTU/KWH) ($/MWH)(1)
- ---- ---------- ------------ ------------ ----------- --------- ----------
1998(3).............. 778 86.8 85.4 0.8 10,003 17.99
1997................. 679 92.0 73.7 1.2 9,939 19.55
1996(3).............. 514 76.4 56.3 0.0 9,986 22.76
1995................. 643 94.9 68.0 0.6 9,985 19.10
1994................. 658 86.7 69.5 2.5 9,961 21.53
1993................. 740 94.2 78.3 1.4 9,898 21.66
1992................. 783 91.4 82.5 1.0 9,957 20.67
- ---------------
(1) Production costs are average costs for both Unit 3 and Unit 4. The
components of production costs are: operations, maintenance and fuel.
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(2) Unit 3 was put on long-term cold standby in April 1994 due to market
conditions and used principally for voltage support rather than energy
generation during the remainder of 1994 and 1995. During the summer of 1996,
Unit 3 was shut down for a major boiler overhaul. In 1998, from January to
mid-April, NYSEG put Unit 3 on long-term cold standby due to market
conditions. Electric energy generation began again in mid-1998.
(3) Unit 4 underwent a major turbine overhaul in 1996. In 1998, from June
through the remainder of the year, Unit 4 burned a mix of coal and natural
gas (natural gas at 15% by heat input) for an average reduction in NO(x)
emissions of 50% from baseline levels. Because of Boiler 6's marginal
precipitators, which have since been upgraded, this NO(x) compliance
strategy negatively impacted the equivalent availability factors.
Capital Expenditures
In 1975, NYSEG installed electrostatic precipitators on each generator to
comply with the federal Clean Air Act standards. In the 1980s, NYSEG implemented
extensive capital projects including the installation of redesigned boiler
casings, replacement of high pressure turbine sections and a plant-wide digital
computer based control system.
NYSEG completed over 60 separate projects totaling in excess of $50
million. These projects have lowered production costs and improved the
efficiency of the plant. In addition to the control room expenditures, a gas
reburning system was implemented, turbines were upgraded, generators were
rewound, turbine water induction systems were installed, much of the asbestos
insulation was replaced, and boiler tubes were replaced as needed to insure life
extension. The Unit 4 condenser had its tubing replaced, a new demineralizer was
installed to purify waste water used to make steam, and workshops were
modernized. In March and April of 1999, NYSEG conducted a major boiler overhaul
for Unit 4. In this overhaul, the Boiler 6 precipitator was upgraded, which
included additional power, controls and sectionalization.
Employees
As of December 1999, we employed a workforce of 44 at the Greenidge
Generating Station, of which 7 were salaried and 37 were paid hourly. All hourly
employees are represented by the IBEW. Greenidge employees have an average of 20
years of service. We retained a substantial majority of the existing NYSEG
workforce at the Greenidge Generating Station.
Environmental
The advanced gas reburning system, which is a research and development
project at the Greenidge Generating Station, began in 1996 and is the first
full-scale demonstration of this technology. The goal of this research and
development project is to demonstrate a NO(x) reduction capability approaching
conventional selective catalytic reduction system process, but at a much lower
capital and operational cost. Various system configurations will be tested
throughout the three-year test program. In addition, the system can utilize
natural gas, up to 25% by heat input (25MW), to lower the level of SO(2)
emissions and provide fuel switching capability to permit maintenance of
pulverized coal equipment.
The Greenidge Generating Station is also permitted to burn a variety of
alternative fuels, including construction/demolition wood, clean wood, waste
woods, particle board, and sander fines. The system can burn almost 80 tons of
wood per shift, which would equate to about 10MW of capacity. This provides the
station with a lower SO(2) emissions rate, lower fuel costs, and 10MWh of
environmentally attractive power. The Greenidge Generating Station is also
permitted to burn waste oil. The facility has also successfully test burned
paper and plastic products, the use of which can reduce fuel costs by 10-15%.
Ash from the Greenidge Generating Station is disposed at the Lockwood ash
disposal site, which is located approximately one-half mile west of the
Greenidge Generating Station. We assumed responsibility for the Lockwood ash
disposal site in connection with the asset purchase agreement with NYSEG. Fly
ash from the Greenidge Generating Station is also occasionally disposed at the
Weber ash disposal site.
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In an area adjacent to the Lockwood ash disposal site, our environmental
consultant, TRC Environmental Corporation, reported that approximately 500 to
700 drums of abrasives were disposed in the early 1970s and covered with ash.
TRC Environmental Corporation projected most probable costs of approximately
$520,000 to conduct a site investigation and remove the drums. These costs have
been included in our financial projections. In addition, groundwater sampling in
this area and around the Lockwood ash site indicates that some monitoring wells
have parameters which exceed state regulatory limits. We included in our
financial projections $6 million in closure costs for the disposal site with
closure of a portion of the landfill scheduled for 2006 and closure of the
remaining acres projected for 2016. These costs also include annual groundwater
monitoring costs. We also included in our financial projections approximately $2
million for the share of closure and post-closure expenses that our subsidiary,
AEE2, L.L.C., has agreed to bear with respect to the closure of the Weber ash
disposal site.
Coal pile leachate indicator compounds have been detected in downgradient
wells at the Greenidge Generating Station at levels exceeding state regulatory
limits. This may indicate that the coal pile liner has been breached and
requires replacement. Our environmental consultant, TRC Environmental
Corporation, projects that replacement of the liner and continued groundwater
monitoring in the coal pile area may cost approximately $1.2 million. These
costs have been included in our financial projections.
Transmission
The Greenidge Generating Station is interconnected to the New York power
pool bulk transmission system via four 115kV transmission lines and three 34.5kV
lines.
THE ACQUISITION OF OUR ELECTRICITY GENERATING STATIONS
Description of Asset Purchase Agreement
The following description is a summary of the Asset Purchase Agreement with
NYSEG. For additional or more specific information, refer to the Asset Purchase
Agreement, a copy of which has been filed with the SEC as an exhibit to the
registration statement of which this prospectus is a part.
AES NY, L.L.C. entered into the Asset Purchase Agreement dated as of August
3, 1998, with NYSEG to purchase our electricity generating stations, the
Jennison Generating Station, the Hickling Generating Station, the stock of
Somerset Railroad and related assets for an aggregate purchase price of
$950,000,000. The Asset Purchase Agreement provided that the assets acquired
would be acquired "as is, where is" and, in particular, expressly provided that
NYSEG made no representations or warranties with respect to whether systems
included among the assets to be sold are Year 2000 compliant. See "DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- YEAR 2000
COMPLIANCE." AES NY, L.L.C. assigned to us the contract rights and obligations
relating to our electricity generating stations.
Assets. Under the Asset Purchase Agreement, AES NY, L.L.C. agreed to
acquire various assets to operate the six electricity generating stations,
including parcels of real property and all buildings, equipment, fixtures, fuel
inventories, assignable contracts, real property leases, environmental permits
and allowances to emit SO(2) and NO(x). AES NY, L.L.C. also acquired the issued
and outstanding stock of Somerset Railroad, together with certain books and
records of Somerset Railroad. AES NY, L.L.C. did not have the right to acquire
the electrical transmission or distribution facilities of NYSEG located on or at
the six electricity generating stations, gas facilities, communication
facilities, cash and cash equivalents, certificates of deposit, shares of stock
(other than stock of Somerset Railroad) and interests in joint ventures,
partnerships, limited liability companies and other entities, the rights of
NYSEG to the names "New York State Electric & Gas Corporation," "NYSEG," "NGE,"
"NGE Generation" and all emission reduction credits associated with the six
electricity generating stations.
Liabilities. Under the Asset Purchase Agreement, AES NY, L.L.C. agreed to
assume specified liabilities relating to the acquired assets, including
specified post-closing liabilities, employee liabilities and obligations, tax
liabilities and environmental liabilities. Those environmental liabilities
include liabilities related to or arising out of former, current or future
environmental laws, whether that liability is known or
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unknown, contingent or accrued other than environmental liability arising out of
the disposal, storage, transportation, treatment, release or recycling of
hazardous substances prior to May 14, 1999 at any off-site location, except the
Weber and Lockwood off-site ash disposal sites, for which AES NY, L.L.C. agreed
to assume responsibility. We will have responsibility for the Lockwood ash
disposal site and AES Creative Resources, L.P. will have responsibility for the
Weber ash disposal site. See "RISK FACTORS -- OUR BUSINESS IS EXTENSIVELY
REGULATED AND NEW REGULATIONS MAY IMPOSE REQUIREMENTS THAT WE ARE UNABLE TO MEET
OR THAT REQUIRE US TO MAKE ADDITIONAL EXPENDITURES" and "-- DESCRIPTION OF ASSET
PURCHASE AGREEMENT -- LIABILITIES." AES NY, L.L.C. was not obligated to assume
any liability under the Asset Purchase Agreement arising out of or related to
the assets retained by NYSEG or for liabilities or obligations arising prior to
May 14, 1999, except with respect to obligations or claims related to
environmental liabilities and other liabilities expressly assumed by AES NY,
L.L.C.
Representations and Warranties. The Asset Purchase Agreement provided that
the representations and warranties of the parties (other than those with respect
to corporate organization and authority, capitalization of Somerset Railroad,
enforceability and absence of conflicts, breaches and violations) did not
survive the closing of the transaction. The representations and warranties of
the parties with respect to organization and authority, capitalization of
Somerset Railroad, enforceability, and absence of conflicts, breaches and
violations survive for 18 months from May 14, 1999.
Inspection of Purchased Assets. Under the Asset Purchase Agreement, AES
NY, L.L.C. waived its right to object to the existing environmental conditions
of the sites included in the acquired assets (including the Weber and Lockwood
off-site ash disposal sites). In addition, AES NY, L.L.C. agreed that the
completion of the transactions contemplated in the Asset Purchase Agreement was
not conditioned on or subject to further inspection of the acquired assets, or
the existence of, or the absence of, any physical condition or circumstance with
respect to the acquired assets. The Asset Purchase Agreement expressly
prohibited AES NY, L.L.C. from performing or conducting environmental sampling
or testing at, in, or underneath the acquired assets, and provided that AES NY,
L.L.C. must rely on environmental reports and inspections relating to the
acquired assets prepared by an independent environmental consulting firm
commissioned by NYSEG. See "-- SUMMARY OF INDEPENDENT ENGINEER'S REPORT."
Indemnification. The Asset Purchase Agreement provides rights to
indemnification to NGE Generation, Inc., its officers, directors, employees,
shareholders, affiliates and agents from and against any and all claims asserted
against or resulting from or arising out of:
(1) any breach by AES NY, L.L.C. of any covenant or agreement in the Asset
Purchase Agreement or certain representations and warranties related to
corporate organizational matters;
(2) the liabilities assumed under the Asset Purchase Agreement by AES NY,
L.L.C.;
(3) any loss or damage to the assets arising out of inspection of these
assets by AES NY, L.L.C.; or
(4) any third party claims arising out of or in connection with the
ownership or operation of the acquired assets after May 14, 1999.
The Asset Purchase Agreement also provides rights to indemnification to AES
NY, L.L.C., its officers, directors, employees, shareholders, affiliates and
agents from and against any and all claims resulting from:
(1) any breach by NYSEG of any covenant or agreement in the Asset Purchase
Agreement or of any representation and warranty related to corporate
organizational matters;
(2) the liabilities not assumed by AES NY, L.L.C. under the Asset Purchase
Agreement;
(3) noncompliance by NYSEG with any bulk sales laws; or
(4) any third party claims arising out of or in connection with the
ownership or operation of the assets retained by NYSEG. AES NY, L.L.C.,
on behalf of its representatives and affiliates, agreed to release NGE,
its representatives and some affiliates for losses, whether known or
unknown, hidden or concealed, resulting from any violation of
environmental law relating to the acquired assets (other than certain
liabilities related to environmental conditions or violations of
environmental law in
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connection with the off-site disposal of hazardous substances at
locations other than the Weber and Lockwood ash disposal sites).
The Asset Purchase Agreement limits the amounts payable under the
indemnification provisions to direct damages, court costs and reasonable
attorneys' fees. Except in connection with indemnification for third party
claims, the parties also waived the right to recover punitive, special,
incidental, exemplary and consequential damages.
Employees. AES NY, L.L.C. was required to offer employment, effective as
of May 14, 1999, to those employees of New York State Electric & Gas Corporation
and NGE Generation, Inc. who were hourly-paid employees, covered by the IBEW
collective bargaining agreement and listed in the Asset Purchase Agreement and
salaried employees listed in the Asset Purchase Agreement. Hourly employees to
whom AES NY, L.L.C. was required to offer employment will retain their seniority
and receive full entitlement to vacation and benefits under the IBEW collective
bargaining agreement and salaried employees to whom AES NY, L.L.C. was required
to offer employment will also be given full credit for the purposes of benefit
entitlement. For the period beginning on May 14, 1999 and ending on June 30,
2000, AES NY, L.L.C. is obligated to provide all salaried employees to whom AES
NY, L.L.C. was required to offer employment with total compensation and
benefits, including, but not limited to, base pay, overtime, bonuses and
benefits, which are in the aggregate at least comparable in value and nature to
their total compensation and benefits prior to May 14, 1999. Finally, AES NY,
L.L.C. is obligated to pay to salaried employees whose employment is terminated
before June 30, 2000 a severance package as outlined in the Asset Purchase
Agreement.
Acquisition-Related Contracts
The following descriptions are summaries of the other principal contracts
related to our acquisition of our electricity generating stations. For
additional or more specific information, refer to the contracts, copies of which
have been filed with the SEC as exhibits to the registration statement of which
this prospectus is a part.
Milliken Operating Agreement. AES NY, L.L.C. and New York State Electric &
Gas Corporation entered into an agreement, dated as of August 3, 1998, as
amended as of May 6, 1999, to specify the obligations, responsibilities, and
liabilities of New York State Electric & Gas Corporation and AES NY, L.L.C. as
they relate to operating the Milliken Generating Station during peak load
periods. This agreement provides that service will commence on May 14, 1999 and
continue for five years thereafter, and, at the option of New York State
Electric & Gas Corporation, for an additional two-year term. AES NY, L.L.C.
assigned this agreement to us.
This agreement requires us to satisfy specified voltage regulation
requirements, including among others:
(1) to supply a functioning automatic voltage regulator at each unit;
(2) to supply voltage support service; and
(3) to operate the Milliken Generating Station to produce an agreed upon
voltage level.
The agreement further provides that when New York State Electric & Gas
Corporation forecasts that its load within its Ithaca Division will be equal to
or greater than a specified wattage for the following day or days, New York
State Electric & Gas Corporation may direct the operation of the units at the
Milliken Generating Station according to procedures set forth in the agreement.
The right to direct the operation of the units at the Milliken Generating
Station is subject to whether we have previously dispatched the units or have
scheduled the units to be out of service on the day or days in question. To the
extent New York State Electric & Gas Corporation directs the operation of the
units, New York State Electric & Gas Corporation is obligated to pay us the
amount by which our costs, on the days the unit or units that New York State
Electric & Gas Corporation directed us to operate, exceed our revenues from the
same unit during the same day, subject to limitations detailed in the agreement.
This agreement also limits scheduled maintenance outages. We are required
to provide written notice of a proposed outage to New York State Electric & Gas
Corporation at least 72 hours in advance of the scheduled outage. All outages
are subject to the written approval of New York State Electric & Gas Corporation
and
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must comply with independent system operator and New York power pool rules. The
agreement also requires us to provide written notice to New York State Electric
& Gas Corporation if we desire to retire one or both of the Milliken Generating
Station units. Upon delivery of written notice, the parties must cooperate (1)
to find alternatives to replace the voltage support provided by the retired
unit(s) and (2) to amend the agreement when a mutually acceptable voltage
support source has been identified. To the extent that the parties cannot agree
on an alternative source for voltage support, the agreement will remain in full
force and effect.
If we fail to comply with our obligations under the agreement and this
failure forces New York State Electric & Gas Corporation to remove load from its
electrical system in the Ithaca Division in response to an abnormal condition to
maintain the integrity of the electric system and minimize overall customer
outages, we are required to pay the following amounts:
(1) for each occurrence, $3,000 per hour for each hour that New York State
Electric & Gas Corporation removes load;
(2) for the second occurrence in a 365-day period, $22,000 per hour for
each hour that New York State Electric & Gas Corporation removes load;
and
(3) for the third occurrence and any subsequent occurrences, $42,000 per
hour for each hour that New York State Electric & Gas Corporation
removes load.
However, if at least one unit is operating at or above its minimum
generating level and New York State Electric & Gas Corporation removes load, we
are not liable to make payments to New York State Electric & Gas Corporation.
The agreement further provides that New York State Electric & Gas
Corporation will appoint an independent engineer to investigate the causes
requiring New York State Electric & Gas Corporation to remove load and to
recommend actions to remedy any problems contributing to the occurrences. The
agreement requires us to implement the recommendations of the independent
engineer.
Interconnection Agreement. AES NY, L.L.C. and New York State Electric &
Gas Corporation entered into an Interconnection Agreement, dated as of August 3,
1998, as amended as of May 6, 1999, to establish the requirements, terms and
conditions for the interconnection of the assets acquired from NYSEG to the
transmission system of New York State Electric & Gas Corporation. AES NY, L.L.C.
assigned this agreement to us insofar as it relates to our electricity
generating stations. The agreement will remain in effect with respect to an
interconnected facility for 50 years unless terminated earlier by mutual
agreement or otherwise in accordance with the agreement. New York State Electric
& Gas Corporation is not required to upgrade or modify its transmission system
unless required by law and is not liable for any claims or damages associated
with any interruptions in the availability of the New York State Electric & Gas
Corporation facilities or damage to the facilities resulting from electrical
transients unless this damage is caused by the gross negligence or willful
misconduct of New York State Electric & Gas Corporation. Under the agreement, we
are required to reimburse New York State Electric & Gas Corporation for the
reasonable cost of any additions, modifications or replacements to the
transmission system made necessary as a result of any modification by us to the
assets we acquired from NYSEG.
Agreement to Assign Transmission Rights and Obligations. AES NY, L.L.C.
and New York State Electric & Gas Corporation entered into an Agreement to
Assign Transmission Rights and Obligations, dated as of August 3, 1998, for the
purpose of transferring from New York State Electric & Gas Corporation to AES
NY, L.L.C. certain rights and obligations under two existing transmission
agreements: (a) an agreement, dated December 12, 1983, among Niagara Mohawk
Power Corporation, the New York Power Authority, New York State Electric & Gas
Corporation and Rochester Gas & Electric Corporation concerning the transmission
of energy from the Kintigh Generating Station; and (b) an agreement between NY
Electric & Gas and Niagara Mohawk Power Corporation known as the "Remote Load
Wheeling Agreement." AES NY, L.L.C. assigned this agreement to us insofar as it
relates to our electricity generating station. This agreement provides for the
assignment of rights to transmit energy from the Kintigh Generating Station, the
Nine Mile Point 2 electricity generating station and other sources to remote
load areas and other delivery points.
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Capacity Purchase Agreement. AES NY, L.L.C. and New York State Electric &
Gas Corporation entered into a New York Transition Agreement, dated as of August
3, 1998, to ease the transition of New York State Electric & Gas Corporation's
native load customers' installed capacity requirements. Under this agreement,
New York State Electric & Gas Corporation agreed to purchase, and AES NY, L.L.C.
agreed to sell, installed capacity in the amount of 1,424MW (which is the
aggregate capacity of all of the generating assets included in the assets
acquired from NYSEG) for the term of the agreement. The parties' performance
under the agreement commenced on May 14, 1999 and will terminate on April 30,
2001, or earlier in accordance with the agreement. AES NY, L.L.C. assigned this
agreement to us insofar as it relates to our electricity generating stations.
New York State Electric & Gas Corporation is required to compensate us for
installed capacity at the price of $68/MW-Day. Whenever installed capacity
provided to New York State Electric & Gas Corporation by us is less than the
amount of installed capacity that we are required to supply, we will pay New
York State Electric & Gas Corporation monthly for costs incurred by New York
State Electric & Gas Corporation due to this failure, in an amount equal to the
sum of:
(1) charges imposed on New York State Electric & Gas Corporation by the New
York power pool or the independent system operator, to the extent they
exceed charges that would have been due had we fulfilled our
obligations, including penalties and fines;
(2) New York State Electric & Gas Corporation's replacement capacity cost
(to the extent not included in (1)), if we fail to provide replacement
capacity; and
(3) all transaction costs not included in (1) or (2) that are associated
with this failure.
This agreement does not address the purchase or sale of electric energy or
ancillary services and does not obligate either New York State Electric & Gas
Corporation or us to purchase or sell and deliver energy to the other party.
This agreement is subject to regulatory acceptance or approval without material
modification or condition. The parties have agreed to indemnify one another for
claims arising out of or connected with this agreement.
Reciprocal Easement Agreement. New York State Electric & Gas Corporation
and AES NY, L.L.C. entered into a Reciprocal Easement Agreement, dated as of
August 3, 1998, to provide both New York State Electric & Gas Corporation and
AES NY, L.L.C. with easement rights with respect to one another's property in
order for each to enjoy the full benefit of its property located on, or adjacent
to, the other's property, fulfill legal requirements and perform its obligations
under the agreement. AES NY, L.L.C. will grant to New York State Electric & Gas
Corporation easements over AES NY, L.L.C.'s property in order to permit some
items of New York State Electric & Gas Corporation's property to remain in their
present locations on AES NY, L.L.C.'s property and to be used in New York State
Electric & Gas Corporation's normal conduct of business. In addition, AES NY,
L.L.C. agreed to grant an easement permitting future installation of some items.
New York State Electric & Gas Corporation also agreed to grant to AES NY, L.L.C.
certain easements on its property. The easements granted under the agreement are
both irrevocable and without charge or fee to the grantee of the easement. AES
NY, L.L.C. assigned this agreement to us.
Coal Sales Agreement. Approximately 100% of the Kintigh Generating
Station's and 70% of the Milliken Generating Station's coal requirements
initially will be supplied under a Coal Sales Agreement, dated as of November 1,
1983, as amended, among NYSEG and Consol, CONSOL Pennsylvania Coal Company,
Nineveh Coal Company, Greenon Coal Company, McElroy Coal Company and Quarto
Mining Company. Pursuant to the terms of this agreement, the coal sellers have
agreed to sell and deliver, and NYSEG has agreed to purchase, bituminous coal
which meets specified quality requirements to allow full load operation of the
Kintigh Generating Station and the Milliken Generating Station. The agreement
terminates on December 31, 2003 unless extended by the parties.
Pursuant to the terms of the agreement, the total amount of coal to be
purchased for the Kintigh Generating Station is divided into three lots: Lot A,
Lot B and Lot C. In any given calendar year, each of the three lots contains the
exact same tonnage of coal, with each lot representing one-third of the coal
purchased from the coal sellers for use at the Kintigh Generating Station in a
given year. Pursuant to the terms of a letter
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agreement, dated December 8, 1997, between NYSEG and Consol, the price for each
of Lots A, B and C was fixed at $0.868 per million Btu (which we estimate to be
equivalent to $22.57 per ton) in the year 2000, in each case subject to
adjustment for variations in "as received" heating quality and other
adjustments. Thereafter, each lot of coal becomes eligible for price
renegotiation every third year in staggered order.
During price renegotiations in any year following a year in which NYSEG and
the coal sellers were unable to agree on revised pricing terms with respect to a
given lot, NYSEG and the coal sellers may negotiate not only with respect to the
lot then eligible for renegotiation but also with respect to the lot lost in the
previous year's renegotiation. If NYSEG and the coal sellers are unable to agree
on revised terms with respect to any given lot for two successive
renegotiations, then the obligations of NYSEG and the coal sellers with respect
to that lot terminates. NYSEG may then replace this lot's tonnage by any means
and from any source it deems appropriate throughout the remaining term of the
agreement.
In any year in which the coal sellers supply only one lot (that is,
one-third of the coal purchased for the Kintigh Generating Station) and this lot
is then up for renegotiation, either of NYSEG or the coal sellers may terminate
the agreement in its sole discretion. Any such termination would become
effective on the next specified termination date for this lot.
During 2000, Consol is committed to sell and we are committed to purchase
all three lots of coal and either party may request renegotiation of the price
of one lot of coal for the following year. If either party requested
renegotiation during 2000 but the parties failed to reach agreement, then the
parties would have commitments with respect to only two lots in 2001. If the
same thing happened in 2001, the parties would have commitments with respect to
only one lot in 2002 and either party could terminate the contract in its sole
discretion at the end of 2002.
Under the terms of the agreement, if the parties' obligations with respect
to one or more lots of coal to be delivered to the Kintigh Generating Station
cease as a result of the failure of the parties to reach agreement during the
price renegotiations or heating quality adjustment renegotiations outlined
above, the obligations of the parties with respect to coal supply for the
Milliken Generating Station change as follows:
DELIVERIES TO THE KINTIGH STATION DELIVERIES TO THE MILLIKEN STATION
--------------------------------- ----------------------------------
3 Lots 70% of Milliken's annual coal tonnage
requirement
2 Lots 50% of Milliken's annual coal tonnage
requirement
1 Lot 50% of Milliken's annual coal tonnage
requirement
The price under the Coal Sales Agreement for coal supplied to the Milliken
Generating Station is the average price of the lots supplied for the Kintigh
Generating Station, but the price can be adjusted for variations in "as
received" heating quality and certain other adjustments.
The agreement was assigned to us by AES NY, L.L.C. The coal sellers have
consented to the assignment but have refused to release NYSEG from its
obligations under the agreement. We will indemnify NYSEG if NYSEG incurs any
liability as a result of our performance under the agreement.
Coal Hauling Agreement. Somerset Railroad and NYSEG entered into a Coal
Hauling Agreement, dated as of March 9, 1983, for the purpose of Somerset
Railroad hauling coal and other materials required by NYSEG to the Kintigh
Generating Station. NYSEG is obligated to pay Somerset Railroad the amounts that
will be sufficient, when added to funds available to Somerset Railroad from
other sources, to enable Somerset Railroad to pay, when due, all of its
operating and other expenses, including interest on and principal of outstanding
indebtedness. This agreement provided that NYSEG and Somerset Railroad may
subsequently enter into amendments detailing specific rates and terms for the
hauling of coal and other materials. The Coal Hauling Agreement between Somerset
Railroad and NYSEG was terminated when we acquired our electricity generating
stations on May 14, 1999. At that time, we entered into a Coal Hauling Agreement
with Somerset Railroad containing similar terms. Somerset Railroad currently has
a 364-day term loan of up to $26 million principal amount from an affiliate of
CIBC World Markets (the "Somerset Railroad credit facility"). This term loan
bears interest at a rate per annum, as selected by us, equal to either LIBOR
plus 1.35% or a base rate plus 1.25%. The term loan is secured by a security
interest in substantially all of the assets of Somerset Railroad, a pledge by
AES NY3, L.L.C. of all of the shares of stock of Somerset Railroad and an
assignment of the rights of Somerset Railroad under the Coal Hauling Agreement.
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THE LEASE TRANSACTIONS
The transactions relating to the lease of the Kintigh Generating Station
and the Milliken Generating Station raised $666 million of the funds for the
acquisition of the Kintigh Generating Station and the Milliken Generating
Station, excluding real property and the Kintigh selective catalytic reduction
system, and for transaction expenses. The equity investment of the institutional
investors that formed the special purpose business trusts that acquired the
Kintigh Generating Station and the Milliken Generating Station was $116 million.
The remaining $550 million of the amount raised in the lease transactions was
raised through the issuance and sale of the pass through trust certificates. The
twelve special purpose business trusts formed by the institutional investors
leased the undivided interests in the Kintigh Generating Station and the
Milliken Generating Station to us under twelve separate lease agreements. The
terms and conditions of each lease are substantially similar.
Each pass through trust used its share of the proceeds of the offering of
the pass through trust certificates to purchase the secured lease obligation
notes to be held in that pass through trust. The secured lease obligation notes
held in the pass through trusts represent in the aggregate the entire debt
portion of the lease transactions. The pass through trustee will distribute the
amount of payments of principal and interest received by it as holder of the
secured lease obligation notes to the pass through trust certificate holders of
the pass through trust in which those secured lease obligation notes are held. A
pass through trust certificate holder has an ownership interest only in the
related pass through trust that is the issuer of that pass through trust
certificate.
We, as lessee, leased an undivided interest in the Kintigh Generating
Station and the Milliken Generating Station from each special purpose business
trust under a lease. Concurrently, we, as lessor, leased to each respective
special purpose business trust an undivided interest either in a portion of the
Kintigh real property and the Kintigh selective catalytic reduction system or in
a portion of the Milliken real property, and granted non-exclusive easements
over the remainder of the Kintigh real property or the Milliken real property
for the benefit of the special purpose business trusts pursuant to a facility
site lease agreement. Each special purpose business trust also leased the real
property and easements to us, as sublessee pursuant to a facility site sublease
agreement. The secured lease obligation notes issued by each special purpose
business trust are secured by a lien on and first priority security interest in
the rights and interests of the special purpose business trust (other than
customary excepted payments and excepted rights reserved to this special purpose
business trust and the applicable institutional investor) in the related lease,
including the right to receive payments of periodic rent, its undivided interest
in the Kintigh Generating Station or the Milliken Generating Station and in
other agreements relating to the leases (including the site leases and the
subleases) and in the special purpose business trust's interest under the coal
hauling agreement with Somerset Railroad.
We are required to pay rent under each lease to one of the special purpose
business trusts. However, each special purpose business trust has assigned its
interest in its lease to the indenture trustee, who acts as trustee under each
lease indenture corresponding to each undivided interest in the Kintigh
Generating Station or the Milliken Generating Station. Therefore, we will make
rental payments directly to the indenture trustee. From these rental payments
the indenture trustee will first make payments to the pass through trustee that
are due under the secured lease obligation notes issued under the lease
indenture and held in the related pass through trust. The indenture trustee will
pay any remaining balance to each special purpose business trust for the benefit
of the institutional investor who holds the beneficial interest in that special
purpose business trust. Bankers Trust Company will act as the pass through
trustee of each of the pass through trusts and as indenture trustee under each
of the lease indentures. The pass through trustee will distribute to the pass
through trust certificate holders of each pass through trust payments that it
receives on the secured lease obligation notes held in this pass through trust.
We have established under the deposit and disbursement agreement a rent
reserve account for the benefit of the special purpose business trusts that own
the Kintigh Generating Station and the Milliken Generating Station and providers
of loans to us. The rent reserve account required balance is an amount equal to
the maximum semiannual payment with respect to the sum of (a) basic rent (other
than deferrable payments)
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and (b) fixed charges expected to become due on any one basic rent payment date
in the immediately succeeding three-year period. We are currently satisfying the
rent reserve account required balance by entering into a payment undertaking
agreement with a financial institution rated at least Aa3 by Moody's and AA- by
S&P. We can also satisfy our obligation to maintain the rent reserve account
required balance either by depositing amounts into the rent reserve account or
by making amounts available under a payment undertaking agreement, such that the
aggregate amount of these deposits in the rent reserve account and amounts
available to be paid under the payment undertaking agreement shall be equal to
the rent reserve account required balance. Our failure to maintain the rent
reserve account required balance on three consecutive basic rent payment dates
(after giving effect to the payment of rent other than deferrable basic rent on
these dates) is a Lease Event of Default, as defined under the caption
"DESCRIPTION OF THE PASS THROUGH TRUST CERTIFICATES -- THE LEASES, THE FACILITY
SITE LEASES AND THE FACILITY SITE SUBLEASES -- LEASE EVENTS OF DEFAULT."
The AES Corporation established an additional liquidity account with the
depositary and disbursement agent for our benefit. The AES Corporation is
currently funding the additional liquidity account with a letter of credit in an
amount equal to the additional liquidity required balance. The additional
liquidity required balance is initially equal to the greater of (a) $65,000,000
less the rent reserve account balance on May 14, 1999 and (b) $30,000,000. The
additional liquidity required balance will be permanently reduced by 50% at such
time after May 14, 2002 as
(a) the pass through trust certificates are rated at least Baa3 by Moody's
and at least BBB- by S&P,
(b) before and after any PPA Term (as defined in "DESCRIPTION OF THE PASS
THROUGH TRUST CERTIFICATES -- DEFINITIONS"),
(i) the average Coverage Ratio (as defined under the caption
"DESCRIPTION OF THE PASS THROUGH TRUST
CERTIFICATES -- DEFINITIONS") for the immediately preceding
three-year period is not less than 2.5:1.0, and
(ii) the minimum Coverage Ratio for each of the immediately preceding
three years is not less than 2.0:1.0; and
(c) during any PPA Term,
(i) the average Coverage Ratio for the immediately preceding three-year
period is not less than 1.5:1.0, and
(ii) the minimum Coverage Ratio for each of the immediately preceding
three years is not less than 1.4:1.0.
The additional liquidity required balance will be permanently eliminated at
such time after May 14, 2002 as
(a) the pass through trust certificates are rated at least Baa2 by Moody's
and BBB by S&P,
(b) before and after any PPA Term,
(i) the average Coverage Ratio for the immediately preceding three-year
period is not less than 2.5:1.0, and
(ii) the minimum Coverage Ratio for each of the immediately preceding
three years is not less than 2.0:1.0, and
(c) during any PPA Term,
(i) the average Coverage Ratio for the immediately preceding three-year
period is not less than 1.75:1.0, and
(ii) the minimum Coverage Ratio for each of the immediately preceding
three years is not less than 1.5:1.0.
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Our failure to cause the additional liquidity account to be funded in an
amount equal to the additional liquidity required balance is not a Lease Event
of Default, but the funding of this account is a condition precedent to our
making any restricted payment or other distribution.
During a special rent reserve period, we are required to fund a special
rent reserve account until the amount on deposit in this account equals the
special rent reserve account required balance. The special rent reserve account
required balance is equal to the maximum payment of basic rent (other than
deferrable basic rent) expected to become due (a) prior to May 14, 2004, on any
three basic rent payment dates, or (b) after May 14, 2004, on any two basic rent
payment dates, in each case in the immediately succeeding three-year period. The
special rent reserve account required balance will be reduced by the rent
reserve account required balance attributable to basic rent (other than
deferrable payments). We will satisfy our obligation to fund the special rent
reserve account by making amounts available under a payment undertaking
agreement in an amount equal to the special rent reserve account required
balance. Our failure to cause the special rent reserve account to be funded in
an amount equal to the special rent reserve account required balance is not a
Lease Event of Default.
EMPLOYEES
As of December 1999, we employed 319 people who operate our electricity
generating stations. The IBEW represents hourly labor at the Kintigh Generating
Station, the Milliken Generating Station, the Goudey Generating Station and the
Greenidge Generating Station. The IBEW represents approximately 246 workers.
Pursuant to the terms of the Asset Purchase Agreement, we (as assignee) were
required to offer employment to substantially all of the people employed by
NYSEG at our electricity generating stations. We were also required to assume
the collective bargaining agreement for our electricity generating stations
between NYSEG and the IBEW. The term of the collective bargaining agreement ends
on June 30, 2000 but will automatically renew from year to year unless
terminated by either party upon 60 days' notice. We retained a substantial
majority of the existing NYSEG workforce at each of the electricity generating
stations. We believe that relations with the people employed at our electricity
generating stations are satisfactory.
LEGAL PROCEEDINGS
On November 23, 1999, NYSEG commenced an action in the United States
District Court for the Southern District of New York against us and AES NY,
L.L.C. seeking declaratory and injunctive relief, together with unspecified
monetary damages, based on alleged breaches of the agreements relating to the
purchase by us and AES NY, L.L.C. from NYSEG of the Kintigh Generating Station.
This action arises from our alleged refusal to cooperate with NYSEG's efforts to
obtain an appraisal of the Kintigh Generating Station that we believe NYSEG will
use in an action for a refund of real estate taxes paid by NYSEG while it owned
the Kintigh Generating Station. See "DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION -- RESULTS OF OPERATIONS." We must respond to
the complaint on or before February 7, 2000.
AES Creative Resources, L.P. assumed responsibility for asbestos-related
personal injury suits in which NYSEG is named as one of numerous defendants and
AES NY, L.L.C., the general partner of our company and of AES Creative
Resources, L.P., and AES NY2, L.L.C., the limited partner of our company and of
AES Creative Resources, L.P., guaranteed the obligations of AES Creative
Resources, L.P. NYSEG agreed that it would not assert that we have
responsibility for these suits. As of December 1, 1999, 24 of these lawsuits
were pending.
In addition, in August 1998, NYSEG received notice of intent to file a
citizen suit with the New York State Department of Environmental Protection
regarding an alleged water discharge limit exceedence at the Kintigh Generating
Station. NYSEG has advised us that no citizen suit has been filed in connection
with this matter. If this suit is filed, we believe that under the Asset
Purchase Agreement any liability would be the responsibility of NYSEG.
On October 14, 1999, we received an information request letter from the New
York Attorney General which seeks detailed operating and maintenance history for
the Goudey and Greenidge Generating Stations. On January 13, 2000, we received a
subpoena from the New York State Department of Environmental
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Conservation seeking similar operating and maintenance history from the all four
of our electricity generating stations. This information is being sought in
connection with the Attorney General's and the Department of Environmental
Conservation's investigations of several electricity generating stations in New
York which are suspected of undertaking modifications in the past (from as far
back as 1977) without undergoing an air permitting review. If the Attorney
General or the Department of Environmental Conservation does file an enforcement
action against the Kintigh, Milliken, Goudey or Greenidge Generating Stations,
then there is the possibility that penalties may be imposed and further emission
reductions may be required.
We recently received a draft consent order from the New York State
Department of Environmental Conservation that alleges violations of the opacity
emission limitations in the air permits for the Milliken, Goudey, and Greenidge
Generating Stations. The draft consent order would require us to prepare an
opacity compliance plan and would impose penalties for opacity violations
occurring after the date of the acquisition of our electricity generating
stations, May 14, 1999. We expect to enter a final consent order with the
Department of Environmental Conservation early in 2000. AES NY L.L.C. also
recently received notice from NYSEG that NYSEG has received a draft consent
order from the Department of Environmental Conservation seeking penalties
primarily for opacity violations occurring prior to May 14, 1999. In the notice,
NYSEG asserts that it will seek indemnification from AES NY L.L.C. for any
penalties, attorney fees, and related costs that it incurs in connection with
the consent order. We and AES NY L.L.C. have denied liability for the
pre-closing violations and intend to vigorously defend this claim if NYSEG
pursues litigation or arbitration.
See "RISK FACTORS -- WE OR OUR AFFILIATES MAY HAVE TO DEFEND LAWSUITS
RELATING TO ASBESTOS EXPOSURE AT OUR ELECTRICITY GENERATING STATIONS WHILE THEY
WERE OWNED BY NYSEG AND DAMAGES IN THOSE SUITS OR THE COST OF DEFENDING THEM
COULD BE MATERIAL" and "-- WE WILL HAVE RESPONSIBILITY FOR PREEXISTING
ENVIRONMENTAL LIABILITIES AND WILL INCUR EXPENSES AS A RESULT; THESE EXPENSES
MAY EXCEED OUR PROJECTIONS" and "REGULATION -- ENVIRONMENTAL REGULATORY
MATTERS."
SUMMARY OF INDEPENDENT ENGINEER'S REPORT
The following is a summary of the report produced by Stone & Webster as
Independent Engineer, a copy of which is set forth in Appendix A to this
prospectus. Stone & Webster is an international engineering and consulting firm
in the electric power industry.
In the preparation of the Independent Engineer's Report and the opinions
therein, Stone & Webster has made certain assumptions with respect to conditions
that may exist or events that may occur in the future. While Stone & Webster
believes these assumptions to be reasonable for the purposes of the Independent
Engineer's Report, they are dependent upon future events that may differ from
those assumed. In addition, Stone & Webster has used and relied upon certain
information provided to it by sources that Stone & Webster believes to be
reliable. Stone & Webster believes the use of this information and these
assumptions is reasonable for the purposes of the Independent Engineer's Report.
However, some assumptions may vary significantly due to unanticipated events and
circumstances. Some of these events and circumstances are described in "RISK
FACTORS" and, in particular, "THE MARKET IN WHICH OUR BUSINESS WILL BE
CONCENTRATED IS BEING DEREGULATED AND WE MAY NOT BE ABLE TO SELL OUR ENERGY,
INSTALLED CAPACITY AND ANCILLARY SERVICES AT PRICES THAT WILL PRODUCE A PROFIT,"
"OPERATION OF OUR STATIONS MIGHT BE DISRUPTED," "WE HAVE ONLY A LIMITED
OPERATING HISTORY AND WE HAVE NOT DEMONSTRATED THAT WE CAN OPERATE OUR
ELECTRICITY GENERATING STATIONS IN A PROFITABLE MANNER," "OUR BUSINESS IS
EXTENSIVELY REGULATED AND NEW REGULATIONS MAY IMPOSE REQUIREMENTS THAT WE ARE
UNABLE TO MEET OR THAT REQUIRE US TO MAKE ADDITIONAL EXPENDITURES" AND "THE
FINANCIAL PROJECTIONS AND THE UNDERLYING ASSUMPTIONS THAT WE HAVE PRESENTED TO
HELP YOU EVALUATE THE MERITS OF AN INVESTMENT IN THE PASS THROUGH TRUST
CERTIFICATES AND FINANCIAL PROJECTIONS ARE INHERENTLY IMPRECISE AND ACTUAL
RESULTS ARE EXPECTED TO DIFFER." To the extent that actual future conditions
differ from those assumed in the Independent Engineer's Report or in the
information provided to Stone & Webster by others, the actual results may vary
from those forecast. The Independent Engineer's Report summarizes Stone &
Webster's work up to May 12, 1999, the date of the Independent Engineer's
Report. Thus, changed conditions occurring or becoming known after such date
could affect the material presented. You should read the Independent Engineer's
Report in its entirety.
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On the basis of the information contained, and the assumptions made, in the
Independent Engineer's Report, Stone & Webster has expressed the following
opinions:
(1) The Kintigh, Milliken, Goudey and Greenidge Generating Stations have
operated at availabilities of 95.7%, 92.2%, 91.8% and 87.4% in
non-overhaul years between 1988 and 1998, which are above average
availabilities compared to published data on similar facilities. Based
on the improvements made by NYSEG prior to the sale of our electricity
generating stations to us and continued life extension and replacement
work planned by us, it is reasonable to expect that our electricity
generating stations will continue to operate at availability levels
which support the capacity factor projections in our financial
projections.
(2) The normal claimed capacities of our electricity generating stations
are reasonable estimates of the capability of the stations. With
continued budgeted capital investment in our electricity generating
stations, it is reasonable to expect that these capacities can be
maintained over the period shown in our financial projections.
(3) The heat rates of our electricity generating stations in our financial
projections have been developed based on historical information. With
continued budgeted capital expenditures in our electricity generating
stations, it is reasonable to expect that these heat rates can be
maintained over the period shown in our financial projections.
(4) Our maintenance and capital expenditure budgets appear reasonable and
adequate to support the conclusions expressed above and to meet our
maintenance and performance objectives, excluding any unforeseeable
catastrophic failures near the end of a unit's design life. These
maintenance and capital budgets have been used as the basis for the
operation and maintenance expenses and capital expenditure expenses
used in our financial projections. Stone & Webster prepared an
independent life extension study to compare against our life extension
budget. The two budgets were within approximately 10% of each other
for the 38 years of our financial projections. Therefore, Stone &
Webster believes the capital expenditure budget prepared by us is
adequate and reasonable.
(5) We have projected continued operation of our electricity generating
stations to the year 2035. Based on Stone & Webster's review, it
appears that there are no existing conditions that would preclude the
long-term operation of any of our electricity generating stations.
This assumes the continuation of condition assessments, maintenance,
and capital improvement programs, and the implementation of our
budgeted life extension program.
(6) Our electricity generating stations have all necessary permits in
place. Stone & Webster has no reason to believe that the stations will
not be able to renew their permits as needed. They believe the
environmental reports commissioned by NYSEG and by us were prepared in
accordance with good industry practice. Stone & Webster believes the
reports have recommended adequate budgets for environmental
remediation, which are included in our financial projections. They
further believe the NO(x) and SO(2) compliance strategies presented by
us are reasonable.
(7) The technology of our electricity generating stations is proven. The
ability to obtain replacement parts should not be a concern during the
period covered by our financial projections.
(8) The AES Corporation has considerable experience operating coal-fired
power plants. Stone & Webster believes that The AES Corporation is
well qualified to operate these plants. The AES Corporation has
achieved the availability projections for the plants at several of its
other locations. In addition, The AES Corporation has demonstrated the
ability to improve the operations of its plants through the
involvement of all the plant personnel. This enables it to keep costs
under control and find innovative solutions, which lowers operating
costs and capital expenditures.
(9) Under base case assumptions, our average fixed charge coverage ratio
is forecast to be 3.38 from 1999 through 2028. The minimum fixed
charge coverage ratio is 1.67 and occurs in 1999.
(10) Six sensitivity cases were prepared to test the impact on the fixed
charge coverage ratios of different market forces on the energy and
capacity forecasted by London Economics and on the operating
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and capital costs projected by us. The sensitivities include (i) the
downside projection of energy and capacity prices and reduced capacity
factors from London Economics, (ii) reduced capacity factors by 10%,
(iii) increased fuel costs by 10%, (iv) increased operations and
maintenance expenses by 25%, (v) increased capital expenditures by
50%, and (vi) increased heat rates at each unit by 500 Btu/kWh. The
fixed charge coverage ratio was most sensitive to reduced energy
prices used in sensitivity case (i). The average fixed charge coverage
ratio in this case fell to 2.66 with a minimum of 1.28 in 1999. After
1999, the minimum fixed charge coverage ratio was 1.61 in the year
2005.
(11) Stone & Webster has reviewed the footprints of the portions of the
Kintigh and Milliken sites conveyed as security to the indenture
trustee and the contracts and other rights assigned as indirect
collateral for the pass through trust certificates, which contracts
and rights are essential for the operation of our electricity
generating stations. Stone & Webster believes that this security and
these assignments, taken together, would be sufficient to permit a
transferee to operate the Kintigh Generating Station and the Milliken
Generating Station as they have been historically operated.
SUMMARY OF INDEPENDENT MARKET CONSULTANT'S REPORT
The following is a summary of the report produced by London Economics, as
Independent Market Consultant. This summary should be read in conjunction with,
the full text of the Independent Market Consultant's Report set forth in
Appendix B to this prospectus.
In the preparation of the Independent Market Consultant's Report and the
opinions in the report, London Economics has made the following qualifications
with respect to the information contained in the report and the circumstances
under which this report was prepared. Some of the information in the Independent
Market Consultant's Report is necessarily based on assumptions and predictions
of future events and behavior. These assumptions and predictions may differ from
that which other experts specializing in the electricity industry might present.
The provision of the Independent Market Consultant's Report does not obviate the
need for any potential investor to make further appropriate inquiries as to the
accuracy of the information included in the report, or to undertake an analysis
of its own. In addition, the Independent Market Consultant's Report is not
intended to be a complete and exhaustive analysis of the subject issues and
therefore does not necessarily consider all of the factors which may be
important to a potential investor's analysis. Nothing in the Independent Market
Consultant's Report should be taken as a promise or guarantee as to the
occurrence of any future events.
London Economics' report included a compilation of 1997 total production
costs and average heat rates for thermal units in the northeastern United
States. This data showed that our electricity generating stations were among the
lowest cost, most efficient thermal units in this region. London Economics'
report also presented weighted-average production cost and heat rate data for
the five-year period from 1993-1997. The Kintigh Generating Station ranked 7th,
the Milliken Generating Station ranked 10th, the Goudey Generating Station
ranked 14th and the Greenidge Generating Station ranked 16th out of 48
coal-fired electric utility plants in the northeast in terms of five-year
weighted average total production costs.
Conclusions
London Economics has concluded that:
- Our electricity generating stations are likely to maintain a competitive
advantage over the most likely form of new generating plants, combined
cycle gas-fired turbines, during the study period. The intrinsic value of
the coal-fired assets lies in their competitive cost structure, which
will remain economic in comparison to other known generation
technologies. Based on fuel forecasts by John T. Boyd Company, our
Independent Coal Market Consultant, and other consultants, the report of
Stone & Webster, and projected variable operations and maintenance costs,
London Economics projected that the cost efficiency of our electricity
generating stations relative to their peers (other coal-fired generation)
in the New York power pool should remain high going forward.
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- London Economics does not find a scenario credible at this time that
involves the construction of substantial new nuclear, run-of-river hydro
or coal generation in New York. It is unlikely that new gas or oil-fired
generation will be able to compete with our electricity generating
stations on a variable cost basis (at forecast gas prices). This will
limit the risk that our electricity generating stations will be displaced
in the energy dispatch order by new generating plants.
- In addition, our electricity generating stations will have the advantage
of revenue stability due to their projected high capacity factors. This,
combined with relatively stable coal purchase costs, provides relatively
stable operating margins for us, which may become increasingly valuable
as the market develops and prices become more volatile and unpredictable.
The profitability of the coal plants will tend to be positively
correlated with gas and oil prices in the future. This could provide a
hedge against gas and oil price fluctuations and could have a positive
value in the electricity contract market.
- Furthermore, our electricity generating stations are well positioned to
take advantage of potential market developments in and outside New York.
The western New York market has traditionally been low cost in comparison
to most neighboring markets. This may allow for additional export
earnings over time.
- The expected development of the New York power market will be driven by a
range of factors: economic, regulatory and technological. For the short
to medium-term, market dynamics will be dominated by the initial
conditions at the start of competition:
High downstate prices due to lack of investment in new generation
technologies. The urban utilities downstate, especially Consolidated
Edison and the former Long Island Lighting Company, were slow to invest
in new technologies and to replace old generating units. While this
helped keep down rates for a while (as their older units were already
partially depreciated in the ratebase), downstate New York is now stuck
with high operating costs, low thermal efficiencies and a preponderance
of high cost oil and gas-fired units. The implementation of competition
will both allow new entry and remove some regulatory uncertainty. London
Economics has therefore predicted that substantial new entry and
re-powering will occur downstate as long as high cost units can be
displaced.
A shift between energy and capacity prices to signal new entry. Energy
prices generally reflect the variable cost-basis of the most expensive
unit dispatched. In the early years, new entrant combined-cycle gas
turbines can cover much of their capital costs in addition to their
variable costs from their energy market profits because energy prices
are reflecting the higher cost basis of the downstate units. As more of
these combined-cycle gas turbine units enter the market, marginal prices
(energy prices at a particular hour) will decline, especially at higher
levels of demand. This will tend to shift value into a limited number of
peak hours and into the capacity market. This effect is reflected in the
results of London Economics' modeling analysis.
Upstate prices will remain lower due to transmission constraints. The
transmission constraints which block the free flow of power from lower
cost upstate units to downstate will not be removed quickly. For this
reason, prices in the upstate region remain lower than downstate prices
over time in London Economics' forecasts, generally below new entry
trigger levels.
Prices in general must rise from those reported in the current wholesale
spot market. The existing wholesale power markets in the United States
are heavily distorted by the presence of large numbers of
vertically-integrated ratebase utilities. These utilities are able to
recover the majority of their fixed and capital costs from their captive
customers under ratebase, and will often sell power at little over
variable cost. Experience in other markets (in foreign markets and
California, for example) has shown that prices must eventually rise over
time for generators to recover full costs from the market, once the
distorting effects of ratebase and transitional contracts are removed.
Environmental restrictions will produce substantial upward pressure on
prices. The Kintigh Generating Station and the Milliken Generating
Station are currently the only coal-fired plants in New York State
equipped with flue gas desulfurization systems. Other coal-fired units
in New York will have to add emissions controls or switch to low sulfur
compliance coals in order to meet federal
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environmental restrictions. This will add to their fixed or variable
costs or both. Since the capital expenditure required to meet even
existing environmental laws is high, London Economics expects that many
older units will instead be closed.
Modeling and Analysis
London Economics' proprietary power markets model was used to forecast
system dispatch and operations over the study period, and the resulting energy
prices for two transmission-constrained regions: the high cost downstate zone,
which covers New York City, Long Island and the lower Hudson valley, and the
lower cost upstate zone. Our electricity generating stations are all located in
the upstate zone. This two-zoned modeling approach forms a simplified
representation of the technical details of the proposed transmission congestion
and pricing systems in New York.
The chart below was prepared by London Economics and illustrates the energy
dispatch curve for the New York power market in 2000 projected by London
Economics using the base case assumptions in its report. The system has
significant nuclear and "must-run" NUG (non-utility generator) capacity that
runs at baseload when available. Our electricity generating stations are among
the lowest cost thermal generators. Further, there is a large number of higher
cost oil, gas and dual-fired steam turbine units, mostly in the downstate
region. This chart shows that the position of our electricity generating
stations in the projected energy dispatch curve is slightly above the minimum
statewide projected hourly load and significantly lower than the average load
for 2000. This chart is not adjusted for availability, which is affected
primarily by planned and forced outages. Under London Economics' modeling
simulations, which account for availability adjustments such as forced outages
and planned outages, these plants are almost always dispatched. The capacity
factors of the least efficient units among our electricity generating stations
(the non-reheat units at Goudey (Unit 7) and Greenidge (Unit 3)) are most
sensitive to unfavorable changes in the model inputs while the most efficient
units (the Kintigh Generating Station and the Milliken Generating Station) are
likely not to be sensitive to such unfavorable changes.
[PROJECTED NEW YORK DISPATCH CURVE IN 2000 CHART]
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The following assumptions, which London Economics believes are
conservative, have been used in constructing both the base and downside
scenarios. London Economics has assumed that all nuclear capacity in New York
will continue to run until its license expiration date, with no early
retirements. London Economics has also assumed that all generators bid into the
energy market only at variable (fuel plus variable operations and maintenance)
cost, and that substantial new entry and re-powering will occur downstate in the
early years up to 2005. At the date of London Economics report, March 1999, fuel
oil prices and traded forward prices were below the forecast oil prices prepared
by an independent consulting firm that were used by London Economics. London
Economics performed additional analysis for the years 1999 to 2010 to determine
the effects of lower oil prices, partially offset by NO(x) allowance costs
(which were not incorporated in the base and downside cases). Incorporating both
of these effects leads to a decrease in our revenues during 1999 through 2003.
The decreased revenues during these years would fall between the base case and
downside case revenues.
In addition, London Economics assumed that Ontario Hydro will get
sufficient amounts of its nuclear capacity back online to return to its
historical level of exports to New York. The projected level of imports from
Ontario is assumed to decrease gradually as Ontario Hydro's nuclear units meet
their license expiration dates.
Capacity prices were analyzed using a capacity balance approach. For the
downside case, capacity prices in each region were determined by the minimum
going-forward revenues required to keep sufficient installed capacity available.
This capacity requirement included the sum of regional peak demands and reserve
requirements. Costs considered under the capacity analysis included fixed
operation and maintenance costs, projected property and other taxes, and the
costs of life extension for units over 30 years old. For the base case, the
capacity analysis also included a moderate return on investment for these
existing units, based on estimated net book values. For both scenarios, capacity
prices are set to allow new entrant plants to achieve a target revenue level
when demand growth requires that new capacity be brought online. Both projected
average energy and capacity prices for the Upstate New York are shown in the
table below.
For the Upstate region, where our electricity generating stations are
located, capacity prices rise as forecast energy prices fall sharply over the
period 2000 to 2005. The fall in energy prices is triggered by the level of new
entry, most of it downstate, and the re-powering of less efficient plants. Even
with these capacity changes, the capacity balance is projected to return to
equilibrium by early in the next decade. This implies that downstate capacity
prices must rise to trigger needed new entry, as the fuel cost savings to new
more efficient units will no longer be adequate. Under the base and downside
cases, London Economics has projected that total energy and capacity prices for
the Upstate region will be generally below projected new entrant prices.
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FORECASTED ENERGY AND CAPACITY PRICES IN BASE AND DOWNSIDE CASES (UPSTATE NEW
YORK) (1999$)
BASE CASE DOWNSIDE CASE
--------------------------------- ---------------------------------
ENERGY CAPACITY TOTAL ENERGY CAPACITY TOTAL
($/MWH) ($/KW-YEAR) ($/MWH) ($/MWH) ($/KW-YEAR) ($/MWH)
------- ----------- ------- ------- ----------- -------
1999 $25.0 $27.0 $28.1 $23.3 $25.0 $26.2
2000 26.2 30.0 29.6 24.4 26.0 27.4
2001 27.4 37.0 31.6 25.4 31.0 29.0
2002 28.4 40.8 33.1 26.4 36.0 30.5
2003 27.3 46.2 32.5 25.0 39.5 29.5
2004 24.9 51.6 30.8 22.9 45.3 28.1
2005 22.8 57.0 29.3 21.0 51.0 26.8
2006 23.1 56.2 29.5 21.2 50.6 27.0
2007 23.3 55.4 29.7 21.4 50.2 27.2
2008 23.6 54.6 29.8 21.7 49.8 27.3
2009 23.9 53.8 30.0 21.9 49.4 27.5
2010 24.2 53.0 30.2 22.1 49.0 27.7
2011 24.5 52.6 30.5 22.3 47.8 27.8
2012 24.8 52.2 30.7 22.5 46.6 27.9
2013 25.1 51.8 31.0 22.8 45.4 27.9
2014 25.4 51.4 31.3 23.0 44.2 28.0
2015 25.7 51.0 31.5 23.2 43.0 28.1
2016 25.3 52.6 31.3 23.0 44.8 28.1
2017 24.9 54.2 31.1 22.7 46.6 28.0
2018 24.5 55.8 30.8 22.5 48.4 28.0
2019 24.1 57.4 30.6 22.2 50.2 28.0
2020 23.7 59.0 30.4 22.0 52.0 27.9
2021* 23.7 59.0 30.4 22.0 52.0 27.9
2022* 23.7 59.0 30.4 22.0 52.0 27.9
2023* 23.7 59.0 30.4 22.0 52.0 27.9
2024* 23.7 59.0 30.4 22.0 52.0 27.9
2025* 23.7 59.0 30.4 22.0 52.0 27.9
2026* 23.7 59.0 30.4 22.0 52.0 27.9
2027* 23.7 59.0 30.4 22.0 52.0 27.9
2028* 23.7 59.0 30.4 22.0 52.0 27.9
2029* 23.7 59.0 30.4 22.0 52.0 27.9
2030* 23.7 59.0 30.4 22.0 52.0 27.9
2031* 23.7 59.0 30.4 22.0 52.0 27.9
2032* 23.7 59.0 30.4 22.0 52.0 27.9
2033* 23.7 59.0 30.4 22.0 52.0 27.9
2034* 23.7 59.0 30.4 22.0 52.0 27.9
2035* 23.7 59.0 30.4 22.0 52.0 27.9
- ---------------
* Energy prices and capacity prices from 2021 through 2035 have not been
modeled. London Economics assumed zero growth in real prices after 2020.
SUMMARY OF COAL MARKET STUDY
The following is a summary of the Coal Market Study produced by the
Independent Coal Market Consultant, John T. Boyd Company. This summary should be
read in conjunction with, the full text of the
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Coal Market Study set forth in Appendix C hereto. Although the market analysis
is based on John T. Boyd Company's extensive knowledge of the coal industry
within the regional study area and its numerous databases of published
information on historic coal production, coal reserves, coal prices and other
sources, unforeseen changes or new developments (for example, environmental
regulation) could substantially affect future coal demand, quality needs, and
prices. Thus, nothing in the Coal Market Study should be taken as a guaranty as
to the occurrence of any future events.
For the Coal Market Study, John T. Boyd Company analyzed the market for
coals supplied to the northeastern U.S. utilities from Maryland, eastern Ohio,
Pennsylvania, and northern West Virginia. These areas are defined as coal
producing Districts 2, 3, 4 and 6. This analysis included a review of supply
sources, supply availability, demand, and impacts of the federal Clean Air Act
Amendments. The Coal Market Study focused primarily on major producers in the
Pittsburgh Seam coal formation. John T. Boyd Company also completed an overview
of District 1, which includes central Pennsylvania, western Maryland, and three
counties in northern West Virginia.
Current Production. In 1997, the Districts 2, 3, 4 and 6 produced
approximately 116 million tons, 99 million tons from mines producing in excess
of 500,000 tons per year. The five largest producers in 1997 produced
approximately 78 million tons from the Pittsburgh Seam.
Pittsburgh Seam Operations. The Pittsburgh Seam is one of the major coal
deposits in the eastern United States. Pittsburgh Seam coal producers have
stated in filings with the SEC that there are nearly 1.9 billion assigned or
accessible recoverable reserves associated with their current mines. Pittsburgh
Seam mines dominate Districts 1, 2, 3, 4 and 6, accounting for approximately 50%
of their production (70% of the underground production), and include some of the
lowest cost, high volume supply sources delivering to utilities in New York
State.
Future Supply. John T. Boyd Company has examined the recoverable reserves
of the major Pittsburgh Seam mines as reported in the respective companies'
filings with the SEC. Based on the 1997 production and recoverable reserves at
these Pittsburgh Seam operations, there are sufficient coal reserves available
to sustain production of current levels for more than 32 years. John T. Boyd
Company believes that any increase in near-term demand caused by the closing of
existing mining operations or additional generating stations installing flue gas
desulfurization systems will be met primarily by incremental production from
existing Pittsburgh Seam mines and by development of brownfield sites. There are
sufficient undeveloped Pittsburgh Seam reserves to enable the development of
numerous new Pittsburgh Seam longwall mines. However, based on John T. Boyd
Company's analysis, current and foreseeable market prices do not justify the
capital investment required to develop new greenfield capacity. John T. Boyd
Company believes that the price of Pittsburgh Seam coals will continue to
decline in real terms.
Coal Producing District 1. District 1 includes mines located in central
Pennsylvania, Maryland and a portion of northeastern West Virginia. Of the 251
mines operating in 1997, only 16 (approximately 6%) produced more than 500,000
tons. John T. Boyd expects the number of operating mines to continue to decline
and Pittsburgh Seam production from District 2 primarily to provide the
replacement tonnages.
Sulfur Dioxide Limitations. Sulfur dioxide limitations have impacted
regional coal supply patterns and increased demand for lower sulfur coals. Of
the 261 units in the United States affected by federal Clean Air Act Amendments
Phase I sulfur dioxide restrictions, an estimated 173 units (66%) have been
switched either to lower sulfur coals or to a blend of various quality coals
while 28 units (11%) have been or are being equipped with flue gas
desulfurization systems. In 1997, Districts 2, 3, 4 and 6 supplied to stations
equipped with flue gas desulfurization systems located east of the Mississippi
River a total of 50 million tons of coal, which is approximately 33% of their
production (93% of these 50 million tons were medium- and high-sulfur coal).
John T. Boyd Company believes this market will expand due to installation of
additional flue gas desulfurization systems to meet the requirements of federal
Clean Air Act Amendments Phase II sulfur dioxide restrictions.
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REGULATION
ENERGY REGULATORY MATTERS
General
We and our ownership and operation of our electricity generating stations
are regulated under numerous federal, state and local statutes and regulations.
Among other aspects of electric generation, these statutes and regulations
govern the rates that we may charge for the output of our electricity generating
stations, establish in certain instances the operating parameters of our
electricity generating stations, and define standards for ownership of our
electricity generating stations. While there exists a strong interest at both
the federal and state level to deregulate certain aspects of the electric
generation industry, we currently remain subject to extensive regulation.
Federal Energy Regulation
Federal Power Act. Under the Federal Power Act, the Federal Energy
Regulatory Commission possesses exclusive rate-making jurisdiction over
wholesale sales of electricity and transmission in interstate commerce. FERC
regulates the owners of facilities used for the wholesale sale of electricity
and transmission in interstate commerce as "public utilities" under the Federal
Power Act.
Pursuant to the Federal Power Act, all public utilities subject to FERC's
jurisdiction are required to obtain FERC's acceptance of their rate schedules in
connection with the wholesale sale of electricity. Our rate schedule was
approved by FERC as a market-based rate schedule and, accordingly, FERC granted
us waivers of the principal accounting, record-keeping and reporting
requirements that otherwise are imposed on utilities with a cost-based rate
schedule.
Public Utility Holding Company Act. The Public Utility Holding Company Act
provides that any corporation, partnership or other entity or organized group
that owns, controls or holds 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 regulation under PUHCA,
unless an exemption is established or an order is issued by the SEC declaring it
not to be a holding company. Registered holding companies under PUHCA are
required to limit their utility operations to a single integrated utility system
and to divest any other operations not functionally related to the operation of
the utility system. In addition, a public utility company that is a subsidiary
of a registered holding company under PUHCA is subject to financial and
organizational regulation, including approval by the SEC of certain of its
financing transactions. However, under the Energy Policy Act of 1992, a company
engaged exclusively in the business of owning and/or operating a facility used
for the generation of electric energy exclusively for sale at wholesale may be
exempted from PUHCA regulation as an "exempt wholesale generator." On February
5, 1999, we received exempt wholesale generator status from FERC for our
ownership and operation of generation and associated facilities. If, after
having received this status, there is a "material change" in facts that might
affect our continued eligibility for exempt wholesale generator status, within
60 days of this material change, we must (a) file a written explanation of why
the material change does not affect our exempt wholesale generator status, (b)
file a new application for exempt wholesale generator status or (c) notify FERC
that we no longer wish to maintain exempt wholesale generator status. However,
if we should lose exempt wholesale generator status, then we would either have
to restructure ourselves or risk subjecting ourselves and our affiliates to
PUHCA regulation.
State Regulation. In New York State, recent legislation has significantly
deregulated the rate setting aspects of the industry. However, significant risks
remain, including, but not limited to, the potential that the state deregulation
initiatives are not implemented in the manner anticipated by us or that they
could be reversed or nullified. We have obtained authorization from the New York
State Public Service Commission for the issuance of the pass through trust
certificates and the incurrence of debt pursuant to the working capital credit
facility with Credit Suisse First Boston.
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Lease Transactions Filings and Approvals. As conditions to completion of
the lease transactions relating to the Kintigh Generating Station and the
Milliken Generating Station, we and the appropriate financial participants in
the lease transactions were required to obtain certain approvals from FERC. We
obtained all of our approvals, including authorization to sell wholesale
electric energy under our market-based rate schedule and related waivers and
blanket authorization. We believe that the special purpose business trusts have
obtained all energy-related approvals required to be obtained by them as of the
date of this prospectus. The special purpose business trusts have been included
in the approval by FERC of the transfer of jurisdictional facilities and the
acquisition and leaseback of FERC-jurisdictional facilities, and FERC has
granted a disclaimer of jurisdiction over each of the institutional investors
and the special purpose business trusts and the trustees of those trusts as
public utilities under Part II or III of the Federal Power Act. The special
purpose business trusts have received determinations from FERC that they are
exempt wholesale generators. The special purpose business trusts obtained a
no-action letter from the SEC staff that no enforcement action would be
recommended against them under PUHCA if they proceeded with the lease
transactions prior to obtaining exempt wholesale generation determinations from
FERC.
ENVIRONMENTAL REGULATORY MATTERS
General
As is typical for electric generators, our electricity generating stations
are required to comply with federal, state and local environmental regulations
relating to the safety and health of personnel and the public, including
- the identification, generation, storage, handling, transportation,
disposal, recordkeeping, labeling, reporting of and emergency response in
connection with hazardous and toxic materials associated with our
electricity generating stations;
- limits on noise emissions from our electricity generating stations;
- safety and health standards, practices and procedures applicable to the
operation of our electricity generating stations; and
- environmental protection requirements, including standards and
limitations relating to the discharge of air and water pollutants.
Failure to comply with any of these statutes or regulations could have material
adverse effects on us, including the imposition of criminal or civil liability
by regulatory agencies or civil fines and liability to private parties, and the
required expenditure of funds to bring our electricity generating stations into
compliance. In addition, pursuant to the Asset Purchase Agreement, we (as
assignee of AES NY, L.L.C.) have, with a few exceptions, agreed to indemnify
NYSEG against the consequences of NYSEG's handling, storage or emission of
hazardous and toxic materials on any of the sites of our electricity generating
stations and the Lockwood off-site ash disposal site and for NYSEG's past
non-compliance, if any, with environmental requirements.
It is likely that the stringency of environmental regulations affecting us
and our operations will increase in the future. In the meantime, we will monitor
potential regulatory developments that may impact our operations and we will
participate in rulemaking proceedings applicable to our operations when we
consider it advisable to do so. We do not expect any currently proposed
regulations to have a material adverse effect on our results of operations or
our financial condition.
Expenditures. Compliance with environmental standards will continue to be
reflected in our capital expenditures and operating costs. Based on the current
status of regulatory requirements and other than the expenditures for the
Kintigh selective catalytic reduction system, including the construction of new
landfill space to manage ash from selective catalytic reduction system
operations, and possible expenditures for a Milliken selective catalytic
reduction system, we do not anticipate that any capital expenditures or
operating expenses associated with our compliance with current laws and
regulations will have a material effect on our results of operations or our
financial condition. See "AIR EMISSIONS -- NITROGEN OXIDES."
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Air Emissions
The federal Clean Air Act and many state laws require significant
reductions in utility SO(2) and NO(x) emissions that result from burning fossil
fuels in order to reduce acid rain and ground-level ozone (smog).
Sulfur Dioxide (SO(2)). SO(2) emissions are regulated under Title IV of
the federal Clean Air Act Amendments and by the New York Acid Deposition Control
Act. One of the primary goals of Title IV of the Amendments was to reduce SO(2)
emissions by 10 million tons from 1980 levels. The SO(2) emission reduction
requirements generally apply to almost all fossil-fuel fired electric generating
units producing electricity for sale. Power plants subject to Title IV are
required to obtain acid rain permits, to hold sufficient emission allowances to
cover their SO(2) emissions, and to comply with various monitoring and
recordkeeping requirements. The federal SO(2) requirements are implemented in
two phases -- Phase I applies to the 110 plants listed in section 404 of the Act
and Phase II generally affects all other electric generating plants selling over
25MW to the electricity distribution grid. Phase I of the federal Clean Air Act
Amendments SO(2) program went into effect January 1, 1995, with Milliken 1 and 2
and Greenidge 4 falling under the program. Phase II went into effect January 1,
2000 and affects all units.
Flue gas desulfurization systems or "scrubbers" are operated at both the
Kintigh Generating Station and the Milliken Generating Station to reduce total
SO(2) emissions from these plants to quantities substantially below the Title IV
SO(2) "allowance" allocations for these plants. An allowance is a freely
transferable right to emit one ton of a substance, in this case, SO(2). The
excess allowances are accumulated and can either be used for other of our
electricity generating stations or sold to provide liquidity to us. We may sell
SO(2) allowances rather than save them for Phase II of Title IV of the federal
Clean Air Act Amendments. During Phase II, we may need to purchase SO(2)
allowances beginning in 2000 to cover SO(2) emissions for the Greenidge
Generating Station and the Goudey Generating Station. Market prices for SO(2)
allowances currently range from $196 - $212 per ton. The estimated costs of
purchasing allowances in future years are provided for in our financial
projections. Nevertheless, we believe that, with minor operational changes and
minimal additional expenditure, we could improve the efficiency of our scrubbers
by 10% or more, which would compensate for most, if not all, of the possible
shortfall of SO(2) allowances for the stations. We believe that the annual cost
of the additional sulfur control and the purchasing of SO(2) allowances would
not be material.
On October 14, 1999, New York Governor Pataki announced a new initiative
which directs the New York State Department of Environmental Conservation to
issue regulations requiring electric generators to reduce SO(2) emissions by
another 50% below Phase II standards. The Governor is calling for the new
regulations to be phased in starting on January 1, 2003 with implementation
completed by January 1, 2007. If enacted, the Governor's initiative has the
potential to require further SO(2) reductions at our electric generating
stations and may necessitate that either additional SO(2) emission controls be
installed, lower sulfur coal be utilized or surplus SO(2) allowances be
purchased. We are not currently in a position to quantify the potential costs of
complying with the Governor's SO(2) initiative; however, if enacted by the New
York State Legislature, the costs of compliance could be substantial.
In addition, on October 14, 1999, we received an information request letter
from the New York Attorney General which seeks detailed operating and
maintenance history for the Goudey and Greenidge Generating Stations. On January
13, 2000, we received a subpoena from the New York State Department of
Environmental Conservation seeking similar operating and maintenance history
from all four of our electricity generating stations. This information is being
sought in connection with the Attorney General's and the Department of
Environmental Conservation's investigations of several electric generation
stations in New York which are suspected of undertaking modifications in the
past (from as far back as 1977) without undergoing an air permitting review.
Both the Governor's initiative and the Attorney General's and the Department of
Environmental Conservation's investigations have the potential of triggering
further emission reductions at the Company's plants and possibly resulting in
the necessity of installing additional emissions control equipment. If the
Attorney General or the Department of Environmental Conservation does file an
enforcement action against the Goudey and Greenidge Generating Stations, then
penalties may also be imposed.
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Nitrogen Oxides (NO(x)). New York State and the other states in the
Mid-Atlantic and Northeast region are classified as the Ozone Transport Region
in the federal Clean Air Act, which designates the Ozone Transport Region as
being not in compliance with the ozone National Ambient Air Quality Standard.
The states in the Ozone Transport Region have agreed to implement a three-phase
process to reduce NO(x) emissions in the region in order to comply with the
federal Clean Air Act Title I requirements for ozone non-compliance areas. NYSEG
complied with Phase I through operational modifications to reduce NO(x)
emissions, reduction of electric output from selected generating units to reduce
emissions to cap levels, and installation of NO(x) reduction equipment on
selected generating units.
The Phase I regulations require facilities in New York State to implement
NO(x) control requirements based on reasonably available control technology. The
New York State Department of Environmental Conservation has approved a
facility-wide plan for the former NYSEG generating plants to take advantage of
operating flexibility offered by grouping the plants together under a common
NO(x) emissions averaging plan. Under this approach, a system-wide emission rate
limit is continually calculated based upon which of the former NYSEG plants are
operating. By emitting into a common compliance averaging plan, or "bubble,"
electricity generating stations that emit well below the system-wide limit
reduce the overall average for electricity generating stations that emit in
excess of the system-wide limit.
Implementation of the Phase II emission rules commenced on May 1, 1999. The
Phase II NO(x) regulations set forth a NO(x) allowance allocation program which
is expected to give us 6,292 NO(x) emission allowances annually. Each allowance
will authorize us to emit one ton of NO(x) during the ozone season (May 1 to
September 30), beginning in 1999.
To comply with the stricter emissions regulations beginning in 1999, we
installed a selective catalytic reduction system at the Kintigh Generating
Station which became operational in June 1999.
The NO(x) requirements that took effect on May 1, 1999 essentially require
that the former NYSEG plants keep their summertime ozone season (May
1 - September 30) NO(x) emissions within a specific budget of NO(x) emissions
allowances. If the total emissions during this period are below the budget
total, we can sell the excess allowances to companies that emit more than their
budget. Operation of the Kintigh selective catalytic reduction system makes it
likely that the total NO(x)emissions will be below budget, as does the extended
outage for improvements of the Kintigh Generating Station between the middle of
May and the end of June in 1999. The Kintigh selective catalytic reduction
system commenced operation in June 1999. We have experienced, and expect to
continue to experience in the near future, less than the full reduction
efficiency anticipated for the Kintigh selective catalytic reduction system.
Until the technical issues associated with the startup of the Kintigh selective
catalytic reduction system can be fully rectified, we expect that we will not be
able to consistently achieve the fully anticipated removal efficiency (90%). As
a result, we will generate greater NO(x) emissions and, consequently, we will
consume more NO(x) allowances. During the 1999 ozone season, we achieved a
removal efficiency of between 70% and 90% for the Kintigh selective catalytic
reduction system; however, we anticipate that the technical problems will be
resolved in time for the 2000 ozone season.
The Kintigh Generating Station is expected to accumulate approximately
3,400 excess allowances per year from 1999 to 2002 and approximately 2,500
excess allowances from 2003 onwards. A portion of our compliance strategy
involves the selling or trading of excess allowances. We expect that we will be
permitted to sell these excess allowances or to trade them, including trades
between our electricity generating stations as needed to offset NO(x) emissions
at our other electricity generating stations. We are currently permitted to sell
or accumulate NO(x) allowances for use in future years. However, we believe that
accumulated allowances may be subject to discounting depending on the ratio of
total accumulated allowances in the state to New York's state-wide NO(x) budget.
We expect that accumulated allowances would be subject, at most, to a 2-to-1
discount in some future years.
The accumulated allowances would allow each of our electricity generating
stations to run at their planned capacity factors through 2003, when the likely
more stringent Phase III NO(x) regulations are imposed. Since the Phase III
program is still under development, it is difficult for us to predict the size
of the allowance shortfall, if any, that may exist at that time. We may decide
to install a second selective catalytic reduction system at the Milliken
Generating Station in order to continue operation of each of our electricity
generating
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stations at full planned capacity factors during Phase III. We are also
considering other compliance strategies, however, such as the addition of a
selective non-catalytic reduction system as well as repowering the smaller
plants. Considered in the aggregate, we project that our electricity generating
stations will create 2,000 excess allowances per year through 2002 and, if a
selective catalytic reduction system is installed at the Milliken Generating
Station, 400 excess allowances per year after 2002.
New York Governor Pataki's October 14, 1999 initiative also directs the New
York State Department of Environmental Conservation to issue regulations
requiring electric generators to impose stringent NO(x) reduction requirements
on a year-round basis, rather than just during the summertime ozone season. The
Governor is calling for the new regulations to be phased in starting on January
1, 2003 with implementation completed by January 1, 2007. If enacted, the
Governor's initiative has the potential to require further NO(x) emission
reductions at our electricity generating stations and may necessitate the
installation of additional emissions control equipment at certain stations.
The capital cost of the Kintigh Generating Station selective catalytic
reduction system was $31 million. We expect that the system will operate for 20
years at which time we will need to replace the catalyst at an estimated cost of
$4.5 million in 1999 dollars.
We have obtained all material approvals for installation and operation of
the selective catalytic reduction system from the Public Service Commission, the
New York State Board on Electric Generation Siting and the Environment, the New
York State Department of Environmental Protection and the Federal Environmental
Protection Agency, Region II.
Our electricity generating stations have generally achieved continuous
compliance with the current NO(x) reduction requirements with the exception of a
one-time violation of the facility-wide NO(x) emission cap in May 1998. We
believe that, under the Asset Purchase Agreement, any penalty assessed for that
exceedence would be the responsibility of NGE Generation, Inc.
Particulates and Opacity. Each of our electricity generating stations is
currently in compliance with particulate emission limits.
Each of our electricity generating stations is required to meet an opacity
limit. In the past, several of the plants exceeded these limits on various
occasions. This was a common problem at coal-fired electricity generating
plants, and the New York State Department of Environmental Protection has
initiated an enforcement action against several utilities, including NYSEG.
Potential fines and required actions cannot be divulged to the public until a
final settlement is reached. Nevertheless, it would appear that any consent
order will likely have additional monitoring and equipment upgrade requirements,
especially involving upgrades to the electrostatic precipitator at the Greenidge
Generating Station. NYSEG has performed much of this work at NYSEG's expense.
We recently received a draft consent order from the New York State
Department of Environmental Conservation that alleges violations of the opacity
emission limitations in the air permits for the Milliken, Goudey, and Greenidge
Generating Stations. The draft consent order would require us to prepare an
opacity compliance plan and would impose penalties for opacity violations
occurring after the date of the acquisition of our electricity generating
stations, May 14, 1999. We expect to enter a final consent order with the
Department of Environmental Conservation early in 2000. AES NY L.L.C. also
recently received notice from NYSEG that NYSEG has received a draft consent
order from the Department of Environmental Conservation seeking penalties
primarily for opacity violations occurring prior to May 14, 1999. In the notice,
NYSEG asserts that it will seek indemnification from AES NY L.L.C. for any
penalties, attorney fees, and related costs that it incurs in connection with
the consent order. We and AES NY L.L.C. have denied liability for the
pre-closing violations and intend to vigorously defend this claim if NYSEG
pursues litigation or arbitration.
Carbon Dioxide (CO(2)). Environmental concerns related to the impacts of
greenhouse gases (e.g., carbon dioxide, "CO(2)") led to the adoption in 1992 of
the United Nations-sponsored Framework Convention, which was ratified by over
150 countries, including the United States. In 1993, President Clinton committed
the United States to limit CO(2) and other climate-altering gas emissions to
their 1990 levels by the year 2000. However, it became apparent that this goal
was unlikely to be met by most industrialized nations. The Kyoto
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Conference was called in December 1997 to expedite a global climate treaty
supported by the United States. If adopted by the participating nations, any
legally binding global climate treaty will have significant economic
consequences for all U.S. industries, including the electricity generating
industry.
The AES Corporation has been on the leading edge of creating CO(2) offset
projects since 1988 when it started its own project in Guatemala to offset the
emissions from the AES Thames electricity generating station in Connecticut.
Since that time, The AES Corporation has procured four additional projects to
offset CO(2) emissions from other facilities. All of these projects have been
completed at cost-effective margins (that is, approximately 10 cents per ton).
We do not currently plan to use these types of CO(2) offsets for our electricity
generating stations. Cost-effective greenhouse gas mitigation projects like
these may not be available to offset emissions from our electricity generating
stations in the future, especially if numerous other facilities in the United
States and elsewhere are competing for the necessary CO(2) reduction credits.
Water Issues
The federal Clean Water Act prohibits the discharge of any pollutant
(including heat), except in compliance with a discharge permit issued by the
states or the federal Environmental Protection Agency for a term of no more than
five years. There is potential uncertainty with permitting issues in the future,
but much of the uncertainty on these issues is industry-wide because of new
regulatory requirements for cooling water discharges under the National
Pollutant Discharge Elimination System program.
Our electricity generating stations and their ash disposal sites have been
designed and are operated to comply with strict water and wastewater compliance
standards. Groundwater protection measures include coal pile liners at all
stations, lined active ash disposal sites, no active fly ash settling ponds, and
a network of approximately 400 groundwater monitoring wells. New York State has
not only technology-based effluent limitations for surface water discharges, but
is one of the first states in the nation to impose more restrictive limits on
wastewater discharges to ensure that very protective water quality-based
standards are maintained. Our electricity generating stations have numerous
wastewater treatment facilities in order to ensure compliance with these
restrictive discharge limits. In addition, the Kintigh Generating Station
normally operates in a zero process wastewater discharge mode, reusing
wastewater for various plant processes. Similarly, the ash disposal sites must
comply with both technology and water quality-based discharge limits. Where
necessary, lime treatment is employed to remove metals from ash site wastewater
prior to discharge.
In August 1998, NYSEG received notice of intent to file a citizen suit with
the New York State Department of Environmental Protection regarding an alleged
water discharge limit exceedence at the Kintigh Generating Station. NYSEG has
advised us that no citizen suit has been filed in connection with this matter.
If this suit is filed, we believe that under the Asset Purchase Agreement any
liability would be the responsibility of NYSEG.
Hazardous Material and Wastes
The electric utility industry typically uses and/or generates in its
operations a range of potentially hazardous products and by-products. We have
identified a number of site remediation issues at our electricity generating
stations. Under the terms of the Asset Purchase Agreement, NYSEG will retain
pre-closing off-site environmental liabilities associated with our electricity
generating stations (other than liabilities arising from the Weber and Lockwood
ash disposal sites), but we will assume responsibility for contamination at our
electricity generating stations and at the Lockwood ash disposal site.
Prior to presenting the assets for bid, NYSEG had Phase I and Phase II
environmental site assessment reports prepared by an environmental consulting
firm for each of our electricity generating stations and the Lockwood ash
disposal site. Only a Phase I report was prepared for the Weber ash disposal
site. NYSEG's consultant identified environmental contamination at several of
the sites which may potentially require remediation. The AES Corporation
subsequently hired TRC Environmental Corporation to evaluate NYSEG's
consultant's estimated costs for liabilities at these sites. Based upon the
environmental sampling data and observations of NYSEG's environmental
consultants, TRC Environmental Corporation projects that the most probable
estimated cost for environmental liabilities at our electricity generating
stations is $3.834
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million, which is slightly higher than NYSEG's consultant's most probable cost
projection. Overall, TRC Environmental Corporation essentially agreed with
NYSEG's consultant's estimates based on the data available and projected a
maximum estimated total cost of $9.8 million at our electricity generating
stations (excluding closure and post-closure costs for the Weber and Lockwood
ash disposal sites). This maximum cost estimate has been included in our
financial projections.
No estimates for costs of environmental liabilities were established for
the Weber and Lockwood ash disposal sites because NYSEG had budgeted $3 million
and $6 million for closure and post-closure (monitoring and maintenance)
expenses at the Weber and Lockwood ash disposal sites, respectively, and the
consultants did not expect additional costs for environmental investigation or
remediation. We included in our financial projections approximately $6 million
for closure and post-closure (monitoring and maintenance) expenses for the
Lockwood ash disposal site, based solely on amounts previously budgeted for
these activities by NYSEG. AES Creative Resources, L.P. assumed responsibility
for the Weber ash disposal site. Our subsidiary, AEE2, L.L.C., has agreed to
contribute two-thirds of the closure costs for the Weber ash disposal site
(approximately $2 million) based on the amount of ash disposed at the site from
the Goudey Generating Station and the Greenidge Generating Station, which are
owned by AEE2, L.L.C., compared to the amount disposed from the Hickling
Generating Station and the Jennison Generating Station, which were acquired by
AES Creative Resources, L.P.
In October 1999, AES Creative Resources, L.P. entered into a consent order
with the New York State Department of Environmental Protection to resolve
alleged violations of the water quality standards in the groundwater
downgradient of the Weber ash disposal site. The consent order includes a
suspended $5,000 civil penalty and a requirement to submit a work plan to
initiate closure of the landfill by October 8, 2000. The consent order also
calls for a site investigation and there is a possibility that some groundwater
remediation at the site may be required. AEE2, L.L.C. will contribute two-thirds
of the costs to close the landfill, which are anticipated to be approximately $3
million, as well as additional costs for long-term groundwater monitoring. While
the actual closure costs may exceed $3 million, we do not expect any added
closure costs to be material. Nevertheless, if a groundwater remediation is
required, these costs have not been budgeted, and AEE2, L.L.C. may be
responsible for a portion of such costs.
These projected environmental cost estimates are not a guarantee that
additional environmental liabilities will not be incurred, and it is possible
that the actual costs could be significantly higher. In addition, it is possible
that previously unknown environmental conditions will be discovered in the
future. See "RISK FACTORS -- WE WILL HAVE RESPONSIBILITY FOR PRE-EXISTING
ENVIRONMENTAL LIABILITIES AND WILL INCUR EXPENSES AS A RESULT; THESE EXPENSES
MAY EXCEED EXPECTATIONS."
Because the new selective catalytic reduction system at the Kintigh
Generating Station may result in ammonia-contaminated fly ash, we expect to
develop Area 3 of the Kintigh landfill to contain the ammoniated ash. Area 3
will also be used for disposal of ammoniated sludge produced during flue gas
desulfurization system operation while the selective catalytic reduction system
is also in operation (May 1 to September 30). Area 3 will comply with modern
landfill design and performance standards and will be built with a synthetic
liner and a leachate collection system. The disposal area could not be completed
in time for commencement of operation of the selective catalytic reduction
system at the Kintigh Generating Station and we will manage the ash and sludge
in the lined coal pile storage area until the disposal area is ready to receive
it. On April 26, 1999, the New York State Board on Electric Generation Siting
and the Environment approved the plan to use Area 3, subject to approval by the
New York State Department of Environmental Protection of more detailed design
submissions, and approved the use of the coal pile storage area for the
temporary storage of the ammoniated ash.
The Kintigh landfill is under the jurisdiction of the Public Service
Commission. NYSEG's original compliance filing with the Public Service
Commission in 1983 provided that the landfill would be constructed in a 200 acre
section of the site, which NYSEG divided into three areas (Areas 1, 2, and 3).
The landfill was designed to comply with the then-existing solid waste landfill
standards of the New York State Department of Environmental Conservation. Each
area was to receive a separate landfill unit lined with a low permeability
material, usually clay. However, the first 17-acre section of Area 1 of the
landfill was lined with compacted soil
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only. To date, only Area 1 has been used by NYSEG. The Area 1 landfill has been
expanded six times during the years since 1983. When a portion of Area 1 reaches
the maximum allowable elevation (130 feet), it is "capped" by adding compacted
soil and planting ground cover. The entire process is meant to be self-
implementing, with little input from the Public Service Commission unless there
is a problem or a change in design or operation.
In the period since the original approval of the Kintigh landfill, the
Department of Environmental Conservation has modified its solid waste landfill
regulations extensively. As a result of these changes, these regulations
currently allow construction or expansion of landfills only with low
permeability liners and sophisticated leachate collection systems, and impose
higher standards for capping and closing solid waste facilities.
Groundwater conditions present at the Kintigh site make it very difficult
to distinguish between landfill leachate and naturally occurring substances in
the groundwater. Substances that are typically considered indicators of leachate
infiltration into groundwater from ash monofill operations, namely sulfates,
iron and manganese, are also naturally occurring in the groundwater around and
beneath Area 1. NYSEG commissioned independent consultants to perform
groundwater testing using sophisticated geochemical fingerprinting techniques,
which distinguish the major ions of a water sample. NYSEG's consultants have
shown, to the satisfaction of the Public Service Commission, that there has been
no material release of leachate from Area 1 into the groundwater.
In April 1999, the Department of Environmental Conservation and the Public
Service Commission negotiated a Memorandum of Understanding that clarifies their
respective roles with respect to the regulation of the Kintigh landfill.
According to the Memorandum of Understanding, the Public Service Commission's
decisions will continue to control all aspects of Areas 1 and 2 of the landfill,
but the Public Service Commission must defer to current and future Department of
Environmental Conservation regulations, standards and policies with respect to
the development, use and closure of Area 3. The Memorandum of Understanding was
approved by the New York State Board on Electric Generation Siting and the
Environment and was incorporated as part of the April 26, 1999 amendment to the
Certificate of Environmental Compatibility for the Kintigh Generating Station
that we received in connection with installation of the selective catalytic
reduction system.
Factors which could cause actual costs of disposal in Areas 1, 2 and 3 to
vary include, but are not limited to, adoption of more stringent solid waste
landfill regulations by the Department of Environmental Conservation, the
discovery of groundwater contamination from Area 1 and escalation of the costs
of landfill development.
Exceedences of state groundwater standards at the Milliken Generating
Station were reported in the vicinity of the coal pile area, the coal pile
runoff pond, and the ash disposal site. In 1997, a new liner was installed under
the coal pile. Based on data provided by NYSEG, TRC Environmental Corporation,
our environmental consultant, has estimated most probable monitoring and
investigation costs of $270,000 for the coal pile runoff pond and $163,000 for
the disposal area. We have included these costs in our financial projections.
In an area adjacent to the Lockwood ash disposal site, our environmental
consultant, TRC Environmental Corporation, reported that approximately 500 to
700 drums of abrasives were disposed in the early 1970s and covered with ash.
TRC Environmental Corporation projected that the most probable cost to conduct a
site investigation and remove the drums is approximately $520,000. These costs
have been included in our financial projections. In addition, groundwater
sampling in this area and around the Lockwood ash disposal site indicates that
some monitoring wells have parameters which exceed state regulatory limits. As
noted above, we have included $6 million in closure and post-closure (monitoring
and maintenance) costs in our financial projections for the Lockwood ash
disposal site.
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Noise
Noise emissions from our electricity generating stations are regulated
pursuant to New York law which establishes different acceptable noise levels
based upon the nature of the neighboring property uses, with the lowest being
noise standards that must be met at residential properties. In general,
compliance with noise standards is not a material concern with respect to our
electricity generating stations.
The Certificate of Environmental Compatibility that was issued to NYSEG in
1978 for the development and operation of the Kintigh Generating Station
contains a number of requirements for mitigating environmental impacts from the
facility, including noise impacts. Among the noise requirements was an
obligation to obtain noise easements from neighboring landowners or, as
subsequently approved by the Public Service Commission, to purchase their
property in a buffer zone where noncompliance with noise standards was expected
to occur. Subsequent analyses predicted that these exceedences would occur only
in connection with ash disposal operations when Area 2 of the Kintigh landfill
was constructed. Prior to the acquisition of our electricity generating
stations, NYSEG had purchased neighboring properties for a combined cost
totaling approximately $1.5 million and had a standing offer to purchase the
remainder. We obtained an appraisal of the remaining properties which places
their aggregate current value at approximately $3.1 million. We have not
included any amount in our financial projections for the acquisition of these
properties. The Public Service Commission has also required that a noise
mitigation plan be developed and submitted for Public Service Commission
approval at least one year prior to commencement of Area 2 development. The
Public Service Commission could require additional noise control measures at
that time. We do not expect that the noise compliance costs we may incur,
including as a result of taking over the land purchase program, will be
material.
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MANAGEMENT
Our managers are appointed by AES NY, L.L.C., as general partner of our
company. Our managers may be appointed from time to time by AES NY, L.L.C. and
hold their positions at the discretion of AES NY, L.L.C. AES NY, L.L.C. may
elect to appoint additional managers from time to time. The AES Corporation
indirectly owns all member interests in and controls AES NY, L.L.C.
The following table sets forth certain information concerning our
management team as of December 1, 1999.
NAME AGE POSITION
- ---- --- --------
Dan Rothaupt 48 General Manager
John Ruggirello 49 Assistant General Manager
Richard Santoroski 35 Manager of Marketing
Harry Lovrak 48 Kintigh Plant Manager
Mark Adams 42 Milliken Plant Manager
James Mulligan 51 Goudey Plant Manager
Douglas Roll 44 Greenidge Plant Manager
Dan Rothaupt, our management team leader, is a former plant manager for AES
Thames, a coal-fired facility located in the New England power pool region. Mr.
Rothaupt has been with The AES Corporation for 10 years. In addition to AES
Thames, he has managed a number of complex operations including the startup of
The AES Corporation's business in Hawaii with its coal-fired Barbers Point
facility. Mr. Rothaupt has a proven track record of reducing costs while
organizing The AES Corporation's businesses at various locations in the United
States and has 25 years experience working in various aspects of power systems.
Mr. Rothaupt is General Manager of our company. Mr. Rothaupt has a Bachelor of
Science degree in Mechanical Engineering from the United States Coast Guard
Academy.
John Ruggirello is a Vice President of The AES Corporation and has over 21
years of industry experience. Mr. Ruggirello also serves as a board member of
NIGEN, Ltd., a joint venture of The AES Corporation which acquired 760MW of
coal-fired generating assets from the government of Northern Ireland, including
a 45-year-old plant which had an availability of 100% in 1998. Mr. Ruggirello
heads a group within The AES Corporation responsible for project development,
construction and plant operations in much of the eastern United States and
Canada. He served as President of AES Beaver Valley from 1990 to 1996. Mr.
Ruggirello is Assistant General Manager of our Company. He has a Bachelor of
Science degree in Mechanical Engineering from the New Jersey Institute of
Technology.
Richard Santoroski worked for NYSEG for 13 years prior to May 14, 1999
primarily in engineering positions in the system protection and control group
(relay) and in field distribution offices. Mr. Santoroski was formerly the lead
engineer in the electric resource planning group. Mr. Santoroski has extensive
experience in power marketing, including trading physical power options, swaps
and forwards, developing and marketing structured products in the New York power
pool, the New England power pool and the Pennsylvania-New Jersey-Maryland power
pool and overseeing NYSEG's trading, risk management and billing. Mr. Santoroski
is the Manager of Power Marketing of our company. Mr. Santoroski has a Bachelor
of Science degree in Electrical Engineering from Pennsylvania State University
and a Master of Science degree in Electrical Engineering and a Master of
Business Administration, both from Syracuse University.
Harry Lovrak has over 16 years experience in design, start-up and
management of utility plants and has worked for The AES Corporation for 13
years. Mr. Lovrak was formerly the plant manager for AES Beaver Valley, a 50
year old coal-fired facility which has consistently achieved capacity factors in
excess of 90% under Mr. Lovrak's leadership. Mr. Lovrak is the plant manager of
the Kintigh Generating Station. Mr. Lovrak has a Bachelor of Science degree in
Chemical Engineering from Ohio University.
Mark Adams has worked for The AES Corporation for 10 years with experience
primarily in the area of financial accounting and reporting. He has recently
assisted in the takeover of 4,000MW of generating capacity purchased from
Southern California Edison as part of that utility's divestiture program. Mr.
Adams is
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the plant manager of the Milliken Generating Station. Mr. Adams holds a Bachelor
of Science degree in Accounting and Business Administration from Northeastern
State University.
James Mulligan has over 25 years experience in the power generation
business including design and management of utility plants. Mr. Mulligan was
formerly employed by NYSEG as the plant manager at the Milliken Generating
Station. Prior to that, he was responsible for NYSEG's four central area plants,
which achieved the lowest production costs and highest availabilities in their
operating history during his tenure. Mr. Mulligan is the plant manager of the
Goudey Generating Station. Mr. Mulligan has a Bachelor of Science degree in
Mechanical Engineering from the New York Institute of Technology.
Douglas J. Roll has over 17 years experience in the power generation
business in areas of plant management, engineering, design, construction and
start-up of fossil fuel-fired power plants. Mr. Roll was formerly the Station
Manager at NYSEG's Greenidge Station where he directed the efforts of the
station's staff to the lowest production cost and heat rate and highest
reliability and availability in 25 years. Prior to that, Mr. Roll was the
Manager of Mechanical Engineering in NYSEG's Generation Department, responsible
for directing the engineering, design, construction and start-up of large scale
capital projects at NYSEG's coal fired power plants. Mr. Roll is the Plant
Manager of the Greenidge Generating Station. Mr. Roll holds a Bachelor of
Science degree in Mechanical Engineering from Cornell University and a Bachelor
of Arts degree in Biology from Queens College of the City University of New
York. Mr. Roll is a registered Professional Engineer in the State of New York.
DUAL STATUS OF TWO MEMBERS OF MANAGEMENT
We expect that Mr. Ruggirello and Mr. Rothaupt will continue to devote a
portion of their time to other projects for The AES Corporation in addition to
serving us. We expect that Mr. Ruggirello will devote approximately 10% of his
time to the affairs of our company and Mr. Rothaupt will devote approximately
50% of his time to the affairs of our company. We and The AES Corporation
acknowledge that the dual status of these persons may, from time to time,
require attention by one or both of these persons to matters for The AES
Corporation rather than us. In the event that these circumstances arise, we
intend to shift responsibilities of other members of our management team, or to
authorize other persons to act, and to take such other action as may be
necessary to avoid an adverse effect on our business. The remaining portions of
their working time will be devoted to other projects for The AES Corporation,
including electricity generating stations in and around the New York power pool.
In the future, these projects may compete with us. See "RISK FACTORS -- IN THE
FUTURE WE MIGHT COMPETE WITH OTHER ELECTRICITY GENERATING STATIONS OWNED BY THE
AES CORPORATION," and "RELATIONSHIPS WITH AFFILIATES AND RELATED TRANSACTIONS."
COMPENSATION OF MANAGEMENT
We are a recently formed limited partnership. We estimate that for the
first year after organization, the aggregate amount of compensation that we will
pay to all members of our management team as a group, on an annual basis for
services to us in all capacities, is $896,000.
All members of our management team will participate in employee benefit
plans and arrangements sponsored by The AES Corporation, including The AES
Corporation Incentive Stock Option Plan, The AES Corporation Profit Sharing and
Stock Ownership Plan, The AES Corporation Deferred Compensation Plan for
Executive Officers, health and life insurance plans and other plans which may be
established in the future. We will reimburse The AES Corporation for the costs
of health and life insurance based on the proportion of time spent by each
person in attending to our business. We will not reimburse The AES Corporation
for the costs of providing benefits to these persons under any other of the
existing plans.
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MANAGEMENT OF AES NY, L.L.C., THE GENERAL PARTNER OF OUR COMPANY
AES NY, L.L.C., the general partner of our company, is a Delaware limited
liability company managed by managers who are designated as directors. The Board
of Directors of AES NY, L.L.C. comprises two classes of directors, the Class A
Directors and the Class B Director. There are three Class A Directors, Barry J.
Sharp, John R. Ruggirello and Dan Rothaupt, each elected by the members of the
limited liability company. The business and affairs of AES NY, L.L.C. are
managed by the Class A Directors. The Class B Director's only participation in
the management of AES NY, L.L.C. is in matters of bankruptcy or related matters.
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RELATIONSHIPS WITH AFFILIATES AND RELATED TRANSACTIONS
CONTROL BY THE AES CORPORATION; CONFLICTS
We are an indirect, wholly owned subsidiary of The AES Corporation. Since
our formation, The AES Corporation has provided all of our equity funding for
our business and operations. Our only other sources of funding will be our
internally generated cash flow from our electricity generating stations and
amounts available under the working capital credit facility with Credit Suisse
First Boston. In the event of a shortfall between the amount of our commitments
and the foregoing sources of funds, The AES Corporation is not obligated to
provide, and may decide not to provide, any loans or equity contributions to
make up this shortfall. See "DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL RESOURCES."
The AES Corporation has the power to control us. In circumstances involving
a conflict of interest between The AES Corporation, as the sole indirect equity
owner, on the one hand, and the holders of the pass through trust certificates,
effectively as our creditors on the other, there can be no assurance that The
AES Corporation would not exercise its power to control us in a manner that
would benefit The AES Corporation to the detriment of the holders of the pass
through trust certificates.
As of December 31, 1998, the two founders of The AES Corporation, Roger W.
Sant and Dennis W. Bakke, and their immediate families together owned
beneficially approximately 22.2% of the outstanding common stock of The AES
Corporation. As a result of their ownership interests, Messrs. Sant and Bakke
may be able to significantly influence or exert control over the affairs of The
AES Corporation, including the election of directors. As of December 31, 1998,
all of the officers and directors of The AES Corporation and their immediate
families together owned beneficially approximately 29.9% of the outstanding
common stock of The AES Corporation. To the extent that they decide to vote
together, these stockholders would be able to influence significantly or control
the election of the directors, the management and policies of The AES
Corporation and any action requiring stockholder approval, including significant
corporate transactions.
The AES Corporation's existing plants in and around the New York power
pool, such as AES Thames (Uncasville, Connecticut) and AES Beaver Valley
(Monaco, Pennsylvania), do not currently compete with our electricity generating
stations due to having their entire outputs committed for sale under existing
power purchase agreements. Upon expiration or early termination of these
contracts, these operations may compete with our electricity generating
stations. In addition, The AES Corporation may undertake future projects that
could ultimately compete with our electricity generating stations in the New
York power pool.
We have entered into a coal hauling agreement with Somerset Railroad, which
is owned by a wholly owned subsidiary of The AES Corporation. We are obligated
to pay Somerset Railroad amounts that will be sufficient, when added to funds
available to Somerset Railroad from other sources, to enable Somerset Railroad
to pay, when due, all of its operating and other expenses, including interest on
and principal of outstanding indebtedness. We believe that our relationship with
Somerset Railroad, including the coal hauling agreement, enables us to obtain
transportation of coal and other supplies on more favorable terms to us than we
could obtain in an arm's-length transaction with an unrelated railroad. Our
relationship with Somerset Railroad enables us to get the benefit of a dedicated
rail network and to get rail delivery of coal and other supplies at cost. If we
had to obtain these services on an arm's-length basis, we believe that it is
likely that we would have to pay higher charges since an unrelated railroad
would seek to obtain a profit as well as cover costs. Somerset Railroad and the
related electricity generating assets have traditionally been kept separate for
regulatory and liability reasons.
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DESCRIPTION OF THE PASS THROUGH TRUST CERTIFICATES
The existing pass through trust certificates were issued under two separate
pass through trust agreements between us and Bankers Trust, as the pass through
trustee. The pass through trusts were formed for the benefit of the holders of
the pass through trust certificates. The new pass through trust certificates
will be issued under the pass through trust agreements in an aggregate principal
amount of $550,000,000 and will be identical in all material respects to the
existing pass through trust certificates.
The statements under this caption are a summary only. The definitions of
some of the capitalized terms used in the following summary are set forth below
under the caption "-- DEFINITIONS."
As used in this section, (1) the term "existing pass through trust
certificates" refers to the outstanding $550,000,000 Pass Through Trust
Certificates, Series 1999; (2) the term "new pass through trust certificates"
refers to the $550,000,000 Pass Through Trust Certificates, Series 1999, which
will be registered under the Securities Act and which are being offered in this
exchange offer; and (3) the term "pass through trust certificates" refers to
both the existing pass through trust certificates and the new pass through trust
certificates.
For the purposes of this section, the term "operative documents" includes
the pass through trust certificates, the Participation Agreements, the leases,
the facility site leases, the facility site subleases, the lease indentures, the
secured lease obligation notes, the pass through trust agreements, the Deeds,
the Bills of Sale, the memoranda of lease which were recorded to give notice of
the leases, the memoranda of site lease which were recorded to give notice of
the site leases, the memoranda of site sublease which were recorded to give
notice of the site subleases, the mortgages granted by the special purpose
business trusts to the indenture trustee, the tax indemnity agreements among us
and the other parties to the lease transactions, the guaranties from the
corporate parent of some of the institutional investors that formed the special
purpose business trusts of obligations of those institutions, the deposit and
disbursement agreement and the Facilities Support Agreements.
For additional or more specific information, refer to the pass through
trust agreements, Participation Agreements, leases, lease indentures and deposit
and disbursement agreement, which were delivered by the parties at the closing
of the lease transactions on May 14, 1999, copies of which have been filed with
the SEC as exhibits to the registration statement of which this prospectus is a
part.
GENERAL
Except as otherwise indicated, the following summaries relate to each of
the two pass through trust agreements, the pass through trusts formed under the
pass through trust agreements in connection with the closing of the lease
transactions and the pass through trust certificates issued by, or to be issued
by, each pass through trust.
- The existing pass through trust certificates were, and the new pass
through trust certificates will be, issued in fully registered form
without coupons.
- Each new pass through trust certificate will represent a fractional,
undivided interest in the pass through trust created by the pass through
trust agreement under which the new pass through trust certificate will
be issued.
- The property of each pass through trust consists solely of the secured
lease obligation notes held in the pass through trust, all monies at any
time paid on the secured lease obligation notes, all monies due and to
become due on the secured lease obligation notes, funds from time to time
deposited with the pass through trustee in accounts relating to the pass
through trust and any proceeds from the sale by the pass through trustee
of any secured lease obligation note pursuant to the pass through trust
agreement (the "Trust Property").
- Each new pass through trust certificate corresponds to a pro rata share
of the outstanding principal amount of the secured lease obligation notes
held in the related pass through trust and is issuable in minimum
denominations of $100,000 or integral multiples of $1,000 in excess of
$100,000.
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The new pass through trust certificates represent interests in the
respective pass through trusts and do not represent an interest in or obligation
of our company, the pass through trustee or the special purpose business trusts,
or any of their respective affiliates. The pass through trustee will make
distributions to the registered holders of pass through trust certificates (the
"Certificateholders") solely from the Trust Property, to the extent the Trust
Property contains sufficient proceeds to make a distribution. By accepting a new
pass through trust certificate, each Certificateholder agrees that it will look
only to the income and proceeds of the Trust Property provided the Trust
Property is available for distribution. The new pass through trust certificates
will be prepaid when and to the extent that the related secured lease obligation
notes are redeemed, prepaid or purchased. See "-- REDEMPTION OF SECURED LEASE
OBLIGATION NOTES" and "-- THE SECURED LEASE OBLIGATION NOTES -- SPECIAL PURPOSE
BUSINESS TRUST'S RIGHT TO PURCHASE THE SECURED LEASE OBLIGATION NOTES."
FORM OF CERTIFICATES
No person acquiring a beneficial interest in the pass through trust
certificates (a "Certificate Owner") will be entitled to receive a definitive
certificate representing this person's interest in the new pass through trust
certificates, except as set forth below under "-- BOOK-ENTRY; DELIVERY AND
FORM." A "definitive certificate" is a physical certificate in fully registered
form without interest coupons.
Unless and until definitive certificates are issued under the limited
circumstances described in this prospectus, all references to actions by
Certificateholders shall refer to actions taken by The Depository Trust Company
upon instructions from any organization that is a participant in The Depository
Trust Company system and all references in this prospectus to distributions,
notices and communications to Certificateholders shall refer, as the case may
be, to distributions, notices and communications to The Depository Trust Company
or its nominee, Cede & Co., as the registered holder of the certificates, or to
any organization that is a participant in The Depository Trust Company system
for distribution to Certificate Owners in accordance with The Depository Trust
Company procedures. See "-- BOOK-ENTRY; DELIVERY AND FORM."
REGISTRATION RIGHTS; ADDITIONAL INTEREST
We and the institutions that initially purchased the existing pass through
trust certificates (the "initial purchasers") entered into the registration
rights agreement on May 11, 1999. Under the registration rights agreement, we
agreed to file with the SEC the exchange offer registration statement of which
this prospectus is a part under the Securities Act with respect to an exchange
offer to the Certificateholders of existing pass through trust certificates. As
part of the exchange offer, we are also soliciting consents from the holders of
the existing pass through trust certificates to a waiver of our obligation to
file a shelf registration statement as a result of our failure to complete the
exchange offer on or prior to November 10, 1999. If we obtain the consent of the
holders of a majority of the aggregate principal amount of the existing pass
through trust certificates, we will not file a shelf registration statement
unless otherwise required by the registration rights agreement.
Upon the effectiveness of this exchange offer registration statement, we
will offer new pass through trust certificates in exchange for existing pass
through trust certificates to the Certificateholders of existing pass through
trust certificates who are able to make certain representations.
SHELF REGISTRATION STATEMENT. We agreed to use our reasonable best efforts
to prepare and file, as promptly as practicable, with the SEC, and cause to be
declared effective a registration statement under Rule 415 of the Securities Act
(a "shelf registration statement") as described below in clauses (1) through
(4). We will not be required to file a shelf registration statement as provided
in clause (2) if the holders of a majority of the aggregate principal amount of
the existing pass through trust certificates consent to the proposed waiver of
that obligation under the registration rights agreement. The waiver we are
seeking will not affect our obligation to file a shelf registration statement
under clauses (1), (3) or (4). The shelf registration statement will cover the
offer and sale of the existing pass through trust certificates from time to
time. We will file a shelf registration statement if:
(1) we determine that an exchange offer is not available or may not be
completed as soon as practicable after the last date the exchange offer
is open because it would violate applicable law or the applicable
interpretations of the staff of the SEC;
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(2) the exchange offer is not completed within 180 days after the date of
original issue of the existing pass through trust certificates; this
provision will not be applicable if we obtain the consent of the
holders of a majority of the aggregate principal amount of the existing
pass through trust certificates;
(3) the initial purchasers so request with respect to the securities not
eligible to be exchanged for new pass through trust certificates in the
exchange offer and held by them following completion of the exchange
offer; or
(4) any Certificateholder, other than an exchanging dealer, is not eligible
to participate in the exchange offer, or any Certificateholder, other
than an exchanging dealer, that participates in the exchange offer does
not receive freely tradeable new pass through trust certificates on the
date of the exchange for validly tendered existing pass through trust
certificates, which are not withdrawn.
No Certificateholder, other than the initial purchasers, is entitled to
have any existing pass through trust certificates held by it covered by the
shelf registration statement unless that Certificateholder agrees in writing to
be bound by all the provisions of the registration rights agreement applicable
to that Certificateholder.
EXISTING PASS THROUGH TRUST CERTIFICATES. The term "existing pass through
trust certificates" means each existing pass through trust certificate until:
(1) the date on which a person other than a broker-dealer exchanges the
existing pass through trust certificate for a freely transferable new
pass through trust certificate in the exchange offer;
(2) following the exchange by a broker-dealer in the exchange offer of an
existing pass through trust certificate for a new pass through trust
certificate, the date on which the new pass through trust certificate
received in the exchange offer is sold to a purchaser who receives from
the broker-dealer, on or prior to the date of the sale, a copy of the
prospectus constituting part of the exchange offer registration
statement;
(3) the date on which the existing pass through trust certificate has been
effectively registered under the Securities Act and disposed of in
accordance with the shelf registration statement; or,
(4) the date on which the existing pass through trust certificate is
distributed to the public pursuant to Rule 144 under the Securities Act
or becomes freely tradeable under Rule 144(k) under the Securities Act.
An "exchanging dealer" is a Certificateholder that is a broker-dealer
electing to exchange existing pass through trust certificates, acquired for its
own account as a result of market-making activities or other trading activities,
for new pass through trust certificates.
OUR OBLIGATIONS REGARDING THE EXCHANGE OFFER REGISTRATION STATEMENT. The
registration rights agreement further provides that:
(1) we will use our best efforts to cause the exchange offer registration
statement to be declared effective by October 11, 1999, which is 150
days after the original issue date of the existing pass through trust
certificates;
(2) unless the exchange offer would not be permitted by applicable law or
SEC policy, we will begin the exchange offer and keep the exchange
offer open for not less than 30 days, or longer if required by
applicable law, after the date on which notice of the exchange offer is
mailed to Certificateholders; and
(3) if we are obligated to file a shelf registration statement instead of
an exchange offer registration statement, we will use our reasonable
best efforts to file, as promptly as practicable, the shelf
registration statement with the SEC and to cause the shelf registration
statement to be declared effective by the SEC.
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ADDITIONAL INTEREST. We are required to pay interest in addition to the
interest otherwise due on the existing pass through trust certificates
("Additional Interest") at the rate of 0.50% per annum as a result of our
failure to complete this exchange offer on or prior to November 10, 1999, which
is 180 days after the original issue date of the existing pass through trust
certificates. Additional Interest will accrue until we complete this exchange
offer. We will also be required to pay Additional Interest in the event that we
are obligated to file a shelf registration statement under the registration
rights agreement and after the date that any shelf registration statement is
declared effective, (A) that shelf registration statement ceases to be effective
or (B) that shelf registration statement or the related prospectus ceases to be
usable in connection with resales of existing pass through trust certificates,
in each case during the period that we are required to maintain the
effectiveness of the shelf registration statement and other than as permitted
under the registration rights agreement. Additional Interest will continue to
accrue until a shelf registration statement is declared effective and continues
to be effective for use in connection with the resale of existing pass through
trust certificates. Under the registration rights agreement, we agreed to pay
Additional Interest on the existing pass through trust certificates on regular
interest payment dates.
REPRESENTATIONS AND OBLIGATIONS OF CERTIFICATEHOLDERS. Certificateholders
will be required to:
(1) make the representations to us, which are described in the registration
rights agreement, in order to participate in the exchange offer;
(2) deliver information to be used in connection with the shelf
registration statement, if any; and
(3) provide comments on the shelf registration statement within the time
periods set forth in the registration rights agreement in order to have
their existing pass through trust certificates included in the shelf
registration statement.
SAME-DAY SETTLEMENT AND PAYMENT
We will make all payments under the leases to the indenture trustee, as
assignee of the special purpose business trusts, and subsequently to the pass
through trustee in immediately available funds which will be passed through to
The Depository Trust Company in immediately available funds.
Secondary trading in long-term notes and debentures of corporate issuers is
generally settled in clearinghouse or next-day funds. In contrast, secondary
trading in pass through trust certificates is generally settled in immediately
available funds. The pass through trust certificates will trade in The
Depository Trust Company's Same-Day Funds Settlement System until maturity, and,
therefore, The Depositary Trust Company will require that secondary market
trading activity in the pass through trust certificates settle in immediately
available funds. No assurance can be given as to the effect, if any, of
settlement in immediately available funds on trading activity in the pass
through trust certificates.
PAYMENTS AND DISTRIBUTIONS
Scheduled payments of principal and interest on the secured lease
obligation notes are referred to in this section as "Scheduled Payments," and
January 2 and July 2 of each year, beginning January 2, 2000, are referred to in
this section as "Regular Distribution Dates."
Each Certificateholder is entitled to receive a pro rata share of any
distribution in respect of Scheduled Payments of principal and interest made on
the secured lease obligation notes. The pass through trustee will distribute all
Scheduled Payments of principal and interest on the secured lease obligation
notes held in each pass through trust received by the pass through trustee prior
to 2:00 p.m., New York time, to Certificateholders on the same date. The pass
through trustee will distribute Scheduled Payments received by the pass through
trustee after 2:00 p.m., New York time, on the next Business Day.
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INTEREST. Payments of interest on the unpaid principal amount of the
secured lease obligation notes held in the pass through trusts are scheduled to
be received by the pass through trustee on each January 2 and July 2 of each
year, beginning January 2, 2000, at the applicable rate per annum for the pass
through trust, at the rate indicated on the cover page of this prospectus, until
the final distribution date for the pass through trust. Interest will be passed
through to Certificateholders of each of the pass through trusts at the
applicable rate per annum, calculated on the basis of a 360-day year of twelve
30-day months.
PRINCIPAL. The initial principal amount of the pass through trust
certificates is as follows:
Series 1999-A........................................ $282,000,000
Series 1999-B........................................ 268,000,000
------------
$550,000,000
Scheduled aggregated payments in respect of principal of the secured lease
obligation notes for each of the Series 1999-A Pass Through Trust Certificates
and the Series 1999-B Pass Through Trust Certificates are as follows:
SCHEDULED AGGREGATED SCHEDULED AGGREGATED
PAYMENTS OF PERCENTAGE OF PAYMENTS OF PERCENTAGE OF
PRINCIPAL INITIAL BALANCE PRINCIPAL INITIAL BALANCE
OF SERIES 1999-A OF SERIES 1999-A OF SERIES 1999-B OF SERIES 1999-B
REGULAR DISTRIBUTION DATES CERTIFICATES CERTIFICATES CERTIFICATES CERTIFICATES
- -------------------------- -------------------- --------------------- -------------------- ----------------
January 2, 2000........ $ 0 0.0000000000% $ 0 0.0000000000%
July 2, 2000........... 0 0.0000000000% 0 0.0000000000%
January 2, 2001........ 0 0.0000000000% 0 0.0000000000%
July 2, 2001......... 0 0.0000000000% 0 0.0000000000%
January 2, 2002........ 0 0.0000000000% 0 0.0000000000%
July 2, 2002......... 0 0.0000000000% 0 0.0000000000%
January 2, 2003........ 0 0.0000000000% 0 0.0000000000%
July 2, 2003......... 1,526,405 0.5412782128% 0 0.0000000000%
January 2, 2004........ 5,395,888 1.9134355319% 0 0.0000000000%
July 2, 2004......... 5,638,703 1.9995401312% 0 0.0000000000%
January 2, 2005........ 2,942,445 1.0434201489% 0 0.0000000000%
July 2, 2005......... 4,974,855 1.7641329184% 0 0.0000000000%
January 2, 2006........ 2,348,723 0.8328806028% 0 0.0000000000%
July 2, 2006......... 6,354,416 2.2533389539% 0 0.0000000000%
January 2, 2007........ 3,690,365 1.3086399149% 0 0.0000000000%
July 2, 2007......... 6,806,431 2.4136280035% 0 0.0000000000%
January 2, 2008........ 4,162,720 1.4761419716% 0 0.0000000000%
July 2, 2008......... 7,300,043 2.5886676525% 0 0.0000000000%
January 2, 2009........ 4,678,545 1.6590584043% 0 0.0000000000%
July 2, 2009......... 7,839,079 2.7798153227% 0 0.0000000000%
January 2, 2010........ 5,241,838 1.8588077234% 0 0.0000000000%
July 2, 2010......... 11,315,220 4.0124895319% 0 0.0000000000%
January 2, 2011........ 8,599,405 3.0494345390% 0 0.0000000000%
July 2, 2011......... 12,211,379 4.3302761135% 0 0.0000000000%
January 2, 2012........ 9,535,891 3.3815215177% 0 0.0000000000%
July 2, 2012......... 14,240,006 5.0496474326% 0 0.0000000000%
January 2, 2013........ 11,555,806 4.0978035532% 0 0.0000000000%
July 2, 2013......... 17,238,317 6.1128784716% 0 0.0000000000%
January 2, 2014........ 14,514,042 5.1468232518% 0 0.0000000000%
July 2, 2014......... 18,667,173 6.6195650496% 0 0.0000000000%
January 2, 2015........ 16,007,196 5.6763107270% 0 0.0000000000%
July 2, 2015......... 20,227,520 7.1728794610% 0 0.0000000000%
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SCHEDULED AGGREGATED SCHEDULED AGGREGATED
PAYMENTS OF PERCENTAGE OF PAYMENTS OF PERCENTAGE OF
PRINCIPAL INITIAL BALANCE PRINCIPAL INITIAL BALANCE
OF SERIES 1999-A OF SERIES 1999-A OF SERIES 1999-B OF SERIES 1999-B
REGULAR DISTRIBUTION DATES CERTIFICATES CERTIFICATES CERTIFICATES CERTIFICATES
- -------------------------- -------------------- --------------------- -------------------- ----------------
January 2, 2016........ 17,637,758 6.2545242837% 0 0.0000000000%
July 2, 2016......... 21,931,458 7.7771126277% 0 0.0000000000%
January 2, 2017........ 19,418,373 6.8859479468% 0 0.0000000000%
July 2, 2017......... 0 0.0000000000%
January 2, 2018........ -- -- 19,645,840 7.3305371269%
July 2, 2018......... -- -- 24,742,076 9.2321180373%
January 2, 2019........ -- -- 22,438,356 8.3725207948%
July 2, 2019......... -- -- 27,023,250 10.0833023246%
January 2, 2020........ -- -- 24,829,824 9.2648598433%
July 2, 2020......... -- -- 22,257,313 8.3049675261%
January 2, 2021........ -- -- 20,526,124 7.6590014552%
July 2, 2021......... -- -- 10,085,543 3.7632623470%
January 2, 2022........ -- -- 0 0.0000000000%
July 2, 2022......... -- -- 10,164,581 3.7927539590%
January 2, 2023........ -- -- 0 0.0000000000%
July 2, 2023......... -- -- 11,197,434 4.1781470224%
January 2, 2024........ -- -- 0 0.0000000000%
July 2, 2024......... -- -- 12,335,239 4.6027010261%
January 2, 2025........ -- -- 0 0.0000000000%
July 2, 2025......... -- -- 13,588,659 5.0703952276%
January 2, 2026........ -- -- 0 0.0000000000%
July 2, 2026......... -- -- 14,969,443 5.5856132388%
January 2, 2027........ -- -- 0 0.0000000000%
July 2, 2027......... -- -- 16,490,533 6.1531840896%
January 2, 2028........ -- -- 0 0.0000000000%
July 2, 2028......... -- -- 8,643,925 3.2253452687%
January 2, 2029........ -- -- 9,061,859 3.3812907127%
Detailed information about the scheduled payments of principal in respect of the
secured lease obligation notes is set forth in Schedule I attached to this
prospectus.
REDEMPTION. The secured lease obligation notes may be redeemed prior to
maturity in some circumstances. It is possible that some, but not all, secured
lease obligation notes could be redeemed prior to maturity. For example, the
secured lease obligation notes relating to the Milliken Generating Station could
be redeemed without the secured lease obligation notes relating to the Kintigh
Generating Station being redeemed. Redemption of secured lease obligation notes
prior to maturity would result in the distribution of principal in respect of
these secured lease obligation notes earlier than the scheduled distribution
dates shown in the table above and in Schedule I. See "-- REDEMPTION OF SECURED
LEASE OBLIGATION NOTES."
GENERAL. Certificateholders of record will receive all Scheduled Payments
on each Regular Distribution Date if the pass through trustee receives the
Scheduled Payments due on a particular date by 2:00 p.m., New York time. The
record date for the distribution of Scheduled Payments will be the fifteenth day
preceding the Regular Distribution Date, subject to limited exceptions. If a
Scheduled Payment is not received by the pass through trustee on a Regular
Distribution Date but is received within five days after a Regular Distribution
Date, it will be distributed on the date received to the holders of record (if
received by the pass through trustee by 2:00 p.m., New York time on such date).
If it is received after the five-day grace period, it will be treated as a
special payment ("Special Payment") and distributed as described below.
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The pass through trust agreements require that the pass through trustee
establish and maintain with itself, on behalf of and for the benefit of the
Certificateholders, one or more non-interest bearing accounts (each, a
"Certificate Account") for the deposit of payments representing Scheduled
Payments on the secured lease obligation notes held in the related pass through
trust. The pass through trust agreements also require that the pass through
trustee establish and maintain with itself, on behalf of and for the benefit of
the Certificateholders, one or more accounts (each, a "Special Payments
Account") for the deposit of payments representing Special Payments.
Under the terms of the pass through trust agreements, the pass through
trustee is required to deposit immediately any Scheduled Payments received by it
in the Certificate Account and to deposit immediately any Special Payments so
received by it in the Special Payments Account. The pass through trustee will
distribute all of the deposited amounts on a Regular Distribution Date or a
Special Distribution Date (as defined in the next paragraph), as appropriate.
Each Certificateholder will receive its pro rata share of the aggregate amount
in the Certificate Account or Special Payments Account, as applicable. The pro
rata share will be based on the aggregate fractional undivided interest held by
the Certificateholder.
In addition to Scheduled Payments with respect to principal, the secured
lease obligation notes, and consequently the pass through trust certificates are
subject to partial or full prepayment under some circumstances. See
"-- REDEMPTION OF SECURED LEASE OBLIGATION NOTES." Payments of principal,
premium, if any, and interest received by the pass through trustee on account of
a partial or full prepayment, if any, of the secured lease obligation notes held
in the related pass through trust, and payments received by the pass through
trustee following a default in respect of the secured lease obligation notes
held in the related pass through trust (including, but not limited to, payments
received on account of the sale of these secured lease obligation notes by the
pass through trustee) are Special Payments and will be distributed on the second
day of a month, unless the Special Payment is with respect to the prepayment of
secured lease obligation notes. If the Special Payment relates to the prepayment
of secured lease obligation notes, distributions will be made on the date
prepayment is scheduled to occur under the terms of the applicable lease
indenture. The date on which a Special Payment is scheduled to be made is
referred to in this prospectus as a "SPECIAL DISTRIBUTION DATE." The pass
through trustee will distribute Special Payments on the scheduled Special
Distribution Date so long as payment is received by the pass through trustee by
2:00 p.m., New York time on the Special Distribution Date.
The pass through trustee will mail notice of each Special Payment to the
Certificateholders of record and, upon request, to Certificate Owners. This
notice will contain the following information,
- the Special Distribution Date and record date,
- the amount of the Special Payment per $1,000 of face amount of
certificates and the extent to which it constitutes principal, premium,
if any, and interest,
- the reason for the Special Payment, and
- if the Special Distribution Date is the same as a Regular Distribution
Date, the total amount to be received on this date per $1,000 of face
amount of Certificates.
The record date for each distribution of a Special Payment on a Special
Distribution Date for each pass through trust will be the fifteenth day
preceding the Special Distribution Date. See "-- REDEMPTION OF SECURED LEASE
OBLIGATION NOTES" and "-- EVENTS OF DEFAULT AND CERTAIN RIGHTS UPON AN EVENT OF
DEFAULT." Distributions by the pass through trustee from the Certificate Account
or the Special Payments Account of the related pass through trust on a Regular
Distribution Date or a Special Distribution Date will be made:
(1) by wire transfer in immediately available funds to an account
maintained by a Certificateholder with a bank, if
(A) The Depository Trust Company is the Certificateholder of record,
(B) a Certificateholder holds pass through trust certificates in an
aggregate amount greater than $10 million, or
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(C) any Certificateholder that holds pass through trust certificates in
an aggregate amount greater than $1 million requests that the
distributions be made by wire transfer; or
(2) if none of the options in clause (1) apply, by check mailed to each
Certificateholder of record on the applicable record date at its
address appearing on the register maintained for the related pass
through trust.
The final distribution for each pass through trust, however, will be made
only upon presentation and surrender of the pass through trust certificates at
the office or agency of the pass through trustee specified in the notice given
by the pass through trustee of the final distribution. The pass through trustee
will mail the notice of the final distribution at maturity, redemption or
otherwise to the Certificateholders of record no earlier than 60 days and no
later than 20 days next preceding the final distribution, specifying the date
set for the final distribution and the amount of the final distribution. See
"-- TERMINATION OF THE PASS THROUGH TRUSTS."
If any Regular Distribution Date or Special Distribution Date is not a
Business Day, distributions scheduled to be made on the Regular Distribution
Date or Special Distribution Date may be made on the next succeeding Business
Day without any additional interest accruing during the intervening period.
STATEMENTS TO CERTIFICATEHOLDERS
On each Regular Distribution Date and Special Distribution Date, if any,
the pass through trustee will include with each distribution of a Scheduled
Payment or Special Payment, if any, to Certificateholders of record a statement,
giving effect to the distribution to be made on the Regular Distribution Date or
Special Distribution Date, as the case may be, setting forth the following
information per $1,000 face amount certificate:
(1) the amount of the distribution allocable to principal and the amount
allocable to premium, if any; and
(2) the amount of the distribution allocable to interest.
In addition, within a reasonable time after the end of each calendar year
but not later than the latest date permitted by law, the pass through trustee
will furnish to each person who at any time during the calendar year was a
Certificateholder of record and, upon each Certificate Owner's request, each
person who at any time during the calendar year was a Certificate Owner, a
statement specifying the sum of the amounts determined in clauses (1) and (2)
above with respect to the related pass through trust for the calendar year. In
the event this person was a Certificateholder of record or Certificate Owner
during a portion of the calendar year, the pass through trustee will furnish a
statement specifying the amounts determined in clauses (1) and (2) for the
applicable portion of the calendar year. In addition, the pass through trustee
shall furnish other items as are readily available to the pass through trustee
and which a Certificateholder or Certificate Owner shall reasonably request as
necessary for the purpose of the Certificateholder's or Certificate Owner's
preparation of federal income tax returns.
The report and the other items specified in the immediately preceding
paragraph shall be prepared on the basis of information supplied to the pass
through trustee by participants in The Depository Trust Company system and the
Certificate Owners. The pass through trustee will notify Certificateholders of
all defaults under the pass through trust agreements known to the pass through
trustee within 90 days after the occurrence of a default; provided, however,
that the pass through trustee will be protected if it withholds notice from the
Certificateholders of a default other than a failure to pay principal of,
premium, if any, or interest on any secured lease obligation note, so long as
the board of directors, the executive committee or a trust committee of
directors or specified responsible officers of the pass through trustee
determine in good faith that the withholding of notice is in the interests of
the Certificateholders and the Certificate Owners.
If the pass through trust certificates are issued in definitive form, the
pass through trustee will prepare and deliver the information described above to
each Certificateholder of record as the name and period of record ownership of
the Certificateholder appears on the records of the registrar of the pass
through trust certificates.
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As long as any pass through trust certificates remain outstanding, we will
be required to furnish to the pass through trustee unaudited quarterly and
audited annual financial statements together with a discussion and analysis
substantially conforming with the requirements of Form 10-Q promulgated under
the Exchange Act for quarterly reports and Form 10-K promulgated under the
Exchange Act for annual reports. We are required to furnish all unaudited
quarterly financial statements to the pass through trustee within 60 days
following the end of each of our first three fiscal quarters during each fiscal
year. We are also required to furnish our audited annual financial statements to
the pass through trustee within 120 days following the end of each of our fiscal
years. In addition, we will be required to furnish to the pass through trustee
notice of certain material events related to us within 120 days after their
occurrence. We are also required to furnish to Certificateholders, Certificate
Owners and prospective investors, upon their request, any information required
to be delivered pursuant to Rule 144A(d)(4) under the Securities Act so long as
the existing pass through trust certificates are not freely transferable under
the Securities Act. We are also required to furnish annually to the pass through
trustee a statement as to the fulfillment of our covenants and obligations under
the pass through trust agreements.
The pass through trustee will, upon request, furnish all of this
information directly to Certificateholders and Certificate Owners.
VOTING OF SECURED LEASE OBLIGATION NOTES
The pass through trustee of each pass through trust has the right under the
lease indentures in some circumstances to vote and give waivers in respect of
the secured lease obligation notes held in the pass through trust. Each pass
through trust agreement sets forth the circumstances under which the pass
through trustee will direct any action or cast any vote as the holder of the
secured lease obligation notes at its own discretion and the circumstances in
which the pass through trustee will seek instructions from the
Certificateholders.
Prior to an Event of Default with respect to any pass through trust, the
principal amount of the secured lease obligation notes held in the pass through
trust directing any action or being voted for or against any proposal will be in
proportion to the principal amount of pass through trust certificates held by
the Certificateholders taking the corresponding position. An Event of Default
under the pass through trust agreements is defined as the occurrence and
continuance of an event of default under the related lease indentures (a "Lease
Indenture Event of Default").
REDEMPTION OF SECURED LEASE OBLIGATION NOTES
The secured lease obligation notes may be redeemed under the circumstances
set forth below. The pass through trustee will make distributions to the
Certificateholders of each pass through trust related to the secured lease
obligation notes being redeemed on the date and in the amount paid in respect of
the redemption of these secured lease obligation notes.
OPTIONAL REDEMPTION. All secured lease obligation notes outstanding under
a lease indenture will be redeemed, in whole but not in part, at the principal
amount at the date of redemption together with interest accrued to the date of
redemption plus a "Make Whole Premium," if any, upon any optional refinancing of
the secured lease obligation notes. No such refinancing will occur without our
consent. We have the right, at our option and expense, exercisable on three
occasions at any time following May 14, 2006, to request the special purpose
business trusts or the pass through trusts to refund or refinance the pass
through trust certificates either in the public or private market, in whole or
in part, subject to the conditions set forth in the lease indentures and the
Participation Agreements.
SPECIAL MANDATORY REDEMPTION WITH MAKE WHOLE PREMIUM. All secured lease
obligation notes outstanding under a lease indenture will be redeemed, in whole
but not in part, at the principal amount at the date of redemption, together
with interest accrued to the redemption date plus a Make Whole Premium, if any,
following a Lease Indenture Event of Default caused by the occurrence of an
event of default under the related lease (a "Lease Event of Default") and the
acceleration of the secured lease obligation notes; provided, that no Lease
Event of Default under any other lease shall have occurred. Lease Indenture
Events of Default are described in more detail below under the caption, "-- THE
SECURED LEASE OBLIGATION NOTES --
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LEASE INDENTURE EVENTS OF DEFAULT" and Lease Events of Default are described
below under the caption, "-- THE LEASES, THE FACILITY SITE LEASES AND THE
FACILITY SITE SUBLEASES -- LEASE EVENTS OF DEFAULT."
"Make Whole Premium" means an amount equal to the Discounted Present Value
calculated for any secured lease obligation note which may be redeemed pursuant
to any lease indenture less the unpaid principal amount of this secured lease
obligation note; provided, that the Make Whole Premium shall not be less than
zero.
For purposes of this definition, the "Discounted Present Value" of any
secured lease obligation note which may be redeemed under any lease indenture
shall be equal to the discounted present value of all principal and interest
payments scheduled to become due in respect of the secured lease obligation note
after the date of redemption, calculated using a discount rate equal to the sum
of
- the yield to maturity on the U.S. Treasury security having an average
life equal to the remaining average life of this secured lease obligation
note and trading in the secondary market at the price closest to par, and
- 50 basis points.
If there is no U.S. Treasury security having an average life equal to the
remaining average life of the secured lease obligation note, the discount rate
shall be calculated using a yield to maturity interpolated or extrapolated on a
straight-line basis (rounding to the nearest basis point, if necessary) from the
yields to maturity for two U.S. Treasury securities having average lives most
closely corresponding to the remaining average life of the secured lease
obligation note and trading in the secondary market at the price closest to par.
SPECIAL MANDATORY REDEMPTION WITH A MODIFIED MAKE WHOLE PREMIUM. All
secured lease obligation notes outstanding under a lease indenture will be
redeemed at any time on or after May 14, 2006, in whole but not in part, at the
principal amount at the date of redemption, together with accrued interest to
the redemption date plus a Modified Make Whole Premium, if any, upon the
exercise by us of our right of early termination under the related lease. We may
only exercise this right so long as no Lease Bankruptcy Default or Lease Event
of Default shall have occurred and be continuing, following a determination by
us that the Kintigh Generating Station or the Milliken Generating Station, as
applicable, is economically or technologically obsolete, other than as a result
of a change in Applicable Law, or surplus to our needs or no longer useful in
our trade or business including, but not limited to, as a result of:
(1) a change in the markets for the wholesale purchase and/or sale of
energy, as determined in good faith by the board of directors of our
company's general partner; or
(2) any material abrogation by any purchaser under a power purchase
agreement, as determined in good faith by the board of directors of our
company's general partner.
Prior to any termination, we will deliver to the applicable institutional
investors that formed the special purpose business trusts, the indenture trustee
and the pass through trustee a certificate of the board of directors of our
company's general partner setting forth in reasonable detail the basis on which
we are exercising this termination right.
If we exercise our rights to terminate a lease for a particular electricity
generating station as a result of obsolescence as described above, we can be
required in some cases to terminate all leases, including leases for the other
electricity generating station, in which the applicable institutional investor
that formed the special purpose business trusts or any of its affiliates has an
interest.
In the event of an early termination or an early termination following a
determination by us that the applicable electricity generating station is
economically or technologically obsolete as a result of a change in Applicable
Law, including any regulation or tariff of general application, we will, as
non-exclusive agent for the special purpose business trusts, use commercially
reasonable efforts to obtain bids and sell the special purpose business trusts'
interests in the undivided interests in the Kintigh Generating Station and the
Milliken Generating Station and the ground interests in the real property
related to the electricity generating station. All of the proceeds from any sale
will be paid directly to the applicable special purpose business trusts or to
the
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indenture trustee, as long as the lien of the related lease indentures shall not
have been terminated or discharged. The purchaser of these interests may not be
us, any affiliate of ours or any third party with whom we or an affiliate of
ours has an arrangement to use or operate the facility to generate power for our
benefit or the benefit of an affiliate of ours after the termination of the
lease.
"Modified Make Whole Premium" means an amount equal to the Discounted
Present Value calculated for any secured lease obligation note which may be
redeemed pursuant to any lease indenture less the unpaid principal amount of
this secured lease obligation note. The Modified Make Whole Premium shall not be
less than zero.
For purposes of this definition, the "Discounted Present Value" of any
secured lease obligation note which may be redeemed under any lease indenture
shall be equal to the discounted present value of all principal and interest
payments scheduled to become due in respect of the secured lease obligation note
after the date of redemption. The discounted present value shall be calculated
using a discount rate equal to the sum of
- the yield to maturity on the U.S. Treasury security having an average
life equal to the remaining average life of such secured lease obligation
note and trading in the secondary market at the price closest to par, and
- 100 basis points.
If there is no U.S. Treasury security having an average life equal to the
remaining average life of the secured lease obligation note, the discount rate
shall be calculated using a yield to maturity interpolated or extrapolated on a
straight-line basis (rounding to the nearest basis point, if necessary) from the
yields to maturity for two U.S. Treasury securities having average lives most
closely corresponding to the remaining average life of the secured lease
obligation note and trading in the secondary market at the price closest to par.
MANDATORY REDEMPTION WITHOUT PREMIUM. All secured lease obligation notes
outstanding under a lease indenture will be redeemed, in whole but not in part,
at the principal amount at the date of redemption, together with accrued
interest to the redemption date but without any premium, under any of the
following circumstances:
(1) Upon the occurrence of an Event of Loss (as defined under the heading
"-- THE LEASES, THE FACILITY SITE LEASES AND THE FACILITY SITE
SUBLEASES -- EVENT OF LOSS") under the related lease, other than a
Regulatory Event of Loss (as defined under the heading "-- THE LEASES,
THE FACILITY SITE LEASES AND THE FACILITY SITE SUBLEASES -- EVENT OF
LOSS") in respect of which we acquire the related undivided interest in
the Kintigh Generating Station and the Milliken Generating Station and
assume the related secured lease obligation notes in accordance with
the lease indenture;
(2) So long as no Lease Bankruptcy Default or Lease Event of Default shall
have occurred and be continuing, we exercise our option under the
related lease to terminate the lease, unless we assume the related
secured lease obligation notes in accordance with the related lease
indenture, if
(A) it becomes illegal for us to continue these leases or to make
payments under the leases, other than as a result of events caused
by us or any affiliate of ours with a purpose of enabling us to have
the right to exercise an option to purchase the related undivided
interest in the Kintigh Generating Station and the Milliken
Generating Station, and the transactions contemplated thereby cannot
be restructured in a manner reasonably acceptable to us, or
(B) one or more events, other than as a result of events caused by us or
any affiliate of ours with a purpose of enabling us to have the
right to exercise an option to purchase the related undivided
interest in the Kintigh Generating Station and the Milliken
Generating Station, occur which have given or will give rise to
obligations of us to make indemnification or other payments under
the related operative documents (other than the tax indemnity
agreement) and these indemnity obligations can be avoided by our
purchase of the related undivided interest in the Kintigh Generating
Station and the Milliken Generating Station and the present value of
the
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avoided indemnity obligations exceeds 3% of the Purchase Price of
the undivided interest in the Kintigh Generating Station and the
Milliken Generating Station; or
(3) So long as no Lease Bankruptcy Default or Lease Event of Default shall
have occurred and be continuing, exercise by us of our right under the
related lease to terminate the lease following a determination by us
that the applicable electricity generating station is economically or
technologically obsolete as a result of a change in Applicable Law,
including any regulation or tariff of general application. Prior to
this termination, we shall deliver to the applicable institutional
investors that formed the special purpose business trusts, the
indenture trustee and the pass through trustee a certificate of the
board of directors of our company's general partner setting forth in
reasonable detail the basis on which it is exercising this termination
right.
If we exercise our rights to terminate a lease for a particular electricity
generating station as a result of illegality or a burdensome indemnity as
described above, we can be required to terminate all leases, including leases
for the other electricity generating station, in which the applicable
institutional investor that formed the special purpose business trusts (or any
affiliate) has an interest.
COVENANTS
We will be subject to the following covenants:
MERGER, CONSOLIDATION. We will not, and will not permit AES NY, L.L.C. or
any AES Eastern Energy Subsidiary to, consolidate or merge with or into any
other person, unless we shall have provided 10 Business Days' prior written
notice to the special purpose business trusts, the institutional investors that
formed the special purpose business trusts and, so long as the Lien of the lease
indenture shall not have been terminated or discharged, the indenture trustee
and the pass through trustee and immediately after giving effect to the
transaction:
(1) no Lease Material Default or Lease Event of Default shall have occurred
and be continuing;
(2) the entity resulting from this consolidation or surviving in this
merger shall be (A) in the case of our company, our company, (B) in the
case of AES NY, L.L.C., AES NY, L.L.C., and (C) in the case of any AES
Eastern Energy Subsidiary, our company or any AES Eastern Energy
Subsidiary; and
(3) the Rating Agencies shall have confirmed in writing that, after giving
effect to the merger or consolidation, the credit rating of the pass
through trust certificates shall not be less than (A) Baa2 by Moody's
and BBB by S&P in the case of a consolidation or merger involving our
company and (B) that rating then in effect in the case of a
consolidation or merger involving AES NY, L.L.C. or any AES Eastern
Energy Subsidiary.
LIMITATION ON LIENS. We will not, and will not permit any AES Eastern
Energy Subsidiary to create, incur, assume or suffer to exist any Lessee Liens.
LIMITATION ON INDEBTEDNESS. We will not, and will not permit any AES
Eastern Energy Subsidiary to, create, incur, issue, assume, suffer to exist,
guarantee or otherwise become directly or indirectly liable with respect to any
Indebtedness except for Permitted Indebtedness. Any incurrence of Permitted
Indebtedness shall constitute a representation and warranty by us that all
conditions to this incurrence have been satisfied. The Participation Agreements
state that neither we nor any AES Eastern Energy Subsidiary is required to
discharge or otherwise prepay any Indebtedness properly incurred at the time of
issuance. AES NY3, L.L.C. and Somerset Railroad may not incur any Indebtedness
without the prior written consent of the institutional investors that formed the
special purpose business trusts, except that no such written consent shall be
required in respect of
- the Somerset Railroad credit facility, or
- any operating leases of Somerset Railroad.
MAINTENANCE OF EXISTENCE. Except as permitted under "-- MERGER,
CONSOLIDATION," we will preserve and keep in full force and effect our and each
of the AES Eastern Energy Entities' legal existence and
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qualification to do business in any state in which the conduct of our or their
respective businesses or ownership or leasing of assets used in our or their
respective businesses requires this qualification and where the failure to be so
qualified could reasonably be expected to result in a Material Adverse Effect.
MAINTENANCE OF LICENSES AND PERMITS. We will, and, as applicable, will
cause each AES Eastern Energy Entity to, obtain and maintain all necessary
Governmental Approvals required to operate the Kintigh Generating Station, the
Milliken Generating Station, the Goudey Generating Station and the Greenidge
Generating Station (the Goudey Generating Station and the Greenidge Generating
Station are collectively referred to in this prospectus as, the "Additional
Facilities") and to sell the energy and capacity generated by the Kintigh
Generating Station, the Milliken Generating Station and the Additional
Facilities at wholesale prices, including all licenses and permits necessary to
maintain our status as an "Exempt Wholesale Generator" under the Public Utility
Holding Company Act ("EWG Status"), except where:
(1) failure to so obtain or maintain a Governmental Approval could not
reasonably be expected to result in a Material Adverse Effect; or
(2) the Governmental Approvals, licenses, authorizations and permits are
anticipated to be routinely granted at a later date in the ordinary
course.
FINANCIAL STATEMENTS. We shall deliver to the institutional investors that
formed the special purpose business trusts, the special purpose business trusts
and, so long as the Lien of the lease indenture shall not have been terminated
or discharged, the indenture trustee and the pass through trustee, as soon as
practicable after the end of each fiscal year but in no event later than 120
days after the end of that year:
(1) a consolidated balance sheet of our company and our consolidated
subsidiaries as of the end of the fiscal year and the related
consolidated statements of income, retained earnings and cash flows for
that fiscal year (together with footnotes and a discussion and
analysis), setting forth in each case in comparative form the figures
for the previous fiscal year, to the extent available, all prepared in
accordance with generally accepted accounting principles and reported
on and audited by an independent public accountant of nationally
recognized standing, together with any other information required to be
filed with the SEC in respect of the pass through trust certificates
under applicable securities laws;
(2) a certificate of an officer of our company stating that (A) the signer
has made, or caused to be made under his supervision, a review of the
Participation Agreements and the other operative documents, and (B)
this review has not disclosed the existence during the fiscal year (and
the signer does not have knowledge of the existence as of the date of
the certificate) of any condition or event constituting a Lease
Material Default or Lease Event of Default or an Event of Loss or, if
any such condition or event existed or exists, specifying its nature,
its period of existence and what action we have taken or propose to
take to address the condition or event;
(3) a certificate of an officer of our company stating whether any change
in Applicable Law has occurred during the previous fiscal year that
would result in a Material Adverse Effect and if an Applicable Law has
been enacted what action we have taken or propose to take with respect
thereto including establishing a plan to implement the action (which
plan shall be reasonably satisfactory to the institutional investors
that formed the special purpose business trusts); and we shall update
the institutional investors that formed the special purpose business
trusts annually on the implementation of the plan (including any
changes to the plan);
(4) a copy of Federal Energy Regulatory Commission ("FERC") Form No. 1 to
the extent filed with FERC pursuant to 18 C.F.R. Section 141.1; and
(5) a list of potential transferees to whom the institutional investors
that formed the special purpose business trusts have agreed that they
will not transfer their Beneficial Interests (it being the
understanding of the parties that, if this list is not delivered in any
fiscal year, the list delivered in the previous year shall continue to
apply).
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We shall deliver to the institutional investors that formed the special
purpose business trusts, the special purpose business trusts and, so long as the
Lien of the lease indenture shall not have been terminated or discharged, the
indenture trustee and the pass through trustee, as soon as reasonably
practicable after the end of each fiscal quarter but in no event later than 60
days after the end of that quarter:
(1) an unaudited consolidated balance sheet of our company and our
consolidated subsidiaries as of the end of that quarter and the related
consolidated statements of income for that quarter and for the portion
of our fiscal year ended at the end of that quarter, and the related
consolidated statements of cash flows for that quarter and for the
portion of the fiscal year ended at the end of that quarter, in each
case setting forth comparative figures for previous dates and periods,
to the extent available, and prepared in accordance with generally
accepted accounting principles (subject to normal year-end
adjustments); and
(2) a certificate of an officer of our company stating that (A) the signer
has made, or caused to be made under his supervision, a review of the
Participation Agreements and the other operative documents; and (B) the
review has not disclosed the existence during that fiscal quarter (and
the signer does not have knowledge of the existence as of the date of
that certificate) of any condition or event constituting a Lease
Material Default or Lease Event of Default or an Event of Loss or, if a
condition or event existed or exists, specifying its nature, its period
of existence and what action we have taken or propose to take to
address the condition or event.
We shall, at least 30 days prior to the commencement of any fiscal year,
provide to the institutional investors that formed the special purpose business
trusts and, upon written request, any Certificate Owner, our final Annual
Operating Budget for the fiscal year, together with confirmation by Stone &
Webster, the independent engineer, that the budget is based on reasonable
assumptions and is prepared in accordance with the Participation Agreements. The
Annual Operating Budget shall be subject to the confidentiality agreements set
forth in Participation Agreements. The Annual Operating Budget shall include pro
forma projections and projections indicating updated projected Coverage Ratios,
taking the Independent Forecast into account for the rental period, through the
end of the terms of the leases and shall indicate projected changes, if any, in
the Rent Reserve Account and the Additional Liquidity Account.
We shall furnish to the institutional investors that formed the special
purpose business trusts and, upon written request, to any Certificate Owner,
from time to time information as they shall reasonably request concerning the
Kintigh Generating Station and the Milliken Generating Station and the real
property on which the Kintigh Generating Station and the Milliken Generating
Station are located, including information concerning the condition, operation,
maintenance and use of the electricity generating stations and the real property
and other financial or operating information as they shall reasonably request
and which are routinely made available to our creditors or the creditors of The
AES Corporation, to the extent we or The AES Corporation possesses this
information or can reasonably obtain this information. To the extent this
information consists of information contained in records kept by us, The AES
Corporation or its affiliates, we shall furnish this information without cost to
the recipient. Any information furnished by us shall be subject to the
confidentiality agreements set forth in the Participation Agreements.
For any period that we are subject to the periodic reporting and
informational requirements of the Exchange Act, we shall deliver to the
institutional investors that formed the special purpose business trusts, the
special purpose business trusts and, so long as the Lien of the lease indenture
shall not have been terminated or discharged, the indenture trustee and the pass
through trustee for distribution to the Certificateholders, copies of all
periodic reports and information required under the Exchange Act and any other
applicable securities laws within a reasonable period of time. As soon as
practicable following the end of each month, we shall deliver to the
institutional investors that formed the special purpose business trusts and,
upon written request, to any Certificate Owner, a monthly operations report for
each of the Kintigh Generating Station and the Milliken Generating Station and
the Additional Facilities. We have agreed to amend the monthly operations
reports to include additional operation and maintenance information as the
institutional investors that formed the special purpose business trusts may
reasonably request. The monthly operations reports shall be subject to the
confidentiality agreements set forth in the Participation Agreements.
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We will require Certificate Owners who request information subject to the
confidentiality provisions of the Participation Agreements to execute an
agreement to be bound by such provisions.
REQUIRED NOTICES. We will promptly notify the special purpose business
trusts, the institutional investors that formed the special purpose business
trusts, the indenture trustee and the pass through trustee of any of the
following:
(1) the execution or termination of any PPA, or a related series of PPAs
with the same third party purchaser, with a term in excess of 12
months, for the sale at a scheduled price of more than 25% of the
aggregate capacity and energy of the Kintigh Generating Station and the
Milliken Generating Station and the Additional Facilities;
(2) the initiation, filing or settlement of a significant litigation matter
by or against any AES Eastern Energy Entity;
(3) any anticipated change in our chief executive office, our principal
place of business, our name or the place where we maintain our business
records, which notice shall be provided no later than 10 Business Days
prior to the anticipated change; and
(4) immediately upon obtaining Actual Knowledge of (A) any Lease Material
Default, Lease Event of Default, Event of Loss or other material damage
to the Kintigh Generating Station and the Milliken Generating Station
or either of the Additional Facilities, (B) any litigation, change in
our or any AES Eastern Energy Entity's business or financial condition
or event of force majeure, if it could reasonably be expected to result
in a Material Adverse Effect, (C) the existence of any Lessee Liens,
(D) any labor strike that directly affects us or AEE2, L.L.C., and (E)
the incurrence of Permitted Indebtedness in a principal amount in
excess of $20 million.
BOOKS AND ACCOUNTS. We will keep proper books and accounts in conformity
with U.S. generally accepted accounting principles ("GAAP") and all Applicable
Laws. We will create and maintain our books, records, accounts and financial
statements and those of the AES Eastern Energy Entities separately from any of
our other affiliates and shall be responsible for our own expenses and other
liabilities.
COMPLIANCE WITH LAW. We shall, and shall cause each of the AES Eastern
Energy Entities to, comply in all material respects with Applicable Laws
including, but not limited to, all Applicable Laws in respect of:
(1) the conduct of our or its business as currently conducted and as
proposed to be conducted and the ownership, operation and use of our or
its property, including those relating to environmental standards and
controls;
(2) the production and sale of electric energy;
(3) the performance of our or its obligations under the operative
documents; and
(4) the Employee Retirement Income Security Act of 1974, as amended, and
its regulations and published interpretations, in each case except
where non-compliance is the subject of a Permitted Contest.
PAYMENT OF TAXES. We shall and shall cause each of the AES Eastern Energy
Subsidiaries to file all required tax returns and pay all taxes due and payable,
except those being contested in good faith and on reasonable grounds for which
adequate reserves have been established. We shall promptly pay or cause to be
paid any valid, final judgment enforcing any tax, assessment, charge, levy or
claim and cause the same to be satisfied of record unless this judgment is then
being appealed and enforcement of it is stayed pending appeal.
MAINTENANCE OF AES EASTERN ENERGY SUBSIDIARIES; INSURANCE ON ADDITIONAL
FACILITIES. We shall take all actions required to cause each of the AES Eastern
Energy Subsidiaries:
(1) to remain as a wholly-owned subsidiary of ours; and
(2) collectively to operate and maintain the Kintigh Generating Station,
the Milliken Generating Station and each of the Additional Facilities
for so long as the applicable lease is in effect.
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We shall cause the Additional Facilities to be insured to the same extent
that the Milliken Generating Station is required to be insured under the
applicable leases.
AES EASTERN ENERGY REVENUES. We shall, and shall cause each AES Eastern
Energy Subsidiary to, cause all AES Eastern Energy Revenues to be deposited
directly into the Revenue Account established under the deposit and disbursement
agreement, except, to the extent provided in the deposit and disbursement
agreement, for any revenues received by any AES Eastern Energy Entity under any
Operation and Maintenance Agreement.
ANNUAL OPERATING BUDGET. We shall cause each of the Kintigh Generating
Station, the Milliken Generating Station and the Additional Facilities to be
operated and maintained in accordance with the Annual Operating Budget and shall
not permit the aggregate expenditures in any year for Operating and Maintenance
Costs to exceed 125% of the amount set forth in the Annual Operating Budget. Any
amendment, modification or reallocation of the Annual Operating Budget by us
that would cause a change of more than 25%, either positively or negatively, in
the amounts set forth in the Annual Operating Budget shall be accompanied by
confirmation of Stone & Webster, the independent engineer, that any amendment,
modification or reallocation is based on reasonable assumptions.
COAL HAULING AGREEMENT. We shall comply with all of the terms of the coal
hauling agreement with Somerset Railroad applicable to us, the nonperformance of
which could result in a Material Adverse Effect, and shall take all necessary
actions to enforce the coal hauling agreement in the event of any non-compliance
with any of its terms by Somerset Railroad or AES NY3, L.L.C., as the case may
be. We will not modify, amend or terminate the coal hauling agreement with
Somerset Railroad without the prior written consent of the special purpose
business trusts, the institutional investors that formed the special purpose
business trusts and, so long as the Lien of the lease indenture shall not have
been terminated or discharged, the indenture trustee.
FACILITIES SUPPORT AGREEMENTS. We will provide each special purpose
business trust with access to, and use of, all assets and facilities owned or
controlled by us which are located at or near the related facility site which
are not part of the Kintigh Generating Station or the Milliken Generating
Station, as the case may be, but are necessary to operate and/or maintain the
electricity generating station (including additional easements and rights of way
necessary to provide the applicable special purpose business trust with access
to the electricity generating station and the facility site from public
thoroughfares) at the expiration or earlier termination of the related lease,
pursuant to the facilities support agreements (each, a "Facilities Support
Agreement") to the extent that these assets and facilities are not otherwise
readily available to the special purpose business trust at market prices.
The assets covered by the Facilities Support Agreement include the ash
disposal sites, limestone storage and coal handling and storage facilities, rail
services, all lines of communication, all water lines, electrical cables, sewer
lines and any other ancillary rights and additional equipment, facilities,
supplies and accessories of ours and any other ancillary rights and services as
may be required from time to time to realize the benefits of the related
undivided interest of the special purpose business trust in the Kintigh
Generating Station or the Milliken Generating Station, as the case may be, in a
commercially practicable manner. The special purpose business trusts will pay us
an amount equal to the fair market value of the asset or facility, as determined
in accordance with an appraisal conducted in accordance with the Appraisal
Procedure.
To the extent that the rights described in the Facilities Support
Agreements, which have already been made available to a special purpose business
trust prior to the expiration or termination of the related lease term, are
insufficient to permit on a commercially practicable basis, during the period
following the expiration or termination of the lease term, the use, operation
and maintenance of the Kintigh Generating Station or the Milliken Generating
Station, as the case may be, we will arrange to provide the special purpose
business trust,
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promptly upon the written request of the special purpose business trust, with
any services relating to the use, operation and maintenance of the electricity
generating station to the extent these services:
(1) can be provided through equipment, conduits and pipelines located in,
on or over the real property on which the electricity generating
stations are located or the easement areas granted under the lease
related to the real property on which the electricity generating
stations are located;
(2) are necessary for the special purpose business trust's use, operation
and maintenance of the electricity generating station in accordance
with prudent industry standards for its present use, in its present
location and in compliance with the operative documents; and
(3) are not otherwise readily available to the special purpose business
trust from third parties at fair market prices.
Except as otherwise provided in any Facilities Support Agreement, any
services provided by us will provide for fair market value compensation to us
(as determined by agreement or, absent agreement, by an appraisal conducted
according to the Appraisal Procedure) and will terminate upon the expiration or
termination of the related site lease, unless the special purpose business
trusts choose the early termination of all of these services. The cost of an
appraisal conducted under this provision shall be borne equally by the special
purpose business trusts and us.
INDEPENDENT FORECAST. We shall furnish or cause to be furnished to the
special purpose business trusts, the institutional investors that formed the
special purpose business trusts and, so long as the Lien of the lease indenture
shall not have been terminated or discharged, the indenture trustee and the pass
through trustee no later than 30 days following January 1, 2001 and biennially
thereafter, a report (an "Independent Forecast") prepared by a qualified
independent consultant experienced in forecasting power prices and coal prices,
respectively. We shall select the independent consultant and the independent
consultant shall be reasonably acceptable to the institutional investors that
formed the special purpose business trusts. In addition, we shall notify the
institutional investors that formed the special purpose business trusts of our
selection of a consultant and unless the institutional investors that formed the
special purpose business trusts shall object to our selection within 10 Business
Days of receipt of notice of our selection, the consultant shall be deemed
acceptable by the institutional investors that formed the special purpose
business trusts.
The Independent Forecast shall set forth projections of:
(1) electricity prices, and the basis on which these prices are to be
applied (e.g., energy and capacity), for the New York power pool market
applicable to the Kintigh Generating Station, the Milliken Generating
Station and the Additional Facilities, or if the market no longer
exists in the form contemplated as of May 14, 1999, any successor
market or substitute market as determined in good faith by us which
approximates, to the extent practicable, this region; and
(2) coal prices on a delivered basis to the Assigned Assets, in each case
on at least an annual basis through the Lease Expiration Date.
For purposes of calculating the projected revenues and expenses under the
operative documents, we shall use:
(1) for electricity prices, either (A) the electricity prices forecast in
the most recently furnished Independent Forecast, in each case, during
the relevant period of calculation, or (B) if and to the extent that
electricity sales during the relevant period of calculation are made
pursuant to one or more power sales agreements at prices other than
prices which are by their terms pool-based market prices, the
electricity prices under those power sales agreements; and
(2) for coal prices, either (A) to the extent that coal is not purchased
pursuant to one or more purchase agreements, the coal prices forecasted
in the most recently furnished Independent Forecast, in each case,
during the relevant period of calculation, or (B) if and to the extent
that coal purchases during the relevant period of calculation are made
pursuant to one or more purchase agreements, the coal prices under
those coal purchase agreements.
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LEGALLY DISTINCT PARCEL. We shall take all necessary actions prior to May
14, 2000 to ensure that the real property of each of the Kintigh Generating
Station and the Milliken Generating Station constitutes a legally distinct
parcel or parcels that is (or are) separately taxed and can be independently and
validly conveyed, to the extent that the foregoing is permitted under Applicable
Law.
MAINTENANCE OF PAYMENT UNDERTAKING AGREEMENTS. So long as the Lien of the
lease indenture shall not have been terminated or discharged, we shall, to the
extent commercially reasonable, maintain the portion of the Rent Reserve Account
Required Balance and the Special Rent Reserve Account Required Balance that is
to be applied to the payment of Basic Rent in the form of a Payment Undertaking
Agreement and shall replenish any amounts drawn thereunder as soon as it is
commercially reasonable to do so; provided, however, that we shall be obligated
to:
(1) maintain or replenish a Special Rent Reserve Account Payment
Undertaking Agreement only if the amount is more than $15,000,000;
(2) maintain a Rent Reserve Account Payment Undertaking Agreement only if
the amount is more than $5,000,000; and
(3) replenish a Rent Reserve Account Payment Undertaking Agreement only if
the amount is more than $1,000,000.
RESTRICTED PAYMENTS. Notwithstanding anything to the contrary in the
deposit agreement and subject to certain consent rights of the special purpose
business trusts, distributions by us may only be made on or within five Business
Days after a Rent Payment Date (commencing with the Rent Payment Date occurring
on July 2, 2000 as specified in clause (7) below) so long as the following
conditions are satisfied:
(1) all Rent, including Deferrable Payments, shall have been paid to date;
(2) amounts on deposit or deemed on deposit in the Rent Reserve Account and
the Additional Liquidity Account shall be equal to or greater than the
Rent Reserve Account Required Balance or the Additional Liquidity
Required Balance, as applicable;
(3) no Lease Material Default, Lease Event of Default or event of default
under any Permitted Indebtedness shall have occurred and be then
continuing;
(4) no amounts shall be outstanding under the working capital credit
facility with Credit Suisse First Boston;
(5) we have no indemnity currently due and payable under specified
provisions of the Participation Agreements or any other operative
document or any obligation to fund the Indemnity Accounts (as defined
in the leases) under the leases;
(6) the Coverage Ratios for each of the two semiannual Rent Payment Periods
immediately preceding the Rent Payment Date (based on actual operating
history) shall be equal to or greater than the Required Coverage Ratio
and the pro forma Coverage Ratios for each of the four semiannual
periods immediately succeeding this Rent Payment Date shall be equal to
or greater than the Required Coverage Ratio;
(7) notwithstanding the above paragraphs, the first Rent Payment Date on
which we shall be entitled to make a Distribution shall be July 2,
2000; on this date for the purpose of determining the satisfaction of
the condition in clause (6) above, only the semiannual period
immediately preceding this date shall be relevant; and
(8) with respect to the Somerset Railroad credit facility or any
replacement facility, no event of default shall have occurred and be
then continuing under the facilities and the remaining term of the
Somerset Railroad credit facility or any replacement facility shall not
be less than 30 days.
LIMITATIONS ON OUR ACTIVITIES. We shall not, and shall not permit any of
the AES Eastern Energy Entities to, engage in any business other than the lease,
acquisition, ownership, operation, repowering or expansion of the Assigned
Assets and the ownership of the capital stock of Somerset Railroad and the sale
of
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electricity or capacity generated by, and products derived from, and waste
generated by, the Kintigh Generating Station and the Milliken Generating
Station, including emission allowances, and related activities.
LIMITATION ON DISPOSITION OF ASSETS. Except as otherwise specified under
the caption "-- THE LEASES, THE FACILITY SITE LEASES AND THE FACILITY SITE
SUBLEASES -- USE AND MAINTENANCE" and "-- THE LEASES, THE FACILITY SITE LEASES
AND THE FACILITY SITE SUBLEASES -- SUBLEASE AND ASSIGNMENT" below, we shall not,
and shall not permit AEE2, L.L.C. or any other AES Eastern Energy Subsidiary to:
(1) liquidate, wind up or dissolve; or
(2) transfer or otherwise dispose of its property, assets or business or to
purchase, lease or acquire property or other assets, to or from any
person or persons in one or a series of transactions.
Clause (2), however, shall not apply to any of the following circumstances,
- any transaction in the ordinary course of our business or the business of
any AES Eastern Energy Subsidiary,
- any transfer or other disposition of emission allowances or additional
land to a third party purchaser,
- any Permitted Affiliate Transaction, and
- subject to the prior written consent of the institutional investors that
formed the special purpose business trusts and, so long as the Lien of
the lease indenture shall not have been terminated or discharged, the
indenture trustee, the transfer or other disposition of the Kintigh
Generating Station and the Milliken Generating Station (at any time when
it is owned by us or any of our affiliates otherwise than as a result of
having been acquired as a result of an Event of Loss) or either of the
Additional Facilities.
LIMITATIONS ON TRANSACTIONS WITH AFFILIATES. We will not, and will not
permit any AES Eastern Energy Subsidiary to, enter into any transactions with an
affiliate, other than Permitted Affiliate Transactions, without the prior
written consent of the institutional investors that formed the special purpose
business trusts. Notwithstanding the foregoing, in the event any Rent, including
Deferrable Payments, then due is not paid or the Rent Reserve Account, the
Additional Liquidity Account or the Special Rent Reserve Account, if applicable,
is not fully funded or any Lease Material Default or Lease Event of Default
shall have occurred and be then continuing, the institutional investors that
formed the special purpose business trusts shall have the right, but not the
obligation, to appoint a qualified independent consultant, at our expense, to
review the terms, including pricing, terms and conditions, of any or all of the
Permitted Affiliate Transactions described in clause (3) of the definition of
Permitted Affiliate Transactions.
In the event that independent consultant determines that the market
certification previously delivered with respect to the Permitted Affiliate
Transaction is no longer valid, at no price reduction, cost or penalty to us, we
shall cause the Permitted Affiliate Transaction to be amended to reflect market
terms, which shall be confirmed by the independent consultant.
LIMITATIONS ON INVESTMENTS. We shall not make or authorize any investments
other than Permitted Investments. We shall be permitted to direct the investment
of amounts in all Accounts in Permitted Investments only so long as no Material
Lease Default or Lease Event of Default shall have occurred and be continuing.
NO ABANDONMENT. Except as contemplated by the leases, we shall not, and
shall not permit any AES Eastern Energy Entity to, abandon or agree to abandon
the operation or maintenance of the Kintigh Generating Station and the Milliken
Generating Station or otherwise cease to diligently pursue the operation and
maintenance of the Kintigh Generating Station and the Milliken Generating
Station in accordance with Prudent Industry Practice or voluntarily reduce the
operations of the Kintigh Generating Station and the Milliken Generating Station
in any material respect, except to the extent required by customary maintenance
procedures, prior to the end of the lease terms. "Prudent Industry Practice" is
defined under the caption, "-- THE LEASES, THE FACILITY SITE LEASES AND THE
FACILITY SITE SUBLEASES."
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Subject to the prior written consent of the institutional investors that
formed the special purpose business trusts and, so long as the Lien of the lease
indenture shall not have been terminated or discharged, the indenture trustee,
we shall not, and shall not permit any AES Eastern Energy Entity to, abandon or
agree to abandon the operation or maintenance of either of the Additional
Facilities or otherwise cease to diligently pursue the operation and maintenance
of the Additional Facilities in accordance with Prudent Industry Practice,
except to the extent required by customary maintenance procedures, during the
expected useful life of each Additional Facility.
ASSIGNMENT. We will not, except in connection with a transfer of all of
its assets to a wholly owned affiliate of The AES Corporation or as otherwise
provided in the section "-- THE LEASES, THE FACILITY SITE LEASES AND THE
FACILITY SITE SUBLEASES -- SUBLEASE AND ASSIGNMENT," assign, transfer, sell,
hypothecate or otherwise dispose of any lease or any other operative document or
our interests in any lease or any other operative document without the prior
written consent of the special purpose business trusts, the indenture trustee,
the pass through trustee and the institutional investors that formed the special
purpose business trusts, which consent may be withheld, in each of their
respective sole discretion.
INTERCONNECTION AGREEMENT. We will not modify, amend or terminate the
interconnection agreement, or any alternative arrangement as permitted below,
without the prior written consent of the institutional investors that formed the
special purpose business trusts; provided that we shall have the right, without
the consent of any party, to amend or terminate the interconnection agreement or
any alternate arrangement, if:
(1) We deliver to the institutional investors that formed the special
purpose business trusts a certificate of Stone & Webster, the
independent engineer, that alternate arrangements are in place to
transmit power to the grid;
(2) that the alternate arrangements, considered in their entirety, are no
more expensive to us than the interconnection agreement; and
(3) it is reasonable to expect that the alternate arrangements would
continue to be useable by the special purpose business trusts on
substantially the same terms and conditions upon expiration or
termination of the leases.
DEFINITIONS
As used in this prospectus, the following terms have the meanings set forth
below:
"Accounts" shall mean those accounts listed under the caption "-- THE
DEPOSIT AND DISBURSEMENT AGREEMENT" in this prospectus.
"Actual Knowledge" shall mean, with respect to any person, the actual
knowledge of, including receipt of written notice by, a Responsible Officer of
this person.
"Additional Liquidity Letter of Credit" shall mean, the additional
liquidity letter of credit issued by BankBoston dated May 14, 1999, in the
stated amount of $36,326,900, or any letter of credit, in form, scope and
substance satisfactory to the institutional investors that formed the special
purpose business trusts, issued for our account by a bank, for the benefit of
Bankers Trust as the depositary and disbursement agent, acceptable to the
institutional investors that formed the special purpose business trusts, in the
amount of the Additional Liquidity Required Balance or in the amount of the
letter of credit being replaced or renewed.
"Additional Liquidity Required Balance" shall mean, for any period, an
amount, determined and fixed as of May 14, 1999, equal to the greater of
- $65,000,000 less the balance in the Rent Reserve Account on May 14, 1999,
or
- $30,000,000.
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The Additional Liquidity Required Balance shall be permanently reduced by
50%, if at any time after May 14, 2002:
(1) the pass through trust certificates are rated Baa3 by Moody's and BBB-
by S&P;
(2) before and after any PPA Term, (A) the average Coverage Ratio for the
immediately preceding three-year period is not less than 2.5:1.0, and
(B) the minimum Coverage Ratio for each of the immediately preceding
three years is not less than 2.0:1.0; and
(3) during any PPA Term, (A) the average Coverage Ratio for the immediately
preceding three-year period is not less than 1.5:1.0, and (B) the
minimum Coverage Ratio for each of the immediately preceding three
years is not less than 1.4:1.0.
The Additional Liquidity Required Balance shall be permanently reduced to
zero, if any time after May 14, 2002:
(1) the pass through trust certificates are rated at least Baa2 by Moody's
and BBB by S&P;
(2) before and after any PPA Term, (A) the average Coverage Ratio for the
immediately preceding three-year period is not less than 2.5:1.0, and
(B) the minimum Coverage Ratio for each of the immediately preceding
three years is not less than 2.0:1.0; and
(3) during any PPA Term, (A) the average Coverage Ratio for the immediately
preceding three-year period is not less than 1.75:1.0, and (B) the
minimum Coverage Ratio for each of the immediately preceding three
years is not less than 1.5:1.0.
"AES Eastern Energy Entities" shall mean AES NY, L.L.C., AES NY2, L.L.C.,
AES NY3, L.L.C. and the AES Eastern Energy Subsidiaries.
"AES Eastern Energy Extraordinary Revenues" shall mean any revenues
attributable to any extraordinary, non-recurring or one-time credit, payment or
event, including proceeds of insurance, other than business interruption
insurance, or condemnation awards.
"AES Eastern Energy Revenues" shall mean all cash revenues and other cash
sums from time to time received by or on behalf of us or any AES Eastern Energy
Subsidiary, including, but not limited to:
(1) the proceeds of the sale of power, energy and capacity and by-products
thereof and ancillary services generated by the Kintigh Generating
Station and the Milliken Generating Station and each other electric
generating asset, including the Additional Facilities, now or hereafter
owned by us or AEE2, L.L.C. or any other AES Eastern Energy Subsidiary
and the proceeds from the sale of emission allowances;
(2) the proceeds of business interruption insurance policies;
(3) any AES Eastern Energy Extraordinary Revenues, including the proceeds
of the sale or lease of any assets of ours or AEE2, L.L.C. or any other
AES Eastern Energy Subsidiary to the extent permitted under the
operative documents; and
(4) any earnings on Permitted Investments, including any accretion in value
of these Permitted Investments.
For the purposes of this definition, AES Eastern Energy Revenues shall not
include:
(1) any borrowings, including any borrowings under the working capital
credit facility with Credit Suisse First Boston, or capital
contributions;
(2) any drawings under any Payment Undertaking Agreement or any instrument,
letter of credit, surety, or other undertaking held in any Account;
(3) any transfer of amounts from any Account to any other Account; or
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(4) any reimbursement of amounts held or any instrument, letter of credit,
surety, or other undertaking held in any Account, in escrow by the
special purpose business trusts or the indenture trustee under the
operative documents.
"AES Eastern Energy Subsidiaries" shall mean AES Somerset, L.L.C., AES
Cayuga, L.L.C., AES Westover, L.L.C., AES Greenidge, L.L.C., AEE2, L.L.C. and
any other subsidiary of ours created after May 14, 1999.
"Affiliate Transaction" shall mean any transaction entered into between us
or AEE2, L.L.C. or any other AES Eastern Energy Subsidiary, on the one hand, and
The AES Corporation or any affiliate of The AES Corporation, other than us,
AEE2, L.L.C. or any other AES Eastern Energy Subsidiary, on the other.
"Annual Operating Budget" shall mean, for any applicable calendar year,
each annual operating plan and budget for the Kintigh Generating Station or the
Milliken Generating Station and the Additional Facilities adopted by us in
accordance with the Participation Agreements setting forth in reasonable detail
all pro forma Operating and Maintenance Costs and other expenses, including
capital expenditures, reasonably foreseeable or anticipated to be made during
such year by categories and amounts.
"Applicable Law" shall mean all applicable laws, including, but not limited
to, all environmental laws, and treaties, judgments, decrees, injunctions, writs
and orders of any court, arbitration board or Governmental Entity and rules,
regulations, orders, ordinances, licenses and permits of any Governmental
Entity.
"Appraisal Procedure" shall mean a customary appraisal procedure to be
described in the operative documents.
"Assigned Assets" shall mean the assets that were acquired from NYSEG on
May 14, 1999 excluding those assets acquired by AES Creative Resources, L.P.,
the capital stock of Somerset Railroad acquired by AES NY3, L.L.C. and emission
allowances.
"Basic Rent" shall consist of fixed rent paid during the Lease Interim
Term, the Lease Basic Term and any Renewal Terms. "Lease Interim Term" and
"Lease Basic Term" are defined under the caption, "THE LEASES, THE FACILITY SITE
LEASES AND THE FACILITY SITE SUBLEASES -- TERM AND RENT."
"Beneficial Interest" shall mean the interest of an institutional investor
that formed the special purpose business trusts in the applicable special
purpose business trust.
"Bill of Sale" shall mean the applicable bill of sale, dated May 14, 1999,
between New York State Electric & Gas Corporation and NGE Generation, Inc. and
the applicable special purpose business trust, duly completed, executed and
delivered on May 14, 1999, pursuant to which that special purpose business trust
acquired an undivided interest in the Kintigh Generating Station or the Milliken
Generating Station from New York State Electric & Gas Corporation and NGE
Generation, Inc.
"Business Day" shall mean any day other than a Saturday, a Sunday, or a day
on which commercial banking institutions are authorized or required by law,
regulation or executive order to be closed in New York, New York, the city and
state in which the corporate trust department of Wilmington Trust Company, the
special purpose business trustee, is located or the city and state in which the
corporate trust office of the indenture trustee or the pass through trustee is
located.
"CADS" shall mean, for any relevant period, the excess, calculated on a
cash basis, of (1) all AES Eastern Energy Revenues received or projected to be
received, as the case may be, during that period, other than transactions among
the AES Eastern Energy Entities, over (2) all Operating and Maintenance Costs
paid or projected to be paid during that period; provided, that AES Eastern
Energy Extraordinary Revenues shall not be included in AES Eastern Energy
Revenues for the purpose of calculating CADS for any future period.
"Collateral" shall mean with respect to any secured lease obligation notes,
the first priority security interest in the rights and interest of the special
purpose business trust that issued those notes in the related lease, including
the right to receive payments of periodic rent, the undivided interest in the
Kintigh Generating Station or the Milliken Generating Station (or the subsequent
sublease of this interest), the Participation
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Agreement, the lease relating to the real property of the Kintigh Generating
Station or the Milliken Generating Station, the sublease relating to the real
property of the Kintigh Generating Station or the Milliken Generating Station,
the Facilities Support Agreement, the Support Agreements, and in the special
purpose business trust's interest under the Coal Hauling Agreement with Somerset
Railroad and under any Payment Undertaking Agreement.
"Coverage Ratio" shall mean, for any period, the ratio of (1) CADS to (2)
Fixed Charges for that period.
"Debt Service" shall mean all payments, including principal and interest
payments (including the net costs under interest rate hedge agreements and all
capitalized interest), in respect of Indebtedness of our company and AEE2,
L.L.C. and any other AES Eastern Energy Subsidiary, but excluding Basic Rent and
any principal or interest payments under the working capital credit facility
with Credit Suisse First Boston or any other working capital credit facility and
Permitted Subordinated Indebtedness.
"Deed" shall mean the deed, dated as of May 14, 1999, by New York State
Electric & Gas Corporation and NGE Generation, Inc. in favor of the applicable
special purpose business trust duly completed, executed and delivered on May 14,
1999 under which, together with the Bill of Sale, the special purpose business
trust acquired the undivided interest in the Kintigh Generating Station or the
Milliken Generating Station from New York State Electric & Gas Corporation and
NGE Generation, Inc.
"Deferrable Basic Rent" shall mean deferrable rent with respect to the
Lease Basic Term payable to the special purpose business trust for the lease of
each undivided interest for each Rent Payment Period throughout the Lease Basic
Term, in the amounts payable in advance or in arrears or both, as the case may
be, on each Rent Payment Date as indicated on a schedule to the related lease;
provided, that Deferrable Basic Rent shall not include any rent due in respect
of the pass through trust certificates.
"Deferrable Basic Rent Maturity Date" shall mean the earlier of:
(1) the date of occurrence of any Lease Bankruptcy Default or Lease Event
of Default;
(2) with respect to all or any portion of any Deferrable Payment, the Rent
Payment Date on which sufficient available funds are on deposit in the
Deferrable Rent Account to pay all or such portion of such Deferrable
Payment;
(3) the Rent Payment Date next following the scheduled date of maturity of
the secured lease obligation notes; and without taking into account any
additional secured lease obligation notes; and
(4) the earlier of the expiration dates of the respective leases and the
date of any termination of the lease term pursuant to certain
provisions of the lease and the date of any purchase by us of the
Beneficial Interest pursuant to certain provisions of the Participation
Agreement.
"Deferrable Payments" shall mean Deferrable Basic Rent plus interest
accrued on this rent and unpaid on the maturity date set forth in the leases.
"Distribution" shall mean, with respect to any person:
(1) the declaration or payment of any dividend or making of any other
payment or distribution, including, but not limited to, any dividend or
distribution in connection with any merger or consolidation involving
this person, on account of this person's equity interests or to the
direct or indirect holders of this person's equity interests in their
capacity as holders of this person's equity interests, other than
dividends or distributions payable in equity interests of this person;
(2) the purchase, redemption or other acquisition or retirement by this
person for value of any equity interests of this person; or
(3) the making of any principal payment on, or the purchase, redemption,
defeasance or other acquisition or retirement for value of any
Indebtedness of this person to an affiliate of this person not wholly
owned by this person.
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"Fixed Charges" shall mean, for any relevant period, the sum, calculated on
a cash basis, of:
(1) all Basic Rent, other than Deferrable Payments, paid during this period
(or, in the case of any future period, as of the time of calculation,
scheduled to be paid); and
(2) all Debt Service paid during this period or, in the case of any future
period, as of the time of calculation, scheduled to be paid.
"Fixed Charge Coverage Ratio" or "FCCR" shall mean cash available for fixed
charges divided by rent payments under the leases equal to principal and
interest on the certificates and nondeferrable rent.
"Funding Date" shall mean May 14, 1999, and after this date, the first
Business Day of each month commencing with June 1999.
"Governmental Approvals" shall mean all authorizations, consents,
approvals, including regulatory approvals, waivers, exemptions, orders,
variances, franchises, permissions, permits and licenses, exceptions, filings,
notices to and declarations of, and rulings by any Governmental Entity.
"Governmental Entity" shall mean and include any federal, state, county,
municipal, foreign, international, regional or other governmental or regulatory
authority, agency, board, commission, department, division, organ,
instrumentality, court or political subdivision of any of these entities.
"Indebtedness" of any person shall mean:
(1) all indebtedness of this person for borrowed money;
(2) all obligations of this person evidenced by bonds, debentures, notes or
other similar instruments;
(3) all obligations of this person to pay the deferred purchase price of
property or services;
(4) all indebtedness created or arising under any conditional sale or other
title retention agreement with respect to property acquired by this
person, even though the rights and remedies of the seller or lender
under the agreement in the event of default are limited to repossession
or sale of this property;
(5) all Lease Obligations of this person including all rent under the
leases;
(6) all obligations, contingent or otherwise, of this person under
acceptance, letter of credit or similar facilities;
(7) all unconditional obligations of this person to purchase, redeem,
retire, defease or otherwise acquire for value any capital stock or
other equity interests of this person or any warrants, rights or
options to acquire this person's capital stock or other equity
interests;
(8) all Indebtedness of any other person of the type referred to in clauses
(1) through (7) guaranteed by this person or for which this person
shall otherwise become directly or indirectly liable, including by any
keepwell, makewell or similar arrangement; and
(9) all Indebtedness of the type referred to in clauses (1) through (7)
above secured by, or for which the holder of such Indebtedness has an
existing right, contingent or otherwise, to be secured by, any lien or
security interest on property, including, without limitation, accounts
and contract rights, owned by this person, even though this person has
not assumed or become liable for the payment of such Indebtedness, the
amount of this obligation being deemed to be the lesser of the value of
such property or the amount of the obligation so secured.
"Interconnection Agreement" shall mean the agreement, dated as of August 3,
1998, as amended as of March 6, 1999, between AES NY L.L.C. and New York State
Electric & Gas Corporation, to establish the requirements, terms and conditions
for the interconnection of the assets acquired from NYSEG to the transmission
system of New York State Electric & Gas Corporation.
"Investment Grade" shall mean a credit rating of not less than Baa3 by
Moody's and BBB- by S&P.
"Land" shall mean the land owned by us that does not constitute a part of
the real property on which the Kintigh Generating Station or the Milliken
Generating Station is located and which we have leased to the special purpose
business trusts.
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"Lease Bankruptcy Default" shall mean customary events of bankruptcy or
insolvency, whether voluntary or involuntary, with respect to us or our
company's general partner.
"Lease Expiration Date" shall mean February 13, 2033 with respect to the
leases for the Kintigh Generating Station and November 13, 2027 with respect to
the leases for the Milliken Generating Station.
"Lease Material Default" shall mean the failure by us to make any payment
of Basic Rent (other than Deferrable Payments, but only to the extent provided
in the leases) or termination value (as set forth in the leases), in each case
within five Business Days after the same shall become due, or to make any
payment of Supplemental Rent (other than termination value as set forth on a
schedule to the applicable lease and, unless the applicable institutional
investor that formed the relevant special purpose business trust shall have
declared a default with respect thereto, excepted payments (each as set forth in
the leases)) after the same shall have become due and this failure shall have
continued for 30 days after receipt of notice of this failure by us, or a Lease
Bankruptcy Default.
"Lease Obligations" shall mean without duplication:
(1) Indebtedness represented by obligations under a lease that is required
to be capitalized for financial reporting purposes; and
(2) with respect to noncapital leases of electricity generating facilities,
(A) non-recourse Indebtedness of the applicable special purpose
business trust in the lease, or (B) if this amount is indeterminable,
then the present value, determined using a discount rate equal to our
incremental borrowing rate (as defined in Statement of Financial
Accounting Standards No. 13) under the lease, of rent obligations under
this lease.
"Lease Term" means the Lease Fixed Term plus all Lease Renewal Terms for a
lease.
"Lessee Liens" shall mean any Liens on the Kintigh Generating Station or
the Milliken Generating Station, the real property on which the Kintigh
Generating Station and the Milliken Generating Station are located or on the
Additional Facilities, other than Permitted Liens and Liens on the Additional
Facilities in respect of Permitted Secured Indebtedness.
"Lien" shall mean any mortgage, security deed, security title, pledge,
lien, charge, encumbrance, lease and security interest or title retention
arrangement.
"Material Adverse Effect" shall mean a material adverse effect on our
financial position, property, results of operations or business (on a
consolidated basis), including a material adverse effect on:
(1) the undivided interests in the Kintigh Generating Station and the
Milliken Generating Station, the ground interests in the real property
of the Kintigh Generating Station and the Milliken Generating Station,
the Kintigh Generating Station and the Milliken Generating Station, the
real property on which the Kintigh Generating Station and the Milliken
Generating Station are located or any other Assigned Assets; or
(2) our financial position (on a consolidated basis) affecting our ability
to perform our obligations in any respect under any of the operative
documents; or
(3) the validity or enforceability of any operative document.
"Mortgage" shall mean the applicable mortgage, dated as of May 1, 1999,
between the special purpose business trust, as mortgagor, and the indenture
trustee, as mortgagee.
"Mortgaged Property" shall have the meaning specified in the granting
clause of the Mortgage.
"Operating and Maintenance Costs" shall mean, for any period, all cash
operating and maintenance expenses of ours or any AES Eastern Energy Subsidiary
in respect of the Kintigh Generating Station, the Milliken Generating Station,
the Additional Facilities and any other assets or property of ours or any AES
Eastern Energy Subsidiary for this period, calculated in accordance with cash
accounting, including, but not limited to,
- amounts owed under the coal hauling agreement with Somerset Railroad,
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- interest payable pursuant to the working capital credit facility with
Credit Suisse First Boston or any successor facility,
- the fees set forth in the Operation and Maintenance Agreements,
- capital expenditures made or, in the case of any future period duly
budgeted pursuant to certain provisions of the Participation Agreements,
including all costs of major inspections, unscheduled or scheduled major
maintenance of the Kintigh Generating Station and the Milliken Generating
Station or any Additional Facility and all work on account of
extraordinary equipment failures and contingencies (including overhaul
costs),
- insurance premiums,
- payments due in respect of property or sales taxes,
- the cost of consumables and labor costs,
- costs incurred under any contracts for the purchase, transportation or
handling of fuel and any related options,
- costs incurred with regard to disposal of ash or any products generated
by the Kintigh Generating Station and the Milliken Generating Station or
the Additional Facilities, and
- general and administrative expenses and maintenance costs with regard to
the Kintigh Generating Station or the Milliken Generating Station or the
Additional Facilities and any other assets or property of any AES Eastern
Energy Subsidiary, but excluding Fixed Charges in all such cases, in each
case attributable to such period.
Operating and Maintenance Costs shall not include income taxes, the costs
under the construction contract for the Kintigh selective catalytic reduction
system or any transaction expenses associated with the acquisition or the lease
transactions paid in 1999.
"Operation and Maintenance Agreements" shall mean:
(1) the Operation and Maintenance Agreement, dated as of May 1, 1999,
between us and AES Somerset, L.L.C. relating to the Kintigh Generating
Station;
(2) the Operation and Maintenance Agreement, dated as of May 1, 1999,
between us and AES Cayuga, L.L.C. relating to the Milliken Generating
Station;
(3) the Operation and Maintenance Agreement, dated as of May 1, 1999,
between us and AES Westover, L.L.C. relating to the Greenidge
Generating Station; and
(4) the Operation and Maintenance Agreement, dated as of May 1, 1999,
between us and AES Goudey, L.L.C. relating to the Goudey Generating
Station.
"Participation Agreement" shall mean each of the Participation Agreements,
dated as of May 1, 1999, and entered into on May 14, 1999 with respect to each
of the Kintigh Generating Station and the Milliken Generating Station, among us,
the special purpose business trusts, the institutional investors that formed the
special purpose business trusts, the indenture trustee and the pass through
trustee.
"Payment Event" shall mean:
(1) the occurrence on any Rent Payment Date of the aggregate amounts then
on deposit in the Rent Payment Account, the Additional Liquidity
Account and the Rent Reserve Account, excluding amounts available to be
paid under any Rent Reserve Account Payment Undertaking Agreement and,
in the case of a Special Rent Reserve Account Payment Undertaking
Agreement, the Special Rent Reserve Account (including amounts
available to be paid under any Special Rent Reserve Account Payment
Undertaking Agreement) less amounts required to fund any shortfall in
the Debt Repayment Account being insufficient to pay Basic Rent, other
than Deferrable Payments, due on such Rent Payment Date;
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(2) the occurrence of the applicable Replacement Event;
(3) the occurrence and continuance of a Lease Event of Default and the
exercise by the special purpose business trust of certain remedies
specified in the lease; or
(4) any Termination Date on which we are obligated to pay termination value
as listed on a schedule to the applicable lease.
"Payment Undertaking Agreement" shall mean an agreement
- between us, each special purpose business trust and a PUA Provider,
- that is drawable and payable in the event that a Payment Event shall have
occurred and be continuing,
- the benefits of which are assigned to each indenture trustee, and
- pursuant to which such PUA Provider shall, upon the occurrence of any
Payment Event, be obligated to pay on demand an amount up to the amount
listed on a schedule attached to the agreement.
For purposes of this definition, the amounts on this schedule, at any time,
shall be at least equal to, in the case of the Rent Reserve Account payment
undertaking agreement, the maximum semiannual payment of Basic Rent, other than
Deferrable Payments, scheduled to be paid on any Rent Payment Date in the
immediately succeeding three-year period and in the case of a Special Rent
Reserve Account Payment Undertaking Agreement:
(1) prior to May 14, 2004, (A) the maximum aggregate payment of Basic Rent,
other than Deferrable Payments, expected to become due on any three
successive payment dates in the immediately succeeding three-year
period minus (B) the amount calculated in clause (1) of the definition
of Rent Reserve Account Required Balance; or
(2) after May 14, 2004, (A) the maximum aggregate payment of Basic Rent,
other than Deferrable Payments, expected to become due on any two
successive Basic Rent payment dates in the immediately succeeding
three-year period minus (B) the amount calculated in clause (1) of the
definition of Rent Reserve Account Required Balance.
For purposes of this definition, Basic Rent due on January 2, 2000 shall be
calculated as the product of (a) 78.95% and (b) Basic Rent, other than
Deferrable Payments, payable on January 2, 2000. In any event, any payment
undertaking agreement that has terms and conditions substantially similar to the
Rent Reserve Account payment undertaking agreement in effect on May 14, 1999
shall be a payment undertaking agreement.
"Permitted Affiliate Transaction" shall mean the transactions contemplated
by the coal hauling agreement with Somerset Railroad and the Operation and
Maintenance Agreements and any other Affiliate Transaction:
(1) with respect to:
(A) the sale of emission allowances for cash, at fair market value and
on market terms, so long as we have provided the institutional
investors that formed the special purpose business trusts with a
market certification, supported by a letter from a qualified
independent broker selected by us confirming the reasonableness of
the market certification,
(B) the sale or lease of the additional land at fair market value, so
long as we have provided the institutional investors that formed the
special purpose business trusts with a market certification prior to
such event, and
(C) the sale of any part of the Assigned Assets, other than those
described in clause (A) or (B) above, so long as the institutional
investors that formed the special purpose business trusts shall have
consented in their sole discretion to the sale in writing and, in
respect of the Additional Facilities, the indenture trustee shall
have consented to such sale in writing; or
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(2) in the ordinary course of business:
(A) for a term of less than two years with regard to any single
transaction or any related series of transactions in the aggregate
and which does not provide for any advance payment to such other
person, or
(B) with respect to which (i) we shall have provided the institutional
investors that formed the special purpose business trusts with a
market certification and (ii) if the aggregate value of all
Affiliate Transactions contemplated by clause (2)(A) and subsection
(i) of this clause then in effect is (a) greater than or equal to
10% of the Annual Revenue Amount, such market certification is
supported by a letter from a qualified independent consultant
selected by us (and reasonably satisfactory to the institutional
investors that formed the special purpose business trusts)
confirming the reasonableness thereof, and (b) greater than or equal
to 33% of the Annual Revenue Amount, the institutional investors
that formed the special purpose business trusts shall have consented
in writing.
For the purposes of this definition, "Annual Revenue Amount" shall mean, at
any given time, AES Eastern Energy Revenues less any AES Eastern Energy
Extraordinary Revenues during the immediately preceding 12-month period.
"Permitted Contest" shall mean any contest which does not cause:
(1) any material risk of the foreclosure, sale, forfeiture or loss of, or
imposition of a Lien on the Kintigh Generating Station or the Milliken
Generating Station, the real property on which the Kintigh Generating
Station and the Milliken Generating Station are located, the undivided
interests in the Kintigh Generating Station and the Milliken Generating
Station, the Additional Facilities, the Collateral or any material part
thereof;
(2) any risk of the imposition of any material penalty, charge, fine or
sanction on any non-contesting Transaction Party or on any of its
Related Parties;
(3) any material risk of subjecting any non-contesting Transaction Party,
or on any of its Related Parties, to material civil liability;
(4) any risk of any criminal liability being imposed on or causing any
material adverse effect on any non-contesting Transaction Party or any
of its Related Parties, it being understood that no claim shall be
compromised by the party contesting such claim on a basis that admits
any criminal violation or gross negligence or willful misconduct on the
part of any non-contesting Transaction Party, without the express
written consent of any non-contesting Transaction Party; or
(5) any risk of subjecting any non-contesting Transaction Party or any of
its Related Parties to a regulation as a public utility under
Applicable Law.
"Permitted Encumbrances" shall mean all matters shown as exceptions on a
schedule to the title insurance policies insuring the interests of the indenture
trustee, the special purpose business trusts and our company, as in effect on
May 14, 1999.
"Permitted Indebtedness" shall mean any of the following:
(1) trade accounts payable, other than for money borrowed, and expenses
incurred in the ordinary course of business, and for which payments are
made within 90 days of the delivery of goods or services performed;
(2) Indebtedness relating to required modifications to the Kintigh
Generating Station or the Milliken Generating Station or the Additional
Facilities; provided, that, at the time of incurrence of such
Indebtedness,
(A) no Lease Bankruptcy Default or Lease Event of Default shall have
occurred and be then continuing, or would occur as a result of such
Indebtedness;
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(B) we shall have consulted with Stone & Webster, the independent
engineer, regarding the necessity, scope and cost of required
modifications;
(C) we shall have certified to Stone & Webster, the independent
engineer, and the indenture trustee that any required modifications
are required in both scope and amount to enable the Kintigh
Generating Station, the Milliken Generating Station or the
Additional Facilities, as the case may be, to comply with Applicable
Law, and
(D) after giving effect to the incurrence of such Permitted
Indebtedness, (i) during a PPA Term, the average projected pro forma
Coverage Ratio shall not be less than 1.6:1.0 with a minimum pro
forma Coverage Ratio of 1.3:1.0 and (ii) prior to and after any such
PPA Term, (a) the minimum projected Coverage Ratio for the next two
successive semiannual periods and for each fiscal year for the
remaining lease term will not be less than 2.0:1.0 and (b) the
average projected Coverage Ratio will not be less than 2.5:1.0 for
the remaining lease term;
(3) Indebtedness relating to severable modifications and nonseverable
modifications to the Kintigh Generating Station or the Milliken
Generating Station or to the Additional Facilities; provided, that, at
the time of incurrence of such Indebtedness,
(A) no Lease Bankruptcy Default or Lease Event of Default shall have
occurred and be then continuing or would occur as a result of such
Indebtedness,
(B) after giving effect to the incurrence of such Indebtedness, (i)
during a PPA Term, (a) the average projected pro forma Coverage Ratio
shall not be less than (1) 2.0:1.0 for (aa) severable modifications
to the Kintigh Generating Station or the Milliken Generating Station
and (bb) severable modifications and nonseverable modifications to
the Additional Facilities and (2) 1.75:1.0 for nonseverable
modifications to the Kintigh Generating Station or the Milliken
Generating Station and (b) the minimum projected pro forma Coverage
Ratio shall not be less than (1) 1.75:1.0 for (aa) severable
modifications to the Kintigh Generating Station or the Milliken
Generating Station and (bb) severable and nonseverable modifications
to the Additional Facilities and (2) 1.6:1.0 for nonseverable
modifications to the Kintigh Generating Station or the Milliken
Generating Station and (ii) prior to and after any such PPA Term, the
minimum projected pro forma Coverage Ratio for the next two
successive semiannual periods and for each fiscal year for the
remaining lease term shall not be less than 2.25:1.0, and (a) the
average projected Coverage Ratio will not be less than 2.75:1.0, and
(iii) the Rating Agencies have confirmed in writing that there will
be no rating downgrade of the pass through trust certificates as a
result of this Indebtedness being incurred below that then in effect
but in no event below that in effect on May 14, 1999;
(4) Indebtedness of not more than $100,000,000; provided, that not more
than $75,000,000 of such Indebtedness shall include Permitted Working
Capital Indebtedness and not more than $50,000,000 of such Indebtedness
shall include Permitted Secured Indebtedness; provided, further, that
not more than $25,000,000 of such Indebtedness, whether secured or
unsecured, may be other than Permitted Working Capital Indebtedness and
that all such Indebtedness shall be incurred for our direct benefit;
provided, further, that under certain circumstances such Indebtedness
may not be incurred in connection with the payment of any indemnity
under the operative documents;
(5) Permitted Subordinated Indebtedness; and
(6) all Rent under the leases.
"Permitted Investments" shall mean:
(1) any Payment Undertaking Agreement; or
(2) short-term senior debt instruments or certificates of deposit which
meet the following criteria,
(A) the issuer, guarantor or deposit-taking institution has senior
unsecured debt ratings of A2 or better from Moody's or A or better
from S&P and the securities purchased are rated (i) A1 or
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better by S&P or P1 or better from Moody's, in the case of a financial
institution issuing a bankers acceptance, commercial paper or a certificate of
deposit; (ii) A1 or better by S&P or P1 or better by Moody's, in the case of
money market or bond funds; or (iii) A or better by Moody's or A2 or
better by S&P, for all other forms of investments; provided, that the
obligor is not The AES Corporation or any of its affiliates, and
(B) such instruments or certificates of deposit have a remaining term to
maturity of the shorter of (i) 180 days, or (ii) the date upon which
a payment is anticipated to be required to be made out of such
proceeds from such Account, or
(C) money market mutual funds registered under the Investment Company
Act of 1940, as amended, having a rating in the highest investment
category by S&P and Moody's.
"Permitted Liens" shall mean the following:
(1) Liens for (A) taxes not yet due and payable or (B) taxes being
contested in good faith by a Permitted Contest, if adequate cash
reserves for such taxes have been established and are being maintained
in accordance with GAAP;
(2) suppliers', vendors', workmen's, repairmen's, employee's, mechanics',
materialmen's or other like Liens arising in the ordinary course of
business for amounts the payment of which is either not yet delinquent
or is being contested in good faith by a Permitted Contest and we shall
maintain cash reserves for the discharge of the Lien in accordance with
GAAP;
(3) pre-judgment Liens for claims against us or any sublessee permitted
under the lease which are contested in good faith and liens arising out
of judgments or awards against us or any such sublessee with respect to
which an appeal or proceeding for review is being prosecuted in good
faith and to which a stay of execution has been obtained pending such
appeal or review; provided, however, that we shall post a bond or other
surety obligation, in form, scope and substance satisfactory to the
special purpose business trusts, for any judgment default in excess of
$5 million;
(4) easements, servitudes, covenants, conditions, restrictions and land
charges in respect of the Kintigh Generating Station or the Milliken
Generating Station or any of the Additional Facilities which do not
have a material adverse effect on the current or residual value, useful
life or utility of the Kintigh Generating Station or the Milliken
Generating Station or any of the Additional Facilities;
(5) Liens created or expressly permitted by any operative document,
including, but not limited to, the Lien of the lease indenture;
(6) Liens of the special purpose business trust, Liens of the institutional
investors that formed the special purpose business trusts, Liens of the
indenture trustee and similar Liens under any other operative document;
and
(7) Permitted Encumbrances.
"Permitted Secured Indebtedness" shall mean Indebtedness that is secured
(including any Permitted Working Capital Indebtedness) by a Lien on any of our
assets; provided, however, that not more than $25,000,000 of such Indebtedness
may be other than secured Permitted Working Capital Indebtedness.
"Permitted Subordinated Indebtedness" shall mean Indebtedness, not to
exceed $100,000,000, which Indebtedness shall by its terms:
(1) be payable on a subordinated basis to the payment of all Rent under the
leases and the funding of all reserves under the deposit and
disbursement agreement and only from the distribution account, an
account established under the deposit and disbursement agreement, and
to the extent a distribution is permitted pursuant to the provisions of
the Participation Agreement;
(2) have no right to declare a default with respect to non-payment of
principal or interest;
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(3) have no rights of acceleration or rights of enforcement against, or
permit or result in any Lien on any of our assets, including the
Assigned Assets; and
(4) have no rights to participate as a debtholding creditor in any
bankruptcy proceedings.
"Permitted Working Capital Indebtedness" shall mean Indebtedness incurred
for working capital purposes.
"PPA" shall mean an arm's-length, executed, valid and binding power
purchase agreement between us or any AES Eastern Energy Subsidiary and a third
party relating to the purchase and sale of electric energy or installed
capacity.
"PPA Term" shall mean, a PPA or series of PPAs with a term of at least five
consecutive years, during which we or AEE2, L.L.C. has a legally valid and
binding contract for the sale at a scheduled price of all or a portion of the
installed capacity and electric energy to a third party purchaser or third party
purchasers, each of whose senior unsecured long-term debt credit rating is at
least Investment Grade; provided, however, that the ratio of all AES Eastern
Energy Revenues received under such PPA(s) to Fixed Charges and Operating and
Maintenance Costs, other than variable costs associated with energy production
not associated with a PPA, is at least 1.0:1.0; and provided, further, that no
such PPA has any advance payment or tracking account obligations or other form
of refundable revenues and the PPA and any other related documents provide
reasonable linkage between revenues and costs, which "reasonable linkage" shall
be confirmed by a qualified independent consultant; provided, that costs, unless
otherwise contracted, shall be assumed to escalate with inflation.
Notwithstanding the foregoing, with the consent of the institutional
investors that formed the special purpose business trusts, which consent shall
be determined in their sole discretion, a "PPA Term" shall mean a period of at
least two consecutive years during which we or AEE2, L.L.C., as applicable, has
a PPA or series of PPAs for the sale at a scheduled price of 75% or more of the
installed capacity and electric energy of the Kintigh Generating Station or the
Milliken Generating Station and the Additional Facilities to a third party
purchaser or third party purchasers whose senior unsecured long-term debt rating
is at least Investment Grade.
"PUA Provider" shall mean either:
(1) a financial institution, the senior unsecured long term debt rating of
which is rated at least Aa3 by Moody's and AA- by S&P; or
(2) a financial institution which has provided collateral in an amount
equal to or exceeding the amount referenced in clause (4) of the
definition of Payment Undertaking Agreement.
"Purchase Price" shall mean $650,000,000, the appraised fair market value
of the Kintigh Generating Station and the Milliken Generating Station as of May
14, 1999.
"Rating Agencies" shall mean S&P and Moody's.
"Rent" shall mean Basic Rent and Supplemental Rent.
"Related Party" shall mean, with respect to any person or its successors
and assigns, an affiliate of such person or its successors and assigns and any
director, officer, shareholder, partner, member, manager, servant, employee or
agent of that person or any such affiliate or their respective successors and
assigns; provided, that the special purpose business trustee and the special
purpose business trusts shall not be treated as related parties to each other
and neither the special purpose business trusts nor the special purpose business
trustee shall be treated as a related party to the institutional investors that
formed the special purpose business trusts except that, for purposes of certain
provisions of the Participation Agreements, the special purpose business trusts
will be treated as a related party to the institutional investors that formed
the special purpose business trusts to the extent that the special purpose
business trusts act on the express direction or with the express written consent
of the institutional investors that formed the special purpose business trusts.
"Renewal Rent" shall mean the Basic Rent payable during any renewal period
as determined under the applicable lease.
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"Renewal Term" shall mean the renewal term of a lease permitted under the
lease.
"Rent Payment Date" shall mean each January 2 and July 2, commencing
January 2, 2000, to and including the Lease Expiration Date.
"Rent Payment Period" shall mean in the case of the first rent payment
period, the period commencing on May 14, 1999 and ending on January 2, 2000 and
thereafter each six-month period or shorter period in the case of the last
period during the applicable lease term
- commencing on the day after each rent payment date through and including
the lease Expiration Date, and
- during any Renewal Term, on the day after each Rent Payment Date through
but excluding the expiration of such Renewal Term.
"Rent Reserve Account Required Balance" shall mean an amount equal to the
sum of the maximum aggregate semiannual payment of:
(1) Basic Rent other than Deferrable Payments; and
(2) all other Fixed Charges scheduled to be paid during any semiannual
period ending on a Rent Payment Date in the immediately succeeding
three-year period; provided, however, that for the purposes of the
above calculation, Basic Rent due on January 2, 2000 shall be
calculated as the product of (a) 78.95% and (b) Basic Rent, other than
Deferrable Payments, payable on January 2, 2000.
"Replacement Event" shall mean:
(1) in the case of any Additional Liquidity Letter of Credit, either (A)
the rating of the senior unsecured debt of the issuer of such
Additional Liquidity Letter of Credit being downgraded below A1 by
Moody's or A- by S&P, or (B) the occurrence within the next 15 days of
the expiration date of any Additional Liquidity Letter of Credit and
our failure to provide any letter of credit that satisfies the
requirements of an Additional Liquidity Letter of Credit specified in
the definition of such term; and
(2) in the case of any Payment Undertaking Agreement, the downgrade of the
senior unsecured long term debt rating of the PUA Provider below Aa3 by
Moody's or AA- by S&P and failure of the PUA Provider to provide
collateral in an amount equal to or exceeding the amount set forth on a
schedule attached to the Payment Undertaking Agreement.
"Required Coverage Ratio" shall mean:
(1) for any period during a PPA Term, a Coverage Ratio of 1.5:1.0;
(2) for any period that is not a PPA Term, a Coverage Ratio of 1.7:1.0; and
(3) for any period which spans the beginning or ending of a PPA Term, a pro
rata Coverage Ratio between 1.50:1.0 and 1.7:1.0 based on the number of
days in the period which belong to a PPA Term.
"Responsible Officer" shall mean:
(1) with respect to any Person, its chairman of the board, its president,
any senior vice president, the chief financial officer, any vice
president, the treasurer or any other management employee (A) that has
the power to take the action in question and has been authorized,
directly or indirectly, by the board of directors of such person, (B)
working under the direct supervision of such chairman of the board,
president, senior vice president, chief financial officer, vice
president or treasurer and (C) whose responsibilities include the
administration of the transactions and agreements contemplated by the
operative documents and, in the case of our company, the management of
either the Kintigh Generating Station or the Milliken Generating
Station; and
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(2) with respect to the special purpose business trustee, indenture trustee
and the pass through trustee and the depositary and disbursement agent,
an officer in their respective corporate trust departments.
"Special Payment" shall mean payments received by the pass through trustee
following a default in respect of the secured lease obligation notes held in the
related pass through trust, including, but not limited to, payments received on
account of the sale of such secured lease obligation notes by the pass through
trustee.
"Special Purpose Business Trust Company" shall mean Wilmington Trust
Company, a Delaware banking corporation, in its individual capacity, and each
other person which may from time to time be acting as special purpose business
trust company in accordance with the provisions of the special purpose business
trust agreements.
"Special Purpose Business Trustee" shall mean Wilmington Trust Company, a
Delaware banking corporation, not in its individual capacity, but solely as
special purpose business trustee under the special purpose business trust
agreements and each other person which may from time to time be acting as
special purpose business trustee in accordance with the provisions of the
special purpose business trust agreements.
"Special Rent Reserve Account Required Balance" shall mean, during a
Special Rent Reserve Period, an amount equal to:
(1) prior to May 14, 2004, (A) the maximum aggregate payment of Basic Rent,
other than Deferrable Payments, expected to become due on any three
successive Basic Rent payment dates in the immediately succeeding
three-year period minus (B) the amount set forth in clause (1) of the
definition of the Rent Reserve Account Required Balance; or
(2) after May 14, 2004, (A) the maximum aggregate payment of Basic Rent,
other than Deferrable Payments, expected to become due on any two
successive Basic Rent payment dates in the immediately succeeding
three-year period minus (B) the amount set forth in clause (1) of the
definition of the Rent Reserve Account Required Balance.
For the purpose of this definition, Basic Rent due on January 2, 2000 shall be
the product of (a) 78.95% and (b) Basic Rent, other than Deferrable Payments,
payable on January 2, 2000.
"Special Rent Reserve Period" shall mean at any time prior to January 2,
2029, the period that commences upon the occurrence of:
(1) the senior unsecured long-term debt of The AES Corporation being rated
lower than B+ by S&P; and
(2) our failure to satisfy the Required Coverage Ratio.
A Special Rent Reserve Period shall end on the date that either of the
events specified in clause (1) or (2) no longer exists.
"Supplemental Rent" shall mean any and all amounts, liabilities and
obligations, other than Basic Rent, which we assume or agree to pay under the
registration rights agreement and the operative documents, whether or not
identified as "Supplemental Rent," to the special purpose business trusts or any
other person, including, but not limited to, the termination value set forth on
a schedule to the applicable lease.
"Support Agreements" shall mean the real property leases, the Facilities
Support Agreement, the coal hauling agreement with Somerset Railroad, the
Interconnection Agreement and any other document or agreement, including
easements and rights of way, that provides similar or related support rights for
the lease, use, operation, maintenance and monitoring of the Kintigh Generating
Station or the Milliken Generating Station and the real property of those
electricity generating stations.
"Tax" or "Taxes" shall mean all fees, taxes, including, without limitation,
sales taxes, use taxes, stamp taxes, value-added taxes, ad valorem taxes and
property taxes (personal and real, tangible and intangible), levies,
assessments, withholdings and other charges and impositions of any nature, plus
all related interest, penalties, fines and additions to tax, now or hereafter
imposed by any federal, state, local or foreign government or other taxing
authority.
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"Termination Date" shall mean each of the monthly dates during the lease
terms identified as a "Termination Date" in each of the leases.
"Transaction Party" shall mean, individually or collectively, as the
context shall require, all or any of the parties to each of the Participation
Agreements.
EVENTS OF DEFAULT AND CERTAIN RIGHTS UPON AN EVENT OF DEFAULT
An event of default under the pass through trust agreements is defined as
the occurrence and continuance of an event of default under the related lease
indentures (a "Lease Indenture Event of Default"). For a description of the
Lease Indenture Events of Default, see "-- THE SECURED LEASE OBLIGATION NOTES --
GENERAL." Under the lease indentures, each special purpose business trust has
the right under limited circumstances to cure Lease Indenture Events of Default
that result from the occurrence of an event of default under the related lease
(a "Lease Event of Default"). If the special purpose business trust chooses to
exercise its cure right, the Lease Indenture Events of Default and consequently
the Events of Default will be deemed to be cured.
ACCELERATION ON LEASE INDENTURE EVENT OF DEFAULT. Each pass through trust
agreement provides that, as long as a Lease Indenture Event of Default shall
have occurred and be continuing, the pass through trustee may vote all of the
secured lease obligation notes that are held in the related pass through trust,
and upon the direction of the holders of pass through trust certificates
evidencing fractional undivided interests aggregating not less than a majority
in interest of the related pass through trust, the pass through trustee shall
vote a corresponding majority of such secured lease obligation notes in favor of
directing the indenture trustee to declare the unpaid principal amount of all of
the outstanding secured lease obligation notes and any accrued and unpaid
interest on these notes to be due and payable.
REMEDIES. Each pass through trust agreement in addition provides that, if
a Lease Indenture Event of Default shall have occurred and be continuing, the
pass through trustee may, and upon the direction of the holders of pass through
trust certificates evidencing fractional undivided interests aggregating not
less than a majority in interest of the related pass through trust shall, vote
all of the secured lease obligation notes that are held in such pass through
trust to direct the indenture trustee regarding the exercise of remedies
provided in the lease indenture in a manner consistent with the terms of the
lease indenture.
The lease indentures provide that, if a Lease Indenture Event of Default
and Lease Event of Default shall occur and be continuing under the lease
indentures, neither the indenture trustee nor any Certificateholders shall be
entitled to exercise any remedy under such lease indenture which could or would
divest the applicable special purpose business trust of its ownership interest
in or title to any collateral subject to the related lease indenture, unless in
the case of a Lease Indenture Event of Default as a consequence of a Lease Event
of Default the indenture trustee shall, to the extent it is then entitled to do
so under the lease indenture, and is not then stayed or otherwise prevented from
doing so by operation of law, have begun the exercise of one or more of the
remedies referred to in the related lease intended to dispossess us of the
related undivided interest in the Kintigh Generating Station or the Milliken
Generating Station under the applicable lease and is using good faith efforts to
exercise these remedies and not merely asserting a right or claim to do so;
provided, that if the indenture trustee is then stayed or prevented by operation
of law, then the indenture trustee shall not divest the special purpose business
trust of its interest in the collateral until the earlier of
- the expiration of the 180-day period following the commencement of the
stay or other prevention, or
- the date of repossession of the undivided interest in the electricity
generating station under the lease.
If any event occurs which will mature into an event of default under the
lease indenture which arises out of the failure to pay the equity portion of
Basic Rent under the related lease, the indenture trustee shall not, so long as
no other Lease Indenture Event of Default shall have occurred and be continuing,
be entitled to exercise remedies under the lease indenture for a period of 180
days unless a Lease Event of Default under the related lease is duly declared
prior to the expiration of the 180-day period by the indenture trustee with the
consent of the applicable special purpose business trust or institutional
investor that formed the special purpose business trusts.
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ADDITIONAL REMEDIES; SALE OF SECURED LEASE OBLIGATION NOTES. As an
additional remedy, if a Lease Indenture Event of Default shall have occurred and
be continuing, the pass through trust agreements provide that the pass through
trustee may, and upon the direction of the Certificateholders evidencing
fractional undivided interests aggregating not less than a majority in interest
of the related pass through trust shall, sell all or part of the secured lease
obligation notes that are held in this pass through trust for cash to any
person. In addition, if a particular special purpose business trust elects to
purchase or redeem the secured lease obligation notes upon the occurrence and
continuance of a Lease Indenture Event of Default, the pass through trustee
shall sell the secured lease obligation notes held in the related pass through
trust upon all terms and conditions and at the prices as it may reasonably deem
advisable. Any proceeds received by the pass through trustee upon any sale shall
be deposited in the Special Payments Account with respect to the applicable pass
through trust and shall be distributed to the Certificateholders with respect to
the applicable pass through trust on a Special Distribution Date.
The market for secured lease obligation notes in default may be very
limited and there can be no assurance that they could be sold for a reasonable
price. If a pass through trustee sells any secured lease obligation notes held
in the related pass through trust with respect to which a Lease Indenture Event
of Default exists for less than their outstanding principal amount, the
Certificateholders with respect to this pass through trust will receive a
smaller amount of principal distributions than anticipated and will not have any
claim for the shortfall against us, the applicable special purpose business
trusts or the pass through trustee.
DISTRIBUTIONS ON SALE OF SECURED LEASE OBLIGATION NOTES. Any amount
distributed to the pass through trustee by the indenture trustee on account of
the secured lease obligation notes held in the related pass through trust
following a Lease Indenture Event of Default shall be deposited in the Special
Payments Account with respect to the applicable pass through trust and shall be
distributed to the Certificateholders with respect to the applicable pass
through trust on a Special Distribution Date. In addition, if following a Lease
Indenture Event of Default, the applicable special purpose business trust or
institutional investor that formed the special purpose business trusts exercises
its option to purchase the outstanding secured lease obligation notes held in
the related pass through trust, the purchase price paid by the special purpose
business trust or institutional investor that formed the special purpose
business trusts to the pass through trustee for the secured lease obligation
notes held in the pass through trust shall be deposited in the Special Payments
Account with respect to the applicable pass through trust and shall be
distributed to the Certificateholders with respect to the applicable pass
through trust on a Special Distribution Date.
Any funds representing payments received by the pass through trustee
pursuant to the pass through trust agreement representing a Special Payment with
respect to the applicable pass through trust that is not to be distributed
promptly shall, to the extent practicable, be invested by the pass through
trustee in permitted government investments pending the distribution of these
funds on a Special Distribution Date. The term "permitted government
investments" is defined as being obligations of the United States for the
payment of which the full faith and credit of the United States is pledged
maturing in not more than 60 days or such lesser time as is required for the
distribution of any such funds on a Special Distribution Date. The pass through
trustee is prohibited from selling any permitted government investment prior to
its maturity.
NOTICE OF DEFAULTS. Each pass through trust agreement provides that the
pass through trustee shall, within 90 days after the occurrence of a default in
respect of the pass through trust created under the pass through trust
agreement, give to the Certificateholders, us, the applicable special purpose
business trusts and the indenture trustee notice, transmitted by mail, of all
uncured or unwaived defaults under the related pass through trust agreement
actually known to a Responsible Officer of the pass through trustee; provided,
that except in the case of default in the payment of principal, premium, if any,
or interest on any of the secured lease obligation notes held in the applicable
pass through trust, the pass through trustee shall be protected in withholding
notice if a committee of its directors determines in good faith that the
withholding of notice is in the interests of such Certificateholders with
respect to the applicable pass through trust. The term "default," for the
purpose of the provision described in this paragraph only, shall mean the
occurrence of any event which is or, after notice or a lapse of time or both
would become, an Event of Default.
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Each pass through trust agreement contains a provision entitling the pass
through trustee, subject to the duty of the pass through trustee during a
default to act with the required standard of care, to be indemnified by the
Certificateholders before proceeding to exercise any right or power under the
pass through trust agreement at the request of the Certificateholders.
WAIVER OF DEFAULTS. In certain cases, Certificateholders of a pass through
trust evidencing fractional undivided interests aggregating not less than a
majority in interest of the pass through trust may on behalf of all
Certificateholders with respect to the pass through trust waive any default or
Event of Default and its consequences under the pass through trust agreement
with respect to the pass through trust and thereby annul any direction given by
the holders to the indenture trustee with respect thereto, except:
(1) a default in the deposit of any Scheduled Payment or Special Payment or
in the distribution of any payment;
(2) a default in payment of the principal of, premium, if any, or interest
on, any of the secured lease obligation notes; or
(3) a default in respect of any covenant or provision of the pass through
trust agreement that cannot be modified or amended without the consent
of each Certificateholder affected by any modification or amendment.
The lease indentures provide that, with limited exceptions, the holders of
a majority in aggregate unpaid principal amount of the secured lease obligation
notes may on behalf of all holders waive any past default or Lease Indenture
Event of Default.
MODIFICATION OF THE PASS THROUGH TRUST AGREEMENTS
MODIFICATIONS WITHOUT CONSENT OF CERTIFICATEHOLDERS. Each pass through
trust agreement contains provisions permitting us and the pass through trustee
to enter into a supplemental trust agreement, without the consent of any
Certificateholders, among other things:
(1) to evidence the succession of another corporation to our company and
the assumption by any such successor of our obligations under the pass
through trust agreement;
(2) to add to our covenants for the protection of these Certificateholders;
(3) to cure any ambiguity in, or to correct or supplement any defective or
inconsistent provision of, the pass through trust agreement or to make
any other provisions with respect to matters or questions arising under
the pass through trust agreement; provided any actions taken shall not
adversely affect the interests of the Certificateholders; or
(4) to add, eliminate, or change any provision under the pass through trust
agreement that shall not adversely affect the interests of the
Certificateholders and provided in each case that such supplemental
trust agreement does not cause the pass through trust to be subject to
adverse tax treatment.
MODIFICATIONS WITH CONSENT OF CERTIFICATEHOLDERS AND SPECIAL PURPOSE
BUSINESS TRUSTS. Each pass through trust agreement also contains provisions
permitting us and the pass through trustee, with the consent of the holders of
pass through trust certificates evidencing fractional undivided interests
aggregating not less than a majority in interest of the related pass through
trust, and with the consent of the applicable special purpose business trusts,
which consent may not be unreasonably withheld, to enter into supplemental trust
agreements adding provisions to or changing or eliminating any of the provisions
of the pass through trust agreement or modifying the rights of the
Certificateholders, except that no such supplemental trust agreement may,
without the consent of each Certificateholder so affected:
(1) reduce in any manner the amount of, or delay the timing of, any receipt
by the pass through trustee of payments on the secured lease obligation
notes held in such pass through trust, or distributions in respect of
any pass through trust certificate, or change any date of payment on
any pass through trust certificate, or change the place of payment
where any pass through trust certificate is payable, or
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make distributions payable in coin or currency other than that provided
for in the pass through trust certificates, or impair the right of any
Certificateholder to institute suit for the enforcement of any such
payment when due;
(2) permit the disposition of any secured lease obligation note held in the
related pass through trust, permit the creation of a lien on the pass
through trust or otherwise deprive any Certificateholder of the benefit
of ownership of the secured lease obligation notes or the lien of the
related lease indenture, except as provided in the pass through trust
agreement;
(3) reduce the percentage of the aggregate fractional undivided interest of
the related pass through trust provided for in the pass through trust
agreement that is required to approve any supplemental trust agreement,
or reduce the percentage required for any waiver provided for in the
pass through trust agreement; or
(4) cause the pass through trust to become taxable as an "association" or
to fail to qualify as a fixed investment trust for federal income tax
purposes.
MODIFICATION OF OPERATIVE DOCUMENTS
MODIFICATIONS PERMITTED WITH CONSENT OF SPECIAL PURPOSE BUSINESS
TRUSTS. An indenture trustee may, with the consent of the related special
purpose business trust, enter into any indenture or indentures supplemental to
the applicable lease indenture or execute any amendment, modification,
supplement, waiver or consent with respect to any other operative document:
(1) to evidence the succession of another person as a trustee or the
appointment of a co-trustee in accordance with the terms of the related
trust agreement or to evidence the succession of a successor as the
indenture trustee under the lease indenture, the removal of the
indenture trustee or the appointment of any separate or additional
trustee or trustees and to define the rights, powers, duties and
obligations conferred upon any separate trustee or trustees or
co-trustee or co-trustees;
(2) to correct, confirm or amplify the description of any property at any
time subject to the lien of the lease indenture or to convey, transfer,
assign, mortgage or pledge any property to or with the indenture
trustee;
(3) to provide for any evidence of the creation and issuance of any
additional secured lease obligation notes;
(4) to cure any ambiguity in, to correct or supplement any defective or
inconsistent provision of, or to add to or modify any other provisions
and agreements in, the lease indenture or any other operative document
in any manner that will not in the judgment of the indenture trustee
materially adversely affect the interests of the holders of the secured
lease obligation notes;
(5) to grant or confer upon the indenture trustee for the benefit of the
holders of the related secured lease obligation notes any additional
rights, remedies, powers, authority or security which may be lawfully
granted or conferred and which are not contrary or inconsistent with
the lease indenture;
(6) to add to the covenants or agreements to be observed by the applicable
special purpose business trust and which are not contrary to the lease
indenture, to add Lease Indenture Events of Default for the benefit of
the holders of the related secured lease obligation notes or surrender
any right or power of the applicable special purpose business trust
provided it has consented to any covenant or amendment; and
(7) with respect to any indenture or indentures supplemental to a lease
indenture or any amendment, modification, supplement, waiver or consent
with respect to any other operative document, provided any supplemental
indenture, amendment, modification, supplement, waiver or consent shall
not, in the judgment of the indenture trustee, materially adversely
affect the interest of the holders of the related secured lease
obligation notes; provided, however, that no amendment, modification,
supplement, waiver or consent shall, without the consent of the holders
of a majority in interest of
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the secured lease obligation notes, modify our covenants in the related
Participation Agreement; provided, further, however, that without the
consent of the holders representing one hundred percent (100%) of the
outstanding principal amount of related secured lease obligation notes,
no supplement to or amendment of the lease indenture or the related
lease, the lease relating to the real property on which the Kintigh
Generating Station and the Milliken Generating Station are located, the
sublease relating to the real property on which the Kintigh Generating
Station and the Milliken Generating Station are located or the
Participation Agreement, or waiver or modification of or consent to the
terms of these documents, shall
(A) modify the definition of the majority in interest of holders of
secured lease obligation notes in the lease indenture or reduce the
percentage of holders of the secured lease obligation notes
required to take or approve any action thereunder,
(B) change the amount or the time of payment of any amount owing or
payable under any related secured lease obligation note or change
the rate or manner of calculation of interest payable on any related
secured lease obligation note,
(C) alter or modify the provisions of the lease indenture with respect
to the manner of payment or the order of priorities in which
distributions under the lease indentures shall be made as between
the holders of the related secured lease obligation notes and the
applicable special purpose business trust,
(D) reduce the amount, except to any amount as shall be sufficient to
pay the aggregate principal of and interest on all outstanding
secured lease obligation notes, or extend the time of payment of
Basic Rent, stipulated loss value or termination value as set forth
on a schedule to the applicable lease, except as expressly provided
in the related lease, or change any of the circumstances under which
Basic Rent, stipulated loss value or termination value is payable,
or
(E) consent to any assignment of the related lease if in connection with
the assignment, we will be released from our obligation to pay Basic
Rent, stipulated loss value and termination value, except as
expressly provided under "-- THE LEASES, THE FACILITY SITE LEASES
AND THE FACILITY SITE SUBLEASES -- SUBLEASE AND ASSIGNMENT," or
reduce our obligations in respect of the payment of Basic Rent,
stipulated loss value or termination value or change the absolute
and unconditional character of these obligations as listed in the
related lease.
MODIFICATIONS PERMITTED WITH CONSENT OF CERTIFICATEHOLDERS. In the event
that the pass through trustee, as the holder of the secured lease obligation
notes in trust for the benefit of the Certificateholders, receives a request for
its consent to any amendment, modification, waiver or supplement under any lease
indenture, lease or other related document, the pass through trustee shall mail
a notice of this proposed amendment, modification, waiver or supplement to each
Certificateholder of the applicable pass through trust registered on the
register as of the date of the notice. The pass through trustee shall request
from the Certificateholders of the applicable pass through trust directions as
to:
(1) whether or not to direct the indenture trustee to take or refrain
from taking any action which a holder of a secured lease obligation
note has the option to direct;
(2) whether or not to give or execute any waivers, consents, amendments,
modifications or supplements as a holder of a secured lease
obligation note; and
(3) how to vote any secured lease obligation note if a vote has been
called.
The pass through trustee shall vote or consent with respect to the secured
lease obligation notes held in the related pass through trust in the same
proportion as the pass through trust certificates were actually voted by the
Certificateholders of the pass through trust by the date specified in the
notice. Notwithstanding the foregoing, if an Event of Default under the pass
through trust agreement shall have occurred and be continuing, the pass through
trustee, subject to the voting instructions referred to under the caption
"-- EVENTS OF DEFAULT AND CERTAIN RIGHTS UPON AN EVENT OF DEFAULT," may in its
own discretion consent to any amendment, modification, waiver or supplement, and
may so notify the indenture trustee.
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TERMINATION OF THE PASS THROUGH TRUSTS
The respective obligations of our company and the pass through trustee
created by the pass through trust agreements, and the pass through trusts, will
terminate upon the distribution to Certificateholders of all amounts required to
be distributed to them under the pass through trust agreements and the
disposition of all property held in the pass through trusts. The pass through
trustee will mail to each Certificateholder notice of the termination of the
related pass through trust, the amount of the proposed final payment and the
proposed date for the distribution of the final payment for the pass through
trust. The final distribution to any Certificateholder will be made only upon
surrender of such Certificateholder's pass through trust certificates at the
office or agency of the pass through trustee specified in the notice of
termination.
THE PASS THROUGH TRUSTEE
Bankers Trust Company is the pass through trustee for each pass through
trust. Bankers Trust and any of its affiliates may hold pass through trust
certificates in their own names. With some exceptions, Bankers Trust makes no
representations as to the validity or sufficiency of the pass through trust
agreements, the pass through trust certificates, the secured lease obligation
notes, the lease indentures, the leases or other related documents. Bankers
Trust is also the indenture trustee for the secured lease obligation notes
issued with respect to each undivided interest in the Kintigh Generating Station
and the Milliken Generating Station and the ground interest in the real property
of the Kintigh Generating Station and the Milliken Generating Station under the
lease indentures.
Bankers Trust may resign with respect to any or all of the pass through
trusts at any time, in which event we will be obligated to appoint a successor
trustee. If Bankers Trust ceases to be eligible to continue as trustee under the
pass through trust agreements or becomes insolvent, we may remove Bankers Trust,
or any Certificateholder which has held a pass through trust certificate for at
least six months may, on behalf of himself and all others similarly situated,
petition any court of competent jurisdiction for the removal of Bankers Trust
and the appointment of a successor trustee. Any resignation or removal of
Bankers Trust and appointment of a successor trustee for a pass through trust
does not become effective until acceptance of the appointment by the successor
trustee.
Each pass through trust agreement provides that we will pay Bankers Trust's
fees and expenses. Each pass through trust agreement further provides that
Bankers Trust will be entitled to reimbursement by us for all reasonable
out-of-pocket expenses, disbursements and advances incurred or made by Bankers
Trust in accordance with the pass through trust agreements, except any expense,
disbursement or advance as may be attributable to its negligence, willful
misconduct or bad faith. In addition, Bankers Trust shall be entitled to
reimbursement from, and shall have a lien prior to the pass through trust
certificates upon, all property and funds held or collected by Bankers Trust for
any tax, other than any tax attributable to Bankers Trust's compensation for
serving as the pass through trustee, incurred without negligence, willful
misconduct or bad faith, on its part, arising out of or in connection with the
acceptance or administration of the pass through trust.
BOOK-ENTRY; DELIVERY AND FORM
We will arrange for the pass through trusts to issue new pass through trust
certificates in exchange for existing pass through trust certificates currently
represented by one or more fully registered global certificates. The new pass
through trust certificates will be represented by one or more fully registered
global certificates, and will be deposited upon issuance with The Depository
Trust Company or a nominee of The Depository Trust Company.
The pass through trusts will issue new pass through trust certificates in
certificated form without interest coupons in exchange for existing pass through
trust certificates, which were issued originally in certificated form without
interest coupons.
The Depository Trust Company has advised us as follows: The Depository
Trust Company is a limited purpose trust company organized under the laws of the
State of New York, a "banking organization" within the meaning of the New York
Banking Law, a member of the Federal Reserve System, a "clearing
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corporation" within the meaning of the Uniform Commercial Code and a "Clearing
Agency" registered pursuant to the provisions of Section 17A of the Exchange
Act. The Depository Trust Company was created to hold securities for its
participants and facilitate the clearance and settlement of securities
transactions between participants through electronic book-entry changes in
accounts of its participants, thereby eliminating the need for physical movement
of certificates. Participants include securities brokers and dealers, banks,
trust companies and clearing corporations and some other organizations. Indirect
access to The Depository Trust Company system is available to others such as
banks, brokers, dealers and trust companies that clear through or maintain a
custodial relationship with a participant, either directly or indirectly.
We expect that, pursuant to the procedures established by The Depository
Trust Company,
- upon the issuance of the global certificates, The Depository Trust
Company or its custodian will credit, on its internal system, the
respective principal amount of the individual beneficial interests
represented by global certificates to the accounts of persons who have
accounts with The Depository Trust Company,
- ownership of beneficial interests in the global certificates will be
limited to persons who have accounts with The Depository Trust Company or
persons who hold interests through participants, and
- ownership of beneficial interests in the global certificates will be
shown on, and the transfer of that ownership will be effected only
through, records maintained by The Depository Trust Company or its
nominee (with respect to interests of participants) and the records of
participants (with respect to interests of persons other than
participants).
The laws of some states require some purchasers of securities to take
physical delivery of securities. These limits and laws may limit the market for
beneficial interests in the global certificates. Qualified institutional buyers
may hold their interests in the global certificates directly through The
Depository Trust Company if they are participants, or indirectly through
organizations that are participants in the system.
So long as The Depository Trust Company or its nominee is the registered
owner or holder of the global certificates, The Depository Trust Company or its
nominee, as the case may be, will be considered the sole record owner or holder
of the pass through trust certificates represented by global certificates for
all purposes under the related pass through trust agreements. No beneficial
owners of an interest in global certificates will be able to transfer that
interest except in accordance with The Depository Trust Company's applicable
procedures, in addition to those provided for under the pass through trust
agreements and, if applicable, the Euroclear System and Centrale de Livraison de
Valeurs Mobilieres S.A.
Payments of the principal of, premium, if any, and interest on global
certificates will be made to The Depository Trust Company or its nominee, as the
case may be, as the registered owner of the pass through trust certificates.
Neither we nor the pass through trustee, nor any paying agent will have any
responsibility or liability for any aspect of the records relating to or
payments made on account of beneficial ownership interests in global
certificates or for maintaining, supervising or reviewing any records relating
to beneficial ownership interests.
We expect that
- The Depository Trust Company or its nominee, upon receipt of any payment
of principal, premium, if any, or interest in respect of global
certificates will credit participants' accounts with payments in amounts
proportionate to their respective beneficial ownership interests in the
principal amount of the global certificates, as shown on the records of
The Depository Trust Company or its nominee, and
- payments by participants to owners of beneficial interests in global
certificates held through participants will be governed by standing
instructions and customary practices, as is now the case with securities
held for the accounts of customers registered in the names of nominees
for customers.
Any payments will be the responsibility of participants.
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Neither we nor the pass through trustee will have any responsibility for
the performance by The Depository Trust Company or its participants or indirect
participants of their respective obligations under the rules and procedures
governing their operations.
If The Depository Trust Company is at any time unwilling or unable to
continue as a depositary for global certificates and a successor depositary is
not appointed within 90 days, Bankers Trust or the successor pass through
trustee will issue definitive certificates in exchange for global certificates.
The Depository Trust Company management is aware that some computer
applications, systems, and the like for processing data that are dependent upon
calendar dates, including dates before, on, and after January 1, 2000, may
encounter "Year 2000 problems." The Depository Trust Company has informed its
participants and other members of the financial community that it has developed
and is implementing a program so that its systems, as the same relate to the
timely payment of distributions, including principal and income payments, to
securityholders, book-entry deliveries, and settlement of trades within The
Depository Trust Company, continue to function appropriately. This program
includes a technical assessment and a remediation plan, each of which is
complete. Additionally, The Depository Trust Company's plan includes a testing
phase, which is expected to be completed within approximate time frames.
However, The Depository Trust Company's ability to perform properly its
services is also dependent upon other parties, including but not limited to
issuers and their agents, as well as third party vendors from whom The
Depository Trust Company licenses software and hardware, and third party vendors
on whom The Depository Trust Company relies for information or the provision of
services, including telecommunication and electrical utility service providers,
among others. The Depository Trust Company has informed its participants and
members of the financial community that it is contacting, and will continue to
contact, third party vendors from whom The Depository Trust Company acquires
services to:
(1) impress upon them the importance of their services being Year 2000
compliant; and
(2) determine the extent of their efforts for Year 2000 remediation and, as
appropriate, testing of their services.
In addition, The Depository Trust Company is in the process of developing
contingency plans as it deems appropriate.
According to The Depository Trust Company, the foregoing information with
respect to The Depository Trust Company has been provided to its participants
and members of the financial community for informational purposes only and is
not intended to serve as a representation, warranty, or contract modification of
any kind.
THE SECURED LEASE OBLIGATION NOTES
GENERAL. The secured lease obligation notes were issued in two series or
tranches under each lease indenture between the applicable special purpose
business trust and Bankers Trust, as indenture trustee.
Each special purpose business trust leased the related undivided interest
in the Kintigh Generating Station or the Milliken Generating Station and
subleased the related ground interest to us pursuant to the related lease, the
lease relating to the real property on which the electricity generating stations
are located and the sublease relating to the real property on which the
electricity generating stations are located. We are obligated to make or cause
to be made rental and other payments to each special purpose business trust
under the related lease in amounts that will be at least sufficient to pay the
principal of, premium, if any, and interest on the related secured lease
obligation notes when and as due and payable, except principal and interest
payable upon a Lease Indenture Event of Default that is not caused by a Lease
Event of Default and except any premium payable by the applicable institutional
investor that formed the special purpose business trusts or the special purpose
business trust in connection with the election by such institutional investor
that formed the special purpose business trusts or special purpose business
trust to purchase or redeem the secured lease obligation notes. However, the
secured lease obligation notes are not our obligations or guaranteed by us,
except to the extent that we may, in certain circumstances described in this
section, assume the obligations of
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the applicable special purpose business trust under the secured lease obligation
notes. Payments under each lease in excess of the amounts required to make
required payments on the applicable secured lease obligation notes will be paid
by the indenture trustee to the applicable special purpose business trust for
distribution to the applicable institutional investor that formed the special
purpose business trusts and will not be available for distribution to the
Certificateholders except in some cases upon the occurrence of a Lease Indenture
Event of Default. Our rental obligations under the leases and the other
operative documents to which it is a party are our general obligations.
LEASE INDENTURE EVENTS OF DEFAULT. A "Lease Indenture Event of Default"
under a lease indenture shall consist of the following:
(1) any Lease Event of Default under the related lease, other than our
failure to make some customary excepted payments reserved to the
applicable special purpose business trust and institutional investor
that formed the special purpose business trust, and our failure to
maintain required insurance, if and so long as (A) the insurance
actually maintained by us constitutes Prudent Industry Practice and (B)
the applicable special purpose business trust and institutional
investor that formed the special purpose business trust waive any Lease
Event of Default;
(2) a payment default other than as a result of a Lease Event of Default by
the applicable special purpose business trust under a lease indenture
in respect of principal, interest or any premium in respect of the
secured lease obligation notes that continues unremedied for five
Business Days;
(3) failure by the applicable special purpose business trust to perform any
material covenant contained in a lease indenture to be performed by it,
other than with respect to clause (2) above, or failure of the
applicable special purpose business trust or institutional investor
that formed the special purpose business trust to perform any material
covenant to be performed by it under the related Mortgage or some
provisions of the related Participation Agreement or failure by a
guarantor under the parent guaranty of an institutional investor that
formed the special purpose business trust to perform any material
covenant to be performed by it under the parent guaranty, in any
material respect, which failure remains unremedied for a period of 30
days after written notice thereof; provided, however, that if a
condition is not capable of being remedied in 30 days, the period shall
be extended for up to 180 days, so long as a remedy is diligently
pursued and the condition is reasonably capable of being remedied
within such extended period;
(4) any material representation or warranty made by the applicable
institutional investor that formed the special purpose business trust
or special purpose business trust, in the related Mortgage or in
certain provisions of the related Participation Agreement or in any
certificate delivered on May 14, 1999 or any material representation or
warranty made by a guarantor under a parent guaranty of an
institutional investor that formed the special purpose business trust
shall prove at any time to have been incorrect as of the date made in
any material respect and shall continue to be material and unremedied
for a period of 30 days after receipt by such party of written notice
of the defect; provided, however, that if the representation is not
capable of being remedied in 30 days, the period shall be extended for
up to an additional 90 days, so long as a remedy is diligently pursued
and the representation is reasonably capable of being remedied within
the extended period; and
(5) customary events of bankruptcy and insolvency, whether voluntary or
involuntary, with respect to the applicable special purpose business
trust or institutional investor that formed the special purpose
business trust, provided that any event of bankruptcy or insolvency
commenced involuntarily shall be continuing 60 days after its
commencement.
REMEDIES. Each lease indenture provides that, subject to certain rights of
the applicable special purpose business trust and the applicable institutional
investor that formed the special purpose business trust described below, if a
Lease Indenture Event of Default has occurred and is continuing, the indenture
trustee may exercise specified rights and remedies available to it under
Applicable Law, including, if a Lease Event of Default under the related lease
has occurred, one or more of the remedies with respect to the related undivided
interest in the electricity generating stations and ground interest in the real
property on which the electricity
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generating stations are located afforded to the applicable special purpose
business trust by the lease for Lease Events of Default under the lease. See
"-- THE LEASES, THE FACILITY SITE LEASES AND THE FACILITY SITE
SUBLEASES -- LEASE EVENTS OF DEFAULT."
Any remedies may be exercised by the indenture trustee to the exclusion of
the applicable special purpose business trust and the applicable institutional
investor that formed the special purpose business trust. A sale of the undivided
interest and ground interest upon the exercise of remedies will be free and
clear of any rights of the applicable special purpose business trust and the
applicable special purpose business trustee, other than, in certain cases,
rights of redemption provided by law, including our rights under the related
lease. No exercise of any remedies by the indenture trustee, however, may affect
our rights under the related lease unless a Lease Event of Default has occurred
and is continuing under the lease.
Upon the occurrence and continuance of a Lease Indenture Event of Default
and of a Lease Event of Default, neither any holder of secured lease obligation
notes nor the indenture trustee shall be entitled to exercise any remedy
pursuant to the related lease indenture which could or would divest the
applicable special purpose business trust of title to, or its ownership interest
in, any collateral, unless, in the case of a Lease Indenture Event of Default as
a consequence of a Lease Event of Default, the indenture trustee shall, to the
extent it is then entitled to do so under the related lease indenture and is not
then stayed or otherwise prevented from doing so by operation of law, have
commenced the exercise of one or more of the remedies referred to in the
applicable lease intending to dispossess us of the related undivided interest in
the Kintigh Generating Station or the Milliken Generating Station and is using
good faith efforts to exercise its remedies and not merely asserting a right or
claim to do so; provided, that if the indenture trustee is then stayed or
otherwise prevented by operation of law from exercising any remedies, the
indenture trustee shall not divest such special purpose business trust of its
interest in the collateral until the earlier of
- the expiration of the 180-day period following the commencement of such
stay or other prevention, or
- the date of repossession of the undivided interest in the electricity
generating stations under the related lease.
In the event of any default by us under clause (1) of the definition of
"Lease Events of Default" specified below with respect to the payment of the
equity portion of the Basic Rent only under a lease, the indenture trustee shall
not, so long as no other Lease Indenture Event of Default shall have occurred
and be continuing, be entitled to exercise remedies under the related lease
indenture for a period of 180 days unless the applicable special purpose
business trust or institutional investor that formed the special purpose
business trust consents to the declaration of a Lease Event of Default under the
applicable lease by the indenture trustee.
In the event of the bankruptcy of an institutional investor that formed a
special purpose business trust or a special purpose business trust, the ability
of the indenture trustee to exercise its remedies under the related lease
indenture against the bankrupt party might be limited and payments required to
be made under the related lease might be interrupted, although the indenture
trustee would retain its status as a secured creditor in respect of the
applicable special purpose business trust's interest in the related lease and
undivided interest. In addition, in the event of a bankruptcy it is possible
that the debtor may reject the lease as an executory contract or unexpired
lease. A rejection by the debtor, if successful, would leave the indenture
trustee as a secured creditor in respect of such special purpose business
trust's interest in the applicable lease and undivided interest with a claim
against the bankrupt estate in the amount owing under the related secured lease
obligation notes.
At any time after the outstanding principal amount of the secured lease
obligation notes shall have become due and payable by acceleration pursuant to
the lease indenture, a majority in interest of the holders of the secured lease
obligation notes may, by written notice or notices to the applicable special
purpose business trust, the indenture trustee and us, rescind and annul any
acceleration and any related declaration of default under the lease and their
respective consequences, if:
(1) all amounts of principal, premium, if any, and interest which are then
due and payable in respect of all the secured lease obligation notes
otherwise than as a result of acceleration shall have been paid in
full, together with interest on all such overdue principal and, to the
extent permitted by Applicable
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Law, overdue interest at the rate or rates specified in the secured
lease obligation notes, and an amount sufficient to cover all costs and
expenses of collection incurred by or on behalf of the holders of the
secured lease obligation notes, including, without limitation, counsel
fees and expenses and all expenses and reasonable compensation of the
indenture trustee; and
(2) every other Lease Indenture Event of Default shall have been remedied.
No rescission or annulment shall extend to or affect any subsequent Lease
Indenture Event of Default or impair any related right, and no rescission or
annulment shall require any holder of a secured lease obligation note to repay
any principal or interest actually paid as a result of any acceleration.
SPECIAL PURPOSE BUSINESS TRUST'S RIGHT TO PURCHASE THE SECURED LEASE
OBLIGATION NOTES. Each special purpose business trust shall have the right to
purchase the secured lease obligation notes outstanding under the related lease
indenture, without any premium, at a price equal to the outstanding principal
and accrued interest with respect to the secured lease obligation notes, as well
as any other payments owed pursuant to the related lease indenture, and
outstanding fees and expenses owed to or incurred by the indenture trustee, if:
(1) (A) a Lease Indenture Event of Default, which also constitutes a Lease
Event of Default, shall have occurred and be continuing for a period of
at least 90 days under the lease indenture without the acceleration of
the secured lease obligation notes or the exercise of any remedy under
the related lease by the indenture trustee intended to dispossess us of
the related undivided interest in the Kintigh Generating Station or the
Milliken Generating Station, (B) as a result of the occurrence and
continuation of a Lease Indenture Event of Default, the indenture
trustee accelerates, in its discretion, or a majority in interest of
holders of the secured lease obligation notes directs the acceleration
of the secured lease obligation notes, and the acceleration has not
been rescinded, or (C) within the last 30 days the indenture trustee
has provided us and the applicable institutional investor that formed
the special purpose business trusts written notice that it intends to
exercise remedies available under the related lease intended to
foreclose on the related undivided interest in the Kintigh Generating
Station or the Milliken Generating Station or otherwise dispossess us
of our related undivided interest in the Kintigh Generating Station or
the Milliken Generating Station under the lease as the result of the
occurrence of a Lease Indenture Event of Default;
(2) no Lease Indenture Event of Default, other than solely as the result of
the occurrence of a Lease Event of Default, shall have occurred and be
continuing under the lease indenture; and
(3) the applicable special purpose business trust shall have notified the
indenture trustee in writing of its intention to purchase the secured
lease obligation notes, with assurances reasonably satisfactory to the
indenture trustee of the special purpose business trust's ability to
make the purchase.
SECURITY. The secured lease obligation notes issued by each special
purpose business trust are secured by a Lien on and a first priority security
interest in the rights and interests of the special purpose business trust in
the collateral, which includes, other than certain customary excepted payments
and excepted rights reserved to the special purpose business trust and the
applicable institutional investor that formed the special purpose business
trust:
(1) the related lease and its rights thereunder, including the right to
receive payments of periodic rent thereunder;
(2) the related undivided interest in the Kintigh Generating Station or the
Milliken Generating Station;
(3) the related Participation Agreement;
(4) the related lease relating to the real property on which the Kintigh
Generating Station or the Milliken Generating Station is located, and
the sublease relating to the real property on which the Kintigh
Generating Station or the Milliken Generating Station is located;
(5) any sublease of the related undivided interest in the Kintigh
Generating Station or the Milliken Generating Station subsequently
entered into by us as sublessor;
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(6) the related support agreements including the applicable Facilities
Support Agreement;
(7) any Payment Undertaking Agreement; and
(8) the coal hauling agreement with Somerset Railroad.
So long as no Lease Indenture Event of Default shall have occurred and be
continuing under a lease indenture and the related secured lease obligation
notes have not been accelerated, the applicable special purpose business trust
is entitled to exercise all of the rights of the special purpose business trust
under the related lease and Participation Agreement, subject to certain specific
exceptions, including with respect to amendments, waivers, modifications and
consents under specified provisions of certain of the operative documents. A
special purpose business trust's rights, however, do not include the right to
receive payments of Basic Rent and certain other amounts due under the related
lease, which payments, other than certain excepted payments, will be made
directly to the indenture trustee. The assignment by a special purpose business
trust to the indenture trustee of its rights under the related lease and
Participation Agreement also excludes certain rights of the special purpose
business trust, including rights relating to indemnification by us for certain
matters and insurance proceeds payable to the special purpose business trust
under liability insurance maintained by us under the applicable lease. For a
description of other rights of the special purpose business trusts, see "-- THE
LEASES, FACILITY SITE LEASES AND FACILITY SITE SUBLEASES -- LEASE EVENTS OF
DEFAULT."
Funds, if any, held from time to time by the indenture trustee under a
lease indenture will be invested and reinvested by the indenture trustee, at the
written direction and at the risk and expense of the applicable special purpose
business trust, in Permitted Investments. Each special purpose business trust is
required on demand to pay to the indenture trustee the amount of any loss
resulting from any investment.
LIMITATION OF LIABILITY. The secured lease obligation notes are not
obligations of, or guaranteed by, our company, or the applicable institutional
investor that formed the special purpose business trust that issued those notes.
None of the applicable institutional investors that formed the special purpose
business trusts or the indenture trustee, or any affiliates thereof, shall be
personally liable to any holder of a secured lease obligation note or, in the
case of an institutional investor that formed the special purpose business
trusts, to the indenture trustee for any amounts payable under any secured lease
obligation notes or, except as provided in the related lease indenture with
respect to the indenture trustee, for any liability under the lease indenture.
All payments of principal of, premium, if any, and interest on the secured lease
obligation notes, other than payments made in connection with an optional
redemption or purchase by the applicable special purpose business trust or
institutional investor that formed the special purpose business trust, will be
made only from the assets subject to the Lien of the related lease indenture or
the income and proceeds received by the indenture trustee therefrom, including
Basic Rent payable by us under the related lease.
Except as otherwise provided in the lease indenture, the applicable special
purpose business trust shall not be answerable or accountable under the related
lease indenture or secured lease obligation notes under any circumstances except
for:
(1) its own willful misconduct or gross negligence not caused by a breach
of warranty, covenant, or representation in any operative document by
us or our affiliates;
(2) its own misrepresentation or breach of warranty in any operative
document or breach of covenant by the special purpose business trust
insofar as not caused by a breach of warranty, covenant or
representation in any operative document by us or our affiliates; and
(3) other specified acts or omissions.
THE LEASES, THE FACILITY SITE LEASES AND THE FACILITY SITE SUBLEASES
TERM AND RENT. The interim lease term (the "Lease Interim Term") under
each lease commenced on May 14, 1999 and will continue to, and including,
January 1, 2000. The basic lease term (the "Lease Basic Term") under each lease
will commence on January 2, 2000 for both the Kintigh Generating Station and the
Milliken Generating Station (the "Basic Lease Commencement Date") and terminate
on February 13, 2033
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for the Kintigh Generating Station and on November 13, 2027 for the Milliken
Generating Station. We have the right to renew each lease for one or more
renewal lease terms (the "Lease Renewal Term"). The combined Lease Interim Term
and Lease Basic Term are referred to in this prospectus as the "Lease Fixed
Term."
Basic Rent payable under each lease shall consist of:
(1) rent with respect to the Lease Interim Term;
(2) rent with respect to the Lease Basic Term; and
(3) rent with respect to any Lease Renewal Term.
Basic Rent under each lease shall be paid in advance and/or arrears on each
January 2 and July 2 during the Lease Fixed Term for such lease ("Rent Payment
Dates"), commencing on January 2, 2000 for both the Kintigh Generating Station
and the Milliken Generating Station and ending on January 2, 2033 and July 2,
2027, respectively.
Basic Rent is payable in the amounts indicated in a schedule to the related
lease and:
(1) as long as no Lease Event of Default exists, a portion of Basic Rent
identified as Deferrable Basic Rent on such schedule may be deferred
until the Deferrable Basic Rent Maturity Date for the applicable lease;
(2) the portion of Basic Rent that equals the amount of principal and
interest due upon the secured lease obligation notes on any Rent
Payment Date may not be deferred;
(3) we will pay interest on any part of any payment of Deferrable Basic
Rent not paid on the Rent Payment Date on which it was due for any
period for which the same shall remain unpaid;
(4) our failure to make any payment of all or any portion of Deferrable
Basic Rent or interest on this payment shall not constitute a Lease
Event of Default prior to the Deferrable Basic Rent Maturity Date for
the payment.
Since the leases with respect to the Kintigh Generating Station have a
longer Basic Term than the leases with respect to the Milliken Generating
Station, the Deferrable Basic Rent Maturity Date for the Milliken leases will
occur while the secured lease obligation notes related to the Kintigh leases are
still outstanding. A failure by us to pay all Deferrable Basic Rent under the
Milliken leases prior to the Basic Rent Maturity Date for those leases could
result in a Lease Event of Default under those leases at a time when the failure
to pay Deferrable Basic Rent under the Kintigh leases would not result in a
Lease Event of Default under the Kintigh leases.
USE AND MAINTENANCE. We shall be responsible for maintaining the related
electricity generating station in good condition, repair and working order in
all material respects, including,
- in accordance with Prudent Industry Practice,
- in compliance with all Applicable Laws,
- in accordance with the terms of all insurance policies required to be
maintained pursuant to the related leases,
- in accordance with such operating standards as shall be required to take
advantage of and enforce all available warranties, and
- without discriminating against the related electricity generating station
solely because the undivided interest in the electricity generating
station is leased and not owned by us.
We may, in good faith and by appropriate proceedings, diligently contest
the validity or application of any Applicable Laws in any reasonable manner
pursuant to a Permitted Contest.
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In the ordinary course of maintenance, service, repair or testing, we, at
our own expense, may remove or cause to be removed any components of the Kintigh
Generating Station or the Milliken Generating Station; provided, that we shall
cause such components to be replaced by replacement components that are free and
clear of all Liens, except Permitted Liens. Any replacement components shall be
in as good an operating condition as, and have a current fair market value,
residual value, remaining useful life and utility at least equal to, that of the
component replaced. Notwithstanding the foregoing, if we determine that any
parts, components or portion of an electricity generating station are surplus or
obsolete, we shall have the right to remove those parts, components or portion
without replacing them; provided, that the electricity generating station's then
current fair market value, residual value, utility or remaining useful life
would not be diminished or impaired by more than a de minimis amount as a result
and that the electricity generating station would not thereby become a "limited
use" property.
"Prudent Industry Practice" shall mean, at a particular time:
(1) any of the practices, methods and acts engaged in or approved by a
significant portion of the non-franchised electric generating industry
in the United States at such time; or
(2) with respect to any matter to which clause (1) does not apply, any of
the practices, methods and acts which, in the exercise of reasonable
judgment at the time the decision was made, could have been expected to
accomplish the desired result at a reasonable cost consistent with good
business practices, reliability, safety and expedition; and
(3) in any event, a standard of care and usage no less than that which we
and our affiliates would apply with respect to other similar properties
owned, leased or operated by them.
"Prudent Industry Practice" is not intended to be limited to the optimum
practice, method or act to the exclusion of all others, but rather to be a
spectrum of possible practices, methods or acts having due regard for, among
other things, manufacturers' warranties and the requirements of governmental
bodies of competent jurisdiction, insurers and the requirements of the operative
documents.
MODIFICATIONS TO THE PROPERTY. We shall have the right to make, at our own
expense, such additions, alterations, improvements, betterments or enlargements
to the Kintigh Generating Station or the Milliken Generating Station as we
consider desirable in the proper conduct of our business and shall make all
modifications required by any Applicable Law or any modifications made in
respect of achieving the objective of our life extension forecast as described
in the report of Stone & Webster, the independent engineer. Modifications
required by Applicable Law are referred to in this section as "required
modifications." We may, however, in good faith and by appropriate proceedings,
diligently contest the validity or application of any Applicable Laws in any
reasonable manner pursuant to a Permitted Contest; provided, that except for
required modifications, no modification shall diminish or impair the then
current fair market value, residual value, remaining useful life or utility of
the Kintigh Generating Station or the Milliken Generating Station or cause it to
become "limited use" property.
Modifications that can be readily removed without causing damage to or
diminishing or impairing the fair market value, residual value, remaining useful
life or utility of the Kintigh Generating Station or the Milliken Generating
Station are referred to as "severable modifications." Except for severable
modifications that are also required modifications or severable modifications
that are financed through the related lease, all severable modifications shall
remain our property. All required modifications, nonseverable modifications and
modifications that are financed through the related lease shall automatically,
upon being affixed to the Kintigh Generating Station or the Milliken Generating
Station, become the property of the applicable special purpose business trust
and be subject to the lease and the lien of the related lease indenture.
In respect of a particular lease, at our request and with the consent of
the indenture trustee, the applicable institutional investor that formed the
special purpose business trust will permit the cost of all nonseverable
modifications and required modifications to the related electricity generating
station to be financed through
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additional non-recourse borrowings by the applicable special purpose business
trust to the extent permitted under Rev. Proc. 75-21, subject to the following
conditions:
(1) such financing shall not result in a downgrade in the rating of the
pass through trust certificates below the lower of (A) that in effect
on May 14, 1999 and (B) the rating then in effect, except that in the
case of required modifications, this condition will not apply;
(2) there shall be a maximum of one financing in any calendar year, except
for required modifications;
(3) the additional debt shall have a final maturity date no later than the
final maturity of the original secured lease obligation notes issued
under the related lease indenture and will be fully repaid out of
additional Basic Rent during the lease term;
(4) no Lease Bankruptcy Default or Lease Event of Default under the lease
shall have occurred and be continuing unless the modifications to be
constructed with any financing shall cure such defaults and any
modifications shall be made in compliance with the operative documents;
(5) any financing is for an amount not less than $20 million multiplied by
the undivided interest percentage, nor greater than 100% of the special
purpose business trust's undivided interest percentage of the costs of
the modifications being financed, provided that the aggregate balance
of the pass through trust certificates related to the secured lease
obligation notes issued under the lease indenture never exceeds 85% of
the fair market value of the related undivided interest;
(6) the applicable institutional investor that formed the special purpose
business trust shall have received, at our expense, a favorable opinion
of its tax counsel, reasonably satisfactory to the institutional
investor that formed the special purpose business trust, to the effect
that the financing shall not result in any material unindemnified
adverse tax consequence to the institutional investor and we shall have
indemnified the institutional investor that formed the special purpose
business trust against all tax risks in a manner reasonably
satisfactory to the institutional investor;
(7) the institutional investor that formed the special purpose business
trusts shall have received a fee in the amount of $100,000 in the
aggregate for each financing subsequent to the first such financing;
(8) we shall have made or delivered such representations, warranties,
covenants, opinions or certificates as the institutional investors that
formed the special purpose business trusts may reasonably request; and
(9) the issuance of the additional debt constitutes an incurrence of
Permitted Indebtedness pursuant to clause (2) or (3) of the definition
of Permitted Indebtedness, as applicable.
In the case of a financing through a non-recourse borrowing, the Basic
Rent, among other values, will be appropriately adjusted and we will reimburse
the applicable special purpose business trust, institutional investor that
formed the special purpose business trust and indenture trustee for all their
costs and expenses in connection with any financing. Notwithstanding the above,
we shall at all times have the right to fund modifications to the Kintigh
Generating Station or the Milliken Generating Station other than through the
leases. As used above, "modifications" includes any repowering of any
electricity generating station, and any other improvement to any electricity
generating station which may increase its capacity. An institutional investor
that formed a special purpose business trust may also offer to contribute to the
financing of the cost of any modifications through an additional equity
investment by the institutional investor on terms to be negotiated at the time
and subject to our approval, which we may decline to give in our sole
discretion.
SUBLEASE AND ASSIGNMENT. We will have the right to sublease the Kintigh
Generating Station or the Milliken Generating Station in its entirety without
the consent of the applicable special purpose business trust, the institutional
investor that formed the special purpose business trust or indenture trustee
under the following conditions:
(1) the sublessee (A) is a United States person within the meaning of
Section 7701(a)(30) of the Internal Revenue Code, (B) is solvent and
not subject to bankruptcy proceedings, (C) is not involved in any
material litigation with an institutional investor that formed the
special purpose
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business trust, and (D) is, or its operating and maintenance
obligations under the sublease are guaranteed by, an experienced,
reputable operator of electric generating assets;
(2) the sublease does not have a term of more than 10 years and during the
Lease Basic Term does not extend beyond the date 36 months prior to
the expiration of the Lease Basic Term and is expressly subject and
subordinate to the related lease;
(3) all terms and conditions of the related lease and the other operative
documents remain in effect and we remain fully and primarily liable
for our obligations under the operative documents;
(4) no Lease Material Default or Lease Event of Default under the related
lease shall have occurred and be continuing;
(5) the sublease prohibits further assignment or subletting;
(6) the sublease requires the sublessee to operate and maintain the
electricity generating station in a manner consistent with the related
lease;
(7) the applicable special purpose business trust, the institutional
investor that formed the special purpose business trust, the pass
through trustee and the indenture trustee shall have received all
documentation in respect of the sublease and an opinion of counsel,
which opinion and counsel are satisfactory to them, to the effect that
all regulatory approvals relating to the sublease have been obtained
and that the sublease complies with certain provisions of the related
lease;
(8) (A) the execution of the sublease does not result in any (i)
diminution of applicable Coverage Ratios during the remainder of the
lease term beyond a de minimus amount and in no event below any
Required Coverage Ratio, (ii) reduction in cash flows available to us
as calculated by the then applicable pro forma projections for the
balance of the lease term or (iii) downgrade in any then current
rating of the pass through trust certificates, (B) the sublease
provides for a rent payment stream which at all times during the term
of the sublease exceeds all future Basic Rent payments payable under
the related lease during the term of the sublease and (C) there is no
prepayment of rent or any other lump sum or advance payments payable
to us under the sublease;
(9) all amounts to be paid under the sublease are deposited directly into
the Revenue Account;
(10) our rights as sublessor under the sublease are collaterally assigned
as security to the applicable special purpose business trust; and
(11) such sublease shall not cause the property to become "tax-exempt use
property" within the meaning of section 168(h) of the Internal Revenue
Code, unless we shall make a payment to the applicable institutional
investor that formed the special purpose business trust
contemporaneously with the execution of the sublease that in the
judgment of that institutional investor compensates the institutional
investor for the adverse tax consequences resulting from the
classification of the property as "tax-exempt use property."
Upon any sublease by us, we shall remain primarily liable to the applicable
special purpose business trust under the related lease and the related operative
documents. As a condition precedent to such sublease, we shall provide the
applicable special purpose business trust, the institutional investor that
formed the special purpose business trust and, so long as the Lien of the
related lease indenture shall not have been terminated or discharged, the
indenture trustee, with all documentation in respect of the sublease and an
opinion of counsel to the effect that the sublease complies with the foregoing
conditions. Any documentation or opinion of counsel provided under this section
must be satisfactory to the recipients.
We shall pay on an "after tax basis" all reasonable costs or expenses
incurred by the applicable special purpose business trust, the institutional
investor that formed the special purpose business trust, the indenture trustee
and the pass through trustee in connection with any sublease or proposed
sublease.
For the purposes of this definition, "after tax basis" shall mean, in the
context of determining the amount of a payment to be made, the payment of an
amount which, after reduction by the net increase in actual or
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constructive Taxes of the recipient by reason of the payment, which net increase
shall be calculated by taking into account any reduction in the Taxes resulting
from any Tax benefits realized or to be realized by the recipient as a result of
the payment, shall be equal to the amount required to be paid. In calculating
the amount payable by reason of this provision, all income taxes payable and tax
benefits realized or to be realized shall be determined on the assumptions that:
(1) the recipient shall be subject to the applicable income taxes at the
highest marginal tax rates then applicable to corporate taxpayers taxed
on the same basis as the recipient that are in effect in the applicable
jurisdictions at the time such amount is received or properly accrued;
and
(2) all related tax benefits are utilized at the highest marginal rates
then applicable to corporate taxpayers taxed on the same basis as the
recipient that are then in effect in the applicable jurisdictions.
We may not, without the prior written consent of the applicable special
purpose business trust, the institutional investor that formed the special
purpose business trust, the pass through trustee and the indenture trustee,
which consent may be withheld in their sole business judgment, assign the
related lease or any other related operative document, or any interest therein,
except, in certain circumstances, to a wholly owned affiliate of The AES
Corporation, subject to the following conditions:
(1) the affiliate may not be a tax-exempt entity within the meaning of
Section 168(h)(2) of the Internal Revenue Code;
(2) the affiliate must be a "United States Person" within the meaning of
Section 7701(a)(3) of the Internal Revenue Code;
(3) the Rating Agencies shall confirm that the proposed assignment shall
not result in a downgrade of the then existing credit rating of the
pass through trust certificates; and
(4) the proposed assignment shall comply with other customary terms.
ASSUMPTION OF SECURED LEASE OBLIGATION NOTES BY US. In connection with the
purchase by us of the related undivided interest in the Kintigh Generating
Station or the Milliken Generating Station, we shall have the option to assume
the secured lease obligation notes on a full recourse basis so long as no Lease
Bankruptcy Default or a Lease Event of Default has occurred and is continuing,
upon the termination of the related lease by us as a result of:
(1) a Regulatory Event of Loss;
(2) it having become illegal for us to continue the lease or for us to make
payments under the lease and the transactions contemplated by the lease
cannot be restructured in a manner reasonably acceptable to us; or
(3) Our becoming obligated to pay an indemnity under the related operative
documents in an amount in excess of 3% of the Purchase Price for the
undivided interest in the related electricity generating station.
As a condition to an assumption of the secured lease obligation notes by
us, the indenture trustee shall have received an opinion of our counsel to the
effect that, among other things:
(1) the assumption agreement, the related indenture and the applicable
secured lease obligation notes constitute our legal, valid and binding
obligations, subject to certain exceptions, and the assumption
agreement and the assumption of the secured lease obligation notes
would not cause a taxable transaction to occur as to any direct or
indirect holder of a secured lease obligation note, including any
Certificate Owner; and
(2) the lien of the related lease indenture and the related Mortgage shall
continue to be a perfected first priority lien on the collateral and on
the Mortgaged Property, respectively.
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In addition, the Rating Agencies or, if only one such rating agency is then
rating the pass through trust certificates, that Rating Agency, shall confirm
that the lease assumption shall not result in a downgrade of the credit rating
of the pass through trust certificates below that which was in effect on May 14,
1999.
LIENS. We will not, and will not permit any AES Eastern Energy Subsidiary
to, create, incur, assume or suffer to exist any Lessee Liens, and will promptly
notify the special purpose business trusts of the imposition of any Lessee Liens
of which we have Actual Knowledge and will promptly, at our own expense, take
any actions as may be necessary to fully discharge or release any Lessee Liens.
Each institutional investor that formed the special purpose business trusts
will not create, incur, assume or suffer to exist any Lien or encumbrance on the
trust estate arising as a result of:
(1) claims against or any act or omission of the institutional investor
that formed the special purpose business trusts that are not related
to, or are in violation of, any operative document or the transactions
contemplated by the operative documents, or that are in breach of any
covenant or agreement of that institutional investor as set forth in
the operative documents;
(2) taxes against the institutional investor that formed the special
purpose business trusts for which it is not indemnified by us under the
operative documents; or
(3) claims against or affecting the institutional investor that formed the
special purpose business trusts arising out of the voluntary or
involuntary transfer by the institutional investor of any portion of
its interest other than as permitted under the operative documents.
INSURANCE. We will maintain:
(1) all risk property insurance customarily carried by prudent operators of
coal-fired facilities of comparable size, and of a comparable risk
profile as, the Kintigh Generating Station or the Milliken Generating
Station, and against loss or damage from such causes as are customarily
insured against, which includes coverage for flood and boiler breakdown
and machinery coverage to cover mechanical breakdown with normal policy
exclusions; and
(2) commercial general liability insurance, commercial automobile liability
insurance and contractual liability coverage, workers compensation and
employer's liability insurance and excess liability insurance.
Any such liability insurance policy maintained by us or on our behalf shall
name the applicable special purpose business trust company, special purpose
business trustee, the institutional investors that formed the special purpose
business trusts, the indenture trustee and the special purpose business trusts,
in their individual and trustee capacities, as additional insureds. All
insurance obtained by us will include coverage against direct physical loss or
damage to the related facility including business interruption coverage with a
limit of $350,000,000 per occurrence for the Kintigh Generating Station and
$200,000,000 per occurrence for the Milliken Generating Station, except for the
perils of flood and earthquake, which limit will be an annual aggregate limit of
$100,000,000. Business interruption coverage shall contain an indemnity period
of not less than 15 months. A self-insured retention or deductible of not more
than $1,000,000 for direct physical loss and a 90-day waiting period for
business interruption can apply per occurrence; provided, however, these
deductibles are established as maximum deductibles and we will endeavor to
procure the most competitive deductibles commercially available and economically
feasible.
TERMINATION FOR BURDENSOME EVENTS. If it shall have become illegal for us
to continue a particular lease or for us to make payments under a particular
lease, other than as a result of events caused by us or any of our affiliates
with a purpose to enable us to have the right to exercise an option to purchase
the related undivided interest in the Kintigh Generating Station or the Milliken
Generating Station, and the transactions contemplated thereby cannot be
restructured in a manner reasonably acceptable to us so long as no Lease
Bankruptcy Default or Lease Event of Default shall have occurred and be
continuing, we shall have the right to terminate the lease and purchase the
related undivided interest in the Kintigh Generating Station or the Milliken
Generating Station by payment of at least an amount as determined under the
caption "REDEMPTION OF SECURED LEASE OBLIGATION NOTES -- MANDATORY REDEMPTION
WITHOUT PREMIUM."
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So long as no Lease Bankruptcy Default or Lease Event of Default shall have
occurred and be continuing and so long as the institutional investor that formed
the special purpose business trust shall not have waived its rights, we shall
have the right to terminate the lease on the Termination Date specified by us
and purchase the related undivided interest in the electricity generating
station by payment of at least an amount as set forth under the caption
"-- REDEMPTION OF SECURED LEASE OBLIGATION NOTES -- MANDATORY REDEMPTION WITHOUT
PREMIUM" if:
(1) one or more events, other than as a result of events caused by us or
any affiliate of ours with a purpose of enabling AES Eastern Energy to
have the right to exercise an option to purchase the related undivided
interest in the electricity generating station, occurs that give rise
to indemnity obligations by us under the related operative documents,
other than the tax indemnity agreement;
(2) such obligations can be avoided if the related lease is terminated and
the applicable special purpose business trust sells its undivided
interest in the electricity generating station and the ground interest
in the real property of the electricity generating station to us; and
(3) the present value of the avoided payments would exceed 3% of the
Purchase Price for the undivided interest in the electricity generating
station.
We may exercise the right to terminate a lease as described above provided
that we exercise the similar right with respect to all leases for the same
electricity generating station, and, unless the pass through trust certificates
shall at the time of such exercise have a credit rating of not less than
Investment Grade, the leases related to the other electricity generating
station. The applicable institutional investor that formed the special purpose
business trust, in its sole discretion, may waive our obligation to terminate
all leases for a particular electricity generating station and all of the leases
related to the other electricity generating station, if we exercise the right
described in the preceding paragraph.
Notwithstanding the foregoing, in connection with the termination of a
lease under the circumstances described above and subject to the execution of an
assumption agreement and the purchase by us of the related undivided interest in
the electricity generating station and ground interest in the real property of
the electricity generating station and subject to the satisfaction of certain
other conditions, we shall have the right to assume the applicable secured lease
obligation notes. No termination of a lease under the circumstances described
above shall be effective unless and until either we shall have assumed the
related secured lease obligation notes in accordance with the provisions of the
lease indenture or the applicable special purpose business trust shall have paid
all outstanding principal and accrued interest on the secured lease obligation
notes and all other amounts due under the lease indenture on the proposed date
of termination. Pursuant to the Participation Agreements, we also have the
option of purchasing the Beneficial Interest of the applicable institutional
investor that formed the special purpose business trust under the circumstances
described.
If we exercise our rights to terminate a lease for a particular electricity
generating station as a result of illegality or a burdensome indemnity as
described above, we can be required to terminate all leases, including leases
for the other electricity generating station, in which the applicable
institutional investor that formed the special purpose business trust, or any
affiliate, has an interest.
TERMINATION FOR OBSOLESCENCE. Upon at least six months' prior written
notice to the applicable special purpose business trust, the institutional
investor that formed the special purpose business trust, the pass through
trustee and the indenture trustee, which notice shall contain a certification by
the board of directors of the general partner of our company, and so long as no
Lease Bankruptcy Default or Lease Event of Default shall have occurred and be
continuing, we shall have the option to terminate the related lease at any time
on or after May 14, 2006. We may exercise this option if:
(1) the related electricity generating station is economically or
technologically obsolete as a result of a change in Applicable Law,
including any regulation or tariff of general application, as
determined in good faith by the board of directors of our company's
general partner; or
(2) the related electricity generating station is otherwise economically or
technologically obsolete or is surplus to our needs or no longer useful
in our trade or business, including, without limitation, as a
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result of (A) a change in the markets for the wholesale purchase and/or
sale of energy or (B) any material abrogation by any purchaser under a
power purchase agreement, as determined in good faith by the board of
directors of our company's general partner.
If we exercise our rights to terminate a lease for a particular electricity
generating station as a result of obsolescence as described above, we can be
required to terminate all leases, including leases for the other electricity
generating station, in which the applicable institutional investor that formed
the special purpose business trust or any affiliate of that institution has an
interest, under certain circumstances.
In the event of an early termination, we will, as non-exclusive agent for
the applicable special purpose business trust, use commercially reasonable
efforts to obtain bids for and sell the special purpose business trust's
interest on the Termination Date, all of the proceeds of which will be for the
account of such special purpose business trust. We may not sell these interests
to ourselves, any of our affiliates or to any third party with whom we have or
an affiliate has an arrangement to use or operate the electricity generating
station to generate power for our benefit or the benefit of our affiliate after
the termination of the related lease. On the Termination Date, we shall pay the
special purpose business trust the amount, if any, by which the applicable
termination value exceeds the proceeds received by the special purpose business
trust from the sale, plus any unpaid Basic Rent due and payable before that
date, all of which we agreed to pay under the related Participation Agreement,
including taxes due and payable as a result of the exercise of the termination
option and any premium due with respect to the secured lease obligation notes.
No termination of a lease under the circumstances described above shall be
effective (regardless of whether the applicable special purpose business trust
shall elect to sell or retain the related undivided interest in the electricity
generating station and the ground interest in the real property of the
electricity generating station in connection with the termination of the lease)
unless and until the special purpose business trust shall have paid all
outstanding principal and accrued interest on the secured lease obligation notes
and all other amounts due under the lease indenture on the proposed Termination
Date.
We may, not more than 30 days prior to the proposed Termination Date,
revoke our notice of termination. In the event that we revoke our notice of
termination, the related lease will continue in effect. We will not have the
right to reinitiate a notice to terminate for obsolescence more than once in any
five-year period.
EVENT OF LOSS. Any of the following events, by themselves, shall each
constitute an event of loss (each, an "Event of Loss") under a particular lease:
(1) the loss of the related electricity generating station or use thereof
due to destruction or damage that is beyond economic repair or that
renders the electricity generating station permanently unfit for normal
use;
(2) any damage to the related electricity generating station that results
in an insurance settlement with respect to the electricity generating
station on the basis of a total loss or an agreed constructive or a
compromised total loss of the electricity generating station;
(3) seizure, condemnation, confiscation or taking of, or requisition of
title or use of, the related electricity generating station by any
governmental authority (a "Requisition") for a period of 12 consecutive
months (in case of a Requisition of title) or 36 consecutive months (in
the case of any other Requisition) following exhaustion of all
permitted appeals or a determination by us not to pursue any appeals,
provided, that the event shall be an Event of Loss only if it is
reasonably foreseen to extend beyond the lease term; or
(4) if elected in writing by an institutional investor that formed a
special purpose business trust, and only in circumstances where the
termination of the lease shall remove the basis of the regulation
described below, subjection of the institutional investor or the
special purpose business trust to any public utility regulation of any
Governmental Entity which, in the reasonable opinion of the
institutional investor, is burdensome, or the subjection of the
institutional investor or the special purpose business trust's interest
in the lease to any rate of return regulation by any Governmental
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Entity, in either case by reason of the participation of the special
purpose business trust or the institutional investor in the
transactions contemplated by the operative documents and not, in any
event, as a result of
(A) investments, loans or other business activities of the institutional
investor that formed the special purpose business trust or its
affiliates, or
(B) a failure of the institutional investor that formed the special
purpose business trust or the special purpose business trust to
perform routine, administrative or ministerial actions the
performance of which would not subject such person to any adverse
consequence, provided that we and the special purpose business trust
and the institutional investor that formed the special purpose
business trust agree to cooperate and to take reasonable measures to
alleviate the source or consequence of any regulation constituting
an Event of Loss under this paragraph (4) (a "Regulatory Event of
Loss"), so long as there shall be no adverse consequences to the
special purpose business trust or the institutional investor that
formed the special purpose business trust as a result of such
cooperation or the taking of reasonable measures.
If an Event of Loss described in clause (1) or (2) above occurs, we shall
promptly provide notice of the Event of Loss to the applicable special purpose
business trust, the institutional investor that formed the special purpose
business trust and, so long as the Lien of the related lease indenture shall not
have been terminated or discharged, the indenture trustee. In addition, no later
than six months following the occurrence of the Event of Loss, we shall notify
the special purpose business trust, the institutional investor that formed the
special purpose business trust and, so long as the Lien of the related lease
indenture shall not have been terminated or discharged, the indenture trustee in
writing of our election either
- if no Lease Bankruptcy Default or Lease Event of Default shall have
occurred and be continuing, and subject to certain other specified
conditions, to rebuild and restore the related electricity generating
station in accordance with the related lease, or
- to terminate the related lease and purchase the applicable special
purpose business trust's interests therein by payment of an amount equal
to termination value set forth on a schedule to the related lease and all
other accrued and unpaid Rent.
Notwithstanding anything to the contrary, in the event that an Event of
Loss described in either clause (1) or (2) above occurs with respect to the
Kintigh Generating Station, we shall not have the right to rebuild without the
consent of the related institutional investors that formed the special purpose
business trusts.
If (A) we elect not to rebuild the electricity generating station following
the occurrence of an Event of Loss described in clause (1) or (2) above or (B)
an Event of Loss described in clause (3) or (4) above shall occur and certain
conditions have been met, we shall terminate the related lease and purchase the
applicable special purpose business trust's interest therein by payment of an
amount at least equal to termination value set forth on a schedule to the
related lease and all other accrued and unpaid Rent, whereupon the lease will
terminate.
Notwithstanding the foregoing, in the case of a Regulatory Event of Loss,
if we assume the applicable secured lease obligation notes in accordance with
the provisions of the lease indenture, and so long as no Lease Event of Default
shall have occurred and be continuing and certain other conditions are
satisfied, our obligation to pay the applicable termination value set forth on a
schedule to the related lease shall be reduced by the then scheduled outstanding
principal amount of and accrued interest, if any, on the secured lease
obligation notes assumed by us. Under the Participation Agreements, we also have
the option of purchasing the Beneficial Interests of the institutional investors
that formed the special purpose business trusts under these circumstances.
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Our right to rebuild or restore the applicable electricity generating
station will be subject to the fulfillment of certain conditions, including the
following:
(1) we shall deliver to the institutional investor that formed the special
purpose business trust and the indenture trustee a report of Stone &
Webster, the independent engineer, to the effect that the rebuilding
or restoring of the electricity generating station is technologically
feasible and economically viable and that the rebuilding or restoring
can reasonably be expected to be completed at least 36 months prior to
the expiration of the applicable Lease Basic Term, or 12 months prior
to the expiration of any Renewal Term, but in any event within three
years from the date of the Event of Loss;
(2) we shall demonstrate to the reasonable satisfaction of the applicable
institutional investor that formed the special purpose business trust
that we possess adequate financial resources, from insurance proceeds
or otherwise, to complete the rebuilding or restoration of the
electricity generating station;
(3) we shall cause the rebuilding or restoring to commence as soon as
practicable after we notify the applicable special purpose business
trust and the indenture trustee of our intent and, in any event,
within 18 months of the date of the occurrence of the event that
caused the Event of Loss;
(4) the applicable institutional investor that formed the special purpose
business trust receives an opinion of tax counsel for the
institutional investor, in form and substance reasonably satisfactory
to the institutional investor, that assuming the proposed rebuilding
is in the manner and within the time proposed, the rebuilding will not
result in any unindemnified adverse tax consequences for the
institutional investor and we shall have indemnified the institutional
investor against all tax and other risks arising from the rebuilding
in a manner reasonably satisfactory to the institutional investor;
(5) no Lease Bankruptcy Default or Lease Event of Default shall have
occurred and be then continuing;
(6) we shall deliver documentation in form, scope and substance reasonably
satisfactory to the institutional investor that formed the special
purpose business trust that the pass through trust certificates, at
the time of the rebuilding or restoration, have a credit rating from
the Rating Agencies which is not less than Investment Grade; and
(7) prior to rebuilding or restoring the electricity generating station,
we shall deliver a fixed-price, turn-key construction contract with a
nationally recognized and experienced contractor in form, scope and
substance reasonably satisfactory to the institutional investors that
formed the special purpose business trusts.
LEASE EVENTS OF DEFAULT. Lease Events of Default under a particular lease
include, among other things, the following events:
(1) we shall fail to pay Basic Rent, other than Deferrable Payments, but
only to the extent permitted in the lease, or termination value set
forth on a schedule to the lease when due under the lease, and the
failure shall continue unremedied for five Business Days;
(2) we shall fail to make any payment of Supplemental Rent, other than
termination value set forth on a schedule to the lease and, unless the
institutional investor that formed the special purpose business trust
shall have declared a default with respect thereto, excepted payments,
within 30 days after receipt by us of written notice of the default
from the applicable institutional investor that formed the special
purpose business trust, the special purpose business trust or the
indenture trustee;
(3) we shall fail to maintain insurance in the amounts and on the terms
set forth in the lease;
(4) we shall fail to perform or observe any covenant, obligation or
agreement to be performed by us under the lease or in any other
related operative document in any material respect, which shall
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continue unremedied for 30 days after receipt by us of written notice
of the defect; provided, however, that if the condition cannot be
remedied within the 30-day period, then the period within which to
remedy the condition shall be extended up to an additional 180 days,
so long as we diligently pursue such remedy and the condition is
reasonably capable of being remedied within such additional 180-day
period;
(5) we shall fail to perform or observe in any material respect the
covenants described under the caption "-- COVENANTS -- LIMITATION ON
INDEBTEDNESS; RESTRICTED PAYMENTS; MERGER, CONSOLIDATION; LIMITATIONS
ON DISPOSITION OF ASSETS; LIMITATION ON LIENS; LIMITATIONS ON OUR
ACTIVITIES; LIMITATIONS ON TRANSACTIONS WITH AFFILIATES; LIMITATIONS
ON INVESTMENTS; NO ABANDONMENT; ASSIGNMENT; COAL HAULING AGREEMENT;
AND INTERCONNECTION AGREEMENT" above;
(6) any representation or warranty by us in the related operative
documents, other than a tax representation, or in any Funding Date
Certificate (as defined in the deposit and disbursement agreement)
including, without limitation, any representation or warranty made by
us in the Participation Agreement with respect to us or any AES
Eastern Energy Entity shall prove to have been incorrect in any
material respect when made and continues to be material and unremedied
for a period of 30 days after receipt by us of written notice thereof
by the special purpose business trusts or the indenture trustee;
provided, however, that if such condition cannot be remedied within
the 30-day period, then the period within which to remedy the
condition shall be extended by an additional 180 days, so long as we
diligently pursue the remedy and the condition is reasonably capable
of being remedied within such additional 180-day period;
(7) customary bankruptcy or insolvency proceedings, whether voluntary or
involuntary, with respect to us, AES NY, L.L.C. or AEE2, L.L.C. being
instituted and not dismissed within 90 days;
(8) the holder of any Permitted Indebtedness of ours or any AES Eastern
Energy Subsidiary in an aggregate principal amount in excess of
$20,000,000, shall have commenced the exercise of any remedies upon a
default and declared such indebtedness due and payable prior to the
date on which it would otherwise have become due and payable, and
otherwise accelerated the indebtedness; provided, however, that a
default with respect to any other lease will not result in a Lease
Event of Default;
(9) one or more judgments or decrees shall be entered against us, AES NY,
L.L.C. or AEE2, L.L.C. involving in the aggregate a liability (not
paid or fully covered by insurance) of $25,000,000 or more and all
such judgments or decrees shall not have been vacated, discharged, or
stayed or bonded pending appeal within 60 days after the entry
thereof;
(10) at any time after May 14, 1999
(A) The AES Corporation shall cease to own or control directly or
indirectly at least 51% of the voting and economic interests in our
company, which interests shall be free and clear of all Liens, or
(B) The AES Corporation shall cease to own or control, directly or
indirectly, at least 51% of the voting and economic interests in the
general partner of our company, which interests shall be free and
clear of all Liens, or
(C) The AES Corporation shall cease to own or control, directly or
indirectly, 51% of the voting and economic interests in AES NY3,
L.L.C., which interests shall be free and clear of all Liens; AES
NY3, L.L.C., shall cease to own or control, directly or indirectly,
100% of the voting and economic interests in Somerset Railroad,
which interests shall be free and clear of all Liens other than any
Lien created in connection with the Somerset Railroad credit
facility or any replacement facility, or
(D) We shall cease to own or control, directly or indirectly, 100% of
the voting and economic interests in each of the AES Eastern Energy
Subsidiaries, which interest shall be free and clear of all Liens
other than any Lien created in connection with the working capital
credit facility or
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any replacement facility and any other Liens securing Permitted
Secured Indebtedness; provided, that the exercise by us of our
rights under the section captioned "THE LEASES, THE FACILITY SITE
LEASES AND THE FACILITY SITE SUBLEASES -- SUBLEASE AND ASSIGNMENT"
shall not result in a Lease Event of Default;
(11) we shall fail
(A) to cause the Rent Reserve Account to be funded in an amount at least
equal to the Rent Reserve Account Required Balance (after taking
into consideration all amounts on deposit in the Rent Reserve
Account and all amounts available pursuant to a Payment Undertaking
Agreement) on three consecutive Rent Payment Dates (after giving
effect to the payment of Basic Rent, other than Deferrable Payments,
on such dates), or
(B) at any time after the payment in full of the secured lease
obligation notes, to cause the Additional Liquidity Account to be
funded in accordance with the deposit and disbursement agreement in
an amount at least equal to the Additional Liquidity Required
Balance, on three consecutive Rent Payment Dates (after giving
effect to the payment of Basic Rent on such dates); and
(12) the certificate of formation, operating agreement or partnership
agreement or such other organizational document of our company, AES
NY, L.L.C. or AES NY3, L.L.C., as applicable, shall be amended,
changed, modified or supplemented in any material respect.
Upon the occurrence and continuance of any Lease Event of Default, the
applicable special purpose business trust may declare the related lease to be in
default; provided, that upon the occurrence of a Lease Bankruptcy Default, the
related lease shall automatically be deemed to be in default without the need
for giving any notice. Except as provided below, the special purpose business
trust may at any time thereafter, so long as we shall not have cured all
outstanding Lease Events of Default, exercise one or more of the remedies set
forth in the lease, including:
(1) seeking specific performance of our obligations, at our sole cost,
under such lease by appropriate court actions, either at law or
equity, or seeking to recover damages for breach thereof;
(2) terminating such lease, whereupon we shall be required to return
possession of the undivided interest in the related electricity
generating station to the special purpose business trust, and our
right to the possession and use of the applicable undivided interest
in the real property of the related electricity generating station
under the lease shall absolutely cease and terminate, with our
remaining liable as provided in the lease;
(3) selling the applicable undivided interest in the electricity
generating station and ground interest in the real property of the
electricity generating station at public or private sale, free and
clear of our rights; or
(4) holding, keeping idle or leasing to others the applicable undivided
interest in the electricity generating station and ground interest in
the real property of the electricity generating station, free and
clear of our rights under the lease.
Upon the occurrence and continuance of any Lease Event of Default, the
applicable special purpose business trust may, by written notice to us
specifying a Termination Date, require us to pay on the Termination Date any
unpaid Basic Rent due before the Termination Date and, if such Termination Date
shall be a Rent Payment Date, any Basic Rent (to the extent payable in arrears)
due and payable on the Rent Payment Date, any Supplemental Rent due and payable
as of the payment date specified in the notice, plus as liquidated damages (in
lieu of the Basic Rent due after the Termination Date specified in the notice):
(1) an amount equal to the excess, if any, of the termination value over
the fair market sales value of the undivided interest in the related
electricity generating station and ground interest in the real
property of the electricity generating station, as of such Termination
Date;
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(2) an amount equal to the excess, if any, of the termination value
computed as of such Termination Date over the present value of the
fair market rental value of such special purpose business trust's
interest in the undivided interest in the related electricity
generating station and ground interest in the real property of the
related electricity generating station during the Lease Fixed Term or
the then current Renewal Lease Term; or
(3) an amount equal to the termination value computed as of such
Termination Date, and upon payment of the amount referred to in this
clause (3) and all other rent then due and payable, the special
purpose business trust shall then convey its interests in the
undivided interest in the related electricity generating station and
ground interest in the real property of the related electricity
generating station to us.
Upon the occurrence and continuance of any Lease Event of Default and if
the applicable special purpose business trust shall have sold its interest in
the undivided interest in the related electricity generating station and ground
interest in the real property of the related electricity generating station, the
special purpose business trust may require us to pay as liquidated damages (in
lieu of the Basic Rent due subsequent to the date of such sale) an amount equal
to:
(1) any unpaid Basic Rent due before the date of such sale, plus;
(2) (A) if that date is a Rent Payment Date, the Basic Rent due on that
date (to the extent payable in arrears) or (B) if that date is not a
Rent Payment Date or a Termination Date, the daily equivalent of Basic
Rent (to the extent payable in arrears) for the period from the
preceding Termination Date to the date of such sale, plus;
(3) the amount, if any, by which the termination value computed as of the
Termination Date next preceding the date of the sale or, if the sale
occurs on a Rent Payment Date or a Termination Date then computed as
of this date, exceeds the net proceeds of such sale.
Upon payment of the amounts set forth above, the lease and our obligation
to pay Basic Rent for any periods subsequent to the date of the payment shall
terminate.
SPECIAL PURPOSE BUSINESS TRUST'S RIGHT TO PERFORM. If we fail to make any
payment required to be made under a particular lease or fail to perform or
comply with any other obligations under the lease and this failure continues for
10 days after notice of the failure, the applicable special purpose business
trust or the institutional investor that formed the special purpose business
trust may make the payment or perform or comply with this obligation. The amount
of the payment and the reasonable expenses of the special purpose business trust
or institutional investor that formed the special purpose business trust
incurred in connection with the payment, together with interest on the payment,
shall be deemed to be Supplemental Rent, payable by us to the special purpose
business trust on demand.
THE DEPOSIT AND DISBURSEMENT AGREEMENT
ESTABLISHMENT OF ACCOUNTS. Under the deposit and disbursement agreement,
the depositary and disbursement agent will establish the following segregated
Accounts:
(1) Revenue Account;
(2) Operating Account;
(3) Working Capital Account;
(4) Rent Payment Account;
(5) Debt Repayment Account;
(6) Rent Reserve Account;
(7) Indemnity Account;
(8) Deferrable Payments Account;
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(9) Loss Proceeds Account;
(10) Additional Liquidity Account;
(11) Special Rent Reserve Account; and
(12) Distribution Account.
The depositary and disbursement agent will maintain the Accounts at all
times until the termination of the deposit and disbursement agreement. The
deposit and disbursement agreement will remain in effect until termination of
all of the leases due to the occurrence of a Lease Event of Default. The
Accounts and amounts therein will be held (A) in our name and (B) in the custody
of, and subject to the control of, the depositary and disbursement agent on the
terms set forth in the deposit and disbursement agreement.
REVENUE ACCOUNT. We and each AES Eastern Energy Subsidiary will deposit
the following monies into the Revenue Account no later than three Business Days
after receipt thereof:
(1) all our revenues and all revenues of any AES Eastern Energy Subsidiary
(except from the Operating Account), as the case may be;
(2) any proceeds of a drawing under the working capital credit facility
with Credit Suisse First Boston;
(3) any proceeds of Permitted Indebtedness;
(4) all proceeds from the sale or other disposition of assets; and
(5) all other income, revenue and proceeds of any nature received by us or
any AES Eastern Energy Subsidiary.
Upon deposit into the Revenue Account of the proceeds of any payment in
respect of any insurance (other than business interruption insurance, if any) or
condemnation award, the depositary and disbursement agent will transfer such
amounts to the Loss Proceeds Account. Upon deposit into the Revenue Account of
any proceeds of Permitted Indebtedness, the depositary and disbursement agent
will:
(1) establish and create a sub-account within the Revenue Account;
(2) transfer such proceeds to such sub-account; and
(3) further transfer such proceeds from time to time in accordance with
certificates of officers of our company setting forth instructions as
to the disbursement of such proceeds and stating that such
disbursement is in accordance with the operative documents and the
other conditions, if any, established in the agreements relating to
such Permitted Indebtedness.
The depositary and disbursement agent shall transfer monies from the
Revenue Account in the order of priority set forth below to the extent funds are
available:
First: to the Operating Account, until the amount deposited therein equals
125% of the total amount of non-fuel Operating and Maintenance Costs, plus
fuel, set forth in the then current operating budget applicable to such
six-month period or such larger amount as is confirmed as reasonable by
Stone & Webster, the independent engineer, plus any amounts drawn on the
working capital credit facility with Credit Suisse First Boston;
Second: to the Working Capital Account, until the amount on deposit therein
equals the amount payable in respect of the principal amount of drawings on
the working capital credit facility with Credit Suisse First Boston, for
transfer to the provider thereof;
Third: on each Funding Date on a pro rata basis, (A) to the Rent Payment
Account, until the amount on deposit therein equals the amount of Basic
Rent (other than Deferrable Payments) due and payable on the immediately
succeeding Rent Payment Date for transfer to the indenture trustee on such
Rent Payment Date, and (B) to the Debt Repayment Account, until the amount
on deposit therein equals the amount due and payable on the immediately
succeeding Rent Payment Date in respect of Permitted Indebtedness (other
than Permitted Indebtedness relating to the working capital credit facility
with
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Credit Suisse First Boston or Permitted Subordinated Indebtedness) for
transfer to the provider thereof on such Rent Payment Date;
Fourth: on each Funding Date to the Rent Reserve Account, until the amount
on deposit therein together with amounts available under any Payment
Undertaking Agreement equals the then applicable Rent Reserve Account
Required Balance;
Fifth: on each Funding Date to the Indemnity Account, until the amount on
deposit therein equals the amount due in respect of our indemnity
obligations under the operative documents for transfer to such indemnified
party;
Sixth: to the Deferrable Payments Account, until the amount on deposit
therein equals the amount of Deferrable Payments due and payable for
transfer to the indenture trustee on such Rent Payment Date;
Seventh: to the Additional Liquidity Account, until the amount on deposit
therein equals the then applicable Additional Liquidity Required Balance;
Eighth: to the Special Rent Reserve Account, until the amount on deposit
therein together with amounts available under any Payment Undertaking
Agreement equals the then applicable Special Rent Reserve Account Required
Balance; and
Ninth: on each Rent Payment Date provided that the Accounts to be funded
pursuant to First through Eighth are fully funded and the other conditions
precedent set forth in the operative documents to making a Restricted
Payment are satisfied, to the Distribution Account.
OPERATING ACCOUNT. We are permitted to withdraw funds from the Operating
Account as and when required to pay Operating and Maintenance Costs including
repayment of interest on drawings under the working capital credit facility with
Credit Suisse First Boston. During any six-month period commencing with a Rent
Payment Date, we may not spend more than 125% of the then current operating
budget applicable to such six-month period (in addition to any amounts drawn and
repaid under the working capital credit facility with Credit Suisse First Boston
from the Working Capital Account during such period) without the confirmation of
Stone & Webster, the independent engineer, as to the reasonableness of the
assumptions giving rise to such variance. Upon the occurrence and during the
continuance of a Lease Event of Default, amounts may be withdrawn from the
Operating Account only with the approval of Stone & Webster, the independent
engineer.
ADDITIONAL LIQUIDITY ACCOUNT. The Additional Liquidity Account may be
funded by cash, a Payment Undertaking Agreement or a letter of credit or surety
bond, reasonably acceptable to the institutional investors that formed the
special purpose business trusts. On May 14, 1999, the Additional Liquidity
Account was funded by the deposit of a letter of credit, issued for the account
of The AES Corporation for our benefit in the amount of the Additional Liquidity
Required Balance.
INVASION OF FUNDS. On any date that amounts on deposit in the Operating
Account or the Working Capital Account are insufficient to provide for the
payment of Operating and Maintenance Costs plus amounts then due under the
working capital credit facility with Credit Suisse First Boston, we will make up
such deficiency by instructing the depositary and disbursement agent to transfer
monies to the Operating Account or the Working Capital Account, as appropriate,
in the following order from:
(1) a drawing under the working capital credit facility with Credit Suisse
First Boston for deposit into the Operating Account, to the extent that
funds are available thereunder;
(2) a withdrawal of cash on deposit in the Special Rent Reserve Account, to
the extent funds are on deposit therein;
(3) a withdrawal from the Additional Liquidity Account, to the extent funds
are on deposit therein;
(4) a drawing under the Additional Liquidity Account Letter of Credit, to
the extent that funds are available thereunder;
(5) a withdrawal from the Deferrable Payments Account, to the extent funds
are on deposit therein;
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(6) a withdrawal from the Indemnity Account, to the extent funds are on
deposit therein; and
(7) a withdrawal, pro rata, from the Rent Payment Account and the Debt
Repayment Account, to the extent funds are on deposit therein.
On any Rent Payment Date that amounts available to be paid (a) from the
Rent Payment Account or (b) from the Debt Repayment Account are insufficient to
provide for amounts due on such Rent Payment Date, we will make up such
deficiency by instructing the depositary and disbursement agent to transfer
monies, pro rata, to the Rent Payment Account and the Debt Repayment Account in
the following order from:
(1) a withdrawal from the Special Rent Reserve Account, to the extent that
funds are on deposit therein;
(2) a drawing under the Special Rent Reserve Account Payment Undertaking
Agreement, to the extent funds are available thereunder;
(3) a withdrawal from the Additional Liquidity Account, to the extent funds
are on deposit therein;
(4) a drawing under the Additional Liquidity Account Letter of Credit, to
the extent funds are available thereunder; and
(5) a withdrawal from the Rent Reserve Account or demand under the Payment
Undertaking Agreement, to the extent funds are on deposit therein or
available therefrom.
On any Rent Payment Date that amounts available to be paid from the
Deferrable Payments Account or from the Indemnity Account are insufficient to
provide for amounts due on such Rent Payment Date, we will make up such
deficiency by instructing Bankers Trust, the depositary and disbursement agent,
to transfer monies to the Deferrable Payments Account and the Indemnity Account
from the sources described in clauses (1) through (4) above.
DESCRIPTION OF THE WORKING CAPITAL CREDIT FACILITY
The following description is a summary of the working capital credit
facility that Credit Suisse First Boston has provided to us. For additional or
more specific information, refer to the agreements between us and Credit Suisse
First Boston, copies of which have been filed with the SEC as exhibits to the
registration statement of which this prospectus is a part.
We obtained a $50 million secured working capital credit facility from
Credit Suisse First Boston, New York Branch, as agent and arranger of a
syndicate of financial institutions. Loans under the working capital credit
facility will be used for our and our subsidiaries' operating and maintenance
expenses. Loans under the working capital credit facility are available on a
revolving basis provided that the aggregate principal amount available under the
working capital credit facility will be reduced by the outstanding principal
amount under any secured facility. The entire principal amount of the working
capital credit facility must be repaid prior to, and cannot be reborrowed
during, a 30-day period preceding at least one semiannual lease rental payment
date. Amounts outstanding under the working capital credit facility also must be
reduced to zero prior to any rental payment under the leases.
- Loans under the working capital credit facility bear interest at a rate
per annum, as selected by us, equal to either the applicable adjusted
Eurodollar rate plus a margin of 1.75% or a base rate plus a margin of
1%. As of January 19, 2000, the applicable rates for loans based on the
adjusted Eurodollar rate (including the applicable margin of 1.75%) were
7.56% for one-month loans, 7.79% for three-month loans and 7.97% for
six-month loans and the applicable rate for loans based on the base rate
(including the applicable margin of 1%) was 9.5%.
- The working capital credit facility has a term of three years provided
that we may extend the term for two additional one-year terms with the
consent of the lenders under the working capital credit facility.
- The working capital credit facility is secured by a pledge of our
membership interest in AEE2, L.L.C., our wholly owned subsidiary that
owns the Greenidge Generating Station and the Goudey Generating Station,
and by a security interest in equipment and personal property of AEE2,
L.L.C.
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CONDITIONS TO EACH LOAN
The obligation of each financial institution that is a member of the
syndicate of lenders under the working capital credit facility to make each loan
requested by us is subject to our fulfillment of the following conditions:
(a) we have delivered to Credit Suisse First Boston, as agent, a
certificate stating that, after giving effect to the application for a
requested loan, the amounts remaining in the Revenue Account, the
Operating Account, each of our bank accounts or the bank accounts of
any of our subsidiaries for payment of Operating and Maintenance Costs,
other than some deficiency payments required in the deposit and
disbursement agreement, would, in the aggregate, be less than $10
million; provided that amounts borrowed under the working capital
credit facility do not exceed the sum of 125% of the Annual Operating
Budget for the Rent Payment Period plus fuel costs payable for the rent
payment period;
(b) we shall have delivered to Credit Suisse First Boston, as agent, a
notice of borrowing;
(c) we are in compliance with each of the loan representations and
warranties (listed below) at the time of the loan;
(d) no default shall have occurred and be continuing at the time of the
loan;
(e) we have delivered the information requested by the lending financial
institutions; and
(f) the loan will not contravene any applicable law applicable to the bank.
Unless we have disclosed in the notice of borrowing or in a subsequent
notice, that a condition specified in clause (b) or (c) above will not be
fulfilled as of the requested time for the making of a loan, we will be
considered to have made a representation and warranty that the above conditions
have been fulfilled as of the making of the loan.
REPRESENTATIONS AND WARRANTIES
The working capital credit facility incorporates from the participation
agreements representations and warranties which are customary for facilities of
this type, including representations and warranties relating to the following:
due organization; due authorization, enforceability; no undisclosed conflicts;
no undisclosed government actions; no undisclosed litigation; no undisclosed
defaults; location of chief place of business and chief executive office; no
undisclosed liens; financial statements; projections; use of proceeds;
regulatory status/utility regulation; investment company act status; securities
act; compliance with laws; taxes; ERISA; adequate rights; qualification to do
business; jurisdiction; no undisclosed environmental matters; subsidiaries; no
broker's fees; property; no event of loss; sales taxes; year 2000 compliance. We
make additional representations and warranties in the working capital credit
facility, including representations and warranties relating to the following:
authorization; enforceability; required consents; absence of conflicts; no
litigation; no burdensome provisions; no adverse change or event; and no
additional adverse facts.
COVENANTS
The working capital credit facility also contains covenants which are
customary for facilities of this type, including covenants relating to the
following: preservation of existence and properties, scope of business,
compliance with law, payment of taxes and claims, preservation of existence;
insurance; use of proceeds; liens; merger or consolidation; disposition of
assets; incurrence of debt; limitations on investments; transactions with
affiliates; subsidiaries; additional facilities; payment of Operating and
Maintenance Costs; annual operating budget; our revenues; no abandonment; and
assignment.
The working capital credit facility also contains mandatory and voluntary
prepayment provisions and events of default customary for facilities of this
type.
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U.S. FEDERAL INCOME TAX CONSEQUENCES
PERSONS CONSIDERING THE EXCHANGE OF THE EXISTING PASS THROUGH TRUST
CERTIFICATES FOR NEW PASS THROUGH TRUST CERTIFICATES ARE URGED TO CONSULT THEIR
OWN TAX ADVISORS AS TO THE PRECISE U.S. FEDERAL, STATE AND LOCAL, AND OTHER TAX
CONSEQUENCES OF SUCH EXCHANGE AND THE ACQUISITION, OWNERSHIP AND DISPOSITION OF
THE NEW PASS THROUGH TRUST CERTIFICATES.
The following is a discussion of some of the material U.S. federal income
and estate tax consequences to U.S. Holders and Non-U.S. Holders of exchanging
existing pass through trust certificates for new pass through trust certificates
and of owning and disposing of the new pass through trust certificates. The
remainder of this discussion generally refers to the existing pass through trust
certificates and the new existing pass through trust certificates as the "pass
through trust certificates". As used in this Section, the term "U.S. Holder"
means a beneficial owner of a pass through trust certificate that is a citizen
or resident of the United States, or that is a corporation, partnership or other
entity created or organized in or under the laws of the United States or any
political subdivision of the United States or an estate or trust the income of
which is subject to U.S. federal income taxation regardless of its source. The
term "Non-U.S. Holder" means a beneficial owner of a pass through trust
certificate other than a U.S. Holder.
This discussion has been prepared by and represents the opinion of
Chadbourne & Parke LLP, our counsel, and is based upon the provisions of
existing law on the date hereof, including, in particular, the Internal Revenue
Code of 1986, as amended, Treasury regulations promulgated under the Internal
Revenue Code and other administrative and judicial interpretations relating to
the Internal Revenue Code, all of which are subject to change at any time, with
or without retroactive effect. This discussion also generally assumes that each
holder holds the pass through trust certificates as capital assets and that any
amounts received by a Non-U.S. Holder with respect to the pass through trust
certificates are not effectively connected with the conduct by such Non-U.S.
Holder of a trade or business in the United States. This discussion does not
purport to deal with all aspects of U.S. federal income taxation that might be
relevant to particular holders in light of their personal investment or tax
circumstances or status, nor does it discuss the U.S. federal income tax
consequences to certain types of holders subject to special treatment under the
U.S. federal income tax laws, such as some financial institutions, insurance
companies, dealers in securities or foreign currency, tax-exempt organizations,
foreign corporations or nonresident alien individuals, or persons holding pass
through trust certificates that are a hedge against, or that are hedged against,
currency risk or that are part of a straddle, constructive sale or conversion
transaction, or persons whose functional currency is not the U.S. dollar, or
some U.S. expatriates. Moreover, the effect of any applicable state, local or
foreign tax laws is not discussed.
EXCHANGE OFFER
The exchange of the existing pass through trust certificates for the new
pass through trust certificates in the exchange offer will not constitute a
taxable transaction for U.S. federal income tax purposes. Rather, the new pass
through trust certificates received by any U.S. Holder or Non-U.S. Holder will
be treated as a continuation of the holder's investment in the existing pass
through trust certificates. As a result, there will be no material U.S. federal
income tax consequences to a U.S. Holder or Non-U.S. Holder exchanging the
existing pass through trust certificates for the new pass through trust
certificates in the exchange offer. Certain material U.S. federal income and
estate tax consequences to U.S. Holders and Non-U.S. Holders of owning and
disposing of the pass through trust certificates are described below under
"CLASSIFICATION OF PASS THROUGH TRUST."
CLASSIFICATION OF PASS THROUGH TRUST
In the opinion of Chadbourne & Parke LLP, each pass through trust, if
operated in accordance with the terms of the applicable pass through trust
agreement, should be classified as a fixed investment trust for U.S. federal
income tax purposes. If a pass through trust were determined not to constitute a
fixed investment trust, it would be classified as a partnership for U.S. federal
income tax purposes and since at least 90% of the pass through trust's gross
income for each taxable year of its existence should consist of interest income
and gain from the sale or disposition of capital assets held for the production
of interest income, it should not be
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classified as a publicly traded partnership, which is taxable as a corporation
for U.S. federal income tax purposes.
The following discussion of U.S. federal income tax consequences is
premised on the assumption that each pass through trust is properly classified
as a fixed investment trust for U.S. federal income tax purposes. If, however, a
pass through trust were classified as a partnership for U.S. federal income tax
purposes, the consequences described below would generally apply, except that:
- income or loss with respect to the assets held by the pass through trust
would be calculated at the pass through trust level and a holder of a
pass through trust certificate would be required to report its share of
the items of income and deduction of the pass through trust on its tax
return for its taxable year within which the pass through trust's taxable
year ends;
- income or loss with respect to the pass through trust certificates would
be reported on an accrual basis even if the holder of the pass through
trust certificate otherwise uses the cash method of accounting; and
- the bond premium and market discount rules discussed below would not
apply.
U.S. HOLDERS
Payments of Interest
For U.S. federal income tax purposes, each U.S. Holder will be treated as
if that U.S. Holder directly owned its pro rata share of the secured lease
obligation notes held by the pass through trust. Accordingly, interest on the
underlying secured lease obligation notes will be taxable to a U.S. Holder at
the time that it is accrued or (actually or constructively) received, depending
upon the U.S. Holder's method of accounting for U.S. federal income tax purposes
assuming, as is expected, that the new pass through trust certificates are
issued for their face amount. If a partial acceleration of principal on the pass
through trust certificates were to occur based on an acceleration of principal
on the secured lease obligation notes, it is possible that the special rules
relating to the accrual of original issue discount set forth in Section
1272(a)(6) of the Internal Revenue Code will apply to the pass through trust
certificates. In that event, U.S. Holders are urged to consult their own tax
advisors.
Premium and Market Discount
If the amount paid for a pass through trust certificate, other than on
original issuance, that is allocable to any of the underlying secured lease
obligation notes of the pass through trust is less than, generally, the U.S.
Holder's pro rata share of the outstanding principal amount of a secured lease
obligation note, that difference will generally be market discount (subject to a
de minimis exception). In that case, any gain realized on a disposition of any
secured lease obligation note acquired with market discount or upon any payment
of principal on a secured lease obligation note including, in the case of a
disposition of a pass through trust certificate, the allocable share of the gain
from such disposition that is attributable to any secured lease obligation note
acquired with market discount will be ordinary income to the extent of accrued
market discount and to the extent it has not previously been included in income
under an election to include market discount in income as it accrues. In
addition, deductions for some or all of the interest on any indebtedness
incurred or continued to purchase or carry the pass through trust certificate
may be required to be deferred until the disposition of the pass through trust
certificate or the underlying secured lease obligation note.
In general terms, market discount on a pass through trust certificate will
be treated as accruing ratably over the term of the pass through trust
certificate, or at the election of the U.S. Holder, under a constant yield
method. However, a U.S. Holder may elect to include market discount in income on
a current basis as it accrues on either a ratable or constant yield basis, in
lieu of treating a portion of any gain realized on the sale of a pass through
trust certificate or the underlying secured lease obligation note as ordinary
income. If a U.S. Holder so elects, the interest deduction deferral rule
described above will not apply. Any election to include market discount in
income currently generally applies to all debt instruments acquired by the
electing U.S. Holder during or after the first taxable year to which the
election applies and is irrevocable without the consent
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of the United States Internal Revenue Service. A U.S. Holder should consult a
tax advisor before making the election.
If the amount paid for a pass through trust certificate that is allocable
to any of the underlying secured lease obligation notes of the pass through
trust is in excess, generally, of the U.S. Holder's pro rata share of the
outstanding principal amount of the secured lease obligation note, that excess
will constitute bond premium, which a U.S. Holder may elect to amortize using a
constant-yield method over the remaining term of the pass through trust
certificate. In the case of a U.S. Holder that makes an election to amortize
bond premium or has previously made an election that remains in effect,
amortizable bond premium will generally be treated as a reduction of the
interest income on the secured lease obligation note acquired with bond premium
on a constant yield basis, except to the extent regulations may provide
otherwise, over the term of the secured lease obligation note. The basis of a
debt obligation purchased at a premium is reduced by the amount of amortized
bond premium. An election to amortize bond premium generally applies to all debt
instruments, other than tax-exempt obligations, held by the electing U.S. Holder
on the first day of the first taxable year to which the election applies or
thereafter acquired by such owner, and is irrevocable without consent of the
Internal Revenue Service. With respect to a U.S. Holder that does not elect to
amortize bond premium, the amount of bond premium will continue to be reflected
in the U.S. Holder's tax basis. Therefore, a U.S. Holder that does not elect to
amortize bond premium will generally be required to treat the premium as a
capital loss when the pass through trust certificate matures. A U.S. Holder
should consult a tax advisor before making the election.
Disposition of the Pass Through Trust Certificates
Upon the sale, exchange, redemption, retirement or other disposition of a
pass through trust certificate, a U.S. Holder generally will recognize capital
gain or loss equal to the difference between the amount realized, not including
any amounts attributable to accrued and unpaid interest, and the U.S. Holder's
adjusted basis in the pass through trust certificate for federal income tax
purposes. Such gains or losses will be long-term if the pass through trust
certificates have been held by that U.S. Holder for more than one year.
Generally, for U.S. Holders who are individuals, long-term capital gains will be
eligible for reduced rates of U.S. federal income tax. A U.S. Holder's tax basis
in a pass through trust certificate generally will equal the cost of the pass
through trust certificate to the U.S. Holder increased by the amount of market
discount, if any, previously taken into income by the U.S. Holder or decreased
by any amortized bond premium and any payments other than payments of interest
made on the pass through trust certificate. Gain or loss recognized on the sale
or retirement of a pass through trust certificate will be capital gain or loss
except to the extent attributable to accrued but unpaid interest on the
underlying secured lease obligation notes and except to the extent that the
market discount rules discussed above may require gain or loss to be treated as
ordinary income. Rules similar to the these rules will apply with respect to any
sale or exchange of a secured lease obligation note by the pass through trust.
Fees and Expenses
Each U.S. Holder will be entitled to deduct, consistent with its method of
accounting, its pro rata share of the fees and expenses paid or incurred by the
pass through trust as provided in Sections 162 or 212 of the Internal Revenue
Code. Although we anticipate that these fees and expenses will be borne by
parties other than the holders of pass through trust certificates, it is
possible that these fees and expenses would be treated as constructively
received by the pass through trust, in which event a U.S. Holder would be
required to include in income and would be entitled to deduct its pro rata share
of these fees and expenses. If a U.S. Holder is an individual, estate or trust,
the deduction for these U.S. Holder's share of such fees or expenses will be
allowed only to the extent that all of that U.S. Holder's miscellaneous
deductions, including the holder's share of such fees and expenses, exceed 2% of
the U.S. Holder's adjusted gross income. In addition, in the case of U.S.
Holders who are individuals, additional rules, which limit the amount of the
individual's otherwise allowable itemized deductions under generally applicable
provisions of the Internal Revenue Code, will also apply to any deduction.
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NON-U.S. HOLDERS
Payments of Interest
A Non-U.S. Holder will not be subject to U.S. federal income tax by
withholding on interest on a pass through trust certificate provided that the
beneficial owner of the pass through trust certificate fulfills the
certification requirements set forth in applicable Treasury Regulations unless:
(1) a Non-U.S. Holder (A) actually or constructively owns 10% or more of
the total combined voting power of all classes of stock entitled to
vote of the institutional investor that formed the special purpose
business trust, (B) is a controlled foreign corporation related,
directly or indirectly, to the institutional investor that formed the
special purpose business trust within the meaning of Section 864(d)(4)
of the Internal Revenue Code or (C) is a bank receiving interest
described in Section 881(c)(3)(A) of the Internal Revenue Code; or
(2) the interest is effectively connected with the conduct of a trade or
business by the Non-U.S. Holder in the United States.
To fulfill the certification requirements and qualify for the exemption
from withholding, the last U.S. Person within the meaning of Section 7701(a)(30)
of the Internal Revenue Code in the chain of payment prior to payment to a
Non-U.S. Holder (the "Withholding Agent") must have received in the year in
which such a payment occurs, or in either of the two preceding years, a
statement that
- is signed by the beneficial owner under penalties of perjury,
- certifies that the owner is not a U.S. Holder, and
- provides the name and address of the beneficial owner.
The statement may be made on Internal Revenue Service Form W-8 or a
substantially similar substitute form, and the beneficial owner must inform the
Withholding Agent of any change in the information on the statement within 30
days of the change. If a pass through trust certificate is held through a
securities clearing organization or another financial institution permitted to
provide the necessary statement, the organization or institution may provide a
signed statement to the Withholding Agent. However, in that case, the signed
statement must be accompanied by a copy of a Form W-8 or substitute form
provided by the beneficial owner to the organization or institution holding the
pass through trust certificate on behalf of the beneficial owner.
Recently issued regulations would provide alternative methods for
satisfying the certification requirements described above (the "New
Regulations"). The New Regulations also would require, in the case of pass
through trust certificates held by a foreign partnership, that
- the certification described above be provided by the partners rather than
by the foreign partnership; and
- the partnership provide certain information, including a United States
taxpayer identification number.
A look-through rule would apply in the case of tiered partnerships. The New
Regulations are generally effective for payments made after December 31, 2000.
Gain on Disposition of the Certificates
Generally, any amount which constitutes capital gain to a Non-U.S. Holder
upon retirement or disposition of a pass through trust certificate will not be
subject to U.S. federal income taxation unless (1) in the case of a Non-U.S.
Holder who is an individual, that Non-U.S. Holder is present in the United
States for a period or periods aggregating 183 days or more during the taxable
year of the disposition, in which case that individual may be taxed as a U.S.
Holder in any event, or (2) the gain is effectively connected with the conduct
of a trade or business by the Non-U.S. Holder in the United States. Non-U.S.
Holders should consult a tax advisor.
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Estate Tax
Pass through trust certificates held at the time of death by an individual
holder, who at such time was not a citizen or resident of the United States,
will not be subject to U.S. federal estate tax, provided that at such time:
(1) the holder did not actually or constructively own 10% or more of the
total combined voting power of all classes of stock entitled to vote of
an institutional investor that formed a special purpose business trust;
and
(2) payments of interest with respect to the pass through trust
certificates would not have been, if received at the time of such
individual's death, effectively connected with the conduct of a United
States trade or business by that individual.
INFORMATION REPORTING AND BACKUP WITHHOLDING
Interest and payments of proceeds from the disposition by beneficial owners
who are not exempt recipients may be subject to backup withholding at a rate of
31%. Generally, individuals are not exempt recipients, whereas corporations and
certain other entities generally are exempt recipients. A U.S. Holder generally
will be subject to backup withholding at a rate of 31% unless the recipient of a
payment supplies an accurate taxpayer identification number, as well as certain
other information, or otherwise establishes, in the manner prescribed by law, an
exemption from backup withholding. Compliance with the identification procedures
described in the preceding section would generally establish an exemption from
backup withholding for those Non-U.S. Holders who are not exempt recipients.
In addition, upon the sale of a pass through trust certificate to or
through a broker, the broker must withhold at a rate of 31% of the reportable
payment, unless either:
(1) the broker determines that the seller is a corporation or other exempt
recipient; or
(2) the seller provides, in the required manner, required identifying
information or certifies that it is a Non-U.S. Holder and certain other
conditions are met.
Such a sale must also be reported by the broker to the Internal Revenue
Service, unless either
- the broker determines that the seller is an exempt recipient, or
- the seller certifies its Non-U.S. status and other conditions are met.
Certification of the beneficial owner's Non-U.S. status usually would be
made on Form W-8 under penalties of perjury, although in some cases it may be
possible to submit other documentary evidence. The term "broker" generally
includes all persons who, in the ordinary course of a trade or business, stand
ready to effect sales made by others, as well as brokers and dealers registered
as such under the laws of the United States or a state thereof. These
requirements generally will apply to a United States office of a broker, and the
information reporting requirements generally will apply to a foreign office of a
United States broker, as well as to a foreign office of a foreign broker if the
broker is:
(1) a controlled foreign corporation within the meaning of Section 957(a)
of the Internal Revenue Code;
(2) a foreign person 50% or more of whose gross income from all sources for
the 3-year period ending with the close of its taxable year preceding
the payment or for the part of the period that the foreign broker has
been in existence was effectively connected with the conduct of a trade
or business within the United States; or
(3) under the New Regulations, which are applicable with respect to
payments made after 2000, a foreign partnership if it is engaged in a
trade or business in the United States or if 50% or more of its income
or capital interests are held by U.S. persons.
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Certification requirements may have to be satisfied in order to avoid
backup withholding under the foregoing rules. Under Treasury Regulations, both
backup withholding and information reporting would apply to the proceeds from
dispositions if the broker has actual knowledge that the payee is a U.S. Holder.
Generally, any amounts withheld under the backup withholding rules from a
payment to a beneficial owner would be allowed as a refund or credit against a
beneficial owner's U.S. federal income tax. Holders should consult their tax
advisors regarding the application of information reporting and backup
withholding in their particular situation and the availability of an exemption
therefrom, and the procedures for obtaining any such exemption.
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ERISA CONSIDERATIONS
If you intend to use plan assets to purchase pass through trust
certificates, you should consult with counsel on the potential consequences of
your investment under the fiduciary responsibility provisions of the Employee
Retirement Income Security Act of 1974, as amended, and the prohibited
transaction provisions of ERISA and the Internal Revenue Code.
ERISA and the Internal Revenue Code impose requirements on employee benefit
plans and other retirement plans and arrangements, including individual
retirement accounts and annuities. ERISA and the Internal Revenue Code also
impose requirements on any entity holding assets of any plan, account, or
annuity, for example, a bank common investment fund or an insurance company
general or separate account. Generally, a person who exercises discretionary
authority or control over plan assets will be considered a plan fiduciary under
ERISA. Before investing in a pass through trust certificate, a plan fiduciary
should determine whether its investment:
(1) is permitted under the plan document and other instruments governing
the plan; and
(2) is appropriate for the plan in view of its overall investment policy
and the composition and diversification of its portfolio, taking into
account the limited liquidity of the pass through trust certificates.
ERISA and the Internal Revenue Code also prohibit a wide range of
transactions involving plan assets and persons who have relationships to the
plan. These persons are called "parties in interest" under ERISA and are called
"disqualified persons" under the Internal Revenue Code. The transactions
prohibited by ERISA and the Internal Revenue Code are called "prohibited
transactions." As a result, anyone considering using plan assets to invest in
the pass through trust certificates should consider whether the investment might
be a prohibited transaction under ERISA and/or the Internal Revenue Code.
In addition, if a plan invests in the pass through trust certificates, the
assets of the related pass through trust might be deemed to be plan assets. If
the assets of a pass through trust are deemed to be plan assets, the operation
of the pass through trust might give rise to one or more nonexempt prohibited
transactions under ERISA and/or the Internal Revenue Code. The plan fiduciary
might also be deemed to have engaged in an improper delegation to the pass
through trustee of the plan fiduciary's investment management responsibilities.
Neither ERISA nor the Internal Revenue Code defines the term "plan assets."
Under Section 2510.3-101 of the United States Department of Labor regulations,
when a plan acquires an equity interest in an entity, the plan's assets include
both the equity interest and an undivided interest in each of the entity's
underlying assets unless:
(1) the interest is a publicly offered security;
(2) the interest is issued by an investment company registered under the
Investment Company Act of 1940, as amended;
(3) the entity is a venture capital operating company or real estate
operating company; or
(4) participation by "benefit plan investors" is not significant.
Department of Labor regulations generally define "equity interest" as any
interest in an entity other than an instrument that is treated as indebtedness
under applicable local law and that has no substantial equity features. We
believe that the pass through trust certificates will be treated as equity
interests in the pass through trusts under the Department of Labor regulations.
Participation by benefit plan investors in the pass through trust
certificates will not be significant if less than 25% of the value of the pass
through trust certificates is held by benefit plan investors immediately after
the most recent acquisition of a pass through trust certificate. Benefit plan
investors include plans subject to ERISA, some plans not subject to ERISA (for
example, governmental plans, foreign plans, certain individual retirement
accounts and entities whose assets are treated as "plan assets" under Department
of Labor
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regulations) and entities deemed to be holding the assets of any plan. We will
not restrict or monitor investment in and transfer of the pass through trust
certificates with respect to this 25% limit. It is possible that during the term
of the pass through trust certificates, 25% or more of the pass through trust
certificates will be held by plans and other benefit plan investors. If that
happens, an investment by a plan in the pass through trust certificates during
such period will be considered an investment in the corresponding secured lease
obligation notes and an ongoing loan to the special business purpose trusts, for
purposes of the fiduciary responsibility provisions of ERISA and the prohibited
transaction provisions of ERISA and the Internal Revenue Code. As a result, if
any assets of a pass through trust are considered plan assets, investment by a
plan in the pass through trust certificates could result in a prohibited
transaction or an impermissible delegation of fiduciary authority.
We, the pass through trustee, or any of our or their affiliates may be a
party in interest or a disqualified person to the plan acquiring, holding or
disposing of the pass through trust certificates. If that happens, the
acquisition, holding or disposition will result in a direct or indirect
prohibited transaction regardless of whether the assets of a pass through trust
are considered plan assets.
A prohibited transaction may be treated as exempt under ERISA and the
Internal Revenue Code if the pass through trust certificates are acquired, held
or disposed of pursuant to and in accordance with one or more statutory or
administrative exemptions. Among the prohibited transaction class exemptions or
"PTCE" exemptions are:
(1) PTCE 75-1 -- an exemption for certain transactions involving employee
benefit plans and registered broker dealers (such as reporting dealers
and banks);
(2) PTCE 84-14 -- an exemption for certain transactions determined by an
independent qualified professional asset manager;
(3) PTCE 90-1 -- an exemption for certain transactions involving insurance
company pooled separate accounts;
(4) PTCE 91-38 -- an exemption for certain transactions involving bank
collective investment funds;
(5) PTCE 95-60 -- an exemption for certain transactions involving insurance
company general accounts; and
(6) PTCE 96-23 -- an exemption for certain transactions determined by a
qualified in-house asset manager.
These exemptions do not, however, provide relief from the self-dealing
prohibitions under ERISA and the Internal Revenue Code. In addition, these
administrative exemptions may not be available for a particular transaction
involving the pass through trust certificates. If you represent a plan fiduciary
considering an investment in the pass through trust certificates, you should
consider whether the acquisition, the continued holding, or the disposition of a
pass through trust certificate might be a nonexempt prohibited transaction.
ERISA also prohibits plan fiduciaries from maintaining the indicia of
ownership of any plan assets outside the jurisdiction of the United States
district courts except in certain cases. Before investing in a pass through
trust certificate, you should consider whether the acquisition, holding or
disposition of a pass through trust certificate would satisfy such indicia of
ownership rules.
If you acquire or accept a pass through trust certificate or an interest in
a pass through trust certificate, you will be deemed to have represented and
warranted that either:
(1) you have not used plan assets to acquire such pass through trust
certificate or an interest in a pass through trust certificate; or
(2) your acquisition and holding of a pass through trust certificate or
interest in a pass through trust certificate is exempt from the
prohibited transaction restrictions of ERISA and the Internal Revenue
Code under one or more prohibited transaction class exemptions or does
not constitute a prohibited transaction under ERISA and the Internal
Revenue Code.
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A PLAN FIDUCIARY (AND EACH FIDUCIARY FOR A GOVERNMENTAL OR CHURCH PLAN
SUBJECT TO RULES SIMILAR TO THOSE IMPOSED ON PLANS UNDER ERISA) CONSIDERING THE
PURCHASE OF PASS THROUGH TRUST CERTIFICATES SHOULD CONSULT ITS TAX AND/OR LEGAL
ADVISORS REGARDING THE CIRCUMSTANCES UNDER WHICH THE ASSETS OF A PASS THROUGH
TRUST WOULD BE CONSIDERED PLAN ASSETS, THE AVAILABILITY, IF ANY, OF EXEMPTIVE
RELIEF FROM ANY POTENTIAL PROHIBITED TRANSACTION AND OTHER FIDUCIARY ISSUES AND
THEIR POTENTIAL CONSEQUENCES.
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC, as set forth in no-action
letters issued to third parties unrelated to us, we believe that holders of the
new pass through trust certificates, other than any holder that is a
broker-dealer that acquired existing pass through trust certificates:
- as a result of market-making activities or other trading activities; or
- directly from us for resale pursuant to Rule 144A, Regulation S or
another available exemption under the Securities Act,
who exchange their existing pass through trust certificates for new pass through
trust certificates pursuant to this exchange offer may offer for resale and
otherwise transfer the new pass through trust certificates without compliance
with the registration and prospectus delivery provisions of the Securities Act,
provided that the new pass through trust certificates are:
- acquired in the ordinary course of the holders' business;
- the holders have no arrangement or understanding with any person to
participate in the distribution of the new pass through trust
certificates; and
- the holders are not our "affiliates," within the meaning of Rule 405
under the Securities Act.
The staff of the SEC has not considered this exchange offer in the context
of a no-action letter and we can give no assurance that the staff of the SEC
would make a similar determination with respect to this exchange offer.
Accordingly, any holder of existing pass through trust certificates using this
exchange offer to participate in a distribution of the new pass through trust
certificates to be acquired in this exchange offer:
- cannot rely on the position of the staff of the SEC stated in Exxon
Capital Holdings Corporation (avail. April 13, 1989) or similar letters;
and
- must comply with registration and prospectus delivery requirements of the
Securities Act in connection with a secondary resale transaction.
Each broker-dealer who holds existing pass through trust certificates
acquired for its own account and who receives new pass through trust
certificates in exchange for the existing pass through trust certificates
pursuant to this exchange offer must acknowledge that it will deliver a
prospectus meeting the requirements of the Securities Act in connection with any
resale of the new pass through trust certificates.
By tendering existing pass through trust certificates in exchange for new
pass through trust certificates, you will represent to us, among other things,
that:
(1) you are acquiring the new pass through trust certificates in the
ordinary course of your business;
(2) at the time of the commencement of this exchange offer, you have no
arrangement or understanding with any person to participate in the
distribution, within the meaning of the Securities Act, of the new pass
through trust certificates you will receive in this exchange offer;
(3) you are not our "affiliate," within the meaning of Rule 405 under the
Securities Act, or if you are an affiliate, that you will comply with
the registration and prospectus delivery requirements of the Securities
Act to the extent applicable;
(4) you have full power and authority to tender, exchange, sell, assign and
transfer the tendered existing pass through trust certificates;
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(5) we will acquire good, marketable and unencumbered title to the tendered
existing pass through trust certificates free and clear of all liens,
restrictions, charges and encumbrances; and
(6) the existing pass through trust certificates tendered for exchange are
not subject to any adverse claims or proxies.
If you are not a broker-dealer, by tendering existing pass through trust
certificates and executing a letter of transmittal, you represent and agree that
you are not engaged in, and do not intend to engage in, distribution of the new
pass through trust certificates within the meaning of the Securities Act.
A broker-dealer may use this prospectus, as it may be amended or
supplemented from time to time, in connection with resales of new pass through
trust certificates received in exchange for existing pass through trust
certificates where such existing pass through trust certificates were acquired
for its own account as a result of market-making or other trading activities. We
have agreed that, starting on the expiration date of the exchange offer and
ending on the close of business on the 120th day following the expiration date,
we will make this prospectus, as amended or supplemented, available to any
broker-dealer for use in connection with any resale. For a period of 120 days
after the expiration date, we will send promptly additional copies of this
prospectus and any amendment or supplement to this prospectus to any
broker-dealer that requests such documents in the letter of transmittal.
We will not receive any proceeds from any sale of new pass through trust
certificates by broker-dealers. Broker-dealers that receive new pass through
trust certificates for their own account pursuant to this exchange offer may
resell the new pass through trust certificates from time to time in one or more
transactions:
- in the over-the-counter market;
- in negotiated transactions;
- through the writing of options on the new pass through trust
certificates; or
- a combination of such methods of resale, at market prices prevailing at
the time of resale, at prices related to such prevailing market prices or
negotiated prices.
Any resale may be made directly to purchasers or to or through brokers or
dealers who may receive compensation in the form of commissions or concessions
from any broker-dealer and/or the purchasers of any new pass through trust
certificates. Any broker-dealer that resells new pass through trust certificates
that it receives for its own account in this exchange offer and any broker or
dealer that participates in a distribution of new pass through trust
certificates may be deemed to be an "underwriter" within the meaning of the
Securities Act and any profit from any resale of new pass through trust
certificates and any commissions or concessions received by any of those persons
may be deemed to be underwriting compensation under the Securities Act. The
letter of transmittal states that by acknowledging that it will deliver and by
delivering a prospectus, a broker-dealer will not be deemed to admit that it is
an "underwriter" within the meaning of the Securities Act.
We have agreed to pay all registration expenses incident to this exchange
offer, including the expenses of one counsel for the holders of the existing
pass through trust certificates if it becomes necessary to file a shelf
registration statement, other than commissions or concessions of any brokers or
dealers, and we will indemnify the holders of the existing pass through trust
certificates including any broker-dealers, against certain liabilities,
including liabilities under the Securities Act.
EXPERTS
This document has been prepared by the management of our company and
includes financial statements audited by Deloitte & Touche LLP as stated in
their independent auditors' reports accompanying those financial statements.
These financial statements are included in this prospectus in reliance upon the
independent auditors' reports of such firm given upon their authority as experts
in accounting and auditing. The management of our company is responsible for the
accuracy and completeness of this document, including the "Projected Financial
Data", and Deloitte & Touche LLP makes no warranty as to any of the information
contained herein, nor any representations except as contained in its independent
auditors' reports.
166
171
The Independent Engineer's Report included as Appendix A to this prospectus
has been prepared by Stone & Webster, and is included herein in reliance upon
its conclusions and Stone & Webster's experience in the review of the operation
of electric generation facilities and the preparation of financial projections
with respect thereto. The Independent Market Consultant's Report included as
Appendix B to this prospectus has been prepared by London Economics, and is
included herein in reliance upon its conclusions and London Economics'
experience in energy market policy, price forecasting and economic analysis. The
Pittsburgh Seam Coal Market Study included as Appendix C to this prospectus has
been prepared by John T. Boyd Company, and is included herein in reliance upon
its conclusions and its experience in evaluating the market for coal supplied to
northeastern U.S. utilities from the Pittsburgh Seam.
LEGAL MATTERS
The validity of the pass through trust certificates is being passed upon
for us by our counsel, Chadbourne & Parke LLP, New York, New York.
167
172
INDEX TO FINANCIAL STATEMENTS
PAGE
----
AES EASTERN ENERGY, L.P.
Independent Auditors' Report................................ F-2
Financial Statements:
Consolidated Balance Sheet................................ F-3
Consolidated Statement of Income.......................... F-4
Consolidated Statement of Changes in Partners' Capital.... F-5
Consolidated Statement of Cash Flows...................... F-6
Notes to Consolidated Financial Statements................ F-7
AES NEW YORK, L.L.C. (GENERAL PARTNER OF AES EASTERN ENERGY,
L.P.)*
Independent Auditors' Report................................ F-16
Financial Statements:
Consolidated Balance Sheet................................ F-17
Notes to Consolidated Balance Sheet....................... F-18
- ---------------
*The balance sheet of AES New York, L.L.C. contained in this prospectus should
be considered only in connection with its status as the general partner of AES
Eastern Energy, L.P. The pass through trust certificates do not represent an
interest in or an obligation of AES New York, L.L.C.
F-1
173
INDEPENDENT AUDITORS' REPORT
To the Partners of
AES Eastern Energy, L.P.
We have audited the accompanying consolidated balance sheet of AES Eastern
Energy, L.P. (an indirect wholly owned subsidiary of The AES Corporation), and
subsidiaries (the Partnership) as of September 30, 1999, and the related
consolidated statements of income, changes in partners' capital, and cash flows
for the period from May 14, 1999 (Inception) through September 30, 1999. These
financial statements are the responsibility of the Partnership'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, such consolidated financial statements present fairly, in
all material respects, the financial position of AES Eastern Energy, L.P., and
subsidiaries as of September 30, 1999, and the results of their operations and
their cash flows for the period from May 14, 1999 (inception) through September
30, 1999, in conformity with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
McLean, Virginia
January 18, 2000
F-2
174
AES EASTERN ENERGY, L.P.
CONSOLIDATED BALANCE SHEET
SEPTEMBER 30, 1999
(AMOUNTS IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Restricted cash:
Operating -- cash and cash equivalents................. $ 11,303
Revenue account........................................ 19,953
Accounts receivable -- trade.............................. 51,720
Accounts receivable -- affiliates......................... 310
Accounts receivable -- others............................. 765
Inventory................................................. 21,530
Prepaid expenses.......................................... 11,729
----------
Total current assets.............................. 117,310
----------
PROPERTY, PLANT, EQUIPMENT, AND RELATED ASSETS:
Land...................................................... 6,903
Electric generation assets (net of accumulated
depreciation of $9,818)................................ 990,613
----------
Total property, plant, equipment, and related
assets............................................ 997,516
----------
OTHER ASSETS:
Rent reserve account...................................... 29,188
----------
TOTAL ASSETS................................................ $1,144,014
==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable.......................................... $ 11,223
Accrued interest expense.................................. 23,208
Due to The AES Corporation................................ 3,190
Other accrued expenses.................................... 20,907
Other liabilities......................................... 10,983
----------
Total current liabilities......................... 69,511
----------
LONG-TERM LIABILITIES:
Lease financing -- long-term.............................. 650,000
Environmental remediation................................. 10,195
Defined benefit plan obligation........................... 23,327
Other liabilities......................................... 7,392
----------
Total long-term liabilities....................... 690,914
----------
TOTAL LIABILITIES........................................... 760,425
PARTNERS' CAPITAL........................................... 383,589
----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL..................... $1,144,014
==========
See notes to consolidated financial statements.
F-3
175
AES EASTERN ENERGY, L.P.
CONSOLIDATED STATEMENT OF INCOME
PERIOD FROM MAY 14, 1999 (INCEPTION) THROUGH SEPTEMBER 30, 1999
(AMOUNTS IN THOUSANDS)
OPERATING REVENUES:
Energy...................................................... $107,211
Capacity.................................................. 10,006
Other..................................................... 3,626
--------
Total revenues.................................... 120,843
--------
OPERATING EXPENSES:
Fuel...................................................... 42,363
Depreciation and amortization............................. 9,818
Operating and maintenance................................. 2,978
General and administrative................................ 18,070
--------
Total operating expenses.......................... 73,229
--------
OPERATING INCOME............................................ 47,614
--------
OTHER INCOME (EXPENSE):
Interest expense.......................................... (18,546)
Interest income........................................... 715
--------
Total other income (expense)...................... (17,831)
--------
NET INCOME.................................................. $ 29,783
========
See notes to consolidated financial statements.
F-4
176
AES EASTERN ENERGY, L.P.
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
PERIOD FROM MAY 14, 1999 (INCEPTION) THROUGH SEPTEMBER 30, 1999
(AMOUNTS IN THOUSANDS)
GENERAL LIMITED
PARTNER PARTNER TOTAL
------- -------- --------
BALANCE, MAY 14, 1999....................................... $ -- $ -- $ --
Capital contribution (net of $1.1 million to be returned to
The AES Corporation, see Note 8)............................ 3,538 350,268 353,806
Net income for the period ended September 30, 1999........ 298 29,485 29,783
------ -------- --------
BALANCE, SEPTEMBER 30, 1999................................. $3,836 $379,753 $383,589
====== ======== ========
See notes to consolidated financial statements.
F-5
177
AES EASTERN ENERGY, L.P.
CONSOLIDATED STATEMENT OF CASH FLOWS
PERIOD FROM MAY 14, 1999 (INCEPTION) THROUGH SEPTEMBER 30, 1999
(AMOUNTS IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $ 29,783
Adjustments to reconcile net income to net cash used in
operating activities:
Depreciation and amortization.......................... 9,818
Accrued interest expense............................... 18,546
Interest income accrued in rent reserve account........ (515)
Net defined benefit plan cost.......................... 824
Changes in current operating assets and liabilities:
Accounts receivable -- trade........................... (52,485)
Accounts receivable -- affiliates...................... (310)
Inventory.............................................. 1,337
Prepaid expenses....................................... (11,663)
Accounts payable....................................... 11,223
Other accrued expenses................................. 20,907
---------
Net cash provided by operating activities......... 27,465
---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of assets at inception date................... (267,424)
Payments for capital additions............................ (55,065)
Increase in restricted cash............................... (31,256)
---------
Net cash used in investing activities............. (353,745)
---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash capital contributions................................ 354,953
Payments to rent reserve account.......................... (28,673)
---------
Net cash provided by financing activities......... 326,280
---------
INCREASE IN CASH AND CASH EQUIVALENTS....................... --
CASH AND CASH EQUIVALENTS, MAY 14, 1999..................... --
---------
CASH AND CASH EQUIVALENTS, SEPTEMBER 30, 1999............... $ --
=========
On May 14, 1999, the Partnership acquired electric generation assets valued
at $650 million under leases accounted for as a financing.
See notes to consolidated financial statements.
F-6
178
AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIOD FROM MAY 14, 1999 (INCEPTION) THROUGH SEPTEMBER 30, 1999
1. GENERAL
AES Eastern Energy, L.P. (the Partnership), a Delaware limited partnership,
was formed on December 2, 1998. The Partnership's wholly owned subsidiaries are
AES Somerset, L.L.C., AES Cayuga, L.L.C., and AEE2, L.L.C., (which wholly owns
AES Westover, L.L.C. and AES Greenidge, L.L.C.). The Partnership began
operations on May 14, 1999 (see Note 3). Prior to that date, the Partnership had
no operations. The Partnership is an indirect wholly owned subsidiary of The AES
Corporation. The Partnership has adopted December 31 as its fiscal year-end.
The Partnership was established for the purpose of owning and operating
four coal-fired electric generating stations (the Plants) with a total combined
capacity of 1,268 MW. The partners of the Partnership are comprised of AES New
York, L.L.C. (the General Partner) and AES New York 2, L.L.C. (the Limited
Partner) both of which are indirect wholly owned subsidiaries of The AES
Corporation (AES). The Plants are owned or leased by the Partnership (see Note
3) and are operated by the Partnership's wholly owned subsidiaries in the state
of New York, pursuant to operation and maintenance agreements with the
Partnership.
The Plants sell generated electricity, as well as installed capacity and
ancilliary services, directly into the New York Power Pool (NYPP), Pennsylvania,
New Jersey, Maryland Power Pool (PJM), and New England Power Pool (NEPOOL). For
Federal regulatory purposes, the Partnership is an exempt wholesale generator
(EWG). As an EWG, the Partnership cannot make retail sales of electricity. The
Partnership can only make wholesale sales of electricity, installed capacity,
and ancillary services into wholesale power markets, or through direct sales to
third parties at negotiated prices.
The Partnership has entered into a two-year agreement for energy marketing
services with Merchant Energy Group of the Americas, Inc. (MEGA), an Annapolis,
Maryland-based subsidiary of Gener S.A., a Chilean independent power producer.
MEGA is responsible for marketing the Partnership's electric energy, installed
capacity, and ancillary services.
2. SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The consolidated financial statements
include the accounts of the Partnership, AES Somerset, L.L.C., AES Cayuga,
L.L.C., and AEE2, L.L.C. (which includes its subsidiaries, AES Westover, L.L.C.,
and AES Greenidge, L.L.C.). All material intercompany transactions have been
eliminated.
Cash and Cash Equivalents -- The Partnership considers unrestricted cash on
hand, deposits in banks, and short-term marketable securities with original
maturities of three months or less in operating accounts to be cash and cash
equivalents.
Restricted Cash -- Under the terms of the deposit and disbursement
agreement entered into in connection with the lease of two plants (see Note 6),
all revenues of the Partnership and its subsidiaries are deposited into a
revenue account administered by the depositary agent. On request of the
Partnership and in accordance with the terms of the deposit and disbursement
agreement, funds are transferred from the revenue account to other operating
accounts administered by the depositary agent for payment of operating and
maintenance costs, lease obligations, debt service, reserve requirements, and
distributions. Payment of operating and maintenance costs (other than actual
fuel costs) in excess of 125% of the annual operating budget require
confirmation from an independent engineer that such payment is based on
reasonable assumptions.
F-7
179
AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Inventory -- Inventory, valued at fair market value on the date of
acquisition (see Note 3), and subsequently valued at the lower of cost (average
cost basis) or market, consists of coal and other raw materials used in
generating electricity, and spare parts, materials, and supplies.
Inventory, as of September 30, 1999, consisted of the following (in
thousands):
Coal and other raw materials................................ $ 6,174
Spare parts, materials, and supplies........................ 15,356
-------
Total....................................................... $21,530
=======
Property, Plant, Equipment, and Related Assets -- Electric generation
assets that existed at the date of acquisition (see Note 3) are recorded at fair
market value. The Somerset (formerly known as Kintigh) and Cayuga (formerly
known as Milliken) Plants, which represent $650 million of the electric
generation assets, are subject to a leasing arrangement accounted for as a
financing (see Note 6). Additions or improvements thereafter are recorded at
cost. Depreciation is computed using the straight-line method over the 34-year
and 28-year lease terms for the Somerset and Cayuga Plants, respectively, and
over the estimated useful lives for the other fixed assets, which range from 7
to 35 years. Maintenance and repairs are charged to expense as incurred.
Electric generation assets as of September 30, 1999, consisted of the
following (in thousands):
Electric generation tangible assets......................... $760,280
Other intangible assets..................................... 240,151
Accumulated depreciation and amortization................... (9,818)
--------
Total....................................................... $990,613
========
Other intangible assets represent assets that were identified and valued in
an independent appraisal and that are directly related to the physical assets of
the Plants. These include trading benefits derived from the ability of the
Partnership to enter new deregulated markets through sale of the output of the
Plants, potential revenues from ancillary services, and mitigation of
environmental risk due to the advanced emissions control equipment that has
already been installed at the principal Plants. Trading benefits provide both
the Plants and the Partnership the ability to arbitrage electricity generation
and installed capacity in order to capture the most lucrative prices in
available markets. Ancillary services include voltage support, spinning
reserves, and other activities that enhance the stability and reliability of the
transmission system. These services will be purchased by the organizations that
manage power systems rather than wholesale electricity customers. Mitigation of
environmental risk reflects the Partnership's ability, created by pollution
control devices, to effectively use lower cost and lower grade coal to provide
the same electricity output as its competitors. Amortization is computed on the
same basis as the related assets (28 to 34 years).
Rent Reserve Account -- As part of the Partnership's lease obligation (see
Note 6), the Partnership is required to maintain a rent reserve account equal to
the maximum semiannual payment with respect to the sum of basic rent (other than
deferrable payments) and fixed charges expected to become due on any one basic
rent payment date in the immediately succeeding three-year period. As of
September 30, 1999, the Partnership had fulfilled this obligation by entering
into a Payment Undertaking Agreement, dated as of May 1, 1999, among the
Partnership, each Owner Trust (see Note 3) and Morgan Guaranty Trust Company of
New York (the Payment Undertaking Agreement). On May 14, 1999, the Partnership
deposited with Morgan Guaranty Trust Company of New York approximately $28.7
million pursuant to the Payment Undertaking Agreement. The accreted value of the
Payment Undertaking Agreement at any time includes interest earned thereunder at
an interest rate of 4.79% per annum. Interest earnings as of September 30, 1999
were approximately $515,000 and are included in the rent reserve account
balance. At September 30, 1999, the accreted value of the Payment Undertaking
Agreement exceeded the required balance of the rent reserve
F-8
180
AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
account. This amount is being accounted for as a restricted cash balance and is
included within the rent reserve account on the accompanying balance sheet, as
it can only be utilized to satisfy lease obligations.
In the future, the Partnership may fulfill its obligation to maintain the
required balance of the rent reserve account either by deposits into the rent
reserve account or by making amounts available under the Payment Undertaking
Agreement, such that the aggregate amount of such deposits in the rent reserve
account and amounts available to be paid under the Payment Undertaking Agreement
are equal to the required balance of the rent reserve account.
Line of Credit Agreement -- The Partnership has established a three-year
revolving working capital credit facility of up to $50 million for the purpose
of making funds available to pay for certain operating and maintenance costs.
Amounts outstanding under the working capital facility are required to be
reduced to zero for thirty days prior to any one lease rental payment date in
each year. Interest accrues on outstanding balances at a base rate plus 1% or
the applicable adjusted Eurodollar rate plus 1.75%. The working capital credit
facility is collateralized by a pledge of the Partnership's membership interest
in AEE2, L.L.C. and by a security interest in equipment and personal property of
AEE2, L.L.C. As of September 30, 1999, no amounts were outstanding under this
credit facility.
Revenue Recognition -- Revenues from the sale of electricity are recorded
based upon output delivered and rates specified under contract terms. Revenues
for ancillary and other services are recorded when the services are rendered.
New York Transition Agreement -- As the NYPP represents a deregulated
environment, the Independent System Operator (ISO) of the NYPP will attempt to
ensure stability of the power grid in New York by requiring each entity engaged
in retail sales of electricity to obtain installed capacity commitments from
generators in an amount equal to the entity's forecasted peak load plus a
reserve margin. This requirement is intended to ensure that an adequate supply
of electricity is always available. The General Partner entered into a two-year
transition agreement with NYSEG pursuant to which the Partnership will sell its
installed capacity to NYSEG in order to permit NYSEG to comply with ISO
standards for system stability. The transition agreement was assumed by the
Partnership on the date of acquisition of the Plants. The Partnership recognizes
revenue under this contract as it is earned, which is $68 per MW per day for
installed capacity made available.
Income Taxes -- A provision for Federal and state income taxes has not been
made in the accompanying financial statements since the Partnership does not pay
income taxes but rather allocates its revenues and expenses to the individual
partners. Differences between the results of operations reported in the
financial statements and those reported on individual partners' income tax
returns are due primarily to the use of different lease treatment, accelerated
depreciation methods, and shorter useful lives for income tax purposes.
Use of Estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles requires the Partnership to make
estimates and assumptions that affect reported amounts of assets and liabilities
and disclosures of contingent assets and liabilities at the date of the
financial statements, as well as the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Comprehensive Income -- In 1999, the Partnership adopted Statement of
Financial Accounting Standards (SFAS) No. 130, Reporting Comprehensive Income,
which establishes rules for the reporting of comprehensive income and its
components. The adoption of SFAS No. 130 had no impact on the Partnership's
financial statements as it had no items of other comprehensive income.
New Accounting Pronouncements -- In June 1998, the Financial Accounting
Standards Board (FASB) issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, which established standards for the
accounting and reporting of derivative financial instruments and hedging
F-9
181
AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
activities. The standard will be adopted by the Partnership during fiscal year
2001. The Partnership is currently evaluating the impact of the adoption of SFAS
No. 133.
3. ACQUISITION
On May 14, 1999, the Partnership's four Plants were acquired from NYSEG for
approximately $914 million. The Partnership acquired ownership of two of the
Plants, Westover (formerly known as Goudy) and Greenidge. The other two Plants,
Somerset and Cayuga, were acquired for $650 million by twelve unrelated
third-party owner trusts (collectively, the Owner Trusts) organized by three
unrelated institutional investors. Simultaneously, the Partnership entered into
separate leasing agreements for the Somerset and Cayuga Plants with the Owner
Trusts. The Partnership accounts for these leases as a financing (see Note 6).
The acquisition was financed by capital contributions from the General
Partner and the Limited Partner in an aggregate amount equal to the purchase
price for the Plants, certain associated costs and expenses, and certain amounts
for working capital less the net proceeds from the leasing transactions with
respect to the Somerset and Cayuga Plants described above. The acquisition has
been accounted for as an asset purchase.
In connection with the acquisition, NYSEG engaged an environmental
consulting firm to perform an environmental analysis of the potential required
remediations for soil and ground water contamination. The Partnership engaged
another environmental consulting firm to evaluate the costs estimated by NYSEG's
consultants. The environmental analysis and the Partnership's estimate of other
environmental remediation costs indicated that there existed a range of
potential remediation costs of between $8.5 million and $19.7 million, with a
most probable liability of approximately $12 million. The Partnership recorded
$12 million as an undiscounted liability under purchase accounting for the
projected remediation cost. As of September 30, 1999, $2 million was classified
as a current liability.
Also in connection with the acquisition, the General Partner entered into
an agreement for the construction of a selective catalytic reduction (SCR)
facility at the Somerset Plant. The SCR facility is designed to significantly
reduce the amount of nitrogen oxide emissions from the burning of coal fuel at
the Somerset Plant. The Partnership acquired the SCR work in progress from the
General Partner on May 14, 1999, for approximately $31 million, which was the
contract price for the SCR. Construction of this asset began prior to the
acquisition of the Plants. On the acquisition date, the Somerset Plant was shut
down to complete construction and make other improvements. The outage lasted
until late June 1999. All costs associated with the installation of the SCR,
including construction and engineering costs, wages of people involved in the
construction, and interest expense during the period were capitalized. The
Somerset Plant was placed back in service on June 28, 1999.
The Partnership receives certain payments for installed capacity under the
New York Transition Agreement (see Note 2). Payments received while the Somerset
Plant was out of service, of approximately $2.1 million, have reduced the total
amount of capitalized costs. Total costs capitalized during construction were
approximately $52 million, which included approximately $5.2 million in
capitalized interest.
The purchase agreement with NYSEG relating to the acquisition of the Plants
provided for a post-closing adjustment of the purchase price to reflect the
actual book value of inventories and a pro rata allocation of various expenses
as of the acquisition date. As a result of this adjustment and to settle other
contractual obligations, NYSEG returned approximately $1.6 million.
4. PARTNERSHIP AGREEMENT
The Partnership was capitalized with an initial contribution of $10 from
the General Partner and $990 from the Limited Partner. Subsequently, the General
Partner and the Limited Partner contributed $354 million to the Partnership (see
Note 5).
F-10
182
AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The General Partner is responsible for the day-to-day management of the
Partnership and its operations and affairs, and is responsible for all
liabilities and obligations of the Partnership. Under the terms of the
Partnership Agreement, the Limited Partner is not liable for any obligations,
liabilities, debts, or contracts of the Partnership and is only responsible to
make capital contributions when required under the Partnership Agreement.
All distributions, profits, and losses of the Partnership are allocated
among the partners based on their ownership interests, currently 1% for the
General Partner and 99% for the Limited Partner.
5. CAPITALIZATION
The Partnership is indirectly owned by AES New York Funding, L.L.C. (AES
Funding), which is a special purpose financing vehicle established to raise a
portion of the capital contributed to the Partnership through the General
Partner and the Limited Partner. AES Funding is a direct wholly owned subsidiary
of AES.
On May 11, 1999, AES Funding entered into a three-year loan agreement with
a syndicate of banks, with Morgan Guaranty Trust Company of New York as Agent,
in the amount of $300 million. AES Funding contributed 1% of this amount to the
General Partner and 99% of this amount to the Limited Partner which, in turn,
made an aggregate capital contribution of $300 million to the Partnership. AES
also contributed capital in the amount of approximately $54 million through AES
Funding, which subsequently contributed this amount to the General Partner and
the Limited Partner which, in turn, made a capital contribution of approximately
$54 million to the Partnership.
Collateral for the loan consists of a pledge of the membership interests of
AES New York Holdings, L.L.C., a direct wholly owned subsidiary of AES Funding,
which is the 100% direct owner of both the General Partner and the Limited
Partner.
AES Funding is dependent upon the residual cash flows from the Partnership
received in the form of dividends to service its debt. The loan is payable on
May 14, 2002, and bears interest at a variable rate based on the terms of the
loan agreement, which was 7.938% as of September 30, 1999. The Partnership has
no obligation to repay this loan. If AES Funding were unable to repay this loan,
one of the remedies available to the lenders would be to seek to sell the
membership interests in AES New York Holdings, L.L.C., which would divest AES of
control of the Partnership.
6. LEASE FINANCING
The Partnership's leases for the Somerset and Cayuga Plants are
accounted for as a financing (see Note 3). Minimum lease payments and the
present value of the lease obligation are as follows (in thousands):
LEASE
FISCAL YEARS ENDING DECEMBER 31, PAYMENTS
- -------------------------------- -----------
2000........................................................ $ 67,462
2001........................................................ 58,422
2002........................................................ 62,577
2003........................................................ 57,551
Thereafter.................................................. 1,499,122
-----------
Total minimum lease payments................................ 1,745,134
Less imputed interest....................................... (1,095,134)
-----------
Present value of minimum lease payments..................... $ 650,000
===========
F-11
183
AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Through January 2, 2017, and so long as no lease event of default exists, a
portion of the rent payable under each lease may be deferred until after the
final scheduled payment of the debt incurred by the Owner Trusts to acquire the
Somerset and Cayuga Plants.
The lease obligations are payable to the Owner Trusts. These obligations
bear imputed interest at 9.252% and 9.024% for the Somerset and Cayuga
facilities, respectively. Total assets under the leases of these two Plants were
$650 million at September 30, 1999. These amounts are included in electric
generation assets. The related accumulated depreciation, combined for both
leased facilities, as of September 30, 1999, was approximately $6.2 million.
The agreements governing the leases restrict the Partnership's ability to
incur additional indebtedness, engage in other businesses, sell its assets, or
merge with another entity. The ability of the Partnership to make distributions
to its partners is restricted unless certain covenants, including the
maintenance of certain coverage ratios, are met (see Note 12).
In connection with the lease agreements, the Partnership is required to
maintain an additional liquidity account. The required balance in the additional
liquidity account was initially equal to the greater of $65 million less the
balance in the rent reserve account on May 14, 1999 (see Note 2) or $29 million.
As of September 30, 1999, the Partnership had fulfilled its obligation to fund
the additional liquidity account by establishing a letter of credit, issued by
BankBoston, dated May 14, 1999, in the stated amount of approximately $36
million (the Additional Liquidity Letter of Credit). This letter of credit was
established by AES for the benefit of the Partnership. However, the Partnership
is obligated to replenish or replace this letter of credit in the event it is
drawn upon or needs to be replaced.
An aggregate amount in excess of $65 million is available to be drawn under
the Payment Undertaking Agreement (see Note 2) and the Additional Liquidity
Letter of Credit for making rental payments. In the event sufficient amounts to
make rental payments are not available from other sources, a withdrawal from the
additional liquidity account (which may include making a drawing under the
Additional Liquidity Letter of Credit) and from the rent reserve account (which
may include making a demand under the Payment Undertaking Agreement) may be made
for rental payments.
7. COMMITMENTS AND CONTINGENCIES
Coal Purchases -- In connection with the acquisition of the Plants, the
Partnership has assumed from NYSEG an agreement to purchase the coal required by
the Somerset, Cayuga, and Westover Plants. Each year, either party can request
renegotiation of the price of one-third of the coal supplied pursuant to this
agreement. During 2000, the coal suppliers are committed to sell and the
Partnership is committed to purchase all three lots of coal and either party may
request renegotiation of one lot of coal for the following year. If either party
requested renegotiation during 2000 but the parties failed to reach agreement,
then the parties would have commitments with respect to only two lots in 2001.
If the same thing happened in 2001, the parties would have commitments with
respect to only one lot in 2002. Either party could terminate the contract in
its sole discretion at the end of 2002. As of the acquisition date, the contract
prices were above the market price, and the Partnership recorded a purchase
accounting liability for approximately $15.7 million related to the fulfillment
of its obligation to purchase coal under this agreement. As of September 30,
1999, the remaining liability was approximately $14.1 million.
Transmission Agreements -- On August 3, 1998, the General Partner entered
into an agreement for the purpose of transferring certain rights and obligations
from NYSEG to the General Partner under an existing transmission agreement among
Niagara Mohawk Power Corporation (NIMO), the New York Power Authority, NYSEG,
and Rochester Gas & Electric Corporation, and an existing transmission agreement
between NYSEG and NIMO. This agreement provides for the assignment of rights to
transmit energy from the Somerset Plant and other sources to remote load areas
and other delivery points, and was assumed by the
F-12
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AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Partnership on the date of acquisition of the Plants. In accordance with its
plan, the Partnership discontinued using this service as of the acquisition
date. The Partnership does not intend to transmit over these lines and is
required to pay the current fees until the effective cancellation date, November
19, 1999. These fees are approximately $3.4 million over the six months ending
December 31, 1999, and have been recorded as a purchase accounting liability.
Because the Partnership is not using the lines, the Partnership receives no
economic benefit from this service subsequent to the acquisition date. As of
September 30, 1999, the remaining liability was approximately $2.3 million.
Environmental -- The Partnership has recorded a liability for environmental
remediation associated with the acquisition of the Plants (see Note 3). On an
ongoing basis, the Partnership monitors its compliance with environmental laws.
Because of the uncertainties associated with environmental compliance and
remediation activities, future costs of compliance or remediation could be
higher or lower than the amount currently accrued.
On October 14, 1999, the Partnership received an information request letter
from the New York Attorney General, which seeks detailed operating and
maintenance history for the Westover and Greenidge Plants. On January 13, 2000,
the Partnership received a subpoena from New York State Department of
Environmental Conservation seeking similar operating and maintenance history
from the Plants. This information is being sought in connection with the
Attorney General's and the Department of Environmental Conservation's
investigations of several electricity generating stations in New York that are
suspected of undertaking modifications in the past without undergoing an air
permitting review. If the Attorney General or the Department of Environmental
Conservation does file an enforcement action against the Somerset, Cayuga,
Westover, or Greenidge Plants, then penalties may be imposed and further
emission reductions might be necessary at these Plants. The Partnership is
unable to estimate the impact, if any, of these investigations on its financial
condition or results of future operations.
Nitrogen Oxide and Sulfur Dioxide Emission Allowances -- The Plants emit
nitrogen oxide (NOx) and sulfur dioxide (SO2) as a result of burning coal to
produce electricity. The four Plants have been allocated allowances by the New
York Department of Environmental Conservation to emit NOx during the ozone
season, which runs from May 1 to September 30. Each NOx allowance authorizes the
emission of one ton of NOx during the ozone season. The four Plants are also
subject to SO2 emission allowance requirements imposed by the Federal
Environmental Protection Agency. Each SO2 allowance authorizes the emission of
one ton of SO2 during the calendar year. Two of the Plants, Cayuga and Westover,
are currently subject to SO2 allowance requirements, and starting January 1,
2000, all four Plants will be required to hold sufficient allowances to emit
SO2. Both NOx and SO2 allowances may be bought, sold, or traded. If NOx and/or
SO2 emissions exceed the allowance amounts allocated to the four Plants, then
the Partnership may need to purchase additional allowances on the open market or
otherwise reduce its production of electricity to stay within the allocated
amounts.
Other -- The Partnership is currently being sued by NYSEG for allegedly
refusing to cooperate in NYSEG's efforts to perform an appraisal of the Somerset
Plant. Management believes that NYSEG desires to perform this appraisal in
connection with the proceeding that NYSEG has brought to obtain a refund of real
estate taxes it paid in connection with the Somerset Plant while NYSEG owned it.
If NYSEG is successful in obtaining substantial refunds of prior real estate
taxes, potential savings to the Partnership may be to some extent nullified
because the local governments may be forced to raise real estate tax rates to
bring revenues into balance with expenditures. It is too early to tell what
impact, if any, this will have on the Partnership's financial condition and
results of future operations.
8. RELATED PARTY TRANSACTIONS
The Partnership has entered into a contract with Somerset Railroad
Corporation (SRC), a wholly owned subsidiary of AES New York 3, L.L.C., which is
an indirect wholly owned subsidiary of AES, pursuant to
F-13
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AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
which SRC will haul coal and limestone to the Somerset Plant and make its rail
cars available to transport coal to the Cayuga Plant. The Partnership will pay
amounts sufficient to enable SRC to pay all of its operating and other expenses,
including all out-of-pocket expenses, taxes, interest on and principal of SRC's
outstanding indebtedness, and all capital expenditures necessary to permit SRC
to continue to provide rail service to the Somerset and Cayuga Plants. The
principal on SRC's outstanding indebtedness is approximately $26 million as of
September 30, 1999, and is due on May 12, 2000. This term loan bears interest at
a rate per annum equal to LIBOR plus 1.35% or a base rate plus 1.25%. SRC
intends to refinance this indebtedness prior to the due date. As of September
30, 1999, approximately $1.2 million has been recorded by the Partnership as
operating expenses and other accrued liabilities under this agreement.
Prior to June 30, 1999, AES paid approximately $3.2 million in costs
related to the acquisition of the NYSEG plants, which are to be reimbursed by
the Partnership. Of the $3.2 million, approximately $1.1 million was for
internal costs incurred by AES, and was treated as a reduction of contributed
capital.
9. BENEFIT PLANS
Effective May 14, 1999, the Partnership adopted The Retirement Plan for
Employees of AES New York, L.L.C. (the Plan), a defined benefit pension plan.
The Plan covers people employed both under collectively bargained and
noncollectively bargained arrangements. Certain people formerly employed by
NYSEG (the Transferred Persons) receive credit under the Plan for compensation
and service earned while employed by NYSEG. The amount of any benefit payable
under the Plan to a Transferred Person will be offset by the amount of any
benefit payable to such Transferred Person under the Retirement Plan for
Employees of New York State Electric & Gas. Effective May 29, 1999, the ability
to commence participation in the Plan and the accrual of benefits under the Plan
ceased with respect to non-collectively bargained people and the accrued
benefits of any such participant was fixed as of such date. As of September 30,
1999, the Plan was completely unfunded. The Partnership will make the required
minimum contribution within the Employee Retirement Income Security Act (ERISA)
guidelines, which require a minimum contribution to the Plan by September 15,
2000. Pension benefits are based on years of credited service, age of the
participant, and average earnings.
Significant assumptions used in the calculations of the net benefit cost
and projected benefit obligation are as follows:
Discount rate............................................... 6.25%
Rate of compensation increase............................... 4.75%
Expected long-term rate of return on plan assets............ 8.00%
Net benefit cost for the period ended September 30, 1999, includes the
following components (in thousands):
Service cost................................................ $ 292
Interest cost on projected benefit obligation............... 532
-------
Net benefit cost............................................ $ 824
=======
Change in projected benefit obligation (in thousands):
Projected benefit obligation at May 14, 1999................ $22,503
Service cost................................................ 292
Interest cost............................................... 532
-------
Projected benefit obligation as of September 30, 1999....... $23,327
=======
F-14
186
AES EASTERN ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The projected benefit obligation of the Plan as of May 14, 1999, as
actuarially determined, was recorded by the Partnership as a purchase accounting
liability (see Note 3) under Accounting Principles Board Opinion (APB) No. 16,
Business Combinations.
Additionally, people of the Partnership and its subsidiaries participate in
the AES Profit Sharing and Stock Ownership Plans. The plans provide Partnership
matching contributions. Participants are fully vested in their own contributions
and the Partnership's matching contributions.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of the Partnership's current financial assets and
liabilities approximate their carrying values. The fair value estimates are
based on pertinent information available as of September 30, 1999. The
Partnership is not aware of any factors that would significantly affect the
estimated fair value amounts since that date.
11. SEGMENT INFORMATION
Under the provisions of SFAS No. 131, Disclosures About Segments of an
Enterprise and Related Information, the Partnership's business is expected to be
operated as one reportable segment, with operating income or loss being the
measure of performance measured by the chief operating decision-maker.
12. RESTRICTIONS ON DISTRIBUTIONS TO PARTNERS
The Partnership's ability to make distributions to its partners is
restricted by the terms of the agreements governing the leases of the Somerset
and Cayuga Plants. The Partnership may make a distribution to its partners only
on or within five business days after a semiannual rent payment date (commencing
with the rent payment date occurring on July 2, 2000), so long as the conditions
as specified in the agreements have been met. As of September 30, 1999, no
distributions have been made (see Note 6).
* * * * * *
F-15
187
INDEPENDENT AUDITORS' REPORT
To the Member of
AES New York, L.L.C.
We have audited the accompanying consolidated balance sheet of AES New
York, L.L.C. (an indirect wholly owned subsidiary of The AES Corporation) and
subsidiaries (the Company) as of September 30, 1999. This financial statement is
the responsibility of the Company's management. Our responsibility is to express
an opinion on this financial statement 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 statement is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statement. 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, such consolidated financial statement presents fairly, in
all material respects, the financial position of AES New York, L.L.C. and
subsidiaries as of September 30, 1999, in conformity with generally accepted
accounting principles.
/s/ DELOITTE & TOUCHE LLP
McLean, Virginia
January 18, 2000
F-16
188
AES NEW YORK, L.L.C.
CONSOLIDATED BALANCE SHEET
SEPTEMBER 30, 1999
(AMOUNTS IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Restricted cash:
Operating -- cash and cash equivalents................. $ 13,516
Revenue account........................................ 19,953
Accounts receivable -- trade.............................. 56,128
Inventory................................................. 24,000
Prepaid expenses.......................................... 12,407
----------
Total current assets.............................. 126,004
----------
PROPERTY, PLANT, EQUIPMENT, AND RELATED ASSETS:
Land...................................................... 7,353
Electric generation assets (net of accumulated
depreciation of $11,033)............................... 994,451
----------
Total property, plant, equipment, and related
assets............................................ 1,001,804
----------
OTHER ASSETS:
Rent reserve account...................................... 29,188
----------
TOTAL ASSETS...................................... $1,156,996
==========
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES:
Accounts payable.......................................... $ 11,549
Accrued interest expense.................................. 23,208
Due to The AES Corporation................................ 3,190
Other accrued expenses.................................... 22,764
Other liabilities......................................... 10,983
----------
Total current liabilities......................... 71,694
----------
LONG-TERM LIABILITIES:
Lease financing -- long-term.............................. 650,000
Environmental remediation................................. 12,757
Defined benefit plan obligation........................... 27,445
Due to other affiliates................................... 760
Other liabilities......................................... 7,392
----------
Total long-term liabilities....................... 698,354
----------
TOTAL LIABILITIES........................................... 770,048
MINORITY INTEREST........................................... 383,079
MEMBER'S EQUITY............................................. 3,869
----------
TOTAL LIABILITIES AND MEMBER'S EQUITY....................... $1,156,996
==========
The balance sheet of AES New York, L.L.C. contained in this prospectus
should be considered only in connection with its status as the general partner
of AES Eastern Energy, L.P. The pass through trust certificates do not represent
an interest in or an obligation of AES New York, L.L.C.
See notes to consolidated balance sheet.
F-17
189
AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET
1. GENERAL
AES New York, L.L.C. (the Company), a Delaware limited liability company,
was formed on August 2, 1998. The Company is the sole general partner of AES
Eastern Energy, L.P. (AEE), owning a one percent interest in AEE. The Company is
also the sole general partner of AES Creative Resources, L.P. (ACR), owning a
one percent interest in ACR. AES New York Holdings, L.L.C. is the sole member of
the Company. The Company is an indirect wholly owned subsidiary of The AES
Corporation (AES). The Company began operations on May 14, 1999. Prior to that
date, the Company had no operations.
The Company was established for the purpose of acting as the general
partner of both AEE and ACR. In this capacity, the Company is responsible for
the day-to-day management of AEE and ACR and its operations and affairs, and is
responsible for all liabilities and obligations of both entities.
AEE, a Delaware limited partnership, was formed on December 2, 1998. AEE's
wholly owned subsidiaries are AES Somerset, L.L.C., AES Cayuga, L.L.C., and
AEE2, L.L.C., (which wholly owns AES Westover, L.L.C. and AES Greenidge,
L.L.C.). AEE began operations on May 14, 1999. Prior to that date, AEE had no
operations. AEE was established for the purpose of owning and operating four
coal-fired electric generating stations (the AEE Plants) with a total combined
capacity of 1,268 MW. Two of the plants are owned by AEE and two of the plants
are leased by AEE (see Note 5), and are operated by AEE's wholly owned
subsidiaries in the state of New York, pursuant to operation and maintenance
agreements with AEE. The limited partner of AEE is AES New York 2, L.L.C. (the
Limited Partner), which is also an indirect wholly owned subsidiary of AES.
ACR, a Delaware limited partnership, was formed on December 3, 1998. ACR's
wholly owned subsidiaries are AES Jennison, L.L.C. and AES Hickling, L.L.C.,
which each own a coal-fired electric generating station (the ACR Plants) with a
combined capacity of 156 MW. ACR began operations on May 14, 1999. Prior to that
date ACR had no operations. The limited partner of ACR is AES New York 2. The
AEE Plants and the ACR Plants are hereinafter referred to collectively as "the
Plants."
AEE and ACR have entered into two-year agreements for energy marketing
services with Merchant Energy Group of the Americas, Inc. (MEGA), an Annapolis,
Maryland-based subsidiary of Gener S.A., a Chilean independent power producer.
MEGA is responsible for marketing AEE's and ACR's electric energy, installed
capacity, and ancillary services.
The Plants sell generated electricity, as well as installed capacity and
ancillary services, directly into the New York Power Pool (NYPP), Pennsylvania,
New Jersey, Maryland Power Pool (PJM), and New England Power Pool (NEPOOL). For
Federal regulatory purposes, AEE and ACR are exempt wholesale generators (EWGs).
As EWGs, AEE and ACR cannot make retail sales of electricity. AEE and ACR can
only make wholesale sales of electricity, installed capacity, and ancillary
services into wholesale power markets, or through direct sales to third parties
at negotiated prices.
2. SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The consolidated financial statement
includes the accounts of the Company, AEE and ACR (including all subsidiaries).
The financial statement is presented on a consolidated basis because the
Company, as general partner, controls the operations of AEE and ACR (Note 1).
All material intercompany transactions have been eliminated. The 99% limited
partner ownerships of AEE and ACR are presented as minority interest.
The assets of the Company on a stand-alone basis at September 30, 1999
(using the equity method of accounting) consist only of the 1% ownership
interest in AEE ($3,836,000) and the 1% ownership interest in ACR ($33,000). The
Company has no liabilities as of September 30, 1999.
F-18
190
AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET -- (CONTINUED)
Cash and Cash Equivalents -- The Company considers unrestricted cash on
hand, deposits in banks, and short-term marketable securities with original
maturities of three months or less in operating accounts to be cash and cash
equivalents.
Restricted Cash -- Under the terms of the deposit and disbursement
agreement entered into by AEE in connection with the lease of two AEE Plants
(see Note 5), all revenues of AEE and its subsidiaries are deposited into a
revenue account administered by the depositary agent. On request of AEE and in
accordance with the terms of the deposit and disbursement agreement, funds are
transferred from the revenue account to other operating accounts administered by
the depositary agent for payment of operating and maintenance costs, lease
obligations, debt service, reserve requirements and distributions. Payment of
operating and maintenance costs (other than actual fuel costs) in excess of 125%
of the annual operating budget require confirmation from an independent engineer
that such payment is based on reasonable assumptions.
Inventory -- Inventory, valued at fair market value on the date of
acquisition (see Note 3), and subsequently valued at the lower of cost (average
cost basis) or market, consists of coal and other raw materials used in
generating electricity, spare parts, materials, and supplies.
Inventory, as of September 30, 1999, consisted of the following (in
thousands):
Coal and other raw materials................................ $ 6,174
Spare parts, materials, and supplies........................ 17,826
-------
Total....................................................... $24,000
=======
Property, Plant, Equipment, and Related Assets -- Electric generation
assets that existed at the date of acquisition (see Note 3) are recorded at fair
market value. The AEE Somerset (formerly known as Kintigh) and AEE Cayuga
(formerly known as Milliken) Plants, which represent $650 million of the
electric generation assets, are subject to a leasing arrangement accounted for
as a financing (see Note 5). Additions or improvements thereafter are recorded
at cost. Depreciation is computed using the straight-line method over the
34-year and 28-year lease terms for the Somerset and Cayuga Plants,
respectively, and over the estimated useful lives for the other AEE fixed
assets, which range from 7 to 35 years. Maintenance and repairs are charged to
expense as incurred.
Management of ACR intends to dispose of or shut down the AES Jennison and
AES Hickling plants within the next three years. As such, the electric
generation assets of these two plants are being depreciated over three years
using the straight-line method. Maintenance and repairs are charged to expense
as incurred.
Electric generation assets as of September 30, 1999, consisted of the
following (in thousands):
AEE ACR TOTAL
-------- ------- --------
Electric generation tangible assets......... $760,280 $ 5,053 $765,333
Other intangible assets..................... 240,151 -- 240,151
Accumulated depreciation.................... (9,818) (1,215) (11,033)
-------- ------- --------
Total....................................... $990,613 $ 3,838 $994,451
======== ======= ========
Other intangible assets represent assets recorded by AEE that were
identified and valued in an independent appraisal and that are directly related
to the physical assets of the AEE Plants. These include trading benefits derived
from the ability of AEE to enter new deregulated markets through sale of the
output of the AEE Plants, potential revenues from ancillary services, and
mitigation of environmental risk due to the advanced emissions control equipment
that has already been installed at the principal AEE Plants. Trading benefits
provide both the AEE Plants and AEE the ability to arbitrage electricity
generation and installed capacity in order to capture the most lucrative prices
in available markets. Ancillary services include voltage
F-19
191
AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET -- (CONTINUED)
support, spinning reserves, and other activities that enhance the stability and
reliability of the transmission system. These services will be purchased by the
organizations that manage power systems rather than wholesale electricity
customers. Mitigation of environmental risk reflects AEE's ability, created by
pollution control devices, to effectively use lower cost and lower grade coal to
provide the same electricity output as its competitors. Amortization is computed
on the same basis as the related assets (28 to 34 years).
Rent Reserve Account -- As part of AEE's lease obligation (see Note 5), AEE
is required to maintain a rent reserve account equal to the maximum semiannual
payment with respect to the sum of basic rent (other than deferrable payments)
and fixed charges expected to become due on any one basic rent payment date in
the immediately succeeding three-year period. As of September 30, 1999, AEE had
fulfilled this obligation by entering into a Payment Undertaking Agreement,
dated as of May 1, 1999, among AEE, each Owner Trust (see Note 3) and Morgan
Guaranty Trust Company of New York (the Payment Undertaking Agreement). On May
14, 1999, AEE deposited with Morgan Guaranty Trust Company of New York
approximately $28.7 million pursuant to the Payment Undertaking Agreement. The
accreted value of the Payment Undertaking Agreement at any time includes
interest earned thereunder at an interest rate of 4.79% per annum. Interest
earnings as of September 30, 1999, were approximately $515,000 and are included
in the rent reserve account balance. At September 30, 1999, the accreted value
of the Payment Undertaking Agreement exceeded the required balance of the rent
reserve account. This amount is being accounted for as a restricted cash balance
and is included within the rent reserve account on the accompanying balance
sheet as it can only be utilized to satisfy lease obligations.
In the future, AEE may fulfill its obligation to maintain the required
balance of the rent reserve account either by deposits into the rent reserve
account or by making amounts available under the Payment Undertaking Agreement,
such that the aggregate amount of such deposits in the rent reserve account and
amounts available to be paid under the Payment Undertaking Agreement are equal
to the required balance of the rent reserve account.
Line of Credit Agreement -- AEE has established a three-year revolving
working capital credit facility of up to $50 million for the purpose of making
funds available to pay for certain operating and maintenance costs. Amounts
outstanding under the working capital facility are required to be reduced to
zero for thirty days prior to any one lease rental payment date in each year.
Interest accrues on outstanding balances at a base rate plus 1% or the
applicable adjusted Eurodollar rate plus 1.75%. The working capital credit
facility is collateralized by a pledge of AEE's membership interest in AEE2,
L.L.C. and by a security interest in equipment and personal property of AEE2,
L.L.C. As of September 30, 1999, no amounts were outstanding under this credit
facility.
Revenue Recognition -- Revenues from the sale of electricity are recorded
based upon output delivered and rates specified under contract terms. Revenues
for ancillary and other services are recorded when the services are rendered.
New York Transition Agreement -- As the NYPP represents a deregulated
environment, the Independent System Operator (ISO) of the NYPP will attempt to
ensure stability of the power grid in New York by requiring each entity engaged
in retail sales of electricity to obtain installed capacity commitments from
generators in an amount equal to the entity's forecasted peak load plus a
reserve margin. This requirement is intended to ensure that an adequate supply
of electricity is always available. The Company entered into a two-year
transition agreement with NYSEG pursuant to which AEE and ACR will sell their
installed capacity to NYSEG in order to permit NYSEG to comply with ISO
standards for system stability. The transition agreement was assumed by AEE and
ACR on the date of acquisition of the AEE and the ACR Plants. The Company
recognizes revenue under this contract as it is earned, which is $68 per MW per
day for installed capacity made available.
F-20
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AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET -- (CONTINUED)
Income Taxes -- A provision for Federal and state income taxes has not been
made in the accompanying financial statements since the Company, AEE and ACR do
not pay income taxes but rather allocate their revenues and expenses to the
member or partners. Differences between the results of operations reported in
the financial statements and those reported on individual partners' or member's
income tax returns are due primarily to the use of different lease treatment,
accelerated depreciation methods, and shorter useful lives for income tax
purposes.
Use of Estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles requires the Company to make
estimates and assumptions that affect reported amounts of assets and liabilities
and disclosures of contingent assets and liabilities at the date of the
financial statements, as well as the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Fiscal Year-End -- The Company's fiscal year will end on December 31 of
each year.
Comprehensive Income -- In 1999 the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 130, Reporting Comprehensive Income, which
establishes rules for the reporting of comprehensive income and its components.
The adoption of SFAS No. 130 had no impact on the Company's financial statements
as it had no items of other comprehensive income.
New Accounting Pronouncements -- In June 1998, the Financial Accounting
Standards Board (FASB) issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, which established standards for the
accounting and reporting of derivative financial instruments and hedging
activities. The standard will be adopted by the Company during fiscal year 2001.
The Company is currently evaluating the impact of the adoption of SFAS No. 133.
3. ACQUISITION
On May 14, 1999, the AEE Plants were acquired from New York State Electric
& Gas Corporation (NYSEG) for approximately $914 million. AEE acquired ownership
of two of the Plants, Westover (formerly known as Goudy) and Greenidge. The
other two Plants, Somerset and Cayuga, were acquired for $650 million by twelve
unrelated third-party owner trusts (collectively, the Owner Trusts) organized by
three unrelated institutional investors. Simultaneously, AEE entered into
separate leasing agreements for the Somerset and Cayuga Plants with the Owner
Trusts. The Company accounts for these leases as financing leases.
The acquisition of the AEE Plants was financed by capital contributions
from the Company and the Limited Partner in an aggregate amount equal to the
purchase price for the Plants, certain associated costs and expenses, and
certain amounts for working capital less the net proceeds from the leasing
transactions with respect to the Somerset and Cayuga Plants described above. The
acquisition has been accounted for as an asset purchase.
In connection with the acquisition of the AEE Plants, NYSEG engaged an
environmental consulting firm to perform an environmental analysis of the
potential required remediations for soil and ground water contamination. AEE
engaged another environmental consulting firm to evaluate the costs estimated by
NYSEG's consultants. The environmental analysis and AEE's estimate of other
environmental remediation costs indicated that there existed a range of
potential remediation costs of between $8.5 million and $19.7 million, with a
most probable liability of approximately $12 million. AEE has recorded $12
million as an undiscounted liability under purchase accounting for the projected
remediation cost. As of September 30, 1999, $2 million was classified as a
current liability.
Also in connection with the acquisition, the Company entered into an
agreement for the construction of a selective catalytic reduction (SCR) facility
at the Somerset Plant. The SCR facility is designed to significantly reduce the
amount of nitrogen oxide emissions from the burning of coal fuel at the Somerset
F-21
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AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET -- (CONTINUED)
Plant. AEE acquired the SCR work in progress from the Company on May 14, 1999,
for approximately $31 million, which was the contract price for the SCR.
Construction of this asset began prior to the acquisition of the AEE Plants. On
the acquisition date, the Somerset Plant was shut down to complete construction
and make other improvements. The outage lasted until late June 1999. All costs
associated with the installation of the SCR, including construction and
engineering costs, wages of people involved in the construction, and interest
expense during the period were capitalized by AEE. The Somerset Plant was placed
back in service on June 28, 1999.
AEE receives certain payments for installed capacity under the New York
Transition Agreement (see Note 2). Payments received while the Somerset Plant
was out of service, of approximately $2.1 million, have reduced the total amount
of capitalized costs. Total costs capitalized during construction were
approximately $52 million, which included approximately $5.2 million in
capitalized interest.
The purchase agreement with NYSEG relating to the acquisition of the AEE
Plants provided for a post-closing adjustment of the purchase price to reflect
the actual book value of inventories and a pro rata allocation of various
expenses as of the acquisition date. As a result of this adjustment and to
settle other contractual obligations, NYSEG returned approximately $1.6 million.
Also, in connection with this transaction, ACR acquired from NYSEG two
older coal-fired plants, Jennison and Hickling (Note 1). An environmental
liability of $2.6 million was recorded in connection with this acquisition.
4. CAPITALIZATION
The Company is indirectly owned by AES New York Funding, L.L.C. (AES
Funding), which is a special purpose financing vehicle established to raise a
portion of the capital contributed to AEE and ACR through the Company and AES
New York 2, L.L.C., the limited partner of AEE and ACR. AES Funding is a direct
wholly owned subsidiary of AES.
On May 11, 1999, AES Funding entered into a three-year loan agreement with
a syndicate of banks, with Morgan Guaranty Trust Company of New York as Agent,
in the amount of $300 million. AES Funding contributed 1% of this amount to the
Company and 99% of this amount to AES New York 2 which, in turn, made an
aggregate capital contribution of $300 million to AEE. AES also contributed
capital in the amount of approximately $57 million through AES Funding, which
subsequently contributed this amount to the Company and AES New York 2 which, in
turn, made a capital contribution of approximately $54 million to AEE and
approximately $3 million to ACR.
Collateral for the loan consists of a pledge of the membership interests of
AES New York Holdings, L.L.C., a direct wholly owned subsidiary of AES Funding,
which is the 100% direct owner of both the Company and AES New York 2, L.L.C.
AES Funding is dependent upon the residual cash flows from AEE and ACR
received in the form of dividends to service its debt. The loan is payable on
May 14, 2002, and bears interest at a variable rate based on the terms of the
loan agreement, which was 7.938% as of September 30, 1999. AEE has no obligation
to repay this loan. If AES Funding were unable to repay this loan, one of the
remedies available to the lenders would be to seek to sell the membership
interests in AES New York Holdings, L.L.C., which would divest AES of control of
the Company, AEE, and ACR.
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AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET -- (CONTINUED)
5. LEASE FINANCING
AEE's leases for the Somerset and Cayuga Plants are accounted for as a
financing (see Note 3). Minimum lease payments and the present value of the
lease obligation are as follows (in thousands):
LEASE
FISCAL YEARS ENDING DECEMBER 31, PAYMENTS
- -------------------------------- -----------
2000........................................................ $ 67,462
2001........................................................ 58,422
2002........................................................ 62,577
2003........................................................ 57,551
Thereafter.................................................. 1,499,122
-----------
Total minimum lease payments................................ 1,745,134
Less imputed interest....................................... (1,095,134)
-----------
Present value of minimum lease payments..................... $ 650,000
===========
Through January 2, 2017, and so long as no lease event of default exists, a
portion of the rent payable under each lease may be deferred until after the
final scheduled payment of the debt incurred by the Owner Trusts to acquire the
Somerset and Cayuga Plants.
The lease obligations are payable to the Owner Trusts. These obligations
bear imputed interest at 9.252% and 9.024% for the Somerset and Cayuga
facilities, respectively. Total assets under the leases of these two Plants were
$650 million at September 30, 1999. These amounts are included in electric
generation assets. The related accumulated depreciation, combined for both
leased facilities, as of September 30, 1999, was approximately $6.2 million.
The agreements governing the leases restrict AEE's ability to incur
additional indebtedness, engage in other businesses, sell its assets, or merge
with another entity.
AEE's ability to make distributions to its partners is restricted by the
terms of the agreements governing the leases of the AEE Somerset and Cayuga
Plants. The ability of AEE to make distributions to its partners is restricted
unless certain covenants, including the maintenance of certain coverage ratios,
are met. In addition, AEE may make a distribution to its partners only on or
within five business days after a semiannual rent payment date (commencing with
the rent payment date occurring on July 2, 2000) so long as the conditions as
specified in the agreements have been met. As of September 30, 1999, no
distributions have been made.
In connection with the lease agreements, AEE is required to maintain an
additional liquidity account. The required balance in the additional liquidity
account was initially equal to the greater of $65 million less the balance in
the rent reserve account on May 14, 1999 (see Note 2) or $29 million. As of
September 30, 1999, AEE had fulfilled its obligation to fund the additional
liquidity account by establishing a letter of credit, issued by BankBoston,
dated May 14, 1999, in the stated amount of approximately $36 million (the
Additional Liquidity Letter of Credit). This letter of credit was established by
AES for the benefit of AEE. However, AEE is obligated to replenish or replace
this letter of credit in the event it is drawn upon or needs to be replaced.
An aggregate amount in excess of $65 million is available to be drawn under
the Payment Undertaking Agreement (see Note 2) and the Additional Liquidity
Letter of Credit for making rental payments. In the event sufficient amounts to
make rental payments are not available from other sources, a withdrawal from the
additional liquidity account (which may include making a drawing under the
Additional Liquidity Letter of Credit) and from the rent reserve account (which
may include making a demand under the Payment Undertaking Agreement) may be made
for rental payments.
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AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET -- (CONTINUED)
6. COMMITMENTS AND CONTINGENCIES
Coal Purchases -- In connection with the acquisition of the AEE Plants, AEE
has assumed from NYSEG an agreement to purchase the coal required by the AEE
Somerset , Cayuga, and Westover plants. Each year, either party can request
renegotiation of the price of one-third of the coal supplied pursuant to this
agreement. During 2000, the coal suppliers are committed to sell and AEE is
committed to purchase all three lots of coal and either party may request
renegotiation of one lot of coal for the following year. If either party
requested renegotiation during 2000 but the parties failed to reach agreement,
then the parties would have commitments with respect to only two lots in 2001.
If the same thing happened in 2001, the parties would have commitments with
respect to only one lot in 2002. Either party could terminate the contract in
its sole discretion at the end of 2002. As of the acquisition date, the contract
prices were above the market price, and AEE recorded a purchase accounting
liability for approximately $15.7 million related to the fulfillment of its
obligation to purchase coal under this agreement. As of September 30, 1999, the
remaining liability was approximately $14.1 million.
Transmission Agreements -- On August 3, 1998, the Company entered into an
agreement for the purpose of transferring certain rights and obligations from
NYSEG to the Company under an existing transmission agreement among Niagara
Mohawk Power Corporation (NIMO), the New York Power Authority, NYSEG, and
Rochester Gas & Electric Corporation, and an existing transmission agreement
between NYSEG and NIMO. This agreement provides for the assignment of rights to
transmit energy from the Somerset Plant and other sources to remote load areas
and other delivery points, and was assumed by AEE on the date of acquisition of
the AEE Plants. As of the acquisition date, AEE elected to convert, effective as
of November 19, 1999, its service from firm to nonfirm transmission in
accordance with the provisions of this agreement. AEE does not intend to
transmit over firm lines and is required to pay the current fees until the
effective cancellation date, November 19, 1999. These fees are approximately
$3.4 million over the six months ending December 31, 1999, and have been
recorded as a purchase accounting liability. As of September 30, 1999, the
remaining liability was approximately $2.3 million.
Environmental -- The Company has recorded a liability for environmental
remediation associated with the acquisition of the AEE Plants and the ACR Plants
(see Note 3). On an ongoing basis, the Company monitors its compliance with
environmental laws. Because of the uncertainties associated with environmental
compliance and remediation activities, future costs of compliance or remediation
could be higher or lower than the amount currently accrued.
On October 14, 1999, AEE received an information request letter from the
New York Attorney General, which seeks detailed operating and maintenance
history for the Westover and Greenidge Plants. On January 13, 2000, the Company
received a subpoena from the New York State Department of Environmental
Conservation seeking similar operating and maintenance history from the AEE and
ACR Plants. This information is being sought in connection with the Attorney
General's and the Department of Environmental Conservation's investigations of
several electricity generating stations in New York that are suspected of
undertaking modifications in the past without undergoing an air permitting
review. If the Attorney General or the Department of Environmental Conservation
does file an enforcement action against the Somerset, Cayuga, Westover, or
Greenidge Plants, then penalties might be imposed and further emission
reductions may be necessary at these Plants. The Company is unable to estimate
the impact, if any, of these investigations on its financial condition or
results of operations.
Nitrogen Oxide and Sulfur Dioxide Emission Allowances -- AEE Plants and the
ACR Plants emit nitrogen oxide (NO(x)) and sulfur dioxide (SO(2)) as a result of
burning coal to produce electricity. The six Plants have been allocated
allowances by the New York Department of Environmental Conservation to emit
NO(x) during the ozone season, which runs from May 1 to September 30. Each NO(x)
allowance authorizes the emission of one ton of NO(x) during the ozone season.
The six Plants are also subject to SO(2) emission allowance requirements imposed
by the Federal Environmental Protection Agency. Each SO(2) allowance authorizes
the
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AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET -- (CONTINUED)
emission of one ton of SO(2) during the calendar year. Two of the Plants, Cayuga
and Westover, are currently subject to SO(2) allowance requirements, and
starting January 1, 2000, all six Plants will be required to hold sufficient
allowances to emit SO(2). Both NO(x) and SO(2) allowances may be bought, sold,
or traded. If NO(x) and/or SO(2) emissions exceed the allowance amounts
allocated to the six Plants, then the Company may need to purchase additional
allowances on the open market or otherwise reduce its production of electricity
to stay within the allocated amounts.
Other -- AEE is currently being sued by NYSEG for allegedly refusing to
cooperate in NYSEG's efforts to perform an appraisal of the Somerset Plant.
Management believes that NYSEG desires to perform this appraisal in connection
with the proceeding that NYSEG has brought to obtain a refund of real estate
taxes it paid in connection with the Somerset Plant while NYSEG owned it. If
NYSEG is successful in obtaining substantial refunds of prior real estate taxes,
potential savings to AEE may to some extent be nullified because the local
governments may be forced to raise real estate tax rates to bring revenues into
balance with expenditures. It is too early to tell what impact, if any, this
will have on AEE's financial condition and results of future operations.
ACR assumed from NYSEG responsibility for asbestos-related personal injury
lawsuits in which plaintiffs claim they were exposed to asbestos while employed
by independent contractors providing services at the electricity generating
stations acquired from NYSEG. As of December 1, 1999, 24 of these lawsuits were
pending. While management and legal counsel cannot quantify the potential
liability arising from these suits given the early stage of the proceedings and
the large number of named defendants, the plaintiffs have claimed substantial
compensatory and punitive damages. The Company and AES New York 2, L.L.C., have
guaranteed the obligations of ACR. If ACR, as NYSEG's successor, is held
responsible for all or a substantial part of any judgments granted to the
plaintiffs and not covered under liability insurance, such amounts could be
material and could require the Company and AES New York 2, L.L.C., to satisfy
these judgments as grantors. The Company cannot predict the outcome of these
pending proceedings.
In October 1999, ACR entered into a consent order with the New York State
Department of Environmental Conservation to resolve alleged violations of the
water quality standards in the groundwater downgradient of an ash disposal site.
The consent order includes a suspended $5,000 civil penalty and a requirement to
submit a work plan to initiate closure of the landfill by October 8, 2000. The
consent order also calls for a site investigation and there is a possibility
that some groundwater remediation at the site may be required. AEE2, L.L.C. will
contribute two-thirds of the costs to close the landfill, which are anticipated
to be approximately $3 million, as additional costs for long term groundwater
monitoring. While the actual closure costs may exceed $3 million, which is
included in the environmental remediation liability (see Note 3), management
does not expect any added closure costs to be material.
7. RELATED PARTY TRANSACTIONS
AEE has entered into a contract with Somerset Railroad Corporation (SRC), a
wholly owned subsidiary of AES New York 3, L.L.C., which is an indirect wholly
owned subsidiary of AES, pursuant to which SRC will haul coal and limestone to
the Somerset Plant and make its rail cars available to transport coal to the
Cayuga Plant. AEE will pay amounts sufficient to enable SRC to pay all of its
operating and other expenses, including all out-of-pocket expenses, taxes,
interest on and principal of SRC's outstanding indebtedness, and all capital
expenditures necessary to permit SRC to continue to provide rail service to the
Somerset and Cayuga Plants. The principal on SRC's outstanding indebtedness is
approximately $26 million as of September 30, 1999, and is due on May 12, 2000.
This term loan bears interest at a rate per annum equal to LIBOR plus 1.35% or a
base rate plus 1.25%. SRC intends to refinance this indebtedness prior to the
due date. As of September 30, 1999, approximately $1.2 million in expenses
relating to this agreement is recorded by AEE within other accrued expenses.
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AES NEW YORK, L.L.C.
NOTES TO CONSOLIDATED BALANCE SHEET -- (CONTINUED)
Prior to June 30, 1999, AES paid approximately $3.2 million in costs
related to the acquisition of the NYSEG plants, which are to be reimbursed by
AEE. Of the $3.2 million, approximately $1.1 million was for internal costs
incurred by AES, and was treated as a reduction of contributed capital.
8. BENEFIT PLANS
Effective May 14, 1999, the Company and its subsidiaries adopted The
Retirement Plan for Employees of AES New York, L.L.C. (the Plan), a defined
benefit pension plan. The Plan covers people employed both under collectively
bargained and noncollectively bargained arrangements. Certain people formerly
employed by NYSEG (the Transferred Persons) receive credit under the Plan for
compensation and service earned while employed by NYSEG. The amount of any
benefit payable under the Plan to a Transferred Person will be offset by the
amount of any benefit payable to such Transferred Person under the Retirement
Plan for Employees of New York State Electric & Gas. Effective May 29, 1999, the
ability to commence participation in the Plan and the accrual of benefits under
the Plan ceased with respect to non-collectively bargained people and the
accrued benefits of any such participant was fixed as of such date. As of
September 30, 1999, the Plan was completely unfunded. The Company will make the
required minimum contribution within the Employee Retirement Income Security Act
(ERISA) guidelines, which require a minimum contribution to the Plan by
September 15, 2000. Pension benefits are based on years of credited service, age
of the participant, and average earnings.
Significant assumptions used in the calculations of projected benefit
obligation are as follows:
Discount rate............................................... 6.25%
Rate of compensation increase............................... 4.75%
Expected long-term rate of return on plan assets............ 8.00%
The projected benefit obligation as of September 30, 1999 is $27.4 million.
The projected benefit obligation of the Plan as of May 14, 1999, as
actuarially determined, was recorded by the Company as a purchase accounting
liability (see Note 3) under Accounting Principles Board Opinion (APB) No. 16,
Business Combinations.
Additionally, employees of the Company and its subsidiaries participate in
the AES Profit Sharing and Stock Ownership Plans. The plans provide for Company
matching contributions. Participants are fully vested in their own contributions
and the Company's matching contributions.
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of the Company's current financial assets and liabilities
approximate their carrying values. The fair value estimates are based on
pertinent information available as of September 30, 1999. The Company is not
aware of any factors that would significantly affect the estimated fair value
amounts since that date.
10. SEGMENT INFORMATION
Under the provisions of SFAS No. 131, Disclosures About Segments of an
Enterprise and Related Information, the Company's business is expected to be
operated as one reportable segment, with operating income or loss being the
measure of performance measured by the chief operating decision-maker.
* * * * * *
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GLOSSARY OF CERTAIN ELECTRIC INDUSTRY TERMS
ACCESS: The ability to use transmission/distribution facilities that are
owned or controlled by a third party.
AUTOMATIC GENERATION CONTROL (AGC): Equipment which automatically adjusts
an electric power control area's generation to a central location.
AVAILABILITY: The condition of a unit or major piece of equipment of being
capable of service whether or not it is actually in service.
AVAILABILITY FACTOR: The percentage of total time in a specified period
that a unit was available to operate (at any load).
BASE LOAD: The minimum amount of electric power delivered or required over
a given period of time at a steady rate. The minimum continuous load or demand
in a power system over a given period of time.
BLACK START CAPABILITY: The capability of a generating unit or station to
go from a shutdown condition to an open condition and start delivering power
without assistance from the system.
BRITISH THERMAL UNIT (BTU): The amount of heat energy necessary to raise
the temperature of one pound of water one degree Fahrenheit.
CAPACITY: The real power output rating of a generator or system, typically
in megawatts, measured on an instantaneous basis. The amount of electric power
delivered or required for which a generator, turbine, transformer, transmission
circuit, station, or system is rated by the manufacturer.
CAPACITY FACTOR: The ratio, expressed as a percentage, of the actual net
generation of a generating unit over a period of time to the maximum potential
generation of the generating unit over that period based on its capacity.
COGENERATION: The simultaneous production of both useable heat or steam
and electricity from a common fuel source.
COMBINED CYCLE: The combination of one or more gas turbine and steam
turbines in an electric generating plant. An electric generating technology in
which electricity is produced from otherwise lost waste heat exiting from one or
more gas (combustion) turbines. The exiting heat is routed to a conventional
boiler or to a heat recovery steam generator for utilization by a steam turbine
in the production of electricity. This process increases the efficiency of the
electric generating unit.
COMBINED CYCLE UNIT: An electric generating unit that consists of one or
more combustion turbines and one or more boilers with a portion of the required
energy input to the boiler(s) provided by the exhaust gas of the combustion
turbine(s).
COMBUSTION TURBINE (CT): A fuel-fired turbine engine used to drive an
electric generator. Because of their generally rapid firing time, combustion
turbines are used to meet short-term peak demand placed on power systems.
CONSTRAINT: A generator's high or low output limit, line rating, or other
limiting condition on the electrical system.
DISPATCH: The monitoring and regulation of an electrical system to provide
coordinated operation; the sequence in which generating resources are called
upon to generate power to serve fluctuating loads.
DISPLACEMENT: The substitution of less expensive energy generation for
more expensive generation. Usually this means reducing or shutting down
production at a high cost thermal plant and using cheaper thermal generation
and/or hydroelectric power when it is available.
DISTRIBUTION: The system of lines, transformers and switches that connect
between the transmission network and customer load. The transport of electricity
to ultimate use points such as homes and businesses.
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199
The portion of an electric system that is dedicated to delivering electric
energy to an end user at relatively low voltages.
DISTRIBUTION FACILITIES: Equipment used to deliver electric power at lower
voltages from the transmission system to the final user. Although considered a
distinct segment of the market, distribution facilities generally can be grouped
with transmission facilities because these assets perform a similar function
that is wholly distinct from generating facilities.
DISTRIBUTION SYSTEM: The portion of an electric system that is dedicated
to delivering electric energy to an end user.
DIVESTITURE: Corporate separation of generation, transmission and/or
distribution of the traditional vertically integrated regulated utility.
ECONOMIC DISPATCH: The process of determining the desired generation level
for each of the generating units in a system in order to meet customer demand at
the lowest possible production cost given the operational constraints on the
system.
ENERGY: The capacity for doing work as measured by the capability of doing
work (potential energy) or the conversion of this capability to motion (kinetic
energy). Energy has several forms, some of which are easily convertible and can
be changed to another form useful for work. Most of the world's convertible
energy comes from fossil fuels that are burned to produce heat that is then used
as a transfer medium to mechanical or other means in order to accomplish tasks.
Electrical energy is usually measured in kilowatt-hours, while heat energy is
usually measured in British Thermal Units.
EQUIVALENT AVAILABILITY: The fraction of maximum generation that a
generating unit could provide if limited only by outages, overhauls and
deratings.
ESCOS: Energy supply companies under the new ISO system in New York state.
ESCOs must meet certain criteria before selling their services in New York. They
must demonstrate that they are certified businesses registered with the New York
Department of State and meet criteria established by the local utility and the
Public Service Commission of the State of New York.
EXEMPT WHOLESALE GENERATOR (EWG): A class of generators defined by the
Energy Policy Act of 1992 that includes persons determined by FERC to be
exclusively in the business of being owners and/or operators of facilities used
to generate electricity exclusively for sale at wholesale or used for the
generation of electric energy and leased to one or more public utility companies
and selling electric energy at wholesale.
FLUE GAS DESULFURIZATION (FGD) SYSTEM: An emissions control technology
that reduces SO(2) emissions from electric generation plants.
FOSSIL FUEL: Any naturally occurring organic fuel, such as coal, oil and
natural gas.
FOSSIL-FUEL PLANT: A plant using coal, oil or natural gas as its source of
energy.
GAS TURBINE PLANT: A gas turbine plant consists typically of a generator,
an axial-flow air compressor, and one or more combustion chambers, where liquid
or gaseous fuel is burned and the hot gases are passed to the turbine and where
the hot gases expand to drive the generator and are then used to run the
compressor.
GENERATING UNIT: Any combination of physically connected generator(s),
reactor(s), boiler(s), combustion turbine(s), or other prime mover(s) operated
together to produce electric power.
GENERATION (ELECTRICITY): The process of producing electric energy by
transforming other forms of energy; also, the amount of energy produced,
expressed in watthours (Wh).
GROSS GENERATION: The total amount of electric energy produced by the
generating units at a generating station or stations, measured at the generator
terminals.
NET GENERATION: Gross generation less the electric energy consumed at the
generating station for station use.
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200
GIGAWATT (GW): One billion watts.
GIGAWATT-HOUR (GWh): One billion watt-hours.
HEAT OR HEATING RATE: The measure of efficiency in converting input fuel
to electricity. Heat rate is expressed as the number of Btus of fuel (e.g.,
coal) per kilowatt-hour (Btu/kWh). The heat rate for power plants depends on the
individual plant design, its operating conditions, and level of electric power
output. The lower the heat rate, the more efficient the plant.
HEAT RECOVERY STEAM GENERATOR: See Combined Cycle.
HYDROELECTRIC PLANT: A plant in which the turbine generators are driven by
falling water.
INDEPENDENT SYSTEM OPERATOR (ISO): A neutral operator responsible for
maintaining an instantaneous balance of the electric system. The ISO performs
its function by controlling the dispatch of flexible plants to ensure that loads
match resources available to the system.
INTEGRATED UTILITY: An electric company that owns and operates all means
of production and distribution, including generation units, transmission lines
and distribution facilities.
ISO NEW YORK (ISO-NY): ISO New York, expected to be in place in the later
part of 1999, will be a not-for-profit New York corporation under FERC's
jurisdiction and, to the extent applicable, the Public Service Commission of the
State of New York's jurisdiction. It will be governed by a board of directors
comprised of representatives from all power market participants-buyers of power,
sellers of power, consumer groups and transmission owners. The new ISO system
envisions the establishment of three new entities, the ISO itself, the New York
State Reliability Council ("NYSRC") and the New York Power Exchange ("NYPE").
The NYSRC will have the primary responsibility to preserve the reliability of
electricity service on the bulk power system within New York State and will set
the reliability standards to be used by the ISO. The NYPE will be one of many
possible power exchanges in New York State which will be formed to facilitate
competition in the power markets and to operate the actual day-ahead and
real-time markets.
KILOVOLT (KV): One thousand volts.
KILOWATT (kW): One thousand watts.
KILOWATT-HOUR (kWh): A unit of electrical energy which is equivalent to
one kilowatt of power used for one hour. One kilowatt-hour is equal to 1,000
watt-hours. An average household will use between 800 - 1300 kWh per month
depending upon geographical area.
LOAD: The amount of electric power delivered or required at any specific
point or points on a system. The requirement originates at the energy-consuming
equipment of the consumers. The load of an electric utility system is affected
by many factors and on a daily, seasonal and annual basis, typically following a
pattern. System load usually measured in megawatts (MW).
LOAD FOLLOWING: An electric system's or plant's ability to regulate its
generation to follow the instantaneous changes in its customer's demand. The
obligation of the wheeling utility to provide from its own generating sources
any difference between the amount of power being wheeled and the instantaneous
requirement of the customer receiving, or the supplier delivering the wheeled
power. Load following falls into two categories: (a) dedicating sufficient
generating capacity to the automatic generator control (AGC) mode to allow them
to follow load, and (b) monitoring mismatches between intended and actual
interchanges between control areas, and transmitting control signals to AGC
generators to minimize this mismatch. Both require a system to record mismatches
(over-runs and under-runs). Load following is important because it helps
maintain system frequency. Otherwise, if demand exceeded supply, generators
would slow down; and if supply exceeded demand, generators would speed up. Both
situations could result in an unstable situation, which could lead to a
widespread outage.
MARKET-BASED PRICING: Electric service prices determined in an open market
of supply and demand under which the price is set solely by agreement as to what
a buyer will pay and a seller will accept. Such
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201
prices could recover less or more than the full cost, depending upon what the
buyer and seller see as their relevant opportunities and risks.
MEGAWATT-HOUR (MWh): One million watt-hours.
MMBtu: One million British thermal units.
NEW ENGLAND POWER POOL: The New England power pool, formed in 1971, is an
association of electric utilities in New England who established a single
regional network to direct the operations of the major generating and
transmission (bulk power system) facilities in the region.
NEW YORK POWER POOL (NEW YORK POWER POOL): The New York power pool, formed
in 1966, is an association of the investor-owned utilities in the state, the New
York Power Authority and the Long Island Power Authority. The New York power
pool member systems serve over 99% of New York State's electric power
requirements. In addition, over 5,000MW of capacity is owned by non-utility
generators who sell the bulk of their output to the investor-owned utilities
under long-term contracts. New York power pool is interconnected with the New
England power pool to the northeast and the Pennsylvania-New Jersey-Maryland
power pool to the south as well Hydro Quebec and Ontario Hydro. The New York
power pool system will transform into the ISO New York system, which may be
operational in the later part of 1999.
NOMINAL OR NAMEPLATE CAPACITY: The full-load continuous rating of a
generator, prime mover or other electric power production equipment under
specific conditions as designated by the manufacturer. Installed generator
nameplate rating is usually indicated on a nameplate physically attached to the
generator.
NON-SPINNING RESERVE: The portion of off-line generating capacity that is
capable of being loaded in ten minutes or load that is capable of being
interrupted in ten minutes and that is capable of running (or being interrupted)
for at least two hours.
OFF PEAK: A period of relatively low demand for electrical energy, such as
the middle of the night.
OPERATING RESERVE: The reserve generating capacity necessary to allow an
electric system to recover from generation failures and provide for load
following and frequency regulations. It consists of spinning and non-spinning
reserves.
OUTAGE: Periods, both planned and unexpected, during which power system
facilities (generation unit, transmission line, or other facilities) cease to
provide generation, transmission or the distribution of power.
PEAK DEMAND: The maximum load during a specified period of time.
PEAK LOAD: The maximum electrical load demand in a stated period of time.
On a daily basis, peak loads occur at midmorning and/or in the early evening.
PEAK LOAD PLANT OR PEAKER UNIT: A plant usually housing low-efficiency,
quick response steam units, gas turbines, or pumped-storage hydroelectric
equipment normally used during the maximum load periods.
PEAKING CAPACITY: Capacity of generating equipment normally reserved for
operation during the hours of highest daily, weekly, or seasonal loads. Some
generating equipment may be operated at certain times as peaking capacity and at
other times to serve loads on an around-the-clock basis.
PENNSYLVANIA-NEW JERSEY-MARYLAND POWER POOL: The Pennsylvania-New
Jersey-Maryland power pool is the largest centrally dispatched electric control
area in North America and fourth largest in the world. The Pennsylvania-New
Jersey-Maryland power pool operates the nation's first regional, bid-based
market and handles 8% of the US's electrical power (56,000MW). The
Pennsylvania-New Jersey-Maryland power pool market is characterized by high
price volatility.
POWER MARKETER: Any firm that buys and resells power but does not own
transmission facilities. Power marketers must file with the FERC to obtain
authority to conduct business if they sell power at wholesale in interstate
commerce (i.e., using the FERC regulated transmission grid).
POWER POOL: An association of two or more interconnected electric systems
having an agreement to coordinate operations and planning for improved
reliability and efficiencies.
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REHEAT UNIT: A steam turbine generator in which superheated steam from the
boiler passes through a portion of the turbine and then passes through another
superheater in the boiler called a reheater where it is reheated and then
finally passes through the remaining portion of the turbine. This arrangement is
more efficient than a comparable non-reheat unit in that more of the energy
released in the combustion process can be transferred to the steam which in turn
can do more work in the steam turbine.
REAL-TIME PRICING: The instantaneous pricing of electricity based on the
cost of the electricity available for use at the time the electricity is
demanded by the customer.
REPOWERING: The partial or complete replacement of the existing steam
supply system with a new (usually technologically different) steam supply
system. Most other systems and components, including the steam-turbine
generator, are refurbished and reused. Repowering generally increases the output
of the plant and reduces its heat rate, thus improving overall efficiency.
RESERVES: The electric power needed to provide service to customers in the
event of generating transmission system outages, adverse streamflows, delays in
the completion of new resources or other factors that may restrict generating
capability or increase loads. Reserves normally are provided from additional
resources acquired for that purpose from contractual rights to interrupt,
curtail or otherwise withdraw portions of the power supplied to customers.
RETAIL WHEELING: The sale of electricity by a utility or other supplier to
a customer in another utility service territory. Refers to the use of the local
utility's transmission and distribution facilities to deliver the power from a
wholesale supplier to a retail customer by a third party.
SPINNING RESERVE: Reserve generating capacity running at a zero load to
and synchronized with the grid to serve additional demand. The spinning reserve
must be under automatic control to instantly respond to system requirements.
SPOT MARKET: A market where goods are traded for immediate delivery.
10 MINUTE RESERVE CAPABILITY: In general, 10 minute reserve capability
refers to generating units that can be available for load within a 10-minute
period.
TRANSMISSION FACILITIES: Equipment used to deliver electric power at
higher voltages in bulk quantity, from generating facilities to lower voltage
local distribution facilities, for ultimate retail use.
TRANSMISSION SYSTEM (ELECTRIC): An interconnected group of electric
transmission lines and associated equipment for moving or transferring electric
energy in bulk between points of supply and points at which it is transformed
for delivery over the distribution system lines to consumers, or is delivered to
other electric systems.
TURBINE: A machine for generating rotary mechanical power from the energy
of a stream of fluid (such as water, steam, or hot gas). Turbines convert the
kinetic energy of fluids to mechanical energy through the principles of impulse
and reaction, or a mixture of the two.
VOLT: The unit of measurement of electromotive force. It is equivalent to
the force required to produce a current of one ampere through a resistance of
one ohm, the unit of measure for electrical potential. Generally measured in
Kilovolts or KV. Typical transmission level voltages are 115KV, 230KV and 500KV.
WATT: A measure of real power production or usage equal to one Joule per
second. The rate of energy transfer equivalent to one ampere flowing under a
pressure of one volt at unity factor. An electric unit of power or a rate of
doing work.
WATT-HOUR (Wh): An electrical energy unit of measure equal to one watt of
power supplied to, or taken from, an electric circuit steadily for one hour.
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WHEELING: The use of the transmission facilities of one system to transmit
power for another electric system. Wheeling can apply to either wholesale or
retail service.
WHOLESALE SALES: Energy supplied to other electric utilities,
cooperatives, municipalities, and federal and state electric agencies for resale
to ultimate consumers.
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INDEX OF DEFINED TERMS
DEFINED TERM PAGE
------------ ----
Accounts.............................. 113
Actual Knowledge...................... 113
Additional Facilities................. 106
Additional Interest................... 97
Additional Liquidity Letter of
Credit.............................. 113
Additional Liquidity Required
Balance............................. 113
AES Eastern Energy Entities........... 114
AES Eastern Energy Extraordinary
Revenues............................ 114
AES Eastern Energy Revenues........... 114
AES Eastern Energy Subsidiaries....... 115
Affiliate Transaction................. 115
agent's message....................... 26
Annual Operating Budget............... 115
Applicable Law........................ 115
Appraisal Procedure................... 115
Assigned Assets....................... 115
Basic Lease Commencement Date......... 138
Basic Rent............................ 115
Beneficial Interest................... 115
Bill of Sale.......................... 115
book-entry confirmation............... 26
broker................................ 160
Business Day.......................... 115
CADS.................................. 115
Certificate Account................... 100
Certificate Owner..................... 95
Certificateholders.................... 95
Collateral............................ 115
Consol................................ 53
Coverage Ratio........................ 116
Debt Service.......................... 116
Deed.................................. 116
Deferrable Basic Rent Maturity Date... 116
Deferrable Basic Rent................. 116
Deferrable Payments................... 116
definitive certificate................ 95
Discounted Present Value.............. 103
Distribution.......................... 116
DOE................................... 59
EDGAR................................. i
equity interest....................... 162
Event of Loss......................... 146
EWG Status............................ 106
exchanging dealer..................... 96
existing pass through trust
certificates........................ 94
DEFINED TERM PAGE
------------ ----
expiration date....................... 25
Facilities Support Agreement.......... 109
FCCR.................................. 117
FERC.................................. 106
Fixed Charge Coverage Ratio........... 117
Fixed Charges......................... 117
Funding Date.......................... 117
GAAP.................................. 108
Governmental Approvals................ 117
Governmental Entity................... 117
holder................................ 25
IBEW.................................. 56
Indebtedness.......................... 117
Independent Forecast.................. 110
initial purchasers.................... 95
Interconnection Agreement............. 117
Investment Grade...................... 117
Land.................................. 117
Lease Bankruptcy Default.............. 118
Lease Basic Term...................... 138
Lease Event of Default................ 102
Lease Expiration Date................. 118
Lease Fixed Term...................... 139
Lease Indenture Event of Default...... 102
Lease Interim Term.................... 138
Lease Material Default................ 118
Lease Obligations..................... 118
Lease Renewal Term.................... 139
Lease Term............................ 118
Lessee Liens.......................... 118
Lien.................................. 118
Make Whole Premium.................... 102
Material Adverse Effect............... 118
MEGA.................................. 49
modifications......................... 141
Modified Make Whole Premium........... 103
Mortgage.............................. 118
Mortgaged Property.................... 118
New pass through trust certificates... 94
New Regulations....................... 159
Non U.S. Holder....................... 156
NYSEG................................. 1
O&M................................... 12
Operating and Maintenance Costs....... 118
Operation and Maintenance
Agreements.......................... 119
Operative Documents................... 94
I-1
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DEFINED TERM PAGE
------------ ----
Participation Agreement............... 119
Parties in interest................... 162
Pass through trust certificates....... 94
Payment Event......................... 119
Payment Undertaking Agreement......... 120
Permitted Affiliate Transaction....... 120
Permitted Contest..................... 121
Permitted Encumbrances................ 121
permitted government investments...... 126
Permitted Indebtedness................ 121
Permitted Investments................. 122
Permitted Liens....................... 123
Permitted Secured Indebtedness........ 123
Permitted Subordinated Indebtedness... 123
Permitted Working Capital
Indebtedness........................ 124
PPA Term.............................. 124
PPA................................... 124
prohibited transactions............... 162
Prudent Industry Practice............. 140
PTCE.................................. 163
PUA Provider.......................... 124
Purchase Price........................ 124
Rating Agencies....................... 124
Regular Distribution Dates............ 97
Regulatory Event of Loss.............. 147
Related Party......................... 124
Renewal Rent.......................... 124
Renewal Term.......................... 125
Rent Payment Date..................... 125
Rent Payment Period................... 125
Rent Reserve Account Required
Balance............................. 125
DEFINED TERM PAGE
------------ ----
Rent.................................. 124
Replacement Event..................... 125
Required Coverage Ratio............... 125
Requisition........................... 146
Responsible Officer................... 125
Scheduled Payments.................... 97
severable modifications............... 140
shelf registration statement.......... 95
Somerset Railroad credit facility..... 69
Special Distribution Date............. 100
Special Payment....................... 99
Special Payments Account.............. 100
Special Purpose Business Trust
Company............................. 126
Special Purpose Business Trustee...... 126
Special Rent Reserve Account Required
Balance............................. 126
Special Rent Reserve Period........... 126
Supplemental Rent..................... 126
Support Agreements.................... 126
Tax................................... 126
Taxes................................. 126
Termination Date...................... 127
Transaction Party..................... 127
Trust Property........................ 94
U.S. Holder........................... 156
Withholding Agent..................... 159
GLOSSARY OF CERTAIN ELECTRIC INDUSTRY
TERMS
NYPE.................................. 3
NYSRC................................. 3
Wh.................................... 2
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SCHEDULE I
SCHEDULED PAYMENTS OF PRINCIPAL IN RESPECT OF SECURED LEASE OBLIGATION NOTES
KINTIGH GENERATING STATION MILLIKEN GENERATING STATION
-------------------------------- --------------------------------
SCHEDULED PAYMENT DATES SERIES 1999-A SERIES 1999-B SERIES 1999-A SERIES 1999-B
----------------------- -------------- -------------- -------------- --------------
January 2, 2000............. $ 0.00 $ 0.00 $ 0.00 $ 0.00
July 2, 2000................ 0.00 0.00 0.00 0.00
January 2, 2001............. 0.00 0.00 0.00 0.00
July 2, 2001.............. 0.00 0.00 0.00 0.00
January 2, 2002............. 0.00 0.00 0.00 0.00
July 2, 2002.............. 0.00 0.00 0.00 0.00
January 2, 2003............. 0.00 0.00 0.00 0.00
July 2, 2003.............. 1,526,404.56 0.00 0.00 0.00
January 2, 2004............. 5,395,888.20 0.00 0.00 0.00
July 2, 2004.............. 0.00 0.00 5,638,703.17 0.00
January 2, 2005............. 0.00 0.00 2,942,444.82 0.00
July 2, 2005.............. 0.00 0.00 4,974,854.83 0.00
January 2, 2006............. 0.00 0.00 2,348,723.30 0.00
July 2, 2006.............. 0.00 0.00 6,354,415.85 0.00
January 2, 2007............. 0.00 0.00 3,690,364.56 0.00
July 2, 2007.............. 6,806,430.97 0.00 0.00 0.00
January 2, 2008............. 4,162,720.36 0.00 0.00 0.00
July 2, 2008.............. 7,300,042.78 0.00 0.00 0.00
January 2, 2009............. 0.00 0.00 4,678,544.70 0.00
July 2, 2009.............. 7,839,079.21 0.00 0.00 0.00
January 2, 2010............. 5,241,837.78 0.00 0.00 0.00
July 2, 2010.............. 0.00 0.00 11,315,220.48 0.00
January 2, 2011............. 0.00 0.00 8,599,405.40 0.00
July 2, 2011.............. 0.00 0.00 12,211,378.64 0.00
January 2, 2012............. 9,535,890.68 0.00 0.00 0.00
July 2, 2012.............. 14,240,005.76 0.00 0.00 0.00
January 2, 2013............. 0.00 0.00 11,555,806.02 0.00
July 2, 2013.............. 17,238,317.29 0.00 0.00 0.00
January 2, 2014............. 14,514,041.57 0.00 0.00 0.00
July 2, 2014.............. 18,667,173.44 0.00 0.00 0.00
January 2, 2015............. 16,007,196.25 0.00 0.00 0.00
July 2, 2015.............. 0.00 0.00 20,227,520.08 0.00
January 2, 2016............. 17,637,758.48 0.00 0.00 0.00
July 2, 2016.............. 0.00 0.00 21,931,457.61 0.00
January 2, 2017............. 19,418,373.21 0.00 -- 0.00
July 2, 2017.............. 0.00 -- 0.00
January 2, 2018............. -- 19,645,839.50 -- 0.00
July 2, 2018.............. -- 24,742,076.34 -- 0.00
January 2, 2019............. -- 0.00 -- 22,438,355.73
July 2, 2019.............. -- 0.00 -- 27,023,250.23
January 2, 2020............. -- 24,829,824.38 -- 0.00
July 2, 2020.............. -- 13,030,150.50 -- 9,227,162.47
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KINTIGH GENERATING STATION MILLIKEN GENERATING STATION
-------------------------------- --------------------------------
SCHEDULED PAYMENT DATES SERIES 1999-A SERIES 1999-B SERIES 1999-A SERIES 1999-B
----------------------- -------------- -------------- -------------- --------------
January 2, 2021............. -- 20,526,123.90 -- --
July 2, 2021.............. -- 10,085,543.09 -- --
January 2, 2022............. -- 0.00 -- --
July 2, 2022.............. -- 10,164,580.61 -- --
January 2, 2023............. -- 0.00 -- --
July 2, 2023.............. -- 11,197,434.02 -- --
January 2, 2024............. -- 0.00 -- --
July 2, 2024.............. -- 12,335,238.75 -- --
January 2, 2025............. -- 0.00 -- --
July 2, 2025.............. -- 13,588,659.21 -- --
January 2, 2026............. -- 0.00 -- --
July 2, 2026.............. -- 14,969,443.48 -- --
January 2, 2027............. -- 0.00 -- --
July 2, 2027.............. -- 16,490,533.36 -- --
January 2, 2028............. -- 0.00 -- --
July 2, 2028.............. -- 8,643,925.32 -- --
January 2, 2029............. -- 9,061,859.11 -- --
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208
Appendix A
May 12, 1999
AES Eastern Energy L.P
1001 North 19th Street
Arlington, VA 22209
Stone & Webster is pleased to present this report on our review of the power
plants being acquired by AES Eastern Energy LP from NYSEG. This report provides
our opinions on the power plants being purchased. We believe that the plants are
in good condition and that AEE has developed a credible plan and budget for
operating, maintaining, and extending the life of the units for the term of the
Financial Projections.
Sincerely,
STONE & WEBSTER MANAGEMENT CONSULTANTS, INC.
K.H. Applewhite, Jr.
Vice President
209
LEGAL NOTICE
This report was prepared by Stone & Webster Management Consultants, Inc. and its
affiliated company, Stone & Webster Engineering Corporation, both hereafter
referred to as Stone & Webster, expressly for The AES Corporation. Stone &
Webster has consented to the use of this report in connection with the issuance
and sale of pass through trust certificates as described in the Offering
Memorandum to which this report is attached and to the reference to us as
experts under the heading "Experts" in the Offering Memorandum. Neither Stone &
Webster, The AES Corporation, AES Eastern Energy, L.P., nor any person acting in
their behalf, (a) makes any warranty, express or implied, with respect to the
use of any information or methods disclosed in this report; or (b) assumes any
liability with respect to the use of any information or methods disclosed in
this report. Stone & Webster's review of the Financial Projections relating to
AES Eastern Energy LP in no way serves to transfer to Stone & Webster
responsibility for the correctness and/or accuracy of such information or
modeling results.
E-MAIL NOTICE
E-mail copies of this report are not official unless authenticated and signed by
Stone & Webster and are not to be modified in any manner without Stone &
Webster's expressed written consent.
210
AES EASTERN ENERGY, L.P.
INDEPENDENT TECHNICAL REVIEW
REPORT
SECTION ITEM
1 EXECUTIVE SUMMARY
1.1 Introduction
1.2 Scope of Services
1.3 Condition Assessment
1.4 Performance
1.5 Environmental
1.6 Remaining Life
1.7 Operations and Maintenance
1.8 Financial Projections
1.9 Conclusions
2 PLANT TECHNICAL DESCRIPTION SUMMARY
2.1 Plant Description
2.1.1 Kintigh Station
2.1.2 Milliken Station
2.1.3 Goudey Station
2.1.4 Greenidge Station
2.2 Station Characteristics
3 PLANT CONDITION ASSESSMENT
3.1 Kintigh Technical Evaluation
3.1.1 Unit Overview
3.1.2 Condition Assessment
3.1.3 AEE Life Extension Forecast
3.2 Milliken Technical Evaluation
3.2.1 Station Overview
3.2.2 Condition Assessment
3.2.3 AEE Life Extension Forecast
3.3 Goudey Technical Evaluation
3.3.1 Station Overview
3.3.2 Condition Assessment
3.3.3 AEE Life Extension Forecast
3.4 Greenidge Technical Evaluation
211
3.4.1 Station Overview
3.4.2 Condition Assessment
3.4.3 AEE Life Extension Forecast
4 PERFORMANCE
4.1 Basis of Power Plant Heat Rates
4.2 Unit Heat Rates
4.3 Availability
5 ENVIRONMENTAL
5.1 Air Emission Compliance
5.1.1 Sulfur Dioxide (SO)(2)
5.1.2 Nitrogen Oxides (NO)(2)
5.1.3 Particulates and Opacity
5.1.4 Other EPA Air Pollutant Considerations
5.2 Water and Waste Compliance
5.3 Fish Protection
5.4 Ash Disposal
5.4.1 Kintigh Ash Disposal Site
5.4.2 Milliken Ash Disposal Site
5.4.3 Weber Ash Disposal Site
5.4.4 Lockwood Disposal Site
5.4.5 Other Onsite Inactive Ash Disposal Sites
6 OPERATIONS AND MAINTENANCE
6.1 Operations and Maintenance Costs
6.2 Staffing Levels
6.3 Overhaul and Maintenance Schedule
6.4 Capacity Factors
7 FINANCIAL PROJECTIONS
7.1 Overview
7.2 Revenues
7.3 Expenses
7.3.1 Fuel
7.3.2 Fixed Operations, Maintenance, and Other Costs
7.3.3 Variable Operating Costs
7.4 Sensitivity Cases
7.5 Fixed Charge Coverage Ratios
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1. EXECUTIVE SUMMARY
1.1 INTRODUCTION
Stone & Webster Management Consultants, Inc. and Stone & Webster Engineering
Corporation (collectively referred to as "Stone & Webster") were retained by The
AES Corporation ("AES") on behalf of Morgan Stanley &Co. Inc., Credit Suisse
First Boston Corporation, and CIBC Oppenheimer Inc., as Initial Purchasers, to
provide an independent technical assessment of the AES Eastern Energy, L.P.
("AEE") generation stations. This report is in support of an offering of pass
through trust certificates and lease equity to be issued in respect of a
leveraged lease financing of the Kintigh Station, a 675 MW coal-fired generation
station, and the Milliken Station, a 306 MW coal-fired generation station. This
report should be read in its entirety for a full understanding of the AEE Assets
and the pro forma financial projections contained herein ("Financial
Projections").
The assets, formerly owned by New York State Electric and Gas Corporation
("NYSEG"), include four coal-fired generation facilities (collectively, the "AEE
Assets"). This report includes Stone and Webster's independent technical
assessment of the AEE Assets based on a review of available technical data and
presents our findings and conclusions regarding the following:
- projected revenues, operating and maintenance expenses,
capital costs, and environmental issues relating to the future
operation and maintenance of the AEE facilities,
- projected availability, capacities, and heat rates of the
units, and
- the expected useful lives of the units.
We also reviewed the AEE Financial Projections which incorporate the projected
electricity prices, dispatch rates, and fuel prices provided by other
consultants along with the projected operating costs of the units. The Financial
Projections calculate the fixed charge coverage ratios ("FCCRs") defined as cash
available for fixed charges divided by rent payments under the leases equal to
principal and interest on the pass through trust certificates and non-deferrable
rent.
The coal-fired power production facilities consist of the Kintigh, Milliken,
Goudey and Greenidge stations and have a total projected capacity of
approximately 1,268 MW. Kintigh (675 MW) consists of a single conventional
steam-electric power generation unit. Milliken (306 MW), Goudey (126 MW) and
Greenidge (161 MW) each consist of two conventional steam-electric power
generation units.
AES, through its subsidiary AEE, will have complete operational control of these
units. The plants are in good condition overall as NYSEG has performed
considerable life extension work over the last several years. Kintigh and
Milliken are equipped with flue gas desulfurization units ("FGD"). A selective
catalytic reduction ("SCR") unit for nitrogen oxides ("NO(x)") is expected to be
installed in 1999 at Kintigh. AES has budgeted to install SCRs in 2002 and 2003
at Milliken, but may decide not to install it
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Independent Technical Review
AEE
if more economical options become available. As a result, the plants are well
prepared to meet the expected emission regulations.
The scope of this independent technical review included design and equipment,
operating history, projected performance, technical, logistical, operations and
maintenance ("O&M"), and environmental considerations. Stone & Webster reviewed
information provided by AEE, had meetings with various parties, and visited the
plant sites. Stone & Webster reviewed the technical and commercial assumptions
and the calculation methodology of the Financial Projections developed by AEE as
well as the projected performance, revenues, and expenses. Using AEE's model,
Stone & Webster also conducted sensitivity analyses of certain variables on the
rent coverage ratios for the period of the lease. Model outputs for the base
case and certain sensitivity analyses are provided in Exhibit I. Stone & Webster
has made no determination as to the completeness, reasonableness, and accuracy
of (i) certain financing assumptions provided by AEE in consultation with the
Initial Purchaser or (ii) certain other assumptions described in detail in
Section 7 of this report.
The AEE Assets are discussed in the following sections and summarized in Table
2-1.
1.2 SCOPE OF SERVICES
This report provides a summary of our review and opinions for each plant
regarding the following:
- Condition of Station Equipment
- AEE Life Extension Program
- Proposed Operating Plan and Budget
- Environmental Permits and Site Assessment Documents
- Financial Projections
Stone & Webster conducted this analysis and prepared the report utilizing
reasonable care and skill and applied methods consistent with normal industry
practice. In the preparation of this report and in formulating the expressed
opinions, Stone & Webster has made certain assumptions with respect to
conditions which may exist or events which may occur in the future. If events or
circumstances are different than forecasted then the Financial Projections may
be impacted. The equipment inspection reports and site environmental reports
were performed by others and reviewed by Stone & Webster. Assessment of legal
issues, such as assignment of contractual rights, property rights, easements,
and procedural issues related to permits and permit waivers is outside of Stone
& Webster's scope of work as Independent Technical Consultant.
1.3 CONDITION ASSESSMENT
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Kintigh Station is the largest and newest of the four electric generating
stations included among the AEE Assets. The site is located near Somerset, New
York and comprises 1,722 acres, which adjoins the south shore of Lake Ontario.
Approximately 1,062 acres are utilized for site operations. Kintigh entered
service in 1984 and has a nominal generating capability of 675 MW.
This station benefited from a continuous policy by NYSEG to emphasize
maintenance and invest in new equipment to keep the station operating reliably.
In addition to a good maintenance program, this station also has been the
recipient of new emissions control equipment to control sulfur dioxide
emissions. As a result of its relatively new construction and its good
condition, we believe that AEE's projection of another 45 years of operations is
reasonable and practical assuming life extension work is performed according to
the planned capital expenditure budget included in the Financial Projections.
The Milliken Station is located on the east shore of Cayuga Lake near the town
of Lansing, New York. This station consists of two operating units; Unit 1,
which was placed in operation in 1955, and Unit 2, which began operation in
1958. Unit 1 is nominally rated at 150 MW and Unit 2 is rated at 156 MW, which
gives the station a total generating capability of 306 MW. The station is
situated on a 400-acre site that slopes toward the lake.
Although constructed in the 1950s, a considerable amount of maintenance work and
station equipment upgrades have been accomplished on the two units at Milliken
to make this a reliable generating station. As a result of the well supported
maintenance program and the significant upgrades which totaled approximately
$100 million over the last ten years, this station should be able to operate
reliably through the projected 38 years of remaining station useful life through
the implementation of the life extension and replacement plan.
Goudey station operates on a 40-acre site adjacent to the Susquehanna River near
Johnson City, New York. Today, this station consists of Unit 7, a 43 MW unit
which has produced electricity since 1943 and Unit 8, which is a 1951 vintage
unit rated at 83 MW. The total electrical generating capability for this station
is 126 MW. In addition to generating electricity, the Goudey Station operates as
a cogeneration facility by producing steam for export to a Lockheed-Martin plant
located adjacent to the site. The revenues from the steam sales are not material
compared to the electrical energy revenues of the plant. While this station has
had recent boiler and turbine maintenance work, it has not received an extensive
upgrade of all plant operating systems and does not have the same level of
equipment redundancy as the newer stations. Goudey should be capable of
operating at its projected levels for the term of the Financial Projections
provided it is operated and maintained as anticipated in the life extension
program.
Greenidge station occupies 280 acres and is situated on the west side of Seneca
Lake near Dresden, New York. Presently, this station consists of Unit 3, rated
at 56 MW, and Unit 4, rated at 105 MW. These two units were placed into service
in 1950 and 1953, respectively. During the past 15 years, this station has
benefited from a systematic effort by NYSEG to replace older outdated equipment.
An examination of the station records indicates that a great deal of the
original equipment in both units has been replaced and, consequently; the
overall condition of the station is very good. Greenidge should be capable of
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Independent Technical Review
AEE
operating at its projected levels for the term of the Financial Projections
provided it is operated and maintained as anticipated in the life extension
program.
1.4 PERFORMANCE
Stone & Webster reviewed the heat rate and capacity factor projections used in
the Financial Projections. In general, we believe the heat rate projections are
reasonable and consistent with historical experience. Capacity factor is a
function of plant availability and dispatch. AEE has retained London Economics
as its market consultant to provide projections for dispatch. London Economics
has projected that after availability adjustments are made, the plants are
likely to be dispatched all the time they are available to run and therefore the
capacity factors will be equal to the availability of the plants to run.
Therefore, we have assumed that capacity factors will be equal to availability
factors and we have commented on the reasonableness of the availability
projection. Short-term availability and capacity factor for Kintigh is projected
to be 94 percent decreasing to a long-term availability and capacity factor of
92 percent in non-overhaul years. Capacity factor and availability of Milliken
is projected at 93 percent in the short term and decreases to a long-term
projection of 92 percent in non-overhaul years. The capacity factors and
availability projections for the other plants are less than or equal to 90
percent. We believe these projections are reasonable and achievable given the
historic availability levels achieved by these units. AES is a very capable
operator that regularly achieves exceptional results from its plants. In
addition, Kintigh has demonstrated an availability of approximately 95 percent
in recent years. Milliken has averaged over 92 percent. Following a major
planned overhaul at Kintigh during the first half of 1999, the projections
assume no further planned maintenance on the plants in 1999. As a result, we
believe that the projected unit availabilities and capacity factors of 98
percent at Kintigh after its spring outage and 96 percent at Milliken should be
achieved for the remainder of 1999.
1.5 ENVIRONMENTAL
The environmental assessment prepared by Stone & Webster is based on a review of
environmental permits and licenses and an environmental due diligence review
performed by TRC Environmental Corporation ("TRC"). The overall objective of our
analysis was to assess environmental or permit conditions that could affect the
operation of the AEE Assets.
NYSEG currently complies with all applicable state and federal air regulations
using a combination of unit-specific and system-wide compliance strategies. All
necessary approvals and reporting procedures have been implemented with the DEC
and the United States Environmental Protection Agency ("EPA"). The assets
presently employ an allowance cap and trade program for sulfur dioxide (SO)(2)
emissions and a weighted average emission rate for nitrogen oxides (NO)(x)
emissions to successfully comply with regulations for the four stations. Each
station is allowed to emit a certain tonnage of SO(2) each year. Since Kintigh
and Milliken have flue gas desulfurization systems, they can substantial reduce
their emissions below their annual cap and trade the remaining allowances to
Goudey and Greenidge. The four stations have a weighted average emission rate
(Lb/MMBtu) for NO(x) for annual compliance, and
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operated under an allowance cap during the summer ozone season. Again,
allowances can be traded between the stations.
Flue gas desulfurization ("FGD") systems at the Kintigh and Milliken Stations
reduce SO(2) emissions below the allowance allocation for each plant. The excess
allowances being created by the Kintigh and Milliken Stations are banked and may
be sold or used for SO(2) allowance requirements at other AEE Assets. The SO(2)
allowance bank was approximately 116,000 tons at the end of 1998.
AEE has indicated that it intends to sell this bank of credits and then purchase
credits as needed in future years. The FGD systems at Kintigh and Milliken are
not currently operating at their full reduction capability due to the current
lack of need to further reduce emissions. AEE can increase the reduction
efficiency of the FGD systems at Kintigh and Milliken by operating the FGD units
at a higher reductions capability at minimal additional cost. This option may
substantially reduce the SO(2) allowances that are needed. The Financial
Projections include purchasing allowances based on current operating practices.
AEE plans to install an SCR system for control of NO(x) emissions at the Kintigh
Station by June 1999 that will reduce NO(x) emissions by 90 percent from current
levels. The SCR system will create approximately 3,400 excess NO(x) credits per
year that can be applied to meet the allowance requirements of other AEE Assets.
This will provide enough credits for the plants to operate through 2003 without
having to purchase additional credits. AEE has budgeted to add SCR systems to
Milliken Station by May 1, 2003. If installed, this system will provide
additional excess NO(x) credits which may be applied to other AEE Assets to
satisfy compliance requirements for Title 1, Phase III, which is expected to
become effective in 2003. AEE has indicated that it may decide to use other
means of achieving compliance with the regulations other than installing the SCR
based on the economics of other alternatives at the time. If the SCR is
installed at Milliken, the excess NO(x) credits generated by Kintigh and
Milliken Stations should permit all the AEE Assets to satisfy the requirements
currently expected for Phase III.
1.6 REMAINING USEFUL LIFE
AEE has projected a remaining useful life of 45 years for Kintigh and 38 years
for Milliken. Based on Stone & Webster's review, it appears that there are no
conditions that would preclude the continued long term operation of any of the
AEE Assets assuming AEE aggressively continues proactive and effective asset
condition assessment, maintenance, and capital improvement programs. AEE has
projected Goudey and Greenidge to operate for the useful life of Milliken as
well. Provided AEE aggressively executes the life extension and maintenance
program for these two plants, we believe AEE will be able to continue operating
them in a reliable manner for the 38 year projected useful life as well.
1.7 OPERATIONS AND MAINTENANCE
Stone & Webster reviewed the operating and maintenance ("O&M") costs and the
technical assumptions in the Financial Projections. We believe the O&M costs for
each of the plants are reasonable. The
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capital costs consist primarily of major maintenance items that are typically
capitalized instead of expensed. We believe the overall magnitude of the capital
costs is reasonable and include sufficient funds to perform life extension
activities during the term of the Financial Projections. They will also support
the projected performance levels of each of the facilities.
Similarly, we recognize that industry practice on overhauls has been to extend
the time between turbine overhauls beyond the equipment vendor's normal
recommendation of six years. We are comfortable with eight years between
overhauls based on our recent observations of industry practice in Australia,
but the ten-year interval projected by AEE is not currently recognized industry
practice. The plants we have observed in Australia are more than 20 years old.
Current plant personnel have indicated that when they have performed inspections
after eight years, there has been minimal cleaning, repair, and inspection work
needed on the turbines. Therefore, it may be possible to reliably extend the
time between turbine outages to ten years. Based on our direct experience with
other AES projects, we believe AEE will demonstrate prudent judgement in
deciding when to conduct major inspections as AES has done at the other plants
they operate.
1.8 FINANCIAL PROJECTIONS
Stone & Webster reviewed the Financial Projections prepared by AEE. The
Financial Projections include revenues, expenses, and cash available for fixed
charges for 1999 through 2035. The cash available for fixed charges is compared
to AEE's annual projected rent payment under the leases equal to principal and
interest on the pass through certificates and non-deferrable rent to determine
the FCCR for each year. The Financial Projections include a base case and six
sensitivity cases. The sensitivity cases include the downside projection of
energy prices from London Economics, AEE's market consultant, reduced capacity
factors, increased fuel costs, increased operations and maintenance expenses,
increased capital expenditures, and increased heat rates. In each case, minimum
and average FCCRs were greater than or equal to 1.00 in each year. The
sensitivities illustrate the effects on cash flow in the event actual experience
is different than the base case assumed in the Financial Projections.
The Financial Projections are based upon market and capacity price forecasts and
facility specific capacity factors that were developed by London Economics. The
fuel prices used by London Economics were developed by others for either London
Economics or for AEE. Similarly, the prices for coal were provided by AEE's coal
market advisor, John T. Boyd Company. For information regarding the conclusions
drawn and assumptions used in the electricity and coal projections, please refer
to these respective reports.
AEE has made revenue projections that include capacity payments from NYSEG
through 2001 and capacity payments from the market thereafter. A long-term
capacity factor of 92 percent for Kintigh and Milliken for non-overhaul years is
assumed. These figures should be achievable based on our review of the
historical availability levels and the life extension work accomplished by
NYSEG, and the life extension work planned by AEE. Revenues and expenses
projected from the sale and purchase of NO(x) and SO(2) allowances were provided
by AEE, as were non-operating expenses. The operating costs for
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each plant are reasonable when compared to other facilities with which we are
familiar. The costs for coal transportation are specific to each plant. It is
our understanding that coal transportation costs are based on historical
experience at each plant.
1.9 CONCLUSIONS
Set forth below are the principal opinions which we have reached regarding the
review of AEE. For a complete understanding of the assumptions upon which these
opinions are based, the Report should be read in its entirety. On the basis of
our review and the assumptions set forth in the Report, Stone & Webster is of
the opinion that:
1. The Kintigh, Milliken, Goudey and Greenidge facilities have operated at
availabilities of 95.7 percent, 92.2 percent, 91.8 percent, and 87.4
percent in non-overhaul years between 1988 and 1998, which are above
average availability's compared to published data on similar facilities.
Based on the improvements made by NYSEG prior to the sale of the assets
and continued life extension and replacement work planned by AEE, it is
reasonable to expect that the facilities will continue to operate at
availability levels which support the capacity factor projections in the
Financial Projections.
2. The normal claimed capacities of the AEE Assets are reasonable estimates
of the capability of the facilities. With continued budgeted capital
investment in the AEE Assets, it is reasonable to expect that these
capacities can be maintained over the period shown in the Financial
Projections.
3. The heat rates in the Financial Projections of the AEE Assets have been
developed based on historical information. With continued budgeted
capital expenditures in the AEE Assets, it is reasonable to expect that
these heat rates can be maintained over the period shown in the Financial
Projections.
4. The AEE maintenance and capital expenditure budgets appear reasonable and
adequate to support the conclusions expressed above and to meet AEE's
maintenance and performance objectives, excluding any unforeseeable
catastrophic failures near the end of a unit's design life. These
maintenance and capital budgets have been used as the basis of the O&M
and capital expenditure expenses used in the Financial Projections. We
prepared an independent life extension study to compare against the AEE
life extension budget. The two budgets were within approximately 10
percent of each other for the 38 years of projections. Therefore, we
believe the capital expenditure budget prepared by AEE is adequate and
reasonable.
5. AEE has projected continued operation of its facilities to the year 2035.
Based on Stone &Webster's review, it appears there are no existing
conditions that would preclude the long-term operation of any of the AEE
facilities. This assumes the continuation of condition assessments,
maintenance, and capital improvement programs, and the implementation of
AEE's budgeted life extension program.
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6. The AEE Assets have all necessary permits in place. We have no reason to
believe that the plants will not be able to renew their permits as needed.
We believe the environmental reports commissioned by NYSEG and AEE were
prepared in accordance with good industry practice. We believe the reports
have recommended adequate budgets for environmental remediation, which are
included in the Financial Projections. We further believe the NOx and SO2
compliance strategies presented by AEE are reasonable.
7. The technology of the plants is proven. The ability to obtain replacement
parts should not be a concern during the period covered by the Financial
Projections.
8. AES has considerable experience operating coal-fired power plants. Stone
and Webster believes it is well qualified to operate these plants. It has
achieved the availability projections for the plants at several of its
other locations. In addition, it has demonstrated the ability to improve
the operations of its plants through the involvement of all the plant
personnel. This enables it to keep costs under control and find innovative
solutions, which lower operating costs and capital expenditures.
9. Under base case assumptions, the average FCCR is forecast to be 3.38 from
1999 through 2028. The minimum FCCR is 1.67 and occurs in 1999.
10. Six sensitivity cases were prepared to test the impact on the FCCRs of
different market forces on the energy and capacity forecasted by London
Economics and on the operating and capital costs projected by AEE. The
sensitivities include (i) the downside projection of energy and capacity
prices and reduced capacity factors from London Economics, (ii) reduced
capacity factors by 10%, (iii) increased fuel costs by 10%, (iv) increased
operations and maintenance expenses by 25%, (v) increased capital
expenditures by 50%, and (vi) increased heat rates at each unit by 500
Btu/kWh. The FCCR was most sensitive to reduced energy prices used in
sensitivity case 1. The average FCCR in this case fell to 2.66 with a
minimum of 1.28 in 1999. After 1999, the minimum coverage ratio was 1.61 in
the year 2005.
11. We reviewed the footprints of the portions of the Kintigh and Milliken
sites to be conveyed as security to the Indenture Trustee and the contracts
and other rights being assigned as indirect collateral for the pass through
trust certificates, which contracts and rights are essential for the
operation of these plants. We believe that this security and these
assignments, taken together, would be sufficient to permit a transferee to
operate Kinitgh and Milliken as they have historically operated.
2. PLANT TECHNICAL DESCRIPTION SUMMARY
2.1 PLANT DESCRIPTION
The four coal-fired, electric generating stations are all situated on separate
sites located in the western and south-central areas of New York State. The
stations, consisting of seven units, have a combined electrical generating
capability of 1,268 MW which is distributed in the Northeast Power Coordinating
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Council (NPCC) region. The stations are designated as Kintigh, Milliken,
Greenidge, and Goudey and were constructed from 1943 through 1984.
2.1.1 KINTIGH STATION
This Station is the largest and newest of the four electric generating stations.
The site is located near Somerset, New York and comprises 1,722 acres and
adjoins the south shore of Lake Ontario. Approximately 1,062 acres are utilized
for site operations. This unit, which entered service in 1984, has a nominal
generating capability of 675 MW.
This large site is generally level and is easily accessed by road and rail. The
15.5-mile rail line connecting the Kintigh Station with Lockport, New York is
owned by the Somerset Railroad Corporation ("SRC"), which is being acquired by
AES NY, LLC, the general partner of AEE. SRC will enter into a coal haulage
agreement with AEE. Most of the coal burned at this station originates from
mines in Pennsylvania and West Virginia and is transported to the site by rail.
Limestone used in the FGD system also normally arrives by rail.
The Kintigh Station uses water from Lake Ontario in a once-through cooling
system to cool operating equipment. This station is equipped with an
electrostatic precipitator to remove fly ash and a limestone FGD system to
remove SO(2) from the flue gas before it is released through the stack. The
addition of an SCR system is currently being initiated to reduce emissions of
NO(x). A lined ash disposal area on the site is used to contain the FGD system
sludge and fly ash.
Kintigh Unit 1 generates power at 24 kV. Two 100 percent capacity generator step
up transformers transform the power to 345 kV for interconnection to the 345 kV
bus at the substation. The Kintigh Substation is in turn interconnected to the
grid via two 345 kV transmission lines owned by NYSEG.
2.1.2 MILLIKEN STATION
The Milliken Station is located on the east shore of Cayuga Lake near the town
of Lansing, New York. This station consists of two operating units. Unit 1 was
placed in operation in 1955. Unit 2 began operation in 1958. Unit 1 is nominally
rated at 150 MW and Unit 2 is rated at 156 MW, which gives the station a total
generating capability of 306 MW. The station is situated on a 400-acre site
which slopes toward the lake.
The station is fueled with bituminous coal originating in Pennsylvania or West
Virginia. Coal is delivered primarily by rail, but delivery by truck is also
possible. Limestone for the FGD system is also delivered by rail. The station is
designed with a once-through cooling system using water from Cayuga Lake.
In 1992, the Milliken Station was selected to participate in the Department of
Energy ("DOE") Clean Coal Technology Program. The program provided for the
installation of low NO(x) burners, coal
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pulverizer replacements, electrostatic precipitator upgrades, installation of
heat pipe air heaters, control system upgrade, and installation of an FGD
System. This program was intended to evaluate new equipment and procedures for
burning coal in a cleaner fashion, which provided this station with significant
equipment upgrades and modernization and extended its useful life. NYSEG spent
approximately $100 million in connection with this program.
Milliken Units 1 and 2 generate power at 13.8 kV. Two 60 percent capacity
generator step up transformers are provided for each unit to transform the power
to 115 kV for interconnection to the 115 kV bus at the substation. The Milliken
Substation is in turn interconnected to the grid via three 115 kV transmission
lines and three 34.5 kV lines owned by NYSEG.
The station has black start capability via two additional startup diesel
generators.
2.1.3 GOUDEY STATION
This station operates on a 40-acre site adjacent to the Susquehanna River near
Johnson City, New York. The site was initially developed in the early 1900s. The
older units, designated as Units 1 through 6, were demolished and removed.
Today, this station consists of Unit 7, a 43 MW unit which has produced
electricity since 1943, and Unit 8, which is a 1951 vintage unit rated at 83 MW.
The total electrical generating capability for this station is 126 MW. In
addition to generating electricity, the Goudey Station operates as a
cogeneration facility by producing steam for export to a Lockheed-Martin plant
located adjacent to the site.
The bituminous coal used at Goudey is mined in Pennsylvania and delivered
primarily by rail. The operating permit for this station also allows clean wood
products and waste oil to be burned as alternative fuels. Electrostatic
precipitators have been installed to remove particulate from the flue gas. A
once-through cooling system utilizes the Susquehanna River for cooling plant
equipment.
Goudey Units 7 and 8 generate power at 13.8 kV. Three single-phase generator
step up transformers are provided for Unit 7 to transform the power to 34.5 kV
and 115 kV for interconnection to the 34.5 kV and 115 kV substations. A single
three-phase generator step up transformer is provided for Unit 8 to transform
the power to 115 kV for interconnection to the 115 kV substations. The Goudey
Substations are in turn interconnected to the NYSEG grid via six 115 kV
transmission lines and twelve 34.5 kV lines.
2.1.4 GREENIDGE STATION
The site for this station occupies 280 acres and is situated on the west side of
Seneca Lake near Dresden, New York. The Greenidge Station first generated
electricity in 1938. The initial development consisted of two units, which have
been retired from service and removed. Presently, this station consists of Unit
3, rated at 56 MW, and Unit 4, rated at 105 MW. These two units were placed into
service in 1950 and 1953, respectively.
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The Greenidge Station burns bituminous coal that is mined in Pennsylvania and
transported to the site by rail. This station has an operating permit for
burning waste wood. A wood pulverizing facility has been constructed onsite to
prepare wood products for combustion. In the period from 1995 to 1996, the Unit
4 combustion system was modified to incorporate an advanced gas reburn (AGR)
system to reduce emissions of NO(x). Both units at the Greenidge Station utilize
electrostatic precipitators to remove particulate from the flue gas. This
station uses water from Seneca Lake in a once-through cooling system for cooling
of plant operating equipment.
Greenidge Units 3 and 4 generate power at 13.8 kV. Two generator step up
transformers are provided for Unit 4 and a single generator step up transformer
is provided for Unit 3 to transform power to 115 kV for interconnection to the
115 kV substation. The Greenidge Substation is in turn interconnected to the
grid via four 115 kV transmission lines and three 34.5 kV lines.
2.2 STATION CHARACTERISTICS
The following Table 2-1 presents a summary of the significant station
characteristics and operating data.
TABLE 2-1
STATION SUMMARY
KINTIGH MILLIKEN GOUDEY GREENIDGE
Unit Unit 1 Unit 1 Unit 2 Unit 7 Unit 8 Unit 3 Unit 4
Electrical Rating, MW 675 150 156 43 83 56 105
Service Year 1984 1955 1958 1943 1951 1950 1953
Turbine Generator Manufacturer GE W GE W W GE GE
Turbine Inlet Pressure, psig 2,400 1,800 1,800 875 1,450 850 1450
Turbine Inlet Temp.,(0)F 1000/1000 1000/1000 1000/1000 900 1000/1000 900 1000/1000
Steam Generator Manufacturer B&W CE CE FW CE B&W CE
Type PC PC PC PC PC PC PC
Quantity 1 1 1 2 1 2 1
Primary Fuel Coal Coal Coal Coal Coal Coal Coal
Alternate Fuel(s) Clean Wood, Clean Wood, Gas Wood, Gas
Waste Oil Waste Oil
Cooling System Type Once Once Once Once Once Once Once
Through Through Through Through Through Through Through
Cooling Water Source Lake Ontario Lake Cayuga Lake Cayuga Susquehanna Susquehanna Lake Lake
River River Seneca Seneca
Flue Gas Emissions Control EP, S, SCR EP, S EP, S EP EP EP EP, SNCR
Equipment (Planned)
Low NO(x) Burners No Yes Yes No No No No
Gas Reburn System No No No No No Yes Yes
GE General Electric PC Pulverized Coal
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W Westinghouse
B&W Babcock & Wilcox
CE Combustion Engineering
FW Foster Wheeler
EP Electrostatic Precipitator
S SO(2) Wet Scrubber
SCR Selective Catalytic Reduction System
SNCR Selective Non-Catalytic Reduction System
3. PLANT CONDITION ASSESSMENT
This section documents the results of Stone & Webster's evaluation of each
facility. Stone & Webster conducted the evaluation through a combination of
comprehensive plant walkdowns, interviews with plant operating and maintenance
management, and a review of the plant conditions, assessment, testing, and
metallurgical records and reports. The plant walkdowns were conducted to assess
the overall operability, effectiveness of maintenance programs, apparent
condition, plant cleanliness and equipment configuration. At each facility, the
inspections included an examination of maintenance shops, warehouses,
laboratories and offices. The facilities were found for the most part to be well
maintained and were well equipped with appropriate tools, test equipment, and
computerized engineering and management systems.
3.1 KINTIGH TECHNICAL EVALUATION
3.1.1 UNIT OVERVIEW
As the newest of the four NYSEG generating stations, the Kintigh Station has
modern equipment and is in very good overall condition. Since NYSEG originally
intended to construct two similarly sized units on this site, the land area,
consisting of 1,722 acres, has room for future development. Some of the
infrastructure required for another unit, such as the coal handling system, has
already been installed.
This station benefited from a continuous policy by NYSEG to emphasize
maintenance and invest in new equipment to keep the station operating reliably.
In addition to a good maintenance program, this station also has been the
recipient of new emissions control equipment to control SO(2) and NO(x)
emissions.
BOILER
The Unit 1 coal-fired boiler is a Babcock & Wilcox balanced draft, drum-type
steam generator. This boiler produces 4,283,000 lbs./hr of superheated main
steam, which is supplied to the high pressure steam turbine at 2400 psig and
1000(Degree)F. The boiler reheater also produces 3,902,000 lbs./hr of reheated
steam, which is supplied to the intermediate pressure steam turbine at 517 psig
and 1000(Degree)F. The unit features an efficient energy conversion cycle with
seven stages of feedwater heating. A total of six coal pulverizers are
installed, with five pulverizers required for full load operating conditions.
The boiler combustion air system has two forced draft fans, two primary air fans
and two secondary air fans.
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The boiler draft system features an electrostatic precipitator manufactured by
Combustion Engineering, three induced draft fans, a Peabody FGD system and a 613
foot reinforced concrete stack. The design of the FGD system features six
individual limestone scrubbing modules. This type of arrangement allows for the
isolation of a module for maintenance or repair while the station is operating
with the remainder of the FGD system in service.
TURBINE GENERATOR
The steam turbine generator is a General Electric machine with a tandem-compound
turbine and a hydrogen cooled, synchronous electrical generator rated 727,894
kVA at 60 psig H(2), 24 kV, 60 Hz, 3600 rpm. Since February 1999, the steam
turbine generator experienced an increased vibration level at its number nine
bearing such that it is near its alarm level for vibration. The cause of the
vibration is not know at this time, and it will be investigated during the
spring outage. The cause of the vibration could be as simple as shaft
misalignment due to foundation settling to a worst case scenario of a crack
developing in the turbine rotor. Cracks in turbine rotors have been successfully
repaired in other turbine rotors. Therefore, we do not believe that the
vibration could indicate a situation which would require operating for extended
periods at a reduced output level while a replacement rotor was made. We believe
it would be very unusual for a turbine rotor of this age to develop a crack and
believe it is more likely that there is some other condition which is causing
the vibration. However, we cannot be certain what the cause of the vibration is
until the machine has been opened up and examined. Nevertheless, we do not
believe that the vibration will result in a loss of revenues due to reduced
operating levels for an extended period of time.
The turbine generator is furnished with a turbine supervisory instrumentation
(TSI) monitoring system, providing the capability to closely monitor and trend
the machine's mechanical performance and to anticipate potential problems.
INSTRUMENTATION AND CONTROLS
Control of the plant is accomplished from a centralized control room. The
control room is the operator interface for most major plant control systems. The
coordinated control system (CCS) integrates control of the boiler and turbine
with load demand. A plant computer system (PCS) provides a real time tool for
monitoring plant conditions, logging readings, trending, and performing
operational calculations. A burner control and fuel safety system is provided to
assure safe and efficient operation of boiler combustion.
Programmable logic controllers (PLCs) are used for major out-plant systems such
as coal and limestone handling, water treatment, and FGD systems. A continuous
emissions monitoring system is provided and will be upgraded to allow for onsite
report generation.
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ELECTRICAL SYSTEMS
Power is delivered to the substation via two 100 percent capacity generator step
up transformers. Station service power for the unit is provided by two 100
percent capacity station service transformers directly connected to the
generator 24 kV bus. The generator is provided with a 24 kV horizontal generator
breaker that allows the station service transformers to provide power to plant
auxiliaries during both operating and shutdown conditions. ANSI type metal clad
switchgear, ANSI type secondary unit substations, and NEMA motor control centers
distribute power throughout the plant at 13,800, 4,160, and 480 volts. Most
major station service distribution buses are provided with alternate power feeds
through tie breakers.
Two emergency diesel generators and a safe shutdown transformer connected to the
69 kV switchyard provide backup sources of power for safe shutdown of the unit.
One diesel generator is associated with the FGD system and the second generator
is associated with the balance-of-plant equipment. The station does not have
black start capability.
Three DC power systems are provided to supply stored energy to control,
instrumentation, and critical turbine generator loads. Each system consists of a
battery, redundant chargers, and associated distribution panels. Five
uninterruptible AC power systems ("UPS") provide clean and regulated power to
various loads such as instrumentation, computer systems and communications.
Cathodic protection is provided in concert with appropriate protective coatings
to mitigate effects of corrosion of underground metallic structures throughout
the plant.
Plant lighting, grounding, and lightning protection systems are also provided.
Plant communications systems include a Gai-Tronics page party system. After the
acquisition, there will be two electrical interfaces to the NYSEG system. The
generator interface will be at the load side of the generator step up
transformers. The second interface will be at the high voltage side of the
emergency station service transformer located in the switchyard.
BALANCE OF PLANT
The Kintigh Station has an extensive coal handling system which features a
rotary car dumper and adjoining car thawing shed. Once coal is dumped it is
transferred by conveyor to the coal pile or may be diverted directly to the Unit
1 coal silos. A stacker/reclaimer operates at the coal pile to unload the coal
and to recover it from the pile when necessary to fill the boiler silos. A
synthetic and clay liner has been installed under the coal pile to prevent water
from leaching through the coal pile into the underlying soil. Coal pile runoff
is directed to an adjacent holding pond for treatment. The coal storage capacity
is adequate to meet its operational needs.
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The SRC connects the station with Lockport, New York, located 15.5 miles to the
south. The SRC will be acquired by an affiliate of AEE. SRC will enter into a
coal haulage agreement with AEE.
Dry fly ash and scrubber sludge are collected and mixed together for transfer by
truck to the ash disposal area located on the site. When the present ash
disposal area is filled, it will be covered and re-vegetated.
Additional land is available on the site for future ash disposal.
3.1.2 CONDITION ASSESSMENT
MAINTENANCE AND REPAIR
The overall condition of the primary operating equipment at Kintigh is very
good. No significant equipment replacements have been required or made since the
station was placed in commercial operation. During the past six years, most of
the maintenance attention has been focused on replacement of coal conveyor belts
and restoration of flue gas duct lining downstream of the FGD System. Additional
projects have included modifying the fire protection system, installation of a
fly ash storage silo, and some tube replacements in the superheater and reheater
areas.
The generator stator has not been rewound. However, the AEE budget forecast
includes rewedging in the year 2000 and rewinding in the year 2010. The budget
forecast also includes projections for control system upgrades, PLC
replacements, large motor re-builds, and station battery replacements.
LOSS PREVENTION REPORTS
Loss Prevention Reports, prepared by Arkwright Mutual Insurance Company from
1996 to 1998, were examined to get an independent opinion of the station by this
insurance underwriter. Most of the reports show that the insurance
investigator's inspections coincided with outages, so it was possible to
internally inspect major equipment, such as the boiler. In general, the summary
opinions of equipment condition and station operation were very positive. The
insurance investigator stated that "Management continues to display an interest
in loss prevention and preventive maintenance practices and it is reflected in
the well-maintained condition of the plant's equipment."
HAZARDOUS MATERIALS
The presence of hazardous materials, such as asbestos and PCBs, was discussed
with the NYSEG staff. Stone & Webster was told that the health hazards posed
from use of asbestos were already recognized when Kintigh Unit 1 was being
designed, so a general prohibition of asbestos materials was part of the station
design criteria. As a result, asbestos materials were not used during
construction. In addition, station personnel stated that electrical equipment
does not contain PCBs.
Electrical equipment located in hazardous areas (such as the coal handling
buildings) appears to be adequately rated.
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FIRE PROTECTION SYSTEM
The initial station design included a comprehensive fire protection system which
included an electric motor-driven fire pump, a diesel engine-driven fire pump
and an electric motor-driven jockey pump for pressure maintenance. These pumps
all utilize water from Lake Ontario to supply a ring header fire piping system
extending throughout the plant. Water is distributed off the header to hydrants,
hose reels and branch lines supplying standpipes with hose stations, deluge
spray systems and sprinkler systems. Dry chemical extinguishers are positioned
throughout the station. Separate Halon and foam systems have also been
installed.
EQUIPMENT REDUNDANCY AND SPARE PARTS
The station design criteria show that substantial operating redundancy was used
in the original design. An examination of the critical pumps revealed that the
two condensate pumps are each 60 percent capacity, the feedwater system has two
steam-driven pumps, which are each 60 percent capacity, and a third electric
motor-driven pump, which is a 40 percent capacity pump. Primary air is delivered
with two 80 percent capacity fans, two 60 percent capacity forced draft air fans
are installed, the draft system has three 50 percent capacity induced draft fans
and the compressed air system has three 50 percent capacity compressors. The
ability to bypass certain equipment in the event of a breakdown or due to online
maintenance is incorporated in the station design. This amount of design
redundancy and operating flexibility promotes operational reliability.
The Kintigh Station maintains a good inventory of spare parts and includes large
components such as spare motors for major pumps and fans, and spare rotors for
the large axial fans.
3.1.3 AEE LIFE EXTENSION FORECAST
A review of the details of the AEE O&M forecast shows that the maintenance and
equipment replacement activities are reasonable for a coal-fired station of this
size and age. Stone & Webster believes the plant is capable of reliable
operations for its remaining useful life of 45 years provided it is operated and
maintained according the projected plan and budget.
In order to substantially reduce NO(x) emissions in the combustion gases, a
Babcock & Wilcox SCR system is being purchased for Unit 1. The SCR System is
budgeted at $30M. It will be constructed in the spring of 1999, with operation
expected in June 1999.
The overall configuration and design of the plant instrumentation and control
system are consistent with standard industry practice at the time the plant was
commissioned. This design philosophy should provide a system that will perform
near industry averages.
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Although the original design life expectancy of the control system components
was 35 to 40 years with normal maintenance, AEE has recognized and budgeted for
technology advances and parts obsolescence for this type of equipment which make
it prudent to forecast significant control system upgrades over the evaluated
life cycle.
The overall configuration and design of the electrical system provides
flexibility and redundancy that in many cases exceeds industry standard
practice. This design philosophy provides an electrical system that should
perform at or above industry averages.
The original design life expectancy of most electrical systems and components is
typically 35 to 40 years with normal maintenance, and without significant life
extension work. The AEE budget forecast has addressed items that have shorter
expected lives, such as batteries, major motor rewinds, and generator stator
rewinds.
3.2 MILLIKEN TECHNICAL EVALUATION
3.2.1 STATION OVERVIEW
Although Milliken was constructed in the 1950's, approximately $100 million has
been invested in significant life extension work and $100 million has been
invested in environmental emissions reduction equipment to make this a reliable
generating station. The life extension effort was completed in 1995.
In 1992, this station was selected to participate in the Clean Coal Technology
Demonstration Program sponsored by the Department of Energy. The emphasis of the
program was to demonstrate technology for burning coal in a cleaner manner. For
both units at Milliken, emissions control equipment was installed to reduce
SO(2) and NO(x) from the flue gas. To support the operation of this equipment,
new coal pulverizers and a heat pipe air heater were installed and the
electrostatic precipitators and the control systems were upgraded.
As a result of the well supported maintenance program and the significant
upgrades, this station should be able to operate reliably through the station's
projected remaining useful life of 38 years, provided it is operated and
maintained as anticipated in the Financial Projections.
BOILERS
The two boilers at Milliken were both manufactured by Combustion Engineering and
are very similar in construction. They are balanced draft, drum-type units with
reheat steam capability. Seven feedwater heaters are installed to preheat boiler
feedwater before it enters the economizers. Each boiler utilizes four Raymond
bowl mills to pulverize coal for combustion. Only three of the mills are
required to support the boilers at their maximum continuous rating.
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Flue gas leaving each boiler passes through an electrostatic precipitator for
removal of fly ash and then enters the common FGD system, where a limestone
slurry is used to remove sulfur dioxide. A common chimney is also shared by
Units 1 and 2. The chimney contains three individual flues for emissions from
both boilers and a common bypass, which is used if it is necessary to bypass
either segment of the FGD System.
TURBINE GENERATORS
Unit 1 consists of a Westinghouse Electric Company turbine generator. The steam
turbine is a tandem compound, triple flow, condensing, reheat machine. It drives
a hydrogen-cooled, synchronous electrical generator rated at 182,647 kVA at 0.85
power factor, 13,800 kV and 60 hertz.
Unit 2 consists of a General Electric Company turbine generator. The steam
turbine is a tandem compound, triple flow, condensing, reheat machine. It drives
a hydrogen-cooled, synchronous electrical generator rated at 182,647 kVA at 0.85
power factor, 45 psig H(2), 18 kV and 60 hertz.
INSTRUMENTATION AND CONTROLS
Control of both units is accomplished from a common control room. The plant has
undergone a distributed control system (DCS) upgrade.
PLCs are used for coal handling, water treatment, and FGD systems.
A continuous emissions monitoring system (CEMS) is provided. The system is
budgeted for upgrade to allow onsite generation of emission reports.
ELECTRICAL
Power from Milliken Units 1 and 2 is delivered to the 115 kV substation via two
60 percent capacity generator step up transformers for each unit. Station
service power for each unit is provided by one 100 percent capacity station
service transformer directly connected to the generator 13.8 kV output bus. ANSI
type metal clad switchgear, ANSI type secondary unit substations, and NEMA motor
control centers distribute power throughout the plant at 4,160, 480, and 120/208
volts. Most major station service distribution buses are provided with alternate
power feeds via tie breakers.
An emergency diesel generator and a safe shutdown transformer connected to the
34.5 kV switchyard provide backup sources of power for safe shutdown of the
unit.
DC power systems are provided to supply stored energy to control,
instrumentation, and critical turbine generator loads. Each system consists of a
battery, redundant chargers, and associated distribution panels.
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An uninterruptible AC power supply (UPS) provides clean and regulated power to
various loads such as the DCS and communication systems.
Plant staff indicated that some cathodic protection is provided for the suction
and discharge lines to the lake.
Grounding and lightning protection systems are provided and appear adequate. The
plant is well lit and the lighting system appears to have been recently
upgraded.
Plant communications systems include a Gai-Tronics page party system.
After the acquisition, there will be three electrical interfaces to the NYSEG
system. Each of the generator interfaces will be at the load side of the
respective 115 kV generator breakers located in the substation. The third
interface will be at the high voltage side of the emergency station service
transformer also located in the switchyard.
The unit has black start capability via two additional startup diesel generators
located onsite.
BALANCE OF PLANT
The coal delivery system at Milliken utilizes a linear-type train unloading
system. This is a result of the terrain, since the site slopes down to the lake
and the railroad enters the site near the lake shore. Coal cars are arranged in
a row outside a rotary car dumper and individually pushed onto the dumper by the
engine for unloading. Coal is conveyed from the rotary car dumper to the coal
pile using a stackout conveyor with an unloading boom. Coal is reclaimed from
the pile, conveyed to primary crushers and then is transferred to the coal
bunkers adjacent to the boilers. The coal storage capacity is adequate to meet
its operational needs.
This station uses a once-through cooling water system for cooling the operating
equipment. A deep water inlet pipe was installed to bring water from Lake Cayuga
to the circulating water system and the service water system.
Fly ash and boiler bottom ash are generally saleable by-products at this
station. The FGD system produces commercial quality gypsum, which could be sold
but at present a market has not been identified. The gypsum is currently given
to a wallboard manufacturer that pays the expense of removing it from the
station.
The FGD system was installed in 1994, as part of the DOE Clean Coal Technology
Program. The system uses a wet limestone process which is based on low pH sulfur
dioxide absorption. Operation of the scrubbing system in this manner avoids the
scaling problems associated with limestone wet scrubbers which normally account
for the high maintenance expenses and unplanned outages typical of this
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equipment. Plant personnel consider this FGD system to be very reliable and we
have no reason to disbelieve their assessment as the plant's availability
figures have been good.
3.2.2 CONDITION ASSESSMENT
MAINTENANCE AND REPAIR
The Milliken Station has experienced many equipment replacements or upgrades
during its years of operation. The following is a summary listing of the most
significant modifications.
In 1967, the high temperature reheater was reconstructed in Unit 1 and in 1972
both the high temperature superheater and the high temperature reheater were
reconstructed in Unit 2.
In 1979, an effort to increase the capability of Unit 1 from 146 to 162 net MW
was initiated. To accomplish this, the condensate pumps and the feedwater pumps
were modified to increase their output and new larger electric motors were
installed. The original heater no. 4 was also removed and replaced. The steam
turbine capability was increased by installing a new high pressure rotor and a
new intermediate pressure rotor. During this period, the boiler was also
modified with the installation of a new primary superheater and a new high
temperature reheater. In 1982, Unit 2 was also modified to increase the
electrical generating capability.
In the period from 1983 to 1984, two new fly ash silos were purchased and an
Ultra Filter Plant was installed. In 1985, the Unit 1 high temperature reheater
was reconstructed. Three years later, the Unit 2 high temperature superheater
and the high temperature reheater sections were reworked. The Unit 1 generator
was rewound in 1986.
The Unit 2 generator was rewound in 1988.
During the period from 1993 to 1994, the superheater crossover, the reheater
crossover, the high temperature superheater outlet header, the high temperature
reheater outlet header and the boiler corner tubes were reconstructed in the
Unit 1 boiler and the boiler corner tubes were reconstructed in the Unit 2
boiler. The DOE upgrades consist primarily of the FGD unit and other clean coal
technologies.
LOSS PREVENTION REPORTS
The Factory Mutual inspection reports for both boilers were reviewed for the
past three years and no significant findings were emphasized by the inspectors.
The boilers were found to be in good operating condition during each inspection.
HAZARDOUS MATERIALS
Asbestos materials were installed initially in this station. An asbestos survey
has been conducted and asbestos locations identified. Whenever repairs and
modifications are required in an area where asbestos materials will be
disturbed, a licensed asbestos contractor is hired to isolate the area, remove
the asbestos
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and clean the work area before work continues. Once asbestos has been removed, a
label is applied to the outside surface of the piping or equipment declaring
that the insulation is an asbestos free product. The station still contains some
asbestos products.
Newer electrical equipment in hazardous areas (such as the tripper gallery) is
rated class 2 division 2. Older electrical equipment located in these areas is
not rated.
Plant staff indicated that PCBs in oil filled electrical equipment were within
allowable limits.
FIRE PROTECTION SYSTEM
The service water system serves as the water supply for the fire service booster
pump. This electric motor-driven pump provides water to the fire water header
supplying the hydrants, fire hose reels and the sprinkler system around the
electrical transformers. A second gasoline engine-driven fire pump can be
started in the event the electric fire pump will not operate.
EQUIPMENT REDUNDANCY AND SPARE PARTS
Stone & Webster believes the plant has sufficient redundancy to meet its
projections. When considering the primary operating equipment, a spare coal
pulverizer is available in each unit and a single (50 percent capacity) boiler
feed pump is arranged to be a spare pump shared between the two units. The
station is designed with many operating bypasses in the piping systems to allow
equipment to be bypassed whenever isolation is necessary.
3.2.3 AEE LIFE EXTENSION FORECAST
The AEE Operating and Maintenance (O&M) forecast for the projected term has been
reviewed and is consistent with the historical O&M experiences and is comparable
to similar coal-fired stations of this size. In the near term, the capital
budget forecast provides for significant boiler and turbine plant upgrades in
the years 2001 and 2002. Thereafter, the boilers follow a two-year maintenance
schedule and the turbine generators receive major maintenance on a 10 year
schedule. Stone & Webster believes the operating and capital expenditure budget
and plan are adequate to support the projected remaining useful life.
The overall configuration and design of the plant instrumentation and control
systems are consistent with standard industry practice. The original design life
expectancy of system components is 35 to 40 years with normal maintenance. AEE
has recognized that technology advances and parts obsolescence for this type of
equipment make it prudent to forecast upgrades of distributed control systems,
programmable logic controllers, and continuous emissions monitoring systems over
the evaluated life cycle. Based on these considerations, the instrument and
control systems should perform at or near industry averages.
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The overall configuration and design of the electrical system provide
flexibility and redundancy consistent with industry standard practice for the
vintage of the plant. Electrical equipment supplying power to environmental
control systems (precipitator and FGD) was installed with the associated
environmental control system. Balance of plant electrical equipment, for the
most part, is as supplied with the original plant. The original design life
expectancy of most electrical systems and components is typically 35 to 40 years
with normal maintenance and without significant life extension work. The
originally furnished electrical systems and components for Milliken are at or
beyond normal design life expectancy. Considering the rugged nature of the
electrical equipment provided, and the NYSEG maintenance and life extension
programs to date, it is reasonable to expect that this equipment will remain
operable until replaced under the normal replacement program. Spare parts
availability may also become a consideration during this extended life cycle.
Above average failure rates and maintenance can also be anticipated for plant
wire and cable due to embrittlement of jacket and insulation material. The AEE
budget forecast has addressed several life extension items such as major motor
rewinds. The equipment age and design philosophy combine to provide an
electrical system that should perform near industry averages for the vintage of
the plant, which supports the Financial Projections.
3.3 GOUDEY TECHNICAL EVALUATION
3.3.1 STATION OVERVIEW
The Goudey Station, located near Johnson City in southern New York state, was
constructed early in this century. The older units, designated as Units 1
through 6, have been demolished. Presently the station has Units 7 and 8 in
operation. Unlike the other NYSEG stations, the Goudey station operates in a
cogeneration configuration under an existing contract for steam sales to a
nearby Lockheed-Martin plant.
While this station has had recent boiler and turbine maintenance work, it has
not received an extensive upgrade of all plant operating systems and does not
have the same level of equipment redundancy designed into the station as the
newer stations. However, we believe AEE has budgeted for sufficient maintenance
and renovation work to enable the plant to meet its projected operating levels
for the 38 years remaining in its expected useful life.
BOILERS
Unit 7 was constructed with two Foster-Wheeler opposed-wall, drum type,
pulverized coal-fired steam generators designed for balanced draft operation.
Each of the boilers can produce 200,000 lbs./hr of superheated main steam at 875
psig and 885(Degree)F. The boilers were not designed with reheat steam
capability. The feedwater cycles each operate with four stages of feedwater
heating. Two Raymond bowl type pulverizers were provided with each boiler to
crush the coal before it is introduced to the burners.
The larger Unit 8 boiler is a balanced draft, tangentially-fired, drum type
steam generator manufactured by Combustion Engineering. This boiler can produce
560,000 lbs./hr of superheated high pressure steam
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at 1,465 psig/1,005(Degree)F and superheated reheat steam at 392
psig/1,000(Degree)F. Five stages of feedwater heating are used before feedwater
enters the economizer. This boiler has four Raymond bowl type pulverizers
installed.
TURBINE GENERATORS
A single Westinghouse Electric Company turbine generator was installed on Unit
7. The steam turbine is a tandem-compound, two-cylinder, impulse-reaction type,
condensing machine designed for operation with inlet steam conditions of 875
psig/900(Degree)F. The electrical generator is rated at 50,312 kVA, 13.8 kV at
0.866 power factor and 60 hertz.
Unit 8 utilizes a Westinghouse Electric turbine generator. This is a
two-cylinder, tandem compound, condensing, reheat turbine. It is designed for
inlet steam conditions of 1450 psig and 1,000/1,000(Degree)F. The electrical
generator is hydrogen-cooled and rated for 75,000 kVA at 13.8 kV, 0.80 power
factor and 60 hertz.
INSTRUMENTATION AND CONTROLS
Control of both units is accomplished from a common central control room.
Centralization was completed in 1994. The plant has undergone a distributed
control system upgrade for both units.
The station has a temperature and vibration monitoring system integrated with
the distributed control system for major rotating equipment.
The continuous emissions monitoring system was significantly upgraded in 1994
and is budgeted for an additional upgrade to allow onsite generation of emission
reports.
ELECTRICAL
Three single phase generator step up transformers for Unit 7 and a single three
phase generator step up transformer for Unit 8 supply power to the 34.5 kV and
115 kV substations. Auxiliary power for each unit is provided by a station
service transformer connected to the generator output bus. ANSI type metal clad
switchgear, ANSI type secondary unit substations, and NEMA motor control centers
distribute power throughout the plant at 2,400, 480, 240, and 120/208 volts.
Most major station service distribution buses can be cross connected to the
opposite unit's station service transformer for reliability.
An emergency diesel generator and an emergency station service transformer
directly connected to the 34.5 kV substation are provided to support safe
shutdown of the units.
DC power systems are provided to supply stored energy to control,
instrumentation, and critical turbine generator loads.
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An uninterruptible AC power supply (UPS) provides clean and regulated power to
various loads such as the distributed control system and communication systems.
Grounding and lightning protection systems are provided and appear adequate. The
plant is well lit and the lighting system appears to have been recently
upgraded.
Plant communications systems include a Gai-Tronics page party system.
After the acquisition, there will be four electrical interfaces to the NYSEG
system. One Unit 7 generator interface will be at the load side of the 115 kV
generator breaker located in the 115 kV substation, and the second Unit 7
generator interface will be at the load side of the 34.5 kV generator step up
transformer in the 34.5 kV substation. The Unit 8 generator interface will be at
the load side of the 115 kV generator breaker located in the 115 kV substation.
The fourth interface will be at the high voltage side of the emergency station
service transformer also located in the 34.5 kV substation.
The unit does not have black start capability.
BALANCE OF PLANT
Both units at the Goudey Station are cooled with water from the Susquehanna
River. When Unit 8 was constructed, it was necessary to construct a dam across
the river to raise the river water level at the intake. This dam is still in
place and was recently repaired by NYSEG. The station uses a once-through
cooling system, so water is returned to the river after the equipment has been
cooled.
Coal arrives at the station by train in bottom dump type rail cars. The coal is
dumped into a rail hopper and then conveyed to a crusher to reduce the delivered
size to -3/4 x 0 inches. A bucket elevator transfers the coal to the bunker area
where it is unloaded into the unit coal bunkers. The on-site coal storage
capacity is adequate for the plant's needs.
All of the boilers are equipped with electrostatic precipitators to remove fly
ash before the combustion emissions are discharged through the stacks.
Fuel oil is used at Goudey Station for startup and low load operation. An oil
storage tank and rotary pumps are provided to transfer oil to the burners.
Normally, annual oil consumption for the station is about 100,000 gallons.
3.3.2 CONDITION ASSESSMENT
MAINTENANCE AND REPAIR
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In 1980, the primary superheater, the high temperature superheater and the high
temperature sections of the Unit 8 boiler were replaced. Three years later, the
primary and secondary superheater sections and the attemperator water
circulators were repaired on both of the Unit 7 boilers.
During 1989, repairs were conducted on the secondary superheater outlet headers
on both of the Unit 7 boilers.
In 1991, the Unit 8 boiler was extensively reworked. This involved replacing
tubes in the primary superheater, the secondary superheater and the economizer.
Additional surface area was added to the reheater and the backpass roof tubes
were reworked. Repairs were also conducted on the superheater crossover piping,
the primary superheater header and the economizer inlet header.
The Unit 8 electrical generator was rewound in 1986 and the Unit 7 electrical
generator was rewound in 1991.
LOSS PREVENTION REPORTS
The station inspection reports for the Goudey Station were not the Factory
Mutual Reports used at other stations for reporting operating conditions, but
rather inspection reports conducted by the Grinnell Fire Protection Systems
Company. A summary of the reports prepared from 1995 to 1998 shows that the
station passed the annual inspections.
HAZARDOUS MATERIALS
This station monitors the locations where asbestos has been used. During
modification or repair work in areas where asbestos is present, the asbestos is
first properly removed and the area cleaned. Once the asbestos has been removed
and the work is complete, identification labels are applied to the outside
surfaces of the lagging or equipment to indicate the area is free of asbestos.
It is estimated that over 50 percent of the original asbestos has been removed.
Newer electrical equipment in hazardous areas (such as the tripper gallery) is
rated class 2 division 2. Older electrical equipment located in these areas is
not rated.
Plant staff indicated that PCBs in oil filled electrical equipment were within
allowable limits.
FIRE PROTECTION SYSTEM
The Johnson City water system is used as the source of fire water at the
station. The water is piped to hydrants and hose stations around the station.
When Unit 8 was constructed, an electric motor-driven booster pump was installed
to increase the pressure of the city water by approximately 50 psi.
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EQUIPMENT REDUNDANCY
Goudey Station does not incorporate much equipment redundancy in the station
design. The data book for Unit 8 states that one of the four Raymond bowl mills
was intended to be an operational spare, but plant staff stated that it is
necessary to operate all four mills to reach the maximum continuous rating.
Because of the minimal redundancy, if a critical component breaks down, it is
necessary to reduce unit load or shut the unit down. However, we believe that
Goudey's historical performance supports its projected performance levels.
3.3.3 AEE LIFE EXTENSION FORECAST
AEE is currently planning to upgrade the boilers, the turbine generator, balance
of plant equipment and install a continuous emissions monitoring system over the
next five years. These improvements will enhance the station reliability.
The overall configuration and design of the plant instrumentation and control
systems are consistent with standard industry practice. The original design life
expectancy of system components is 35 to 40 years with normal maintenance. The
distributed control systems for the two units are approximately 15 years old,
and therefore the equipment has adequate life to operate for some time. Based on
these considerations, the instrument and control systems are expected to have
average reliability and average maintenance.
The overall configuration and design of the electrical system provide
flexibility and redundancy consistent with industry standard practice for the
vintage of the plant. Electrical equipment supplying power to environmental
control systems (precipitator and flue gas recirculation) was installed with the
associated environmental control system. Balance of plant electrical equipment
for the most part is as supplied with the original plant. The original design
life expectancy of most electrical systems and components is typically 35 to 40
years with normal maintenance, and without significant life extension work. The
originally furnished electrical systems and components for Goudey are at or
beyond normal design life expectancy. Considering the rugged nature of the
electrical equipment provided, and the NYSEG maintenance and life extension
programs to date, it is reasonable to expect that this equipment will remain
operable until it is replaced under the life extension program. Spare parts
availability may also become a consideration during this extended life cycle.
Above average failure rates and maintenance can also be anticipated for plant
wire and cable due to embrittlement of jacket and insulation material. The AEE
budget forecast has addressed these and other life extension items such as major
motor rewinds. The equipment age and design philosophy combine to provide an
electrical system that should perform at or near industry averages for the
vintage of the plant, which supports the Financial Projections.
3.4 GREENIDGE TECHNICAL EVALUATION
3.4.1 STATION OVERVIEW
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The two original electrical generating units at this site were retired from
service and then removed. As a result, the two existing units are designated as
Units 3 and 4.
The Greenidge Station was selected to participate in a research and development
program to evaluate natural gas reburning. This technology allows coal to be
burned more cleanly. In addition to improving quality of the flue gas emissions
and the operational flexibility of the station, this program also upgraded plant
equipment and systems.
During the past 15 years, this station has benefited from a systematic effort by
NYSEG to replace older outdated equipment. An examination of the station records
indicates that a great deal of the original equipment in both units has been
replaced and consequently the overall condition of the station is very good.
We believe AEE has budgeted for sufficient maintenance and renovation work to
enable the plant to meet its projected operating levels for the 38 years
remaining in its expected useful life.
BOILERS
Unit 3 utilizes two Babcock & Wilcox pulverized coal-fired, balanced draft,
drum-type steam generators. Each boiler is rated to produce 269,000 lb./hr of
superheated steam at 875 psig and 910(Degree)F. Neither unit has reheat steam
capability. Each of the boilers has a forced draft fan, an induced draft fan,
two ball-type pulverizers, two condensate pumps, three boiler feedwater pumps
and five stages of feedwater heating.
Unit 4 has a single Combustion Engineering pulverized coal-fired, balanced
draft, drum-type steam generator. This boiler is rated to produce 732,000 lb./hr
of superheated main steam at 1465 psig and 1005(Degree)F and 581,000 lb./hr of
superheated reheat steam at 366 psig and 1005(Degree)F. The boiler is complete
with two forced draft fans, two induced draft fans, four Raymond bowl type
pulverizers, two vertical condensate pumps, three boiler feed pumps and six
stages of feedwater heating.
TURBINE GENERATORS
The turbine generator for Unit 3 was furnished by the General Electric Company.
The steam turbine is a multi-stage, tandem compound, double flow, condensing,
impulse type design. The hydrogen cooled generator is rated for 58,824 kVA, 13.8
kV at 0.85 power factor and 60 hertz.
The Unit 4 turbine generator was also manufactured by the General Electric
Company. The steam turbine is a tandem compound, double flow reheat, condensing
machine. The hydrogen cooled, electrical generator is rated for 105,882 kVA,
13.8 kV at 0.85 power factor and 60 hertz.
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INSTRUMENTATION AND CONTROLS
The plant has undergone a distributed control system and control room upgrade
for both units in the mid 1980s. The controls upgrade fully automated the plant.
The continuous emissions monitoring system was extensively refurbished in 1993
and is budgeted for an additional upgrade to allow onsite generation of emission
reports.
ELECTRICAL SYSTEMS
Two generator step up transformers for Unit 4 and a single generator step up
transformer for Unit 3 deliver power to the 115 kV substation.
Station service power for each unit is provided by a station service transformer
directly connected to the generator 13.8 kV output bus. Station service power is
distributed within the plant at 2,400, 480, and 120/208 volts. Auxiliary power
for each unit is provided by a station service transformer connected to the
associated unit's generator output bus. ANSI class metal clad switchgear and
ANSI class secondary unit substations distribute power throughout the plant at
2,400, 480, and 120/208 volts. Most major station service distribution buses can
be cross connected to the opposite unit's station service transformer for
reliability.
An emergency diesel generator and an emergency station service transformer,
directly connected to the 34.5 kV substation, are provided to support safe
shutdown of the units.
DC power systems are provided to supply stored energy to control,
instrumentation, and critical turbine generator loads. An uninterruptible AC
power supply provides clean and regulated power to various loads such as the
distributed control system and communication systems.
Grounding and lightning protection systems are provided and appear adequate. The
plant is well lit and the lighting system appears to have been recently
upgraded.
Plant communications systems include a Gai-Tronics page party system.
After the acquisition, there will be four electrical interfaces to the NYSEG
system. One interface for each unit will be at the load side of the 115 kV
generator breaker in the substation. The third interface will be at the high
voltage side of the Unit 4 emergency station service transformer in the 34.5 kV
substation. The fourth interface will be at the high voltage side of the Unit 3
emergency station service transformer bank in the 34.5 kV substation.
The unit does not have black start capability.
BALANCE OF PLANT
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A once-through cooling system is used to cool the operating equipment at the
station. Piping is used to transfer deep water from Seneca Lake to the pump
structure, where it is pumped through the station for cooling purposes. After
cooling the equipment, the water is discharged back to the lake.
The Greenidge Station normally receives coal by train. The coal handling system
was designed for bottom dump rail cars which would discharge coal into a track
hopper. After dumping, coal is transferred to a crusher for the first stage of
crushing and then conveyed to the coal bunkers at the boilers. The on-site coal
storage is adequate for the plant's needs.
The operating permit for this station provides for the combustion of clean wood
waste. It can burn up to 10 percent wood in its fuel. Wood arrives at the site
already sized to approximately 3 x 0 inches. It is loaded into a hopper and
transferred to a mill, where it is reduced further and then pneumatically
transferred to the Unit 4 burner area for injection into the combustion zone.
Historically, it has burned little wood on a sustained basis.
The Advanced Gas Reburn (AGR) program has primarily benefited Unit 4. An
overfire air system and natural gas nozzles have been installed on this unit
above the coal burners to produce a reburn zone for reducing the NO(x) in the
boiler flue gas. The overfire air system was installed on Unit 3.
Both units use electrostatic precipitators for control of particulate emissions
before flue gas is discharged through the stack.
3.4.2 CONDITION ASSESSMENT
MAINTENANCE AND REPAIR
Many modification and repair projects have been conducted at the Greenidge
Station during its operating life. The following is a summary of the major
repair efforts.
In 1968, the high temperature reheater on the Unit 4 boiler was reworked. In the
period from 1976 to 1977, the same boiler received extensive boiler tube work.
This work involved modifying the economizer, primary superheater and the high
temperature superheater.
During the early 1970s, the high pressure cylinder of the Unit 3 steam turbine
began to develop cracks from thermal cyclical stress. A new redesigned main
cylinder was installed in 1973. The turbine blading was also modified at this
time. This allowed the electrical generator to be uprated.
In 1985, the coal bunkers for the Unit 4 boiler were relined and new stock
gravimetric feeders were added to replace the original coal feeders. Also, at
this time the evaporator was removed from service and a new demineralizer was
installed.
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The Unit 4 boiler was repaired again in 1986-87. This time the high temperature
reheater, the superheater crossover piping, the reheater crossover piping, the
cold reheat crossover piping, the high temperature superheater outlet header,
the high temperature reheater outlet header, the low temperature reheater and
the waterwalls were all repaired. The condenser was also re-tubed at this time.
In 1988, the two Unit 3 boilers both had piping and tube surfaces replaced in
the primary superheaters, the secondary superheaters, and the superheat headers.
In 1989, the Unit 4 economizer inlet headers were repaired.
The waterwalls were repaired on the Unit 3 boilers in 1998. This involved
replacing approximately 35 feet of the sidewall tubing on both sides and about
43 feet of the waterwall tubes on the rear wall. The front walls still have the
original tubing.
The Unit 4 generator stator was rewound in 1996.
During the past 15 years, a considerable effort has been expended updating Unit
4 operating equipment. This has involved replacing the high pressure heaters
with new heaters, replacing the condenser air ejector, replacing the main steam
stop valve, replacing the hydrogen coolers, rebuilding the condensate pumps and
rebuilding the boiler feed pumps. Similarly, the Unit 3 boilers were upgraded
during this period with new feedwater heaters, elimination of the evaporator,
new boiler feed pumps, new condensate pumps, new coal burners, new variable
speed coal feeders, new primary air fans and new sootblowers.
HAZARDOUS MATERIALS
Asbestos materials were used in the original station construction. The station
has a formal asbestos abatement program in place. All of the asbestos materials
have been identified and when a modification or repair will disturb the existing
asbestos insulation, it is removed and replaced with a non-asbestos insulation
product. After the work is completed, asbestos free labels are posted in the
area.
Newer electrical equipment in hazardous areas (such as the tripper gallery) is
rated class 2 division 2. Older electrical equipment located in these areas is
not rated.
Plant staff indicated that PCBs in oil filled electrical equipment were within
allowable limits.
FIRE PROTECTION SYSTEM
The fire water protection system uses Seneca Lake water and has an electric
motor-driven fire pump and an alternate gas engine driven fire pump. A fire
water header is used to distribute fire water to hydrants, hose reels and
sprinklers. The control room and electrical equipment rooms have Halon systems
installed. Portable fire extinguishers are located around the station.
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EQUIPMENT REDUNDANCY
The Greenidge Station does not have much design redundancy incorporated into the
major equipment. Unit 3 was designed with a common spare boiler feed pump for
the two boilers and Unit 4 was designed with a spare circulating water pump, a
spare boiler feed pump and a spare pulverizer. Bypass capability exists in most
piping systems to allow equipment to be bypassed when necessary. However, we
believe the historical performance of the units supports the projected
performance.
3.4.3 AEE LIFE EXTENSION FORECAST
The AEE Operation and Maintenance (O&M) forecast for the Greenidge Station
reveals a consistent program for maintaining and repairing the equipment, which
has been performing reliably. The next scheduled major expenditures for
overhauling the turbine generators are planned in 2004 and 2005 for Units 3 and
4 respectively and then each will be overhauled nine years later. Major
maintenance on the boilers is forecast to be accomplished every two years.
The configuration and design of the plant controls provide a fully automated
system. The original design life expectancy of system components is 35 to 40
years with normal maintenance. The distributed control systems for the two units
are approximately 15 years old. Therefore the equipment has adequate life to
operate until it is replaced in the life extension program. Based on these
considerations, the instrument and control systems are expected to have average
reliability and average maintenance.
The overall configuration and design of the electrical system provides
flexibility and redundancy consistent with industry practice for the vintage of
the plant. Electrical equipment supplying power to environmental control systems
(precipitator) was installed with the associated environmental control system.
Balance of plant electrical equipment for the most part was supplied with the
original plant. The original design life expectancy of most electrical systems
and components is typically 35 to 40 years with normal maintenance, and without
significant life extension work. The originally furnished electrical systems and
components for Greenidge are at or beyond normal design life expectancy.
Considering the rugged nature of the electrical equipment provided, and the
NYSEG maintenance and life extension programs to date, it is reasonable to
expect that this equipment will remain operable until it is replaced under the
life extension plan. Spare parts availability may also become a consideration
during this extended life cycle. Above average failure rates and maintenance can
also be anticipated for plant wire and cable due to embrittlement of jacket and
insulation material. The AEE budget forecast has addressed several life
extension items such as major motor rewinds. The equipment age and design
philosophy combine to provide an electrical system that should perform at or
near industry averages for the vintage of the plant, which supports the
Financial Projections.
4. PERFORMANCE
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Stone & Webster reviewed the heat rate and capacity factor projections used in
the Financial Projections. We believe the heat rate projections are reasonable
and consistent with historical experience. Capacity factor is a function of
plant availability and dispatch. AEE has retained London Economics to provide
projections for dispatch. London Economics has projected the plants will be
dispatched 100 percent of the time they are available to run and therefore the
capacity factors will be equal to the availability of the plants to run.
Therefore, we have assumed that capacity factors will be equal to availability
factors and we have commented on the reasonableness of the availability
projection. For Kintigh, AEE has projected capacity factors of 98 percent for
the last six months of 1999, 94 percent for the next three years and 92 percent
for each non-overhaul year thereafter. Milliken has a projection of 96 percent
for the last six months of 1999 and 92 percent for each non-overhaul year after
2002 with a projection of 93 percent for non-overhaul years before 2002. The
capacity factors for the other plants are less than or equal to 90 percent. We
believe that Kintigh can sustain an availability of 94 percent in 2000 to 2003.
Kintigh (for years after 2003) and Milliken can sustain an availability of 92
percent during non-overhaul years. We also believe that the projections for the
last six months of 1999 are achievable since no outages are planned. This
assumes AEE is able to recover from the outage slip already experienced, which
we believe they can. Both of these plants have demonstrated availability factors
greater than 92 percent in previous years and should be able to demonstrate
their short term availability projections for the last six months of 1999 since
no outages are planned for those months. AES is a capable operator who regularly
achieves exceptional results from its plants. We are comfortable that AEE will
achieve high enough availabilities to support the projected capacity factors. We
believe AEE will likely be able to exceed the projected capacity factors from
time to time by exceeding the projected availability levels.
4.1 BASIS OF POWER PLANT HEAT RATES
The thermal performance of a fossil power plant is represented by the ratio of
the heat input (based on the higher heating value of the fuel) to the net
electrical output (measured on the low voltage side of the main transformers),
measured in British thermal units per kilowatt-hour (Btu/kWh). Power plants are
most efficient (a lower heat rate) the closer they are operated to their design
basis conditions, typically 100 percent of electrical output rating. When a
power plant is dispatched at lower loads the heat rate will increase (efficiency
decreases). Therefore, for optimal thermal performance, power plants generally
need to operate at or near full load conditions.
The historical thermal performance of the units to be acquired is characterized
in the following table. Additionally, the table contains most recent year
information, projected thermal performance taken from the Financial Projections,
and historical average values. This table provides a representation of
historical, present day, and anticipated performance of each power plant. The
addition of SCRs to Kintigh and possibly Milliken should not noticeably affect
these units' heat rates.
Stone & Webster's opinion on the plausibility of the projected thermal
performance based on historical and present day data for each power plant is
discussed below. In Stone & Webster's analysis of the plausibility of projected
thermal performance, we placed particular importance on historical performance
for periods within the 11 years of data in Table 4.1-1 during which the electric
generation demand for the
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respective units was greatest because these periods best illustrate the
performance capabilities of the units under conditions that most closely
resemble those assumed in the Financial Projections.
TABLE 4.1-1
UNIT HEAT RATES
YEAR KINTIGH MILLIKEN MILLIKEN GOUDEY GOUDEY GREENIDGE GREENIDGE
UNIT 1 UNIT 2 UNIT 7 UNIT 8 UNIT 3 UNIT 4
1988 9,286 9,445 9,392 12,512 10,076 12,496 9,845
1989 9,230 9,447 9,398 12,757 10,216 12,278 9,715
1990 9,228 9,401 9,391 12,901 10,242 12,539 10,012
1991 9,207 9,388 9,417 13,130 10,273 12,421 9,957
1992 9,222 9,429 9,381 12,723 10,073 12,380 9,957
1993 9,254 9,381 9,485 12,655 10,102 12,565 9,897
1994 9,262 9,318 9,470 12,868 10,127 12,732 9,961
1995 9,312 9,709 9,644 -- 10,195 12,854 9,985
1996 9,426 9,706 9,779 13,205 10,309 12,733 9,981
1997 9,464 9,707 9,636 12,959 10,298 -- 9,939
1998 9,266 9,805 9,716 12,659 10,281 13,078 10,003
1988-1998 Average 9,287 9,521 9,519 12,837 10,199 12,607 9,932
Financial Projections 9,271 9,700 9,700 12,841 10,359 12,600 9,850
4.2 UNIT HEAT RATES
KINTIGH STATION
Unit 1
Stone & Webster believes that the projected heat rate (9,271 Btu/kWh) contained
in the Financial Projections for Kintigh Unit 1 is reasonable and achievable.
Both the historical average heat rate of 9,228 Btu/kWh (for consecutive years of
operation 1989-1993 when electric generation demand was greatest) and most
recent year heat rate data (9,266 Btu/kWh) are lower than the projected heat
rate contained in the Financial Projections. Based on this comparison of data,
and if the unit is operated at or near full load, Stone & Webster believes the
projected heat rate is achievable.
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MILLIKEN STATION
Unit 1
Stone & Webster believes that the projected heat rate (9,700 Btu/kWh) contained
in the Financial Projections for Milliken Unit 1 is reasonable and achievable.
The historical average heat rate of 9,383 Btu/kWh (for consecutive years of
operation 1990-1994 when electric generation demand was greatest) is lower than
the heat rate contained in the Financial Projections. The average heat rate for
1995 through the third quarter of 1998 is approximately 9,750 Btu/kWh, which is
slightly higher than the projected heat rate value. We believe that the higher
heat rate during the 1995 through 1998 time period is due, at least in part, to
the addition of a wet scrubber which will continue into the future. Based on
this comparison of data, and if the unit is operated at or near full load as
planned, Stone & Webster believes the projected heat rate is achievable.
Unit 2
Stone & Webster believes that the projected heat rate (9,700 Btu/kWh) contained
in the Financial Projections for Milliken Unit 2 is reasonable and achievable.
The historical average heat rate of 9,447 Btu/kWh (for consecutive years of
operation 1988-1995 when electric generation demand was greatest), and the heat
rate for nine of the last eleven years are both lower than the projected heat
rate contained in the Financial Projections. Based on this comparison of data,
and if the unit is operated at or near full load, Stone & Webster believes the
projected heat rate is achievable.
GOUDEY STATION
Unit 7
The table for Goudey Unit 7 does not contain a data point for 1995 because the
unit was in a year-long cold standby due to NYSEG's projection of economic and
market conditions during this time. Stone & Webster believes that the projected
heat rate (12,841 Btu/kWh) contained in the Financial Projections for Goudey
Unit 7 is reasonable and achievable. Both the historical average heat rate of
12,723 Btu/kWh (for consecutive years of operation 1988-1991 when electric
generation demand was greatest,) and most recent year heat rate data (12,659
Btu/kWh) are lower than the projected heat rate contained in the Financial
Projections. Based on this comparison of data, and if the unit is operated at or
near full load, Stone & Webster believes the projected heat rate is achievable.
Unit 8
Stone & Webster believes that the projected heat rate (10,359 Btu/kWh) contained
in the Financial Projections for Goudey Unit 8 is reasonable and achievable. The
historical average heat rate of 10,176 Btu/kWh (for consecutive years of
operation 1988-1991 when electric generation demand was greatest),
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the most recent year heat rate data (10,281 Btu/kWh), and the average heat rate
for the last eleven years are all lower than the projected heat rate contained
in the Financial Projections. Based on this comparison of data, and if the unit
is operated at or near full load, Stone & Webster believes the projected heat
rate is achievable.
GREENIDGE STATION
Unit 3
The table for Greenidge Unit 3 does not contain data points for 1997 because the
unit was in a year-long cold standby during 1997. The projected heat rate
(12,600 Btu/kWh) contained in the Financial Projections for Greenidge Unit 3 has
not been achieved since 1993 due to a decline in the capacity factor. However,
assuming that the plant will operate at or near full load, Stone & Webster
believes that the projected heat rate is reasonable and achievable.
Unit 4
The projected heat rate (9,850 Btu/kWh) contained in the Financial Projections
for Greenidge Unit 4 has not been achieved since 1989 but the average heat rate
achieved is very close to what is projected. The historical average heat rate of
9,897 Btu/kWh (for consecutive years of operation when electric generation
demand was greatest, 1988-1992), as well as the heat rate for eight out of the
last eleven years of operation is higher than the projected heat rate contained
in the Financial Projections. Based on the recent trend in data, and the
relatively small difference (approximately 0.5 percent) between the historical
average heat rate and the projected heat rate assumed in the Financial
Projections, Stone & Webster believes the projected heat rate is reasonable and
achievable, if the unit is operated at or near full load.
4.3 AVAILABILITY
The following table depicts the historical equivalent availability factors for
the years 1988 through 1997 for each of the seven units being acquired.
Equivalent availability is the fraction of maximum generation that could be
provided if limited only by outages, overhauls, and deratings. It is the ratio
of available generation to maximum generation. This data has been provided by
NYSEG. With the exception of Milliken Unit 1, the table shows a steady increase
in equivalent availability throughout the ten-year period. As regards Milliken
Units 1 and 2, availability would likely have increased were it not for Milliken
Station's selection for participation in the DOE Clean Coal Technology Round IV
demonstration program.
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TABLE 4.2-1
PLANT HISTORICAL EQUIVALENT AVAILABILITY
YEAR KINTIGH MILLIKEN MILLIKEN GOUDEY GOUDEY GREENIDGE GREENIDGE
UNIT 1 UNIT 2 UNIT 7 UNIT 8 UNIT 3 UNIT 4
- -----------------------------------------------------------------------------------------------------------------
1988 94.3 91.4 77.8* 90.2 91.8 73.8 95.2
1989 94.0 87.3 91.5 83.7 88.9 88.3 85.3
1990 90.5* 95.4 93.6 87.2 92.3 52.5* 88.2
1991 98.3 94.8 94.9 94.1 74.3 81.0 65.2
1992 96.5 93.8 92.6 73.9 93.8 88.9 91.4
1993 95.6 61.3* 93.4 94.5 93.3 73.1 94.2
1994 98.5 95.5 49.3* 99.4 97.6 98.0 86.7
1995 92.2 80.8* 90.2 100.0 92.0 99.5 94.9
1996 100 90.8 92.8 99.5 92.2 92.7 76.4*
1997 93.3 91.1 91.2 96.9 95.5 100.0 92.0
1998 94.8 91.9 88.0 99.7 94.3 72.8 86.8
1988-1998 95.7 92.4 92.0 92.6 91.4 86.8 88.0
Average*
*Averages exclude years of major maintenance and rehabilitation.
The availability of these units can be attributed to the effectiveness of the
capital expenditures and various programs instituted by NYSEG during the years
represented by the data as well as the capacity factors of some of the units.
This was compared against statistical data prepared by the North American
Electric Reliability Council (NERC GADS). During this period the units under
consideration usually exceeded the NERC GADS national averages. Even with lower
historical capacity factors for Goudey Unit 7 and Greenidge Unit 3, the
availability achievements are impressive.
Provided there are no significant changes that would negatively affect the
future availability of these stations, such as changes in O&M, management
philosophy, or significant changes in equipment or fuel, Stone & Webster
believes that these units should remain in the top quartile of NERC GADS
national average operating statistics. In addition, we believe these figures
support the projected capacity factors by showing the plants should be available
to generate for the time period implied by the capacity factors.
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5. ENVIRONMENTAL
Information for the environmental assessment has been obtained from the April
1998 Offering Memorandum, Coal-Fired Generation Highlights, "NYSEG Assets" and
Appendices, prepared for NYSEG, and from environmental submittals and permits
provided on the CD-ROMs which accompanied the above documents. The environmental
sections included in the April 1998 Offering Memorandum and Appendices appear to
have been prepared in accordance with established industry practice and present
a good overview of the environmental conditions that exist at the AEE Assets.
Appendix M to the 1998 Offering Memorandum includes an Executive Summary from
Phase I environmental audits performed by Pilko & Associates, Inc. for each
station. The Phase I environmental audits were reviewed from the CD-ROM and were
generally prepared in accordance with established industry practice.
Phase II environmental assessments were also performed by Pilko & Associates,
Inc. for each station and the Weber and Lockwood Ash Disposal Sites; however,
these were not available for review by Stone & Webster. AEE commissioned TRC
Environmental Corporation to review the results of the Phase II environmental
site assessments. The results from their independent investigations are
presented in their report, Order of Magnitude On-Site Environmental Liabilities
Cost Estimates and Comments for Six NYSEG Stations, the Weber and Lockwood Ash
Disposal Sites, and the Kent Laboratory Building, November 1998 ("TRC Report").
This report was reviewed and is considered to have been prepared in accordance
with accepted industry practice. This report is also considered to present a
realistic assessment of the environmental liability risks associated with the
purchase of the AEE Assets.
Each station has at least one employee whose duties include environmental
affairs. Kintigh, the largest and most complex station, has a full time
environmental coordinator. A comprehensive two-volume Environmental Compliance
Program Manual has been prepared for each station and outlines policy and
procedures for implementing environmental affairs at each station. Environmental
coordinators at each station presently rely heavily on NYSEG corporate resources
to obtain the support they need.
AEE is expected to provide, and the Financial Projections include expenditures
for, the level of environmental coordination and support services that is
presently being provided by NYSEG corporate resources for each of the stations
being purchased. The existing environmental programs are well defined for each
station; therefore, very few program changes are required for AEE to be able to
implement the present program.
5.1 AIR EMISSION COMPLIANCE
NYSEG currently complies with all applicable state and federal air regulations
using a combination of unit-specific and system-wide compliance strategies. All
necessary approvals and reporting procedures have been implemented with the DEC
and the EPA. It is presently necessary to employ an allowance cap and trade
program to successfully comply with certain sulfur dioxide (SO(2)) and nitrogen
oxides (NO(x)) regulations for the four stations.
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5.1.1 SULFUR DIOXIDE (SO2)
SO(2) emissions are regulated under Title IV of the Federal Clean Air Act
Amendment (CAAA) and by the State Acid Deposition Control Act (SADCA). Title IV
establishes an allowance trading program that is phased in over five years.
Phase I went into effect January 1, 1995 with Milliken 1 and 2 and Greenidge 4
falling under the program. Phase II will go into effect January 1, 2000 with all
the remaining units being affected.
FGD systems at the Kintigh and Milliken Stations reduce SO2 emissions below the
allowance allocation for each plant. The excess allowances created by the
Kintigh and Milliken Stations may be sold or used for SO2 allowance requirements
at other AEE Assets. The SO(2) allowance bank was approximately 116,000 tons at
the end of 1998. It is our understanding that AEE intends to sell these
allowances and purchase new ones as needed. This is represented in the Financial
Projections.
The CAAA Title IV, Phase II requirements will be implemented for all stations on
January 1, 2000. When Phase II goes into effect, the AEE Assets may have to
purchase SO(2) allowances to meet these new requirements. This expense has been
included in the Financial Projections. The FGD systems at Kintigh and Milliken
are not currently operating at their full reduction capability due to the
current lack of need for further emissions reductions. AEE can increase the
reduction efficiency of the FGD systems at Kintigh and Milliken by operating the
FGD units at a higher reduction capability at minimal additional cost. This
option may substantially reduce the SO(2) allowances that are needed.
5.1.2 NITROGEN OXIDES (NO(x))
The CAAA Title I, Phase II requirements (Provisions for Attainment and
Maintenance of National Ambient Air Quality Standards) are anticipated to be in
effect on May 1, 1999. While allowances should be tradable between the AEE
Assets, as needed, the final trading rules have not been promulgated to date.
The AEE Assets will be allocated approximately 6,292 tons during the ozone
season (May 1 through September 30). AEE is planning to install an SCR system
for control of NO(x) at the Kintigh Station by June 1999 that will provide a 90
percent reduction from current NO(x) emissions. This SCR system will provide
approximately 3,400 excess NOx allowances per year that can be applied to other
stations to meet allowance requirements by the AEE Assets to 2003. As of
mid-March 1999, the installation of the SCR is behind schedule by approximately
three weeks due to delays in obtaining necessary approvals. AEE believe the
contractor, Babcock and Wilcox, can make up approximately half of the delay. If
the SCR is further delayed, it would start to impact the capacity factor for the
second half of 1999. We believe that the outage has been well planned and that
the installation of the SCR by June 1999 is achievable.
It is anticipated that the Title I, Phase III requirements will be implemented
on May 1, 2003. All AEE Assets will be affected by these requirements. None of
the current operating stations, except Kintigh Station with its planned SCR,
will comply with allowance requirements at that time. In response, AEE has
budgeted to add SCR systems to Milliken by May 1, 2003 at a cost of
approximately $14 million, but
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may decide not to do so if other more economical means are available to meet the
requirements at that time. If it is installed, the SCR will provide additional
excess NO(x) allowances which can be applied to other AEE Assets to satisfy
compliance requirements for Title 1, Phase III. It is anticipated that the
excess NO(x) allowances generated by Kintigh and Milliken Stations should more
than meet compliance requirements for the AEE Assets for Phase III and that any
excess allowances may be sold.
5.1.3 PARTICULATES AND OPACITY
The AEE Assets are currently in compliance with particulate emission limits. For
all of the AEE Assets, except Kintigh Station, opacity exceedances during
startup, shutdown and malfunction may be excused at the discretion of the
Commissioner of the DEC, as long as it can be demonstrated that these
exceedances were not preventable. The standards for opacity do not apply during
startup, shutdown or malfunction for the Kintigh Station.
In the past several years, a number of stations have exceeded the opacity
limits. This is a common problem with coal-fired facilities. The DEC has
initiated enforcement action against several stations, including some of the
former NYSEG stations. The opacity enforcement action is expected to be settled
in the near future. NYSEG would be responsible for any penalties assessed. The
DEC has no other actions against NYSEG at this time. NYSEG is to make
modifications to their units in the spring of 1999 which should enable them to
meet the opacity requirements without further incidents.
5.1.4 OTHER EPA AIR POLLUTANT CONSIDERATIONS
The EPA has proposed new fine particulate matter ambient air quality standards
that may establish additional areas of nonattainment. Lower particulate matter
emission limits could be imposed, as well as lower SO(2) and NO(x) limits in the
future. The EPA is also identifying other potentially hazardous emissions that
may pose a potential health threat, such as mercury. The remainder of the air
pollutants, CO(2) and other global warming greenhouse gases being studied by the
EPA may result in regulations that will be imposed in the future. It is
currently too early to tell what the impact of future EPA regulations might be
or whether they will affect the AEE Assets.
5.2 WATER AND WASTE WATER COMPLIANCE
The AEE Assets and ash disposal sites have been designed and are operated to
comply with the very strict environmental standards applicable to waste water
and water run-off, including the State Pollution Discharge Elimination System
("SPDES") Permit. Groundwater and surface water protection measures include coal
pile liners at all stations. The stations also feature lined ash and scrubber
sludge disposal sites, no active fly ash settling ponds, and a network of
approximately 400 groundwater monitoring wells.
Numerous wastewater treatment facilities have been provided to ensure compliance
with restrictive discharge limits. The Kintigh Station normally operates in a
zero wastewater discharge mode, reusing
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wastewater for various plant processes. Similarly, ash and scrubber sludge
disposal sites comply with water quality-based discharge limits. Where
necessary, lime treatment is employed to remove metals from ash disposal site
wastewater prior to discharge. Additionally, the stations and disposal sites
have negotiated flow-proportionate discharge limits to provide compliance with
water quality-based standards by restricting discharge flow rates to ensure that
receiving water quality is protected. This should not noticeably affect plant
performance.
No impending water and waste water compliance regulations are anticipated from
the EPA or DEC that will have an adverse affect for the present design and
operation of the AEE Assets.
In August 1998, NYSEG received a notice of intent to file a citizen suit with
the DEC regarding an alleged discharge limit exceedance at the Kintigh Station.
If this suit results in a fine, AEE believes that it will be the responsibility
of NYSEG. To this point, we are not aware of a suit actually being filed.
5.3 FISH PROTECTION
Kintigh Station uses fine mesh screens and a fish return system at the
circulation water intakes for fish protection. The Milliken Station employs an
experimental strobe light system to minimize fish impingement at the cooling
water intake. The DEC is currently evaluating the adequacy of this system. The
DEC is presently indicating that they may require a fish protection system at
Greenidge Station that is similar to that being used at the Milliken Station. We
do not believe the cost would be material. The DEC has determined that fish
protection is not required at Goudey.
5.4 ASH DISPOSAL
5.4.1 KINTIGH ASH DISPOSAL SITE
The Kintigh Ash Disposal Site will be transferred to AEE and is not considered
to have high risk liabilities since the areas are lined. The section of landfill
currently in use was originally permitted by the PSC as part of Kintigh's
construction. AEE will develop a new section of the landfill for disposal of
ammoniated ash and sludge produced during operation of the SCR that is currently
being installed at Kintigh. The new section of the landfill will be permitted by
the PSC applying the current solid waste landfill standards of the DEC which
require, among other things, the use of a synthetic liner. The DEC and the PSC
have recently been negotiating a Memorandum of Understanding ("MOU") that will
clarify their respective roles with respect to the regulation of the Kintigh
landfill. According to a draft of the MOU, the PSC's decisions will continue to
control all aspects of the original section of the landfill, but current and
future DEC regulations, standards and polices will control the development, use
and closure of the new section. The MOU is expected to be formally approved by
the Power Plant Siting Board in the near future. However, the situation is not
formally resolved at this time. Groundwater monitoring does not indicate any
water quality problems and the site is located on the station property.
5.4.2 MILLIKEN ASH DISPOSAL SITE
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The primary source of ash at the Milliken Ash Disposal Site is the Milliken
Station. The site is located on the station property. A groundwater plume,
contaminated by ash leachate, has continued to improve with the closure of the
unlined disposal areas. Continued monitoring will still be required to verify
continued groundwater improvement. Present ash disposal areas are lined and do
not appear to result in groundwater contamination. We do not anticipate that
remedial action will be required to improve groundwater quality.
5.4.3 WEBER ASH DISPOSAL SITE
The Weber Ash Disposal Site is a permitted ash disposal landfill equipped with a
geomembrane liner. The landfill is currently in operation but is expected to
close in 1999. The sources of ash at the Weber Ash Disposal Site are the Goudey
and Greenidge stations. Goudey expects to be able to utilize other landfills in
the area for its ash or to dispose of its ash at Kintigh. We believe this is
reasonable.
Groundwater beneath Cell No. 1 contains ash leachate that exceeds the DEC
groundwater quality standards. With the exception of sulfate, it has been
concluded that the exceedances do not appear to be related to landfill
operation, but are naturally occurring. The sulfate concentrations can be traced
to past operational practices where the underdrains were periodically closed and
allowed to recharge into the groundwater system.
The Weber wastewater discharge pond has elevated levels of ammonia; however, the
pond is managed so that the discharge complies with permit limits. With the
closure of the Weber Ash Disposal Site, it may be necessary to cover the site
with a low permeable cap design to reduce leachate generation. AES Creative
Resources L.P. will assume responsibility for the Weber Ash Disposal Site
following the closing of the acquisition.
5.4.4 LOCKWOOD ASH DISPOSAL SITE
The Lockwood Ash Disposal Site is contiguous with an area lying immediately
north of Lockwood, known as the Greenidge Gravel site. Ash from Greenidge is
disposed of at the Lockwood Ash Disposal Site.
Transelco used two to three acres of the Greenidge Gravel site until 1973 to
dispose of 500 to 700 drums containing zirconium oxide, barium titanate, and
cerium oxide. In 1975, the DEC granted permission to cover the drums with ash
and use the site as an ash disposal facility. In 1979, the ash was capped with
two feet of soil and seeded. Groundwater monitoring down gradient of the
Greenidge Gravel site indicates that no exceedances of groundwater quality
limits have occurred for leachate constituents.
The Lockwood Ash Disposal Site includes a leachate sedimentation pond and a
stormwater impoundment. Sections of the landfill have either been constructed
with a compacted clay liner with
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leachate collection or with a synthetic liner. Additional phases of the landfill
have been permitted but have not yet been developed.
Significant groundwater investigations have recently been conducted at the
Lockwood Ash Disposal Site, and it is inconclusive if leachate from the ponds or
landfill is causing any contamination of the groundwater. Groundwater impacts
from present practice are deemed to be minimal or not present at the Lockwood
Ash Disposal Site.
In an area adjacent to the Lockwood Ash Disposal Site, TRC reported that
approximately 500-700 drums of abrasives were disposed in the early 1970s and
covered with ash. TRC projected most probable costs of approximately $520,000 to
conduct a site investigation and remove the drums. These costs have been
included in the Financial Projections. In addition, groundwater sampling in this
area and around the Lockwood Ash Disposal Site indicates that some monitoring
wells have parameters which exceed state regulatory limits. AEE has included in
the Financial Projections $6 million in closure costs for the disposal site with
closure of a portion of the landfill scheduled for 2006 and closure of the
remaining acres projected in 2016. The costs also include annual groundwater
monitoring costs.
5.4.5 OTHER ONSITE INACTIVE ASH DISPOSAL SITES
Inactive ash disposal sites are present at the Goudey and Greenidge stations.
Ash landfill materials were generated and disposed of at each respective
station. No information was available from the material reviewed to offer an
opinion whether there are any risks in assuming liabilities from these disposal
sites with the property transfers. There was no groundwater monitoring or
sampling data available for review, and past disposal practice or disposal
design and site closure were not available for these Stations. We believe that
environmental remediation costs have been adequately identified in the TRC
report and included in the budget of the Financial Projections.
6. OPERATIONS AND MAINTENANCE
Stone & Webster reviewed the operating and maintenance ("O&M") costs and the
technical assumptions in the Financial Projections. We believe the O&M costs
included in the Financial Projections for each of the plants are reasonable. We
believe the overall magnitude of the capital costs is also reasonable. The
capital costs consist primarily of major maintenance items that are typically
capitalized instead of expensed as well as life extension work, which will be
performed as the plants age.
6.1 OPERATIONS AND MAINTENANCE COSTS
Stone & Webster reviewed the operating costs, maintenance costs, and capital
expenditures for each plant. Plant O&M and capital expenditures are based on a
detailed 20-year maintenance and capital expenditure plan, which we have
reviewed, and which we believe is reasonable. The plan was prepared by current
plant personnel under AEE's supervision. The plan includes all the systems of
the plant and the major overhauls. Items in the plan are identified as either
maintenance, which is an expense, or
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capital, which is depreciated. General and administrative costs consist of
miscellaneous expenses such as telephone, travel, training, and other
miscellaneous items. The projections were subsequently extended to 37 years by
including funds for life extension and extending the base assumptions for fixed
and variable O&M.
The items that fluctuate from year to year are the plant O&M and the capital
expenditures. These items vary due to the differing requirements for maintenance
and equipment replacement each year. The remaining items escalate according to
the assumptions. The fixed O&M consists of the O&M expenses for the FGD and SCR
O&M at Kintigh and Milliken (assuming an SCR is installed at Milliken) the
regular plant O&M, general and administrative expenses, payroll and benefits,
environmental compliance, insurance, property taxes, the short line railroad for
coal transportation from where it is unloaded, environmental remediation, and
transmission expenses. Plant O&M consists of chemical consumption, preventive
maintenance activities, contractor expenses, and equipment repairs and
overhauls. Overhauls have been considered variable expenses on other independent
power projects, but are often budgeted as fixed expenses in utility practice.
TABLE 6.1-1
O&M COSTS (37 YEAR AVERAGE)
FIXED COSTS KINTIGH MILLIKEN GOUDEY GREENIDGE
($000S) IN 1999$
- --------------------------------------------------------------------------------------------------------------------------
Plant O&M 3,647 2,388 1,652 1,462
Capital Costs 4,503 1,638 537 556
Payroll and Benefits 11,082 6,514 2,644 3,413
Environmental Compliance 454 330 374 482
G&A 190 624 221 229
FGD O&M 268 329 N/A N/A
Insurance 669 294 136 151
Property Taxes 8,935 2,906 655 915
6.2 STAFFING LEVELS
The anticipated final staffing levels for each plant are provided in the
following table. The staffing levels appear reasonable. The current NYSEG
staffing levels are slightly higher than the final levels shown here, as AEE
anticipates some voluntary staff retirements and departures.
TABLE 6.2-1
STAFFING PLANNED AT POWER STATIONS
STAFF POSITION KINTIGH MILLIKEN GOUDEY GREENIDGE
- --------------------------------------------------------------------------------
Total 140 82 41 42
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The staffing levels and distribution are considered satisfactory to operate and
maintain the units safely in accordance with regulatory requirements. The
numbers are typical of those found in similarly configured plants that Stone &
Webster has reviewed.
The staffing numbers also compare favorably to the industry average number of
employees per megawatt as reported in Utility Data Institute Report UDI-2011-97.
A comparison of the AEE staffing levels to the UDI data reveals that all four
plants are slightly above the mean for the 397 coal-fired plants in the UDI
sample. Therefore, we believe the staffing levels are adequate and may be
somewhat conservative.
6.3 OVERHAUL AND MAINTENANCE SCHEDULE
Equipment vendors typically recommend that turbine and generator overhauls be
performed after 50,000 operating hours, which is approximately six years.
Independent power producers and utility operators have been extending the time
interval between turbine and generator overhauls beyond the vendor recommended
interval. In particular, we are aware that in Australia it is standard practice
to perform inspections on an eight-year basis rather than a six-year basis. We
are comfortable with eight years between overhauls based on our recent
observations of industry practice in Australia, but the ten-year interval
currently projected by AEE is not consistent with current industry practice.
Current plant personnel have indicated that when they have performed inspections
after eight years, there has been minimal cleaning, repair, and inspection work
needed on the turbines. Therefore, it may be possible to reliably extend the
time between turbine outages to ten years. Based on our direct experience with
other AES projects, we believe AEE will demonstrate prudent judgement in
deciding when to conduct major inspections as AES has done at the other plants
they operate.
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TABLE 6.3-1
PLANNED OVERHAUL AND MAINTENANCE SCHEDULE IN DAYS
YEAR KINTIGH MILLIKEN MILLIKEN GOUDEY GOUDEY GREENIDGE GREENIDGE
UNIT 1 UNIT 2 UNIT 7 UNIT 8 UNIT 3 UNIT 4
- -------------------------------------------------------------------------------------------------------------
1999 45 16 22 15 14* 14
2000 3 22 48 46 14
2001 14 30 12 12 14
2002 16 36 15 14 14
2003 23 22 15 12 14
2004 16 12 12 30
2005 14 16 22 15 14 30
2006 22 15 12 14
2007 16 12 12 14
2008 16 22 48 14 14
2009 40 22 15 12 14
2010 16 12 46 14
2011 14 30 22 15 14 14
2012 36 15 12 14
2013 14 16 12 12 30
2014 14 16 22 15 14 30
2015 22 15 12 14
2016 14 16 12 15 12 14
2017 14 16 22 14 14
2018 40 22 48 14
* All 14's at Greenidge 3 represent 28 days at half load.
Milliken Unit 2 has a different outage schedule due to the cleaning requirements
for its unique air heater. The air heater is a heat pipe air heater and requires
a 4 day outage every six or seven months for cleaning.
6.4 CAPACITY FACTORS
The capacity factors are a function of availability and dispatch. Our review
focused on the ability of the plants to be available to generate power at the
capacity factors projected by London Economics. Except for Goudey Unit 7 and
Greenidge Unit 3, the plants have basically operated in a base load manner.
Table 6.4-1 provides the capacity factors for the years 1988-1997 and table
6.4-2 provides the capacity factor for 1998.
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TABLE 6.4-1
UNIT CAPACITY FACTORS, 1988-1997
Years KINTIGH MILLIKEN MILLIKEN GOUDEY GOUDEY GREENIDGE GREENIDGE
UNIT 1 UNIT 2 UNIT 7 UNIT 8 UNIT 3 UNIT 4
- -------------------------------------------------------------------------------------------------------------------
1988-1997 83.3% 77.5% 74.8% 44.5% 76.5% 39.1% 72.7%
Average
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TABLE 6.4-2
1998 UNIT CAPACITY FACTORS
YEAR KINTIGH MILLIKEN MILLIKEN GOUDEY GOUDEY GREENIDGE GREENIDGE
UNIT 1 UNIT 2 UNIT 7* UNIT 8 UNIT 3 UNIT 4
- -------------------------------------------------------------------------------------------------------------------
1998 83.3% 84.6% 83.5% 52% 79% 34% 87.8%
*Goudey 7 was shut down by NYSEG for 2,139 hours between February and May to
preserve NOx allowances.
We believe the plants are likely to achieve the projected capacity factors based
on their availability to run, provided they are dispatched whenever they are
available. Table 6.4-3 provides the first 31 years of capacity factors used in
developing the Financial Projections. The remaining years follow a similar
pattern.
TABLE 6.4-3
PROJECTED CAPACITY FACTORS (%)
YEAR KINTIGH MILLIKEN MILLIKEN GOUDEY GOUDEY GREENIDGE GREENIDGE
UNIT 1 UNIT 2 UNIT 7 UNIT 8 UNIT 3 UNIT 4
- -------------------------------------------------------------------------------------------------------------
1999 98* 96 96 88 90 86 88
2000 94 93 93 86 86 86 88
2001 94 88 93 90 90 86 88
2002 94 93 88 90 90 86 88
2003 94 92 92 90 90 86 88
2004 92 92 92 90 90 82 88
2005 92 92 92 90 90 86 82
2006 92 92 92 90 90 86 88
2007 92 92 92 90 90 86 88
2008 92 92 92 86 90 86 88
2009 88 92 92 90 90 86 88
2010 92 92 92 90 86 86 88
2011 92 88 92 90 90 86 88
2012 92 92 88 90 90 86 88
2013 92 92 92 90 90 82 88
2014 92 92 92 90 90 86 82
2015 92 92 92 90 90 86 88
2016 92 92 92 90 90 86 88
2017 92 92 92 90 90 86 88
2018 88 92 92 86 90 86 88
2019 92 92 92 90 90 88 88
2020 92 92 92 90 86 88 88
2021 92 88 92 90 90 88 88
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YEAR KINTIGH MILLIKEN MILLIKEN GOUDEY GOUDEY GREENIDGE GREENIDGE
UNIT 1 UNIT 2 UNIT 7 UNIT 8 UNIT 3 UNIT 4
- -------------------------------------------------------------------------------------------------------------
2022 92 92 88 90 90 82 88
2023 92 92 92 90 90 88 82
2024 92 92 92 90 90 88 88
2025 92 92 92 90 90 88 88
2026 92 92 92 90 90 88 88
2027 92 92 92 90 90 88 88
2028 88 92 92 86 90 88 88
2029 92 92 92 90 90 88 88
*After Kintigh's spring outage
7. FINANCIAL PROJECTIONS
7.1 OVERVIEW
The Financial Projections consist of a financial pro forma model prepared by
AEE. Stone & Webster has reviewed the assumptions, data, and the calculations
that support the projections of the cash flow from operations. Financing
assumptions, including the interest rates, debt amortization schedule, and lease
payments have been provided by AEE in consultation with Morgan Stanley and
McManus & Miles. Market projections for electricity and coal were also provided
by AEE with the help of their market consultants London Economics and John T.
Boyd Company, respectively. In the spreadsheet model used to create the
Financial Projections, the prices for electrical energy and capacity and the
prices for coal and coal transportation are input as constant dollar
projections. AEE used these constant dollar prices and the assumed inflation
rate to directly calculate the nominal electrical energy and capacity revenues
as well as the nominal coal costs.
The Financial Projections for the base case and the sensitivity cases are
included in Exhibit I of this Report. The Financial projections are in current
dollars each year with an inflation rate of 2 percent per annum from 1999
through 2032. Each line item in the Financial Projections has its own escalation
factor. They are provided in the discussion that follows.
In our review of the Financial Projections, Stone & Webster has made certain
assumptions with respect to conditions which may exist or events which may occur
in the future. While Stone & Webster believes these assumptions to be reasonable
for the purpose of this Report, they are dependent upon future events, and
actual conditions may differ materially from those assumed. In addition, the
Financial Projections use and rely upon information provided by sources that we
believe are reliable. Stone & Webster believes that the use of this information
and assumptions are reasonable for the purposes of our Report. However, some
assumptions may vary significantly due to unanticipated events and
circumstances. To the extent that actual future conditions may differ from those
assumed herein or provided to us by others, the actual results will vary from
those forecast. This report summarizes our work up to the date of the
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Report. Thus changes in conditions occurring or becoming known after such date
could affect the material presented to the extent of such changes.
The principal considerations and assumptions used by Stone & Webster in
reviewing the Financial Projections and the principal information provided by
others include the following:
1. Stone & Webster has made no determination as to the validity and
enforceability of any contract, agreement, rule or regulation applicable to
AEE. For purposes of this Report, however, Stone & Webster has assumed that
all such contracts, agreements, rules and regulations will be fully
enforceable in accordance with their terms and that all parties will comply
with the provisions of their respective agreements.
2. London Economics prepared the projections of market capacity and energy
prices for AEE using a market simulation model. Stone & Webster has
reviewed certain technical inputs to the London Economics model for the AEE
Assets, in particular the assumptions for new combined cycle gas turbine
plants. Stone & Webster has not independently verified the methodology used
by London Economics to develop the price forecasts nor has it verified the
accuracy of the forecasts.
3. The methodology used to determine the capacity and energy revenues was
developed by London Economics based on its understanding of the dynamics of
the developing energy markets in New York. Stone & Webster has not
independently verified the accuracy of the revenue methodology developed by
London Economics for the Financial Projections.
4. Stone & Webster has reviewed the O&M and capital budgets for the
electricity generating assets acquired from NYSEG. We assume that AEE will
operate and maintain the assets in accordance with the O&M and capital
budgets and that the assets will be operated in accordance with accepted
industry practice (except for the ten year interval between major outages
as currently projected). We believe that the AEE budget for capital
expenditures represents a reasonable projection for the cost of extending
the life of these units through the term of the Financial Projections.
5. Stone & Webster has assumed for purposes of the Financial Projections that
the Kintigh, Milliken, Goudey and Greenidge units continue to operate
through 2035. We believe Kintigh is capable of operating for another 45
years provided proper maintenance and life extension work is done and
Milliken is capable of operating for another 38 years provided proper
maintenance and life extension work is done. We believe Goudey and
Greenidge are also capable of operating for another 38 years if the life
extension and maintenance program is followed. The Financial Projections
assume no additional generation assets are acquired or constructed by AEE.
We believe it is reasonable for AEE to assume, for purposes of the
Financial Projections,that there will be no degradation in the capacity or
heat rate of these facilities since they are no longer in
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new and clean condition and have already experienced their degradation from
new and clean condition.
6. Stone & Webster has assumed that all licenses, permits and approvals which
have not yet been obtained or which need to be renewed during the period
covered by the Financial Projections are obtained and/or renewed on a
timely basis.
7. The price of the coal in the Financial Projections is based upon the base
case pricing forecasts provided by John T. Boyd Company.
8. Stone & Webster has assumed that current law does not change and that AEE
will be able to transfer SO2 and NOx emission credits from Kintigh and
Milliken to Goudey and Greenidge in order to comply with its emission
limits for these pollutants. AEE has assumed in the Financial Projections
that sufficient demand exists for the sale of certain emission offsets by
AEE at the prices forecast.
9. Stone & Webster has not evaluated the non-operating expenses projected by
AEE. These expenses include property taxes, insurance, and general and
administrative expenses.
7.2 REVENUES
The Financial Projections include revenues primarily from the sale of energy in
the open market. In addition, revenues are obtained from the sale of capacity to
NYSEG through April 2001 and thereafter through the sale of capacity to the
market. It is assumed that there are revenues from ancillary services of
approximately $2 million per year. The revenues for Goudey include a very small
amount for steam sales. Prices for energy and capacity are projected to increase
with inflation at two percent.
The total revenues are projected to be $308.8 million in 2000, the first full
year of revenues, and $458.8 million in 2018. The largest revenue contribution
is from the sale of energy which contributes $275.2 million in 2000 and $353.4
million in 2018. Capacity revenues contribute the remaining revenues except for
the approximately $2 million in ancillary services at Kintigh and approximately
$0.3 million in steam sales at Goudey.
The two key variables in the electric energy revenue forecast are the price
obtained for the electric energy and the electric energy delivered for sale. AEE
provided these projections with the help of its market consultant, London
Economics. Table 7.2-1 shows the projected real energy and capacity prices for
each plant through 2029.
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TABLE 7.2-1
PROJECTED BASE CASE ENERGY PRICES ($/MWH) AND CAPACITY PRICES ($/KW-YR)(1999$)
YEAR KINTIGH MILLIKEN MILLIKEN GOUDEY GOUDEY GREENIDGE GREENIDGE CAPACITY
UNIT 1 UNIT 2 UNIT 7 UNIT 8 UNIT 3 UNIT 4 PAYMENT
- -----------------------------------------------------------------------------------------------------------------------------
1999 25.22 25.17 25.17 25.27 25.00 25.46 25.25 27.00
2000 26.33 26.44 26.31 26.23 26.83 26.30 26.37 30.00
2001 27.54 27.30 27.47 27.66 27.52 27.82 27.88 37.00
2002 28.16 28.56 28.67 28.59 28.63 28.43 28.67 40.80
2003 27.39 27.23 27.40 27.22 27.19 27.59 27.06 46.20
2004 25.14 25.06 25.17 24.99 25.05 25.23 24.99 51.60
2005 22.88 22.88 22.94 22.76 22.91 22.87 22.92 57.00
2006 23.17 23.19 23.19 23.09 23.21 23.18 23.18 56.20
2007 23.47 23.51 23.45 23.43 23.50 23.49 23.45 55.40
2008 23.76 23.82 23.70 23.76 23.80 23.80 23.71 54.60
2009 24.06 24.14 23.96 24.10 24.09 24.11 23.98 53.80
2010 24.35 24.45 24.21 24.43 24.39 24.42 24.24 53.00
2011 24.62 24.76 24.55 24.74 24.70 24.66 24.59 52.60
2012 24.89 25.06 24.90 25.05 25.01 24.90 24.94 52.20
2013 25.17 25.37 25.24 25.35 25.32 25.13 25.28 51.80
2014 25.44 25.67 25.59 25.66 25.63 25.37 25.63 51.40
2015 25.71 25.98 25.93 25.97 25.94 25.61 25.98 51.00
2016 25.31 25.54 25.49 25.50 25.49 25.16 25.53 52.60
2017 24.91 25.10 25.06 25.04 25.04 24.71 25.08 54.20
2018 24.52 24.66 24.62 24.57 24.59 24.27 24.64 55.80
2019 24.12 24.22 24.19 24.11 24.14 23.82 24.19 57.40
2020 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2021 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2022 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2023 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2024 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2025 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2026 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2027 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2028 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
2029 23.72 23.78 23.75 23.64 23.69 23.37 23.74 59.00
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7.3 EXPENSES
The Financial Projections include the following expenses:
- Costs of purchasing and transporting fuel for the thermal power
stations
- Fixed O&M costs for each of the plants including expenses
associated with major maintenance
- Variable O&M costs for each plant
- Property taxes and insurance for each plant
- Sales and purchases of NOx and SO2 emissions allowances.
- Capital Expenditures
7.3.1 FUEL
Fuel cost for each plant is a function of the price of the coal, the cost of
transportation, and the quantity of fuel consumed. The plants are currently
under contract with Consolidated Coal. Purchases under that contract are assumed
to be approximately 2.5 million tons per year in 1999 and 2000 dropping off to
1.76 million tons 2001 and 1.11 million tons in 2002. The balance of AEE's
requirements for 2001 and 2002 and all of its requirements thereafter will be
bought on a spot market basis. The coal commodity prices are projected as
follows for the first 31 years.
TABLE 7.3.1-1
PROJECTED COAL PRICES ($/TON)
YEAR CONSOL CONTRACT HIGH SO2 ($1998) MEDIUM SO2 ($1998) LOW SO2 ($1998)
(NOMINAL $)
- ------------------------------------------------------------------------------------------------------------------
1999 22.67 19.20 22.70 24.00
2000 22.57 19.10 22.50 23.80
2001 23.14 19.00 22.40 23.60
2002 23.71 19.00 22.40 23.60
2003 19.00 22.40 23.60
2004 19.00 22.40 23.60
2005 19.00 22.35 23.60
2006 19.00 22.35 23.60
2007 18.80 22.30 23.60
2008 18.60 22.10 23.50
2009 18.40 21.90 23.40
2010 18.20 21.70 23.30
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YEAR CONSOL CONTRACT HIGH SO2 ($1998) MEDIUM SO2 ($1998) LOW SO2 ($1998)
(NOMINAL $)
- ------------------------------------------------------------------------------------------------------------------------------------
2011 18.20 21.70 23.30
2012 18.20 21.70 23.30
2013 18.20 21.70 23.30
2014 18.20 21.70 23.30
2015 18.20 21.70 23.30
2016 18.20 21.70 23.30
2017 18.20 21.70 23.30
2018 18.20 21.70 23.30
2019 18.20 21.70 23.30
2020 18.20 21.70 23.30
2021 18.20 21.70 23.30
2022 18.20 21.70 23.30
2023 18.20 21.70 23.30
2024 18.20 21.70 23.30
2025 18.20 21.70 23.30
2026 18.20 21.70 23.30
2027 18.20 21.70 23.30
2028 18.20 21.70 23.30
2029 18.20 21.70 23.30
Table 7.3.1-2 provides the projected heat content of the coal in Btu's per
pound.
TABLE 7.3.1-2
HEAT CONTENT OF COAL
COAL HEAT CONTENT OF COAL IN
BTU/LB. OF COAL
- ------------------------------------------------------------------------
High SO2 12,500
Medium SO2 12,800
Low SO2 12,800
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Kintigh and Milliken consume a mixture of high and medium sulfur coal, which
produces a blended price for coal at these plants. The quantity of coal consumed
is a function of the plant's heat rate and power production. The delivered cost
of coal to each plant is projected to be as follows:
TABLE 7.3.1-3
DELIVERED COST OF COAL ($/MMBTU, NOMINAL)
YEAR KINTIGH MILLIKEN GOUDEY GREENIDGE
- ---------------------------------------------------------------------------------------------------------------
1999 1.34 1.32 1.32 1.32
2000 1.33 1.30 1.37 1.37
2001 1.35 1.31 1.38 1.38
2002 1.36 1.32 1.40 1.40
2003 1.36 1.34 1.42 1.42
2004 1.38 1.36 1.44 1.44
2005 1.40 1.38 1.46 1.46
2006 1.42 1.40 1.48 1.48
2007 1.43 1.41 1.50 1.50
2008 1.44 1.42 1.51 1.51
2009 1.45 1.43 1.52 1.52
2010 1.46 1.44 1.53 1.53
2011 1.48 1.46 1.55 1.55
2012 1.50 1.48 1.58 1.58
2013 1.52 1.50 1.60 1.60
2014 1.54 1.52 1.62 1.62
2015 1.56 1.54 1.64 1.64
2016 1.58 1.56 1.67 1.67
2017 1.60 1.58 1.69 1.69
2018 1.63 1.61 1.72 1.72
2019 1.65 1.63 1.74 1.74
2020 1.67 1.65 1.77 1.77
2021 1.70 1.68 1.80 1.80
2022 1.72 1.70 1.82 1.82
2023 1.75 1.73 1.85 1.85
2024 1.77 1.75 1.88 1.88
2025 1.80 1.78 1.91 1.91
2026 1.83 1.81 1.94 1.94
2027 1.85 1.83 1.97 1.97
2028 1.88 1.86 2.00 2.00
2029 1.91 1.89 2.03 2.03
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The coal price projections fall within the range of delivered prices that we
would expect based on our observations at other plants. The prices continue in a
similar pattern for the remainder of the projection.
7.3.2 FIXED OPERATIONS, MAINTENANCE, AND OTHER COSTS
The operations, maintenance, and other costs for all plants are projected as
follows for the first eight years.
TABLE 7.3.2-1
PROJECTED CONSOLIDATED COSTS ($000S, NOMINAL)
1999 2000 2001 2002 2003 2004 2005 2006
------ ------ ----- ------ ------ ----- ------ -----
O&M 8,827 10,103 11,699 9,771 11,394 9,553 12,638 9,956
G&A 17,533 27,245 27,588 27,881 28,261 28,820 29,389 29,970
Environmental 949 1,445 3,527 2,643 2,688 2,734 2,781 5,049
Expenditures
Property Tax 11,937 17,102 16,112 14,895 13,779 13,200 13,200 13,200
Transmission 4,071 1,015 1,030 1,046 1,061 1,077 1,093 1,110
Capital Expenditures 10,609 12,249 7,177 17,003 15,604 6,567 11,151 1,086
The average fixed expenditures per year for the years 2007 through 2032 are as
follows:
TABLE 7.3.2-2
PROJECTED AVERAGE
AVERAGE COST PER YEAR
($000S,NOMINAL)
ITEM (2007-2032)
---- ---------------------
O&M 12,983
G&A 39,461
Environmental Expenditures 2,397
Property Tax 13,200
Transmission 1,365
Capital Exp. 12,404
O&M consists of maintenance expenses and consumable items in the course of
operating the stations. G&A consists of payroll and benefits, insurance, and
other miscellaneous items. Environmental
Report Date: May 12, 1999 55 [Stone & Webster Logo]
267
Independent Technical Review
AEE
expenditures consist of remediation activities and compliance costs. Property
taxes assumed in the projections are lower than current property taxes paid by
NYSEG. Transmission costs are the costs associated with interconnecting with the
grid. Transmission costs are high in 1999 due to buyout of certain transmission
contracts. All items escalate at either one and one half or two percent per
year. Property tax is projected not to escalate.
Stone & Webster has reviewed these costs and believes the FGD O&M, Plant O&M,
G&A, environmental compliance, environmental remediation, payroll and benefits,
and the capital expenditure budget are adequate to provide for the long-term
operation of the plants. AEE has provided projections for insurance, property
taxes, railroad, and transmission costs. We have not reviewed the basis for
these projections.
7.3.3 VARIABLE OPERATING COSTS
Variable costs consist of limestone consumption in the FGD units, ash disposal,
SCR O&M, and the sale or purchase of NOx and SO2 emissions credits. Tables
7.3.3-1 and 7.3.3-2 present these costs and assume an SCRs are installed at
Milliken in 2002 and 2003. The variable operating costs are directly tied to the
operation of each unit. Limestone consumption is a function of the amount of
sulfur in the coal and the quantity of coal consumed. Ash disposal cost is
relatively low due to the ability to sell a large portion of the ash for roadbed
material and other uses. The quantity of ash produced is directly tied to the
ash content of the coal.
TABLE 7.3.3-1
VARIABLE OPERATING COSTS ($000S, NOMINAL)
1999 2000 2001 2002 2003 2004 2005 2006
----- ----- ----- ----- ----- ----- ----- -----
Limestone 1,764 2,817 2,835 2,876 2,936 2,937 2,981 3,026
Ash Disposal 848 1,310 1,364 1,384 1,407 1,408 1,442 1,456
SCR O&M 614 974 1,019 1,035 1,050 1,521 1,579 1,567
NOx Allowances (6,542) (11,521) (6,601) (6,730) (1,447) (1,608) (1,641) (1,577)
SO2 Allowances (2,501) 872 1,128 1,237 1,334 1,300 1,303 1,567
TABLE 7.3.3-2
VARIABLE OPERATING COSTS FOR REMAINDER OF PROJECTION
AVERAGE COST PER YEAR
($000S,NOMINAL)
ITEM (2007-2032)
---- ---------------------
Limestone 3,704
Ash Disposal 1,784
SCR O&M 1,924
Report Date: May 12, 1999 56 [Stone & Webster Logo]
268
Independent Technical Review
AEE
NOx Allowances (2,164)
SO2 Allowances 1,297
We have reviewed the quantities estimated for each of the above items and
believe they are reasonable levels of consumption for each item. The overall
cost for the limestone, ash removal, and SCR O&M seem reasonable based on our
previous experience. The prices for the NOx and SO2 allowance were provided by
AEE. AEE has indicated they projected the prices for NOx and SO2 allowances
based on their discussions with market traders. As part of the sale of NOx
allowances, AEE has projected a sale of NOx offsets in the year 2000 of $5
million. The prices for NOx allowances are projected to increase 2 percent per
year from $3,200 per ton in 1999. The prices for SO2 allowances are projected at
$185 per ton in 1999, escalating to $343 per ton in 2007 and then decreasing to
$270 per ton by 2027 onward.
7.4 SENSITIVITY CASES
Stone & Webster has performed several sensitivities using the Financial
Projections. The purpose of the sensitivities is to demonstrate how each
sensitivity affects the projected coverage ratio. The sensitivities performed
are as follows:
Sensitivity 1 - London Economics' downside scenario for energy and
capacity prices and capacity factors
Sensitivity 2 - Capacity factors reduced by ten percent
Sensitivity 3 - Fuel costs increased by ten percent (including coal
transportation)
Sensitivity 4 - O&M costs increased by 25 percent
Sensitivity 5 - Capital expenditures increased by 50 percent
Sensitivity 6 - Heat rates at each plant increased by 500 Btu's/kWh
Sensitivity 1 incorporates the downside scenario of market prices and capacity
factors prepared by London Economics. Sensitivity 2 illustrates the impact of a
decrease in the capacity factor through either a reduction in availability or a
lack of economic dispatch. Sensitivity 3 demonstrates the impact of increased
fuel prices. Projecting O&M costs has inherent uncertainty, especially with long
term projections. Sensitivity 4 demonstrates the impact of a large increase in
O&M costs. Although, we believe the O&M projections are more accurate than plus
or minus 25 percent, this sensitivity helps to illustrate the limited impact of
O&M costs on cash flows. Capital expenditures could be higher than currently
projected if life extension activities are more involved than what is typical.
Sensitivity 5 illustrates the effect of higher capital expenditures. We believe
the heat rate projected for each unit is reasonable and that additional
degradation of any heat rate from its current level is unlikely. Sensitivity 6
illustrates the impact of increasing the heat rate beyond what we would consider
reasonable for any further degradation in heat rate for each unit.
Report Date: May 12, 1999 57 [Stone & Webster Logo]
269
Independent Technical Review
AEE
Each sensitivity represents an individual case and should not be combined, since
we believe it is unlikely for each of these cases to occur together.
7.5 COVERAGE RATIOS
The FCCRs for the base case and each of the sensitivities are presented in Table
7.5-1. The coverage ratios are calculated on a pre-tax basis. Fixed charge
payments are estimated and may vary from the payments ultimately negotiated by
AEE with the institutional investors who will acquire and lease the Kintigh and
Milliken Facilities to AEE. In all cases the minimum and average fixed charge
coverage ratio is equal to or above 1.0 for each year. Stone & Webster believes
that these sensitivities reasonably demonstrate the impact on cash flows and
coverage ratios that would occur if the sensitivity cases occurred.
TABLE 7.5-1
LEASE DEFAULT RIGHT COVERAGE RATIOS
MINIMUM FIXED CHARGE AVERAGE FIXED CHARGE
COVERAGE RATIO COVERAGE RATIO
-------------------- --------------------
Base Case 1.67 3.38
Sensitivity 1: 1.28 2.66
London Economics Downside
Sensitivity 2: 1.48 3.12
Reduced Capacity Factor
Sensitivity 3: 1.41 3.04
Increased Fuel Costs
Sensitivity 4: 1.34 3.07
Increased O&M
Sensitivity 5: 1.51 3.26
Increased Capital Expenditures
Sensitivity 6: 1.52 3.19
Increased Heat Rate
Report Date: May 12, 1999 58 [Stone & Webster Logo]
270
EXHIBIT I FINANCIAL PROJECTIONS
271
CONFIDENTIAL AES EASTERN ENERGY BASE CASE
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
1 2 3 4 5 6
--------------------------------------------------------------------
(in thousands, except ratios) Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04
--------------------------------------------------------------------
Total Generation (GwHr) 6,584 10,232 10,210 10,208 10,249 10,111
REVENUES
NYSEG ICAP 20,981 31,472 10,491 0 0 0
Other capacity payments 0 0 32,541 54,901 63,411 72,239
Energy payments 165,956 275,205 292,604 307,247 303,264 280,334
Ancillary & Steam sales 1,433 2,154 2,158 2,161 2,165 2,269
--------------------------------------------------------------------
TOTAL REVENUES 188,370 308,831 337,793 364,309 368,840 354,842
OPERATING COSTS
Coal (56,106) (87,625) (88,897) (90,315) (91,557) (92,143)
Transportation (29,203) (45,705) (46,076) (46,510) (47,155) (46,991)
Coal haulage (2,030) (3,123) (3,186) (3,249) (3,314) (3,381)
--------------------------------------------------------------------
FUEL SUBTOTAL (87,338) (136,453) (138,159) (140,075) (142,026) (142,514)
O & M (8,827) (10,103) (11,699) (9,771) (11,394) (9,553)
G&A (17,533) (27,245) (27,588) (27,881) (28,261) (28,820)
Environmental Expenditures (949) (1,445) (3,527) (2,643) (2,688) (2,734)
Property Tax (11,937) (17,102) (16,112) (14,895) (13,779) (13,200)
Transmission (4,071) (1,015) (1,030) (1,046) (1,061) (1,077)
--------------------------------------------------------------------
TOTAL FIXED O&M (43,317) (56,910) (59,956) (56,236) (57,183) (55,384)
Limestone (1,764) (2,817) (2,835) (2,876) (2,936) (2,937)
Ash Disposal (848) (1,310) (1,364) (1,384) (1,407) (1,408)
SCR O&M (614) (974) (1,019) (1,035) (1,050) (1,521)
NOx Allowances sold (purchased) 6,542 11,521 6,601 6,730 1,447 1,608
SO2 Allowances sold (purchased) 2,501 (872) (1,128) (1,237) (1,334) (1,300)
--------------------------------------------------------------------
TOTAL VARIABLE O&M 5,817 5,548 255 197 (5,280) (5,558)
====================================================================
GROSS CASH FLOW FROM OPERATIONS 63,532 121,017 139,933 168,195 164,350 151,386
Capital expenditures (10,609) (12,249) (7,177) (17,003) (15,604) (6,567)
Interest earned on Reserve 1,667 2,048 1,564 1,552 1,551 1,576
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
--------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 54,403 110,628 134,132 152,556 150,110 146,207
====================================================================
Rent for Principal & Interest on Certificates (32,487) (51,296) (51,296) (51,296) (58,149) (59,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (8,454) (9,204) (9,204) (2,351) (1,500)
--------------------------------------------------------------------
TOTAL RENT PAYMENTS (36,487) (59,750) (60,500) (60,500) (60,500) (60,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.67X 2.16X 2.61X 2.97X 2.58X 2.48X
TEN-YEAR AVERAGE FCCR (2000-2009) 2.44X
AVERAGE FCCR OVER TERM OF CERTIFICATES 3.38X
7 8 9 10 11
-----------------------------------------------------------
(in thousands, except ratios) Dec-05 Dec-06 Dec-07 Dec-08 Dec-09
-----------------------------------------------------------
Total Generation (GwHr) 10,076 10,131 10,131 10,116 9,894
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 81,395 81,857 82,306 82,740 83,158
Energy payments 259,704 269,739 278,590 287,259 290,100
Ancillary & Steam sales 2,273 2,277 2,282 2,286 2,290
-----------------------------------------------------------
TOTAL REVENUES 343,372 353,874 363,177 372,284 375,548
OPERATING COSTS
Coal (93,563) (95,995) (97,360) (98,149) (97,186)
Transportation (50,263) (51,547) (52,578) (53,526) (53,463)
Coal haulage (3,448) (3,517) (3,588) (3,659) (3,733)
-----------------------------------------------------------
FUEL SUBTOTAL (147,274) (151,059) (153,526) (155,334) (154,382)
O & M (12,638) (9,956) (11,718) (11,064) (15,076)
G&A (29,389) (29,970) (30,563) (31,167) (31,783)
Environmental Expenditures (2,781) (5,049) (2,878) (2,927) (2,978)
Property Tax (13,200) (13,200) (13,200) (13,200) (13,200)
Transmission (1,093) (1,110) (1,126) (1,143) (1,161)
-----------------------------------------------------------
TOTAL FIXED O&M (59,101) (59,284) (59,485) (59,502) (64,197)
Limestone (2,981) (3,026) (3,071) (3,117) (3,072)
Ash Disposal (1,442) (1,456) (1,478) (1,494) (1,547)
SCR O&M (1,579) (1,567) (1,591) (1,615) (1,676)
NOx Allowances sold (purchased) 1,641 1,577 1,609 1,734 1,764
SO2 Allowances sold (purchased) (1,303) (1,567) (1,655) (1,534) (1,540)
-----------------------------------------------------------
TOTAL VARIABLE O&M (5,664) (6,039) (6,186) (6,026) (6,070)
===========================================================
GROSS CASH FLOW FROM OPERATIONS 131,333 137,491 143,981 151,422 150,900
Capital expenditures (11,151) (1,086) (8,056) (12,566) (11,903)
Interest earned on Reserve 1,602 1,603 1,603 1,678 1,761
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 121,596 137,821 137,339 140,346 140,570
===========================================================
Rent for Principal & Interest on Certificates (57,000) (59,000) (59,000) (59,000) (59,000)
Non-Deferrable Rent 0 0 0 0 0
Deferrable Rent (2,500) (3,500) (3,500) (3,500) (3,500)
-----------------------------------------------------------
TOTAL RENT PAYMENTS (59,500) (62,500) (62,500) (62,500) (62,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.13X 2.34X 2.33X 2.38X 2.38X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Note: (1) Fixed charges consist of principal and interest on the Certificates
and non-deferrable rent payments under the Leases
Note: (2) FCCR equals cash available for fixed charges divided by fixed charges
Consolidated Projections Base-1 Page 1 of 3
272
CONFIDENTIAL AES EASTERN ENERGY BASE CASE
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
12 13 14 15 16 17
---------------------------------------------------------------------
(in thousands, except ratios) Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15
---------------------------------------------------------------------
Total Generation (GwHr) 10,102 10,078 10,076 10,111 10,076 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 83,560 84,588 85,623 86,667 87,717 88,775
Energy payments 305,762 314,896 324,960 336,525 346,015 358,956
Ancillary & Steam sales 2,294 2,299 2,303 2,308 2,313 2,317
---------------------------------------------------------------------
TOTAL REVENUES 391,617 401,782 412,887 425,499 436,044 450,048
OPERATING COSTS
Coal (100,006) (101,822) (103,843) (106,195) (107,971) (110,781)
Transportation (55,629) (56,626) (57,747) (59,065) (60,068) (61,603)
Coal haulage (3,807) (3,883) (3,961) (4,040) (4,121) (4,203)
---------------------------------------------------------------------
FUEL SUBTOTAL (159,442) (162,331) (165,551) (169,300) (172,160) (176,588)
O & M (11,560) (12,563) (12,791) (13,094) (12,263) (10,262)
G&A (32,411) (33,052) (33,705) (34,372) (35,051) (35,744)
Environmental Expenditures (3,029) (3,081) (1,728) (1,754) (1,780) (1,807)
Property Tax (13,200) (13,200) (13,200) (13,200) (13,200) (13,200)
Transmission (1,178) (1,196) (1,214) (1,232) (1,250) (1,269)
---------------------------------------------------------------------
TOTAL FIXED O&M (61,378) (63,091) (62,638) (63,651) (63,545) (62,283)
Limestone (3,211) (3,237) (3,284) (3,358) (3,408) (3,459)
Ash Disposal (1,534) (1,567) (1,591) (1,609) (1,648) (1,665)
SCR O&M (1,664) (1,677) (1,702) (1,740) (1,805) (1,792)
NOx Allowances sold (purchased) 1,841 1,759 1,795 1,921 1,961 1,885
SO2 Allowances sold (purchased) (1,444) (1,487) (1,467) (1,354) (1,252) (1,408)
---------------------------------------------------------------------
TOTAL VARIABLE O&M (6,012) (6,210) (6,249) (6,140) (6,153) (6,440)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 164,785 170,150 178,448 186,408 194,186 204,738
Capital expenditures (3,715) (14,477) (11,701) (4,184) (11,246) (16,752)
Interest earned on Reserve 1,794 1,864 1,909 1,916 1,929 1,936
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 162,676 157,349 168,470 183,953 184,682 189,734
=====================================================================
Rent for Principal & Interest on Certificates (64,500) (64,500) (66,500) (70,000) (70,000) (70,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (4,500) (4,500) (4,500) (4,500) (5,000)
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (68,500) (69,000) (71,000) (74,500) (74,500) (75,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.52X 2.44X 2.53X 2.63X 2.64X 2.71X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
18 19 20 21 22
-----------------------------------------------------------
(in thousands, except ratios) Dec-16 Dec-17 Dec-18 Dec-19 Dec-20
-----------------------------------------------------------
Total Generation (GwHr) 10,131 10,131 9,879 10,131 10,102
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 93,392 98,157 103,076 108,152 113,390
Energy payments 360,185 361,320 353,369 363,289 363,070
Ancillary & Steam sales 2,322 2,327 2,332 2,332 2,332
-----------------------------------------------------------
TOTAL REVENUES 455,899 461,804 458,777 473,773 478,792
OPERATING COSTS
Coal (113,003) (115,263) (114,770) (119,919) (121,926)
Transportation (62,835) (64,092) (63,768) (66,681) (67,811)
Coal haulage (4,288) (4,373) (4,461) (4,550) (4,641)
-----------------------------------------------------------
FUEL SUBTOTAL (180,126) (183,728) (182,998) (191,151) (194,378)
O & M (10,175) (10,671) (9,511) (11,204) (13,037)
G&A (36,451) (37,172) (37,907) (38,657) (39,422)
Environmental Expenditures (6,986) (1,862) (1,890) (1,918) (1,947)
Property Tax (13,200) (13,200) (13,200) (13,200) (13,200)
Transmission (1,288) (1,307) (1,327) (1,347) (1,367)
-----------------------------------------------------------
TOTAL FIXED O&M (68,100) (64,212) (63,835) (66,326) (68,972)
Limestone (3,511) (3,564) (3,512) (3,672) (3,727)
Ash Disposal (1,690) (1,715) (1,697) (1,767) (1,781)
SCR O&M (1,819) (1,846) (1,818) (1,902) (1,931)
NOx Allowances sold (purchased) 1,923 1,961 2,221 2,040 2,244
SO2 Allowances sold (purchased) (1,385) (1,362) (1,189) (1,315) (1,165)
-----------------------------------------------------------
TOTAL VARIABLE O&M (6,483) (6,526) (5,995) (6,615) (6,360)
===========================================================
GROSS CASH FLOW FROM OPERATIONS 201,191 207,337 205,948 209,681 209,082
Capital expenditures (13,613) (6,697) (4,250) (13,103) (13,365)
Interest earned on Reserve 1,936 1,936 1,936 1,936 1,728
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 189,326 202,389 203,447 198,326 197,257
===========================================================
Rent for Principal & Interest on Certificates (70,000) (45,561) (70,000) (70,000) (56,147)
Non-Deferrable Rent (0) (24,439) 0 0 0
Deferrable Rent (5,500) (5,500) (5,500) (5,500) (2,750)
-----------------------------------------------------------
TOTAL RENT PAYMENTS (75,500) (75,500) (75,500) (75,500) (58,897)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.70X 2.89X 2.91X 2.83X 3.51X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Consolidated Projections Base-1 Page 2 of 3
273
CONFIDENTIAL AES EASTERN ENERGY BASE CASE
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
23 24 25 26 27 28
---------------------------------------------------------------------
(in thousands, except ratios) Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 Dec-26
---------------------------------------------------------------------
Total Generation (GwHr) 10,078 10,056 10,076 10,131 10,131 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 115,658 117,971 120,330 122,737 125,192 127,696
Energy payments 369,464 376,054 384,294 394,129 402,012 410,052
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
---------------------------------------------------------------------
TOTAL REVENUES 487,454 496,357 506,956 519,198 529,535 540,079
OPERATING COSTS
Coal (124,141) (126,258) (129,049) (132,415) (135,063) (137,765)
Transportation (69,027) (70,219) (71,787) (73,622) (75,094) (76,596)
Coal haulage (4,734) (4,828) (4,925) (5,024) (5,124) (5,226)
---------------------------------------------------------------------
FUEL SUBTOTAL (197,901) (201,305) (205,761) (211,060) (215,281) (219,587)
O & M (13,233) (13,431) (13,633) (13,837) (14,045) (14,255)
G&A (40,201) (40,997) (41,808) (42,635) (43,478) (44,338)
Environmental Expenditures (1,976) (2,006) (2,036) (2,066) (2,097) (2,129)
Property Tax (13,200) (13,200) (13,200) (13,200) (13,200) (13,200)
Transmission (1,388) (1,408) (1,430) (1,451) (1,473) (1,495)
---------------------------------------------------------------------
TOTAL FIXED O&M (69,997) (71,041) (72,105) (73,189) (74,292) (75,417)
Limestone (3,756) (3,811) (3,897) (3,956) (4,015) (4,075)
Ash Disposal (1,819) (1,839) (1,855) (1,903) (1,932) (1,961)
SCR O&M (1,947) (1,975) (2,019) (2,049) (2,080) (2,111)
NOx Allowances sold (purchased) 2,144 2,319 2,344 2,253 2,298 2,344
SO2 Allowances sold (purchased) (1,258) (1,148) (1,087) (1,243) (1,243) (1,243)
---------------------------------------------------------------------
TOTAL VARIABLE O&M (6,636) (6,455) (6,514) (6,898) (6,971) (7,046)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 212,920 217,555 222,575 228,051 232,990 238,029
Capital expenditures (23,589) (13,905) (14,183) (14,467) (16,499) (13,244)
Interest earned on Reserve 1,254 981 975 974 974 974
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 190,398 204,444 209,179 214,371 217,278 225,572
=====================================================================
Rent for Principal & Interest on Certificates (19,900) (19,000) (19,000) (19,000) (19,000) (19,000)
Non-Deferrable Rent (18,100) (19,000) (19,000) (19,000) (19,000) (19,000)
Deferrable Rent 0 0 0 0 0 0
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) (38,000) (38,000) (38,000) (38,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 5.01X 5.38X 5.50X 5.64X 5.72X 5.94X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
29 30 31 32 33 34
-----------------------------------------------------------------------
(in thousands, except ratios) Dec-27 Dec-28 Dec-29 Dec-30 Dec-31 Dec-32
-----------------------------------------------------------------------
Total Generation (GwHr) 10,131 9,879 10,131 10,102 10,059 10,021
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 130,250 132,854 135,512 138,222 140,986 143,806
Energy payments 418,253 416,022 435,150 442,580 449,511 456,771
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
-----------------------------------------------------------------------
TOTAL REVENUES 550,834 551,209 572,994 583,134 592,829 602,909
OPERATING COSTS
Coal (140,520) (139,927) (146,205) (148,643) (150,937) (153,436)
Transportation (78,128) (77,732) (81,284) (82,662) (83,935) (85,341)
Coal haulage (5,331) (5,438) (5,546) (5,657) (5,770) (5,886)
-----------------------------------------------------------------------
FUEL SUBTOTAL (223,979) (223,097) (233,036) (236,962) (240,642) (244,663)
O & M (14,469) (14,686) (14,906) (15,130) (15,357) (15,587)
G&A (45,216) (46,110) (47,023) (47,953) (48,902) (49,870)
Environmental Expenditures (2,161) (2,193) (2,226) (2,259) (2,293) (2,327)
Property Tax (13,200) (13,200) (13,200) (13,200) (13,200) (13,200)
Transmission (1,517) (1,540) (1,563) (1,587) (1,610) (1,634)
-----------------------------------------------------------------------
TOTAL FIXED O&M (76,562) (77,729) (78,918) (80,129) (81,363) (82,619)
Limestone (4,136) (4,076) (4,261) (4,325) (4,359) (4,423)
Ash Disposal (1,990) (1,970) (2,050) (2,067) (2,103) (2,119)
SCR O&M (2,143) (2,110) (2,208) (2,241) (2,259) (2,292)
NOx Allowances sold (purchased) 2,391 2,707 2,487 2,735 2,770 2,828
SO2 Allowances sold (purchased) (1,243) (1,104) (1,243) (1,122) (1,148) (1,078)
-----------------------------------------------------------------------
TOTAL VARIABLE O&M (7,121) (6,552) (7,275) (7,019) (7,099) (7,085)
=======================================================================
GROSS CASH FLOW FROM OPERATIONS 243,172 243,830 253,765 259,023 263,724 268,541
Capital expenditures (21,065) (13,779) (14,961) (11,380) (11,608) (8,188)
Interest earned on Reserve 974 974 499 12 0 0
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
-----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 222,893 230,838 239,117 247,468 251,930 260,166
=======================================================================
Rent for Principal & Interest on Certificates (19,000) (19,000) 0 0 0 0
Non-Deferrable Rent (19,000) (19,000) 0 0 0 0
Deferrable Rent 0 0 0 0 0 0
-----------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) 0 0 0 0
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 5.87X 6.07X 0.00X 0.00X 0.00X 0.00X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Consolidated Projections Base-1 Page 3 of 3
274
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FINANCIAL PROJECTIONS DOWNSIDE CASE
CONSOLIDATED PROJECTIONS
1 2 3 4 5 6
--------------------------------------------------------------------
(in thousands, except ratios) Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04
--------------------------------------------------------------------
Total Generation (GwHr) 6,469 10,096 10,078 10,089 10,131 10,111
REVENUES
NYSEG ICAP 20,981 31,472 10,491 0 0 0
Other capacity payments 0 0 27,264 48,442 54,215 63,419
Energy payments 151,170 253,113 267,497 283,127 274,164 256,886
Ancillary & Steam sales 1,433 2,154 2,158 2,161 2,165 2,269
--------------------------------------------------------------------
TOTAL REVENUES 173,584 286,738 307,409 333,731 330,544 322,574
OPERATING COSTS
FUEL SUBTOTAL (85,862) (134,818) (136,567) (138,625) (140,534) (142,514)
TOTAL FIXED O&M (43,317) (56,910) (59,956) (56,236) (57,183) (55,384)
TOTAL VARIABLE O&M 6,242 5,753 431 342 (5,131) (5,558)
====================================================================
GROSS CASH FLOW FROM OPERATIONS 50,647 100,765 111,317 139,211 127,696 119,118
Capital expenditures (10,609) (12,249) (7,177) (17,003) (15,604) (6,567)
Interest earned on Reserve 1,667 2,048 1,564 1,552 1,551 1,576
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
--------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 41,518 90,376 105,516 123,572 113,456 113,939
====================================================================
Rent for Principal & Interest on Certificates (32,487) (51,296) (51,296) (51,296) (58,149) (59,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (8,454) (9,204) (9,204) (2,351) (1,500)
--------------------------------------------------------------------
TOTAL RENT PAYMENTS (36,487) (59,750) (60,500) (60,500) (60,500) (60,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.28X 1.76X 2.06X 2.41X 1.95X 1.93X
TEN-YEAR AVERAGE FCCR (2000-2009) 1.90X
AVERAGE FCCR OVER TERM OF CERTIFICATES 2.66X
7 8 9 10 11
-----------------------------------------------------------
(in thousands, except ratios) Dec-05 Dec-06 Dec-07 Dec-08 Dec-09
-----------------------------------------------------------
Total Generation (GwHr) 10,076 10,131 10,131 10,116 9,894
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 72,827 73,701 74,580 75,466 76,357
Energy payments 238,513 247,478 255,343 263,028 265,397
Ancillary & Steam sales 2,273 2,277 2,282 2,286 2,290
-----------------------------------------------------------
TOTAL REVENUES 313,613 323,456 332,205 340,780 344,044
OPERATING COSTS
FUEL SUBTOTAL (147,274) (151,059) (153,526) (155,334) (154,382)
TOTAL FIXED O&M (59,101) (59,284) (59,485) (59,502) (64,197)
TOTAL VARIABLE O&M (5,664) (6,039) (6,186) (6,026) (6,070)
===========================================================
GROSS CASH FLOW FROM OPERATIONS 101,574 107,074 113,008 119,918 119,395
Capital expenditures (11,151) (1,086) (8,056) (12,566) (11,903)
Interest earned on Reserve 1,602 1,602 1,603 1,678 1,761
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 91,837 107,403 106,367 108,841 109,065
===========================================================
Rent for Principal & Interest on Certificates (57,000) (59,000) (59,000) (59,000) (59,000)
Non-Deferrable Rent 0 0 0 0 0
Deferrable Rent (2,500) (3,500) (3,500) (3,500) (3,500)
-----------------------------------------------------------
TOTAL RENT PAYMENTS (59,500) (62,500) (62,500) (62,500) (62,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.61X 1.82X 1.80X 1.84X 1.85X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Note: (1) Fixed charges consist of principal and interest on the Certificates
and non-deferrable rent payments under the Leases
Note: (2) FCCR equals cash available for fixed charges divided by fixed charges
Consol. Proj. Downside Page 1 of 3
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FINANCIAL PROJECTIONS DOWNSIDE CASE
CONSOLIDATED PROJECTIONS
12 13 14 15 16 17
---------------------------------------------------------------------
(in thousands, except ratios) Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15
---------------------------------------------------------------------
Total Generation (GwHr) 10,102 10,078 10,076 10,111 10,076 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 77,253 76,869 76,438 75,959 75,430 74,850
Energy payments 279,442 287,082 295,514 305,305 313,180 324,146
Ancillary & Steam sales 2,294 2,299 2,303 2,308 2,313 2,317
---------------------------------------------------------------------
TOTAL REVENUES 358,990 366,249 374,255 383,571 390,922 401,313
OPERATING COSTS
FUEL SUBTOTAL (159,442) (162,331) (165,551) (169,300) (172,160) (176,588)
TOTAL FIXED O&M (61,378) (63,091) (62,638) (63,651) (63,545) (62,283)
TOTAL VARIABLE O&M (6,012) (6,210) (6,249) (6,140) (6,153) (6,440)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 132,158 134,617 139,816 144,480 149,064 156,002
Capital expenditures (3,715) (14,477) (11,701) (4,184) (11,246) (16,752)
Interest earned on Reserve 1,794 1,864 1,909 1,916 1,929 1,936
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 130,049 121,816 129,837 142,025 139,560 140,999
=====================================================================
Rent for Principal & Interest on Certificates (64,500) (64,500) (66,500) (70,000) (70,000) (70,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (4,500) (4,500) (4,500) (4,500) (5,000)
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (68,500) (69,000) (71,000) (74,500) (74,500) (75,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.02X 1.89X 1.95X 2.03X 1.99X 2.01X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
18 19 20 21 22
-----------------------------------------------------------
(in thousands, except ratios) Dec-16 Dec-17 Dec-18 Dec-19 Dec-20
-----------------------------------------------------------
Total Generation (GwHr) 10,131 10,131 9,879 10,131 10,102
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 79,543 84,393 89,406 94,586 99,937
Energy payments 326,840 329,513 323,937 334,785 336,404
Ancillary & Steam sales 2,322 2,327 2,332 2,332 2,332
-----------------------------------------------------------
TOTAL REVENUES 408,705 416,233 415,675 431,702 438,673
OPERATING COSTS
FUEL SUBTOTAL (180,126) (183,728) (182,998) (191,151) (194,378)
TOTAL FIXED O&M (68,100) (64,212) (63,835) (66,326) (68,972)
TOTAL VARIABLE O&M (6,483) (6,526) (5,995) (6,615) (6,360)
============================================================
GROSS CASH FLOW FROM OPERATIONS 153,997 161,767 162,846 167,611 168,963
Capital expenditures (13,613) (6,697) (4,250) (13,103) (13,365)
Interest earned on Reserve 1,936 1,936 1,936 1,936 1,728
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 142,132 156,818 160,345 156,256 157,138
===========================================================
Rent for Principal & Interest on Certificates (70,000) (45,561) (70,000) (70,000) (56,147)
Non-Deferrable Rent 0 (24,439) 0 0 0
Deferrable Rent (5,000) (5,500) (5,500) (5,500) (2,750)
-----------------------------------------------------------
TOTAL RENT PAYMENTS (75,000) (75,500) (75,500) (75,500) (58,897)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.03X 1.28X 2.24X 2.29X 2.23X 2.80X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Consol. Proj. Downside Page 2 of 3
276
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FINANCIAL PROJECTIONS DOWNSIDE CASE
CONSOLIDATED PROJECTIONS
23 24 25 26 27 28
---------------------------------------------------------------------
(in thousands, except ratios) Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 Dec-26
---------------------------------------------------------------------
Total Generation (GwHr) 10,078 10,056 10,076 10,131 10,131 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 101,936 103,974 106,054 108,175 110,338 112,545
Energy payments 342,333 348,425 356,073 365,191 372,495 379,945
Ancillary & Steam sales 2,332 233 2,332 2,332 2,332 2,332
---------------------------------------------------------------------
TOTAL REVENUES 446,600 454,731 464,459 475,698 485,165 494,822
OPERATING COSTS
FUEL SUBTOTAL (197,901) (201,305) (205,761) (211,060) (215,281) (219,587)
TOTAL FIXED O&M (69,997) (71,041) (72,105) (73,189) (74,292) (75,417)
TOTAL VARIABLE O&M (6,636) (6,455) (6,514) (6,898) (6,971) (7,046)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 172,066 175,930 180,078 184,551 188,620 192,772
Capital expenditures (23,589) (13,905) (14,183) (14,467) (16,499) (13,244)
Interest earned on Reserve 1,254 981 975 974 974 974
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 149,544 162,818 166,681 170,871 172,908 180,314
=====================================================================
Rent for Principal & Interest on Certificates (19,900) (19,000) (19,000) (19,000) (19,000) (19,000)
Non-Deferrable Rent (18,100) (19,000) (19,000) (19,000) (19,000) (19,000)
Deferrable Rent 0 0 0 0 0 0
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) (38,000) (38,000) (38,000) (38,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 3.94X 4.28X 4.39X 4.50X 4.55X 4.75X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
29 30 31 32 33 34
-----------------------------------------------------------------------
(in thousands, except ratios) Dec-27 Dec-28 Dec-29 Dec-30 Dec-31 Dec-32
-----------------------------------------------------------------------
Total Generation (GwHr) 10,131 10,116 10,131 10,102 10,059 10,021
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 114,796 117,092 119,434 121,823 124,259 126,744
Energy payments 387,543 394,700 403,200 410,075 416,485 423,222
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
-----------------------------------------------------------------------
TOTAL REVENUES 504,671 514,124 524,966 534,229 543,075 552,298
OPERATING COSTS
FUEL SUBTOTAL (223,979) (228,013) (233,036) (236,962) (240,642) (244,663)
TOTAL FIXED O&M (76,562) (77,729) (78,918) (80,129) (81,363) (82,619)
TOTAL VARIABLE O&M (7,121) (6,972) (7,275) (7,019) (7,099) (7,085)
=======================================================================
GROSS CASH FLOW FROM OPERATIONS 197,009 201,409 205,738 210,119 213,971 217,930
Capital expenditures (21,065) (13,779) (14,961) (11,380) (11,608) (8,188)
Interest earned on Reserve 974 974 499 12 0 0
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
-----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 176,730 188,417 191,089 198,564 202,176 209,555
=======================================================================
Rent for Principal & Interest on Certificates (19,000) (19,000) 0 0 0 0
Non-Deferrable Rent (19,000) (19,000) 0 0 0 0
Deferrable Rent 0 0 0 0 0 0
-----------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) 0 0 0 0
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 4.65X 4.96X02X 0.00X 0.00X 0.00X 0.00X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Consol. Proj. Downside Page 3 of 3
277
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FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
1 2 3 4 5 6
--------------------------------------------------------------------
(in thousands, except ratios) Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04
--------------------------------------------------------------------
Total Generation (GwHr) 5,925 9,209 9,189 9,187 9,224 9,100
REVENUES
NYSEG ICAP 20,981 31,472 10,491 0 0 0
Other capacity payments 0 0 32,541 54,901 63,411 72,239
Energy payments 149,360 247,685 263,343 276,522 272,937 252,300
Ancillary & Steam sales 1,433 2,154 2,158 2,161 2,165 2,269
--------------------------------------------------------------------
TOTAL REVENUES 171,775 281,310 308,532 333,584 338,513 326,808
OPERATING COSTS
FUEL SUBTOTAL (78,807) (123,491) (124,962) (126,596) (128,155) (128,601)
TOTAL FIXED O&M (43,317) (56,910) (59,956) (56,236) (57,183) (55,384)
TOTAL VARIABLE O&M 7,622 8,246 3,099 3,164 (2,662) (2,828)
====================================================================
GROSS CASH FLOW FROM OPERATIONS 57,273 109,156 126,714 153,917 150,512 139,996
Capital expenditures (10,609) (12,249) (7,177) (17,003) (15,604) (6,567)
Interest earned on Reserve 1,667 2,048 1,564 1,552 1,551 1,576
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
--------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 48,143 98,767 120,913 138,277 136,273 134,817
====================================================================
Rent for Principal & Interest on Certificates (32,487) (51,296) (51,296) (51,296) (58,149) (59,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (8,454) (9,204) (9,204) (2,351) (1,500)
--------------------------------------------------------------------
TOTAL RENT PAYMENTS (36,487) (59,750) (60,500) (60,500) (60,500) (60,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.48X 1.93X 2.36X 2.70X 2.34X 2.29X
TEN-YEAR AVERAGE FCCR (2000-2009) 2.23X
AVERAGE FCCR OVER TERM OF CERTIFICATES 3.12X
7 8 9 10 11
-----------------------------------------------------------
(in thousands, except ratios) Dec-05 Dec-06 Dec-07 Dec-08 Dec-09
-----------------------------------------------------------
Total Generation (GwHr) 9,068 9,118 9,118 9,104 8,905
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 81,395 81,857 82,306 82,740 83,158
Energy payments 233,733 242,765 250,731 258,533 261,090
Ancillary & Steam sales 2,273 2,277 2,282 2,286 2,290
-----------------------------------------------------------
TOTAL REVENUES 317,401 326,900 335,318 343,558 346,538
OPERATING COSTS
FUEL SUBTOTAL (132,891) (136,305) (138,532) (140,167) (139,317)
TOTAL FIXED O&M (59,101) (59,284) (59,485) (59,502) (64,197)
TOTAL VARIABLE O&M (2,837) (3,089) (3,135) (2,981) (3,009)
===========================================================
GROSS CASH FLOW FROM OPERATIONS 122,571 128,221 134,166 140,909 140,016
Capital expenditures (11,151) (1,086) (8,056) (12,566) (11,903)
Interest earned on Reserve 1,602 1,603 1,603 1,678 1,761
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 112,834 128,551 127,525 129,833 129,686
===========================================================
Rent for Principal & Interest on Certificates (57,000) (59,000) (59,000) (59,000) (59,000)
Non-Deferrable Rent 0 0 0 0 0
Deferrable Rent (2,500) (3,500) (3,500) (3,500) (3,500)
-----------------------------------------------------------
TOTAL RENT PAYMENTS (59,500) 62,500 62,500 (62,500) (62,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.98X 2.18X 2.16X 2.20X 2.20X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Note: (1) Fixed charges consist of principal and interest on the Certificates
and non-deferrable rent payments under the Leases
Note: (2) FCCR equals cash available for fixed charges divided by fixed charges
Consol. Proj. CapFac Page 1 of 3
278
CONFIDENTIAL AES EASTERN ENERGY CAPACITY FACTOR - 10%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
12 13 14 15 16 17
---------------------------------------------------------------------
(in thousands, except ratios) Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15
---------------------------------------------------------------------
Total Generation (GwHr) 9,092 9,070 9,068 9,100 9,068 9,118
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 83,560 84,588 85,623 86,667 87,717 88,775
Energy payments 275,186 283,406 292,464 302,873 311,413 323,060
Ancillary & Steam sales 2,294 2,299 2,303 2,308 2,313 2,317
---------------------------------------------------------------------
TOTAL REVENUES 361,040 370,293 380,391 391,847 401,443 414,153
OPERATING COSTS
FUEL SUBTOTAL (143,878) (146,487) (149,392) (152,774) (155,356) (159,349)
TOTAL FIXED O&M (61,378) (63,091) (62,638) (63,651) (63,545) (62,283)
TOTAL VARIABLE O&M (2,945) (3,103) (3,126) (3,016) (3,017) (3,263)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 152,839 157,611 165,234 172,405 179,525 189,258
Capital expenditures (3,715) (14,477) (11,701) (4,184) (11,246) (16,752)
Interest earned on Reserve 1,794 1,864 1,909 1,916 1,929 1,936
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 150,730 144,811 155,255 169,950 170,020 174,254
=====================================================================
Rent for Principal & Interest on Certificates (64,500) (64,500) (66,500) (70,000) (70,000) (70,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (4,500) (4,500) (4,500) (4,500) 5,000
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (68,500) (69,000) (71,000) (74,500) (74,500) (75,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.34X 2.25X 2.33X 2.43X 2.43X 2.49X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
18 19 20 21 22
-----------------------------------------------------------
(in thousands, except ratios) Dec-16 Dec-17 Dec-18 Dec-19 Dec-20
-----------------------------------------------------------
Total Generation (GwHr) 9,118 9,118 8,891 9,118 9,092
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 93,392 98,157 103,076 108,152 113,390
Energy payments 324,167 325,188 318,032 326,960 326,763
Ancillary & Steam sales 2,322 2,327 2,332 2,332 2,332
-----------------------------------------------------------
TOTAL REVENUES 419,880 425,672 423,440 437,444 442,485
OPERATING COSTS
FUEL SUBTOTAL (162,542) (165,793) (165,145) (172,491) (175,405)
TOTAL FIXED O&M (68,100) (64,212) (63,835) (66,326) (68,972)
TOTAL VARIABLE O&M (3,288) (3,314) (2,823) (3,366) (3,122)
===========================================================
GROSS CASH FLOW FROM OPERATIONS 185,950 192,353 191,637 195,261 194,986
Capital expenditures (13,613) (6,697) (4,250) (13,103) (13,365)
Interest earned on Reserve 1,936 1,936 1,936 1,936 1,728
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 174,085 187,404 189,136 183,906 183,161
===========================================================
Rent for Principal & Interest on Certificates (70,000) (45,561) (70,000) (70,000) (56,147)
Non-Deferrable Rent 0 (24,439) 0 0 0
Deferrable Rent 5,000 (5,500) (5,500) (5,500) (2,750)
-----------------------------------------------------------
TOTAL RENT PAYMENTS (75,000) (75,500) (75,500) (75,500) (58,897)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.49X 1.48X 2.68X 2.70X 2.63X 3.26X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Consol. Proj. CapFac Page 2 of 3
279
CONFIDENTIAL AES EASTERN ENERGY CAPACITY FACTOR - 10%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
23 24 25 26 27 28
---------------------------------------------------------------------
(in thousands, except ratios) Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 Dec-26
---------------------------------------------------------------------
Total Generation (GwHr) 9,070 9,051 9,068 9,118 9,118 9,118
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 116,658 117,971 120,330 122,737 125,192 127,696
Energy payments 332,518 338,449 345,864 354,716 361,810 369,047
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
---------------------------------------------------------------------
TOTAL REVENUES 450,507 458,751 468,526 479,785 489,334 499,074
OPERATING COSTS
FUEL SUBTOTAL (178,585) (181,657) (185,678) (190,457) (194,266) (198,151)
TOTAL FIXED O&M (69,997) (71,041) (72,105) (73,189) (74,292) (75,417)
TOTAL VARIABLE O&M (3,355) (3,176) (3,196) (3,506) (3,536) (3,567)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 198,570 202,876 207,548 212,634 217,239 221,939
Capital expenditures (23,589) (13,905) (14,183) (14,467) (16,499) (13,244)
Interest earned on Reserve 1,254 981 975 974 974 974
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 176,049 189,765 194,151 198,953 201,527 209,481
=====================================================================
Rent for Principal & Interest on Certificates (19,900) (19,000) (19,000) (19,000) (19,000) (19,000)
Non-Deferrable Rent (18,100) (19,000) (19,000) (19,000) (19,000) (19,000)
Deferrable Rent 0 0 0 0 0 0
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) (38,000) (38,000) (38,000) (38,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 4.63X 4.99X 5.11X 5.24X 5.30X 5.51X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
29 30 31 32 33 34
-----------------------------------------------------------------------
(in thousands, except ratios) Dec-27 Dec-28 Dec-29 Dec-30 Dec-31 Dec-32
-----------------------------------------------------------------------
Total Generation (GwHr) 9,118 8,891 9,118 9,092 9,053 9,019
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 130,250 132,854 135,512 138,222 140,986 143,806
Energy payments 376,428 374,420 391,635 398,322 404,560 411,094
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
-----------------------------------------------------------------------
TOTAL REVENUES 509,009 509,606 529,479 538,876 547,878 557,232
OPERATING COSTS
FUEL SUBTOTAL (202,114) (201,331) (210,287) (213,832) (217,155) (220,786)
TOTAL FIXED O&M (76,562) (77,729) (78,918) (80,129) (81,363) (82,619)
TOTAL VARIABLE O&M (3,598) (3,048) (3,659) (3,390) (3,422) (3,368)
=======================================================================
GROSS CASH FLOW FROM OPERATIONS 226,735 227,499 236,615 241,525 245,938 250,459
Capital expenditures (21,065) (13,779) (14,961) (11,380) (11,608) (8,188)
Interest earned on Reserve 974 974 499 12 0 0
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
-----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 206,456 214,506 221,966 229,970 234,143 242,084
=======================================================================
Rent for Principal & Interest on Certificates (19,000) (19,000) 0 0 0 0
Non-Deferrable Rent (19,000) (19,000) 0 0 0 0
Deferrable Rent 0 0 0 0 0 0
-----------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) 0 0 0 0
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 5.43X 5.64X 0.00X 0.00X 0.00X 0.00X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Consol. Proj. CapFac Page 3 of 3
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FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
1 2 3 4 5 6
--------------------------------------------------------------------
(in thousands, except ratios) Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04
--------------------------------------------------------------------
Total Generation (GwHr) 6,584 10,232 10,210 10,208 10,249 10,111
REVENUES
NYSEG ICAP 20,981 31,472 10,491 0 0 0
Other capacity payments 0 0 32,541 54,901 63,411 72,239
Energy payments 165,956 275,205 292,604 307,247 303,264 280,334
Ancillary & Steam sales 1,433 2,154 2,158 2,161 2,165 2,269
--------------------------------------------------------------------
TOTAL REVENUES 188,370 308,831 337,793 364,309 368,840 354,842
OPERATING COSTS
FUEL SUBTOTAL (96,072) (150,098) (151,975) (154,082) (156,229) (156,765)
TOTAL FIXED O&M (43,317) (56,910) (59,956) (56,236) (57,183) (55,384)
TOTAL VARIABLE O&M 5,817 5,548 255 197 (5,280) (5,558)
====================================================================
GROSS CASH FLOW FROM OPERATIONS 54,799 107,371 126,117 154,188 150,147 137,134
Capital expenditures (10,609) (12,249) (7,177) (17,003) (15,604) (6,567)
Interest earned on Reserve 1,667 2,048 1,564 1,552 1,551 1,576
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
--------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 45,669 96,982 120,316 138,549 135,907 131,955
====================================================================
Rent for Principal & Interest on Certificates (32,487) (51,296) (51,296) (51,296) (58,149) (59,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (8,454) (9,204) (9,204) (2,351) (1,500)
--------------------------------------------------------------------
TOTAL RENT PAYMENTS (36,487) (59,750) (60,500) (60,500) (60,500) (60,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.41X 1.89X 2.35X 2.70X 2.34X 2.24X
TEN-YEAR AVERAGE FCCR (2000-2009) 2.18X
AVERAGE FCCR OVER TERM OF CERTIFICATES 3.04X
7 8 9 10 11
-----------------------------------------------------------
(in thousands, except ratios) Dec-05 Dec-06 Dec-07 Dec-08 Dec-09
-----------------------------------------------------------
Total Generation (GwHr) 10,076 10,131 10,131 10,116 9,894
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 81,395 81,857 82,306 82,740 83,158
Energy payments 259,704 269,739 278,590 287,259 290,100
Ancillary & Steam sales 2,273 2,277 2,282 2,286 2,290
-----------------------------------------------------------
TOTAL REVENUES 343,372 353,874 363,177 372,284 375,548
OPERATING COSTS
FUEL SUBTOTAL (162,001) (166,165) (168,878) (170,868) (169,820)
TOTAL FIXED O&M (59,101) (59,284) (59,485) (59,502) (64,197)
TOTAL VARIABLE O&M (5,664) (6,039) (6,186) (6,026) (6,070)
===========================================================
GROSS CASH FLOW FROM OPERATIONS 116,605 122,385 128,628 135,889 135,462
Capital expenditures (11,151) (1,086) (8,056) (12,566) (11,903)
Interest earned on Reserve 1,602 1,603 1,603 1,678 1,761
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 106,869 122,715 121,987 124,812 125,132
===========================================================
Rent for Principal & Interest on Certificates (57,000) (59,000) (59,000) (59,000) (59,000)
Non-Deferrable Rent 0 0 0 0 0
Deferrable Rent (2,500) (3,500) (3,500) (3,500) (3,500)
-----------------------------------------------------------
TOTAL RENT PAYMENTS (59,500) (62,500) (62,500) (62,500) (62,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.87X 2.08X 2.07X 2.12X 2.12X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Note: (1) Fixed charges consist of principal and interest on the Certificates
and non-deferrable rent payments under the Leases
Note: (2) FCCR equals cash available for fixed charges divided by fixed charges
Consol. Proj. Fuel Page 1 of 3
281
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FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
12 13 14 15 16 17
---------------------------------------------------------------------
(in thousands, except ratios) Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15
---------------------------------------------------------------------
Total Generation (GwHr) 10,102 10,078 10,076 10,111 10,076 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 83,560 84,588 85,623 86,667 87,717 88,775
Energy payments 305,762 314,896 324,960 336,525 346,015 358,956
Ancillary & Steam sales 2,294 2,299 2,303 2,308 2,313 2,317
---------------------------------------------------------------------
TOTAL REVENUES 391,617 401,782 412,887 425,499 436,044 450,048
OPERATING COSTS
FUEL SUBTOTAL (175,386) (178,565) (182,106) (186,230) (189,376) (194,247)
TOTAL FIXED O&M (61,378) (63,091) (62,638) (63,651) (63,545) (62,283)
TOTAL VARIABLE O&M (6,012) (6,210) (6,249) (6,140) (6,153) (6,440)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 148,841 153,917 161,893 169,478 176,970 187,080
Capital expenditures (3,715) (14,477) (11,701) (4,184) (11,246) (16,752)
Interest earned on Reserve 1,794 1,864 1,909 1,916 1,929 1,936
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 146,732 141,116 151,914 167,023 167,466 172,076
=====================================================================
Rent for Principal & Interest on Certificates (64,500) (64,500) (66,500) (70,000) (70,000) (70,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (4,500) (4,500) (4,500) (4,500) (5,000)
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (68,500) (69,000) (71,000) (74,500) (74,500) (75,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.27X 2.19X 2.28X 2,39X 2.39X 2.46X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
18 19 20 21 22
-----------------------------------------------------------
(in thousands, except ratios) Dec-16 Dec-17 Dec-18 Dec-19 Dec-20
-----------------------------------------------------------
Total Generation (GwHr) 10,131 10,131 9,879 10,131 10,102
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 93,392 98,157 103,076 108,152 113,390
Energy payments 360,185 361,320 353,369 363,289 363,070
Ancillary & Steam sales 2,322 2,327 2,332 2,332 2,332
-----------------------------------------------------------
TOTAL REVENUES 455,899 461,804 458,777 473,773 478,792
OPERATING COSTS
FUEL SUBTOTAL (198,138) (202,101) (201,298) (210,266) (213,816)
TOTAL FIXED O&M (68,100) (64,212) (63,835) (66,326) (68,972)
TOTAL VARIABLE O&M (6,483) (6,526) (5,995) (6,615) (6,360)
===========================================================
GROSS CASH FLOW FROM OPERATIONS 183,178 188,965 187,648 190,566 189,644
Capital expenditures (13,613) (6,697) (4,250) (13,103) (13,365)
Interest earned on Reserve 1,936 1,936 1,936 1,936 1,728
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 171,313 184,016 185,147 179,211 177,819
===========================================================
Rent for Principal & Interest on Certificates (70,000) (45,561) (70,000) (70,000) (56,147)
Non-Deferrable Rent 0 (24,439) 0 0 0
Deferrable Rent (5,500) (5,500) (5,500) (5,500) (2,750)
-----------------------------------------------------------
TOTAL RENT PAYMENTS (75,500) (75,500) (75,000) (75,500) (58,897)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.45X 2.63X 2.64X 2.56X 3.17X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Consol. Proj. Fuel Page 2 of 3
282
CONFIDENTIAL AES EASTERN ENERGY FUEL + 10%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
23 24 25 26 27 28
---------------------------------------------------------------------
(in thousands, except ratios) Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 Dec-26
---------------------------------------------------------------------
Total Generation (GwHr) 10,078 10,056 10,076 10,131 10,131 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 115,658 117,971 120,330 122,737 125,192 127,696
Energy payments 369,464 376,054 384,294 394,129 402,012 410,052
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
---------------------------------------------------------------------
TOTAL REVENUES 487,454 496,357 506,956 519,198 529,535 540,079
OPERATING COSTS
FUEL SUBTOTAL (217,692) (221,436) (226,338) (232,166) (236,810) (241,546)
TOTAL FIXED O&M (69,997) (71,041) (72,105) (73,189) (74,292) (75,417)
TOTAL VARIABLE O&M (6,636) (6,455) (6,514) (6,898) (6,971) (7,046)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 193,129 197,425 210,999 206,945 211,461 216,070
Capital expenditures (23,589) (13,905) (14,183) (14,467) (16,499) (13,244)
Interest earned on Reserve 1,254 981 975 974 974 974
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 170,608 184,313 188,602 193,265 195,749 203,613
=====================================================================
Rent for Principal & Interest on Certificates (19,900) (19,000) (19,000) (19,000) (19,000) (19,000)
Non-Deferrable Rent (18,100) (19,000) (19,000) (19,000) (19,000) (19,000)
Deferrable Rent 0 0 0 0 0 0
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) (38,000) (38,000) (38,000) (38,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 4.49X 4.85X 4.96X 5.09X 5.15X 5.36X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
29 30 31 32 33 34
-----------------------------------------------------------------------
(in thousands, except ratios) Dec-27 Dec-28 Dec-29 Dec-30 Dec-31 Dec-32
-----------------------------------------------------------------------
Total Generation (GwHr) 10,131 9,879 10,131 10,102 10,059 10,021
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 130,250 132,854 135,512 138,222 140,986 143,806
Energy payments 418,253 416,022 435,150 442,580 449,511 456,771
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
-----------------------------------------------------------------------
TOTAL REVENUES 550,834 551,209 572,994 583,134 592,829 602,909
OPERATING COSTS
FUEL SUBTOTAL (246,377) (245,406) (256,339) (260,658) (264,707) (269,130)
TOTAL FIXED O&M (76,562) (77,729) (78,918) (80,129) (81,363) (82,619)
TOTAL VARIABLE O&M (7,121) (6,552) (7,275) (7,019) (7,099) (7,085)
=======================================================================
GROSS CASH FLOW FROM OPERATIONS 220,774 221,521 230,462 235,327 239,660 244,074
Capital expenditures (21,065) (13,779) (14,961) (11,380) (11,608) (8,188)
Interest earned on Reserve 974 974 499 12 0 0
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
-----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 200,495 208,528 215,813 223,772 227,865 235,699
=======================================================================
Rent for Principal & Interest on Certificates (19,000) (19,000) 0 0 0 0
Non-Deferrable Rent (19,000) (19,000) 0 0 0 0
Deferrable Rent 0 0 0 0 0 0
-----------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) 0 0 0 0
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 5.28X 5.49X 0.00X 0.00X 0.00X 0.00X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Consol. Proj. Fuel Page 3 of 3
283
CONFIDENTIAL AES EASTERN ENERGY OM +25%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
1 2 3 4 5 6
--------------------------------------------------------------------
(in thousands, except ratios) Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04
--------------------------------------------------------------------
Total Generation (GwHr) 6,584 10,232 10,210 10,208 10,249 10,111
REVENUES
NYSEG ICAP 20,981 31,472 10,491 0 0 0
Other capacity payments 0 0 32,541 54,901 63,411 72,239
Energy payments 165,956 275,205 292,604 307,247 303,264 280,334
Ancillary & Steam sales 1,433 2,154 2,158 2,161 2,165 2,269
--------------------------------------------------------------------
TOTAL REVENUES 188,370 308,831 337,793 364,309 368,840 354,842
OPERATING COSTS
FUEL SUBTOTAL (87,338) (136,453) (138,159) (140,075) (142,026) (142,514)
TOTAL FIXED O&M (54,146) (71,137) (74,945) (70,295) (71,479) (69,230)
TOTAL VARIABLE O&M 5,817 5,548 255 197 (5,280) (5,558)
====================================================================
GROSS CASH FLOW FROM OPERATIONS 52,703 106,789 124,944 154,137 150,054 137,540
Capital expenditures (10,609) (12,249) (7,177) (17,003) (15,604) (6,567)
Interest earned on Reserve 1,667 2,048 1,564 1,552 1,551 1,576
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
--------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 43,574 96,400 119,143 138,497 135,814 132,361
====================================================================
Rent for Principal & Interest on Certificates (32,487) (51,296) (51,296) (51,296) (58,149) (59,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (8,454) (9,204) (9,204) (2,351) (1,500)
--------------------------------------------------------------------
TOTAL RENT PAYMENTS (36,487) (59,750) (60,500) (60,500) (60,500) (60,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.34X 1.88X 2.32X 2.70X 2.34. 2.24X
TEN-YEAR AVERAGE FCCR (2000-2009) 2.18X
AVERAGE FCCR OVER TERM OF CERTIFICATES 3.07X
7 8 9 10 11
---------------------------------------------------------
(in thousands, except ratios) Dec-05 Dec-06 Dec-07 Dec-08 Dec-09
---------------------------------------------------------
Total Generation (GwHr) 10,076 10,131 10,131 10,116 9,894
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 81,395 81,857 82,306 82,740 83,158
Energy payments 259,704 269,739 278,590 287,259 290,100
Ancillary & Steam sales 2,273 2,277 2,282 2,286 2,290
---------------------------------------------------------
TOTAL REVENUES 343,372 353,874 36,177 372,284 375,548
OPERATING COSTS
FUEL SUBTOTAL (147,274) (151,059) (153,526) (155,334) (154,382)
TOTAL FIXED O&M (73,877) (74,105) (74,356) (74,377) (80,246)
TOTAL VARIABLE O&M (5,664) (6,039) (6,186) (6,026) (6,070)
=========================================================
GROSS CASH FLOW FROM OPERATIONS 116,557 122,670 129,109 136,547 134,851
Capital expenditures (11,151) (1,086) (8,056) (12,566) (11,903)
Interest earned on Reserve 1,602 1,603 1,603 1,678 1,761
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
---------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 106,821 123,000 122,468 125,470 124,521
=========================================================
Rent for Principal & Interest on Certificates (57,000) (59,000) (59,000) (59,000) (59,000)
Non-Deferrable Rent 0 0 0 0 0
Deferrable Rent (2,500) (3,500) (3,500) (3,500) (3,500)
---------------------------------------------------------
TOTAL RENT PAYMENTS (59,500) (62,500) (62,500) (62,500) (62,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.87X 2.08X 2.08X 2.13X 2.11X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Note: (1) Fixed charges consist of principal and interest on the Certificates
and non-deferrable rent payments under the Leases
Note: (2) FCCR equals cash available for fixed charges divided by fixed charges
CONSOL. PROJ. O&M PAGE 1 OF 3
284
CONFIDENTIAL AES EASTERN ENERGY OM +25%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
12 13 14 15 16 17
--------------------------------------------------------------------
(in thousands, except ratios) Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15
--------------------------------------------------------------------
Total Generation (GwHr) 10,102 10,078 10,076 10,111 10,176 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 83,560 84,588 85,623 86,667 87,717 88,775
Energy payments 305,762 314,896 324,960 336,525 346,015 358,956
Ancillary & Steam sales 2,294 2,299 2,303 2,308 2,313 2,317
--------------------------------------------------------------------
TOTAL REVENUES 391,617 401,782 412,887 425,499 436,044 450,048
OPERATING COSTS
FUEL SUBTOTAL (159,442) (162,331) (165,551) (169,300) (172,160) (176,588)
TOTAL FIXED O&M (76,722) (78,864) (78,298) (79,564) (79,431) (77,853)
TOTAL VARIABLE O&M (6,012) (6,210) (6,249) (6,140) (6,153) (6,440)
====================================================================
GROSS CASH FLOW FROM OPERATIONS 149,441 154,377 162,789 170,496 178,300 189,168
Capital expenditures (3,715) (14,477) (11,701) (4,184) (11,246) (16,752)
Interest earned on Reserve 1,794 1,864 1,909 1,916 1,929 1,936
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
--------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 147,332 141,577 152,810 168,040 168,795 174,164
====================================================================
Rent for Principal & Interest on Certificates (64,500) (64,500) (66,500) (70,000) (70,000) (70,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (4,500) (4,500) (4,500) (4,500) (5,000)
--------------------------------------------------------------------
TOTAL RENT PAYMENTS (68,500) (69,000) (71,000) (74,500) (74,500) (75,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.28X 2.19X 2.30X 2.40X 2.41X 2.49X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
18 19 20 21 22
--------------------------------------------------------
(in thousands, except ratios) Dec-16 Dec-17 Dec-18 Dec-19 Dec-20
--------------------------------------------------------
Total Generation (GwHr) 10,131 10,131 9,879 10,131 10,102
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 93,392 98,157 103,076 108,152 113,390
Energy payments 360,185 361,320 353,369 363,289 363,070
Ancillary & Steam sales 2,322 2,327 2,332 2,332 2,332
--------------------------------------------------------
TOTAL REVENUES 455,899 461,804 458,777 473,773 478,792
OPERATING COSTS
FUEL SUBTOTAL (180,126) (183,728) (182,998) (191,151) (194,378)
TOTAL FIXED O&M (85,125) (80,265) (79,794) (82,908) (86,215)
TOTAL VARIABLE O&M (6,483) (6,526) (5,995) (6,615) (6,360)
========================================================
GROSS CASH FLOW FROM OPERATIONS 184,166 191,284 189,989 193,099 191,839
Capital expenditures (13,613) (6,697) (4,250) (13,103) (13,365)
Interest earned on Reserve 1,936 1,936 1,936 1,936 1,728
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
--------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 172,301 186,336 187,488 181,745 180,014
========================================================
Rent for Principal & Interest on Certificates (70,000) (45,561) (70,000) (70,000) (56,147)
Non-Deferrable Rent 0 (24,439) 0 0 0
Deferrable Rent (5,500) (5,500) (5,500) (5,500) (2,750)
--------------------------------------------------------
TOTAL RENT PAYMENTS (75,500) (75,500) (75,500) (75,500) (58,897)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.46X 2.66X 2.68X 2.60X 3.21X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
CONSOL. PROJ. O&M PAGE 2 OF 3
285
CONFIDENTIAL AES EASTERN ENERGY OM +25%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
23 24 25 26 27 28
-----------------------------------------------------------------------
(in thousands, except ratios) Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 Dec-26
-----------------------------------------------------------------------
Total Generation (GwHr) 10,078 10,056 10,076 10,131 10,131 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 115,658 117,971 120,330 122,737 125,192 127,696
Energy payments 369,464 376,054 384,294 394,129 402,012 410,052
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
-----------------------------------------------------------------------
TOTAL REVENUES 487,454 496,357 506,956 519,198 529,535 540,079
OPERATING COSTS
FUEL SUBTOTAL (197,901) (201,305) (205,761) (211,060) (215,281) (219,587)
TOTAL FIXED O&M (87,497) (88,802) (90,131) (91,486) (92,866) (94,271)
TOTAL VARIABLE O&M (6,636) (6,455) (6,514) (6,898) (6,971) (7,046)
=======================================================================
GROSS CASH FLOW FROM OPERATIONS 195,420 199,795 204,549 209,754 214,417 219,175
Capital expenditures (23,589) (13,905) (14,183) (14,467) (16,499) (13,244)
Interest earned on Reserve 1,254 981 975 974 974 974
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
-----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 172,898 186,684 191,152 196,074 198,705 206,717
=======================================================================
Rent for Principal & Interest on Certificates (19,900) (19,000) (19,000) (19,000) (19,000) (19,000)
Non-Deferrable Rent (18,100) (19,000) (19,000) (19,000) (19,000) (19,000)
Deferrable Rent 0 0 0 0 0 0
-----------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) (38,000) (38,000) (38,000) (38,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 4.55X 4.91X 5.03X 5.16X 5.23X 5.44X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
29 30 31 32 33 34
---------------------------------------------------------------------
(in thousands, except ratios) Dec-27 Dec-28 Dec-29 Dec-30 Dec-31 Dec-32
---------------------------------------------------------------------
Total Generation (GwHr) 10,131 9,879 10,131 10,102 10,059 10,021
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 130,250 132,854 135,512 138,222 140,986 143,806
Energy payments 418,253 416,022 435,150 442,580 449,511 456,771
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
---------------------------------------------------------------------
TOTAL REVENUES 550,834 551,209 572,994 583,134 592,829 602,909
OPERATING COSTS
FUEL SUBTOTAL (223,979) (223,097) (233,036) (236,962) (240,642) (244,663)
TOTAL FIXED O&M (95,703) (97,162) (98,648) (100,161) (101,703) (103,274)
TOTAL VARIABLE O&M (7,121) (6,552) (7,275) (7,019) (7,099) (7,085)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 224,031 224,398 234,036 238,991 243,384 247,886
Capital expenditures (21,065) (13,779) (14,961) (11,380) (11,608) (8,188)
Interest earned on Reserve 974 974 499 12 0 0
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 203,753 211,405 219,387 227,436 231,589 239,511
=====================================================================
Rent for Principal & Interest on Certificates (19,000) (19,000) 0 0 0 0
Non-Deferrable Rent (19,000) (19,000) 0 0 0 0
Deferrable Rent 0 0 0 0 0 0
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) 0 0 0 0
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 5.36X 5.56X 0.00X 0.00X 0.00X 0.00X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
CONSOL. PROJ. O&M PAGE 3 OF 3
286
CONFIDENTIAL AES EASTERN ENERGY CAPITAL EXPENDITURES +50%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
1 2 3 4 5 6
----------------------------------------------------------------------
(in thousands, except ratios) Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04
----------------------------------------------------------------------
Total Generation (GwHr) 6,584 10,232 10,210 10,208 10,249 10,111
REVENUES
NYSEG ICAP 20,981 31,472 10,491 0 0 0
Other capacity payments 0 0 32,541 54,901 63,411 72,239
Energy payments 165,956 275,205 292,604 307,247 303,264 280,334
Ancillary & Steam sales 1,433 2,154 2,158 2,161 2,165 2,269
----------------------------------------------------------------------
TOTAL REVENUES 188,370 308,831 337,793 364,309 368,840 354,842
OPERATING COSTS
FUEL SUBTOTAL (87,338) (136,453) (138,159) (140,075) (142,026) (142,514)
TOTAL FIXED O&M (43,317) (56,910) (59,956) (56,236) (57,183) (55,384)
TOTAL VARIABLE O&M 5,817 5,548 255 197 (5,280) (5,558)
======================================================================
GROSS CASH FLOW FROM OPERATIONS 63,532 121,017 139,933 168,195 164,350 151,386
Capital expenditures (15,913) (18,374) (10,765) (25,505) (23,406) (9,851)
Interest earned on Reserve 1,667 2,048 1,564 1,552 1,551 1,576
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 49,099 104,503 130,544 144,055 142,308 142,923
======================================================================
Rent for Principal & Interest on Certificates (32,487) (51,296) (51,296) (51,296) (58,149) (59,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (8,454) (9,204) (9,204) (2,351) (1,500)
----------------------------------------------------------------------
TOTAL RENT PAYMENTS (36,487) (59,750) (60,500) (60,500) (60,500) (60,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.51X 2.04X 2.54X 2.81X 2.45X 2.42X
TEN-YEAR AVERAGE FCCR (2000-2009) 2.34X
AVERAGE FCCR OVER TERM OF CERTIFICATES 3.26X
7 8 9 10 11
---------------------------------------------------------
(in thousands, except ratios) Dec-05 Dec-06 Dec-07 Dec-08 Dec-09
---------------------------------------------------------
Total Generation (GwHr) 10,076 10,131 10,131 10,116 9,894
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 81,395 81,857 82,306 82,740 83,158
Energy payments 259,704 269,739 278,590 287,259 290,100
Ancillary & Steam sales 2,273 2,277 2,282 2,286 2,290
---------------------------------------------------------
TOTAL REVENUES 343,372 353,874 363,177 372,284 375,548
OPERATING COSTS
FUEL SUBTOTAL (147,274) (151,059) (153,526) (155,334) (154,382)
TOTAL FIXED O&M (59,101) (59,284) (59,485) (59,502) (64,197)
TOTAL VARIABLE O&M (5,664) (6,039) (6,186) (6,026) (6,070)
=========================================================
GROSS CASH FLOW FROM OPERATIONS 131,333 137,491 143,981 151,422 150,900
Capital expenditures (16,727) (1,628) (12,084) (18,850) (17,854)
Interest earned on Reserve 1,602 1,603 1,603 1,678 1,761
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
---------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 116,020 137,278 133,311 134,063 134,619
=========================================================
Rent for Principal & Interest on Certificates (57,000) (59,000) (59,000) (59,000) (59,000)
Non-Deferrable Rent 0 0 0 0 0
Deferrable Rent (2,500) (3,500) (3,500) (3,500) (3,500)
---------------------------------------------------------
TOTAL RENT PAYMENTS (59,500) (62,500) (62,500) (62,500) (62,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.04X 2.33X 2.26X 2.27X 2.28X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Note: (1) Fixed charges consist of principal and interest on the Certificates
and non-deferrable rent payments under the Leases
Note: (2) FCCR equals cash available for fixed charges divided by fixed charges
CONSOL. PROJ. CAPX PAGE 1 OF 3
287
CONFIDENTIAL AES EASTERN ENERGY CAPITAL EXPENDITURES +50%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
12 13 14 15 16 17
----------------------------------------------------------------------
(in thousands, except ratios) Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15
----------------------------------------------------------------------
Total Generation (GwHr) 10,102 10,078 10,076 10,111 10,176 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 83,560 84,588 85,623 86,667 87,717 88,775
Energy payments 305,762 314,896 324,960 336,525 346,015 358,956
Ancillary & Steam sales 2,294 2,299 2,303 2,308 2,313 2,317
----------------------------------------------------------------------
TOTAL REVENUES 391,617 401,782 412,887 425,499 436,044 450,048
OPERATING COSTS
FUEL SUBTOTAL (159,442) (162,331) (165,551) (169,300) (172,160) (176,588)
TOTAL FIXED O&M (61,378) (63,091) (62,638) (63,651) (63,545) (62,283)
TOTAL VARIABLE O&M (6,012) (6,210) (6,249) (6,140) (6,153) (6,440)
======================================================================
GROSS CASH FLOW FROM OPERATIONS 164,785 170,150 178,448 186,408 194,186 204,738
Capital expenditures (5,573) (21,715) (17,551) (6,276) (16,869) (25,128)
Interest earned on Reserve 1,794 1,864 1,909 1,916 1,929 1,936
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES
======================================================================
Rent for Principal & Interest on Certificates (64,500) (64,500) (66,500) (70,000) (70,000) (70,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (4,500) (4,500) (4,500) (4,500) (5,000)
----------------------------------------------------------------------
TOTAL RENT PAYMENTS (68,500) (69,000) (71,000) (74,500) (74,500) (75,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.49X 2.33X 2.45X 2.60X 2.56X 2.59X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
18 19 20 21 22
----------------------------------------------------------
(in thousands, except ratios) Dec-16 Dec-17 Dec-18 Dec-19 Dec-20
----------------------------------------------------------
Total Generation (GwHr) 10,131 10,131 9,879 10,131 10,102
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 93,392 98,157 103,076 108,152 113,390
Energy payments 360,185 361,320 353,369 363,289 363,070
Ancillary & Steam sales 2,322 2,327 2,332 2,332 2,332
----------------------------------------------------------
TOTAL REVENUES 455,899 461,804 458,777 473,773 478,792
OPERATING COSTS
FUEL SUBTOTAL (180,126) (183,728) (182,998) (191,515) (194,378)
TOTAL FIXED O&M (68,100) (64,212) (63,835) (66,326) (68,972)
TOTAL VARIABLE O&M (6,483) (6,526) (5,995) (6,615) (6,360)
==========================================================
GROSS CASH FLOW FROM OPERATIONS 201,191 207,337 205,948 209,681 209,082
Capital expenditures (20,420) (10,046) (6,374) (19,655) (20,048)
Interest earned on Reserve 1,936 1,936 1,936 1,936 1,728
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
----------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES
==========================================================
Rent for Principal & Interest on Certificates (70,000) (45,561) (70,000) (70,000) (56,147)
Non-Deferrable Rent 0 (24,439) 0 0 0
Deferrable Rent (5,500) (5,500) (5,500) (5,500) (2,750)
----------------------------------------------------------
TOTAL RENT PAYMENTS (75,500) (75,500) (75,500) (75,500) (58,897)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.61X 2.84X 2.88X 2.74X 3.39X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
CONSOL. PROJ. CAPX PAGE 2 OF 3
288
CONFIDENTIAL AES EASTERN ENERGY CAPITAL EXPENDITURES +50%
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
23 24 25 26 27 28
-----------------------------------------------------------------------
(in thousands, except ratios) Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 Dec-26
-----------------------------------------------------------------------
Total Generation (GwHr) 10,078 10,056 10,076 10,131 10,131 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 115,658 117,971 120,330 122,737 125,192 127,696
Energy payments 369,464 376,054 384,294 394,129 402,012 410,052
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
-----------------------------------------------------------------------
TOTAL REVENUES 487,454 496,357 506,956 519,198 529,535 540,079
OPERATING COSTS
FUEL SUBTOTAL (197,901) (201,305) (205,761) (211,060) (215,281) (219,587)
TOTAL FIXED O&M (69,997) (71,041) (72,105) (73,189) (74,292) (75,417)
TOTAL VARIABLE O&M (6,636) (6,455) (6,514) (6,898) (6,971) (7,046)
=======================================================================
GROSS CASH FLOW FROM OPERATIONS 212,920 217,555 222,575 228,051 232,990 238,029
Capital expenditures (35,383) (20,858) (21,275) (21,701) (24,748) (19,867)
Interest earned on Reserve 1,254 981 975 974 974 974
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
-----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 178,603 197,491 202,087 207,137 209,028 218,949
=======================================================================
Rent for Principal & Interest on Certificates (19,900) (19,000) (19,000) (19,000) (19,000) (19,000)
Non-Deferrable Rent (18,100) (19,000) (19,000) (19,000) (19,000) (19,000)
Deferrable Rent 0 0 0 0 0 0
-----------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) (38,000) (38,000) (38,000) (38,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 4.70X 5.20X 5.32X 5.45X 5.50X 5.76X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
29 30 31 32 33 34
--------------------------------------------------------------------
(in thousands, except ratios) Dec-27 Dec-28 Dec-29 Dec-30 Dec-31 Dec-32
--------------------------------------------------------------------
Total Generation (GwHr) 10,131 9,879 10,131 10,102 10,059 10,021
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 130,250 132,854 135,512 138,222 140,986 143,806
Energy payments 418,253 416,022 435,150 442,580 449,511 456,771
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
--------------------------------------------------------------------
TOTAL REVENUES 550,834 551,209 572,994 583,134 592,829 602,909
OPERATING COSTS
FUEL SUBTOTAL (223,979) (223,097) (233,036) (236,962) (240,642) (244,663)
TOTAL FIXED O&M (76,562) (77,729) (78,918) (80,129) (81,363) (82,619)
TOTAL VARIABLE O&M (7,121) (6,552) (7,275) (7,019) (7,099) (7,085)
====================================================================
GROSS CASH FLOW FROM OPERATIONS 243,172 243,830 253,765 259,023 263,724 268,541
Capital expenditures (31,598) (20,669) (22,441) (17,070) (17,411) (12,281)
Interest earned on Reserve 974 974 499 12 0 0
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
--------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 212,360 223,948 231,636 241,778 246,126 256,072
====================================================================
Rent for Principal & Interest on Certificates (19,000) (19,000) 0 0 0 0
Non-Deferrable Rent (19,000) (19,000) 0 0 0 0
Deferrable Rent 0 0 0 0 0 0
--------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) 0 0 0 0
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 5.59X 5.89X 0.00X 0.00X 0.00X 0.00X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
CONSOL. PROJ. CAPX PAGE 3 OF 3
289
CONFIDENTIAL AES EASTERN ENERGY HEAT RATE + 500 BTU'S/KWH
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
1 2 3 4 5 6
---------------------------------------------------------------------
(in thousands, except ratios) Dec-99 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04
---------------------------------------------------------------------
Total Generation (GwHr) 6,584 10,232 10,210 10,208 10,249 10,111
REVENUES
NYSEG ICAP 20,981 31,472 10,491 0 0 0
Other capacity payments 0 0 32,541 54,901 63,411 72,239
Energy payments 165,956 275,205 292,604 307,247 303,264 280,334
Ancillary & Steam sales 1,433 2,154 2,158 2,161 2,165 2,269
---------------------------------------------------------------------
TOTAL REVENUES 188,370 308,831 337,793 364,309 368,840 354,842
OPERATING COSTS
FUEL SUBTOTAL (91,758) (143,094) (144,916) (146,975) (149,130) (149,638)
TOTAL FIXED O&M (43,317) (56,910) (59,956) (56,236) (57,183) (55,384)
TOTAL VARIABLE O&M 5,102 4,506 (848) (960) (6,247) (6,557)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 58,398 113,334 132,073 160,137 156,279 143,263
Capital expenditures (10,609) (12,249) (7,177) (17,003) (15,604) (6,567)
Interest earned on Reserve 1,667 2,048 1,564 1,552 1,551 1,576
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 49,268 102,945 126,273 144,498 142,039 138,084
=====================================================================
Rent for Principal & Interest on Certificates (32,487) (51,296) (51,296) (51,296) (58,149) (59,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (8,454) (9,204) (9,204) (2,351) (1,500)
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (36,487) (59,750) (60,500) (60,500) (60,500) (60,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.52X 2.01X 2.46X 2.82X 2.44X 2.34X
TEN-YEAR AVERAGE FCCR (2000-2009) 2.29X
AVERAGE FCCR OVER TERM OF CERTIFICATES 3.19X
7 8 9 10 11
--------------------------------------------------------
(in thousands, except ratios) Dec-05 Dec-06 Dec-07 Dec-08 Dec-09
--------------------------------------------------------
Total Generation (GwHr) 10,076 10,131 10,131 10,116 9,894
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 81,395 81,857 82,306 82,740 83,158
Energy payments 259,704 269,739 278,590 287,259 290,100
Ancillary & Steam sales 2,273 2,277 2,282 2,286 2,290
--------------------------------------------------------
TOTAL REVENUES 343,372 353,874 36,177 372,284 375,548
OPERATING COSTS
FUEL SUBTOTAL (154,642) (158,617) (161,206) (163,107) (162,088)
TOTAL FIXED O&M (59,101) (59,284) (59,485) (59,502) (64,197)
TOTAL VARIABLE O&M (6,698) (7,130) (7,320) (7,155) (7,200)
========================================================
GROSS CASH FLOW FROM OPERATIONS 122,931 128,843 135,167 142,521 142,063
Capital expenditures (11,151) (1,086) (8,056) (12,566) (11,903)
Interest earned on Reserve 1,602 1,603 1,603 1,678 1,761
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
--------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 113,194 129,172 128,526 131,445 131,733
========================================================
Rent for Principal & Interest on Certificates (57,000) (59,000) (59,000) (59,000) (59,000)
Non-Deferrable Rent 0 0 0 0 0
Deferrable Rent (2,500) (3,500) (3,500) (3,500) (3,500)
--------------------------------------------------------
TOTAL RENT PAYMENTS (59,500) (62,500) (62,500) (62,500) (62,500)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 1.99X 2.19X 2.18X 2.23X 2.23X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
Note: (1) Fixed charges consist of principal and interest on the Certificates
and non-deferrable rent payments under the Leases
Note: (2) FCCR equals cash available for fixed charges divided by fixed charges
CONSOL. PROJ. HEAT RATE PAGE 1 OF 3
290
CONFIDENTIAL AES EASTERN ENERGY HEAT RATE + 500 BTU'S/KWH
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
12 13 14 15 16 17
---------------------------------------------------------------------
(in thousands, except ratios) Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15
---------------------------------------------------------------------
Total Generation (GwHr) 10,102 10,078 10,076 10,111 10,176 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 83,560 84,588 85,623 86,667 87,717 88,775
Energy payments 305,762 314,896 324,960 336,525 346,015 358,956
Ancillary & Steam sales 2,294 2,299 2,303 2,308 2,313 2,317
---------------------------------------------------------------------
TOTAL REVENUES 391,617 401,782 412,887 425,499 436,044 450,048
OPERATING COSTS
FUEL SUBTOTAL (167,414) (170,447) (173,827) (177,770) (180,767) (185,417)
TOTAL FIXED O&M (61,378) (63,091) (62,638) (63,651) (63,545) (62,283)
TOTAL VARIABLE O&M (7,141) (7,353) (7,396) (7,282) (7,292) (7,596)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 155,684 160,892 169,026 176,797 184,441 194,753
Capital expenditures (3,715) (14,477) (11,701) (4,184) (11,246) (16,752)
Interest earned on Reserve 1,794 1,864 1,909 1,916 1,916 1,936
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 153,575 148,091 159,047 174,342 174,936 179,749
=====================================================================
Rent for Principal & Interest on Certificates (64,500) (64,500) (66,500) (70,000) (70,000) (70,000)
Non-Deferrable Rent 0 0 0 0 0 0
Deferrable Rent (4,000) (4,500) (4,500) (4,500) (4,500) (5,000)
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (68,500) (69,000) (71,000) (74,500) (74,500) (75,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.38X 2.30X 2.39X 2.49X 2.50X 2.57X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
18 19 20 21 22
-------------------------------------------------------
(in thousands, except ratios) Dec-16 Dec-17 Dec-18 Dec-19 Dec-20
-------------------------------------------------------
Total Generation (GwHr) 10,131 10,131 9,879 10,131 10,102
REVENUES
NYSEG ICAP 0 0 0 0 0
Other capacity payments 93,392 98,157 103,076 108,152 113,390
Energy payments 360,185 361,320 353,369 363,289 363,070
Ancillary & Steam sales 2,322 2,327 2,332 2,332 2,332
-------------------------------------------------------
TOTAL REVENUES 455,899 461,804 458,777 473,773 478,792
OPERATING COSTS
FUEL SUBTOTAL 189,132) (192,914) (192,136) (200,708) (204,098)
TOTAL FIXED O&M (68,100) (64,212) (63,835) (66,326) (68,972)
TOTAL VARIABLE O&M (7,642) (7,689) (7,144) (7,784) (7,519)
=======================================================
GROSS CASH FLOW FROM OPERATIONS 191,025 196,989 195,661 198,954 198,203
Capital expenditures (13,613) (6,697) (4,250) (13,103) (13,365)
Interest earned on Reserve 1,936 1,936 1,936 1,936 1,728
Interest paid on Working Cap facility (188) (188) (188) (188) (188)
-------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 179,160 192,040 193,160 187,599 186,378
=======================================================
Rent for Principal & Interest on Certificates (70,000) (45,561) (70,000) (70,000) (56,147)
Non-Deferrable Rent 0 (24,439) 0 0 0
Deferrable Rent (5,500) (5,500) (5,500) (5,500) (2,750)
-------------------------------------------------------
TOTAL RENT PAYMENTS (75,500) (75,500) (75,500) (75,500) (58,897)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 2.56X 2.74X 2.76X 2.68X 3.32X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
CONSOL. PROJ. HEAT RATE PAGE 2 OF 3
291
CONFIDENTIAL AES EASTERN ENERGY HEAT RATE + 500 BTU'S/KWH
FINANCIAL PROJECTIONS
CONSOLIDATED PROJECTIONS
23 24 25 26 27 28
----------------------------------------------------------------------
(in thousands, except ratios) Dec-21 Dec-22 Dec-23 Dec-24 Dec-25 Dec-26
----------------------------------------------------------------------
Total Generation (GwHr) 10,078 10,056 10,076 10,131 10,131 10,131
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 115,658 117,971 120,330 122,737 125,192 127,696
Energy payments 369,464 376,054 384,294 394,129 402,012 410,052
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
----------------------------------------------------------------------
TOTAL REVENUES 487,454 496,357 506,956 519,198 529,535 540,079
OPERATING COSTS
FUEL SUBTOTAL (207,795) (211,374) (216,048) (221,613) (226,045) (230,566)
TOTAL FIXED O&M (69,997) (71,041) (72,105) (73,189) (74,292) (75,417)
TOTAL VARIABLE O&M (7,811) (7,626) (7,695) (8,108) (8,196) (8,285)
======================================================================
GROSS CASH FLOW FROM OPERATIONS 201,850 206,315 211,107 216,288 221,001 225,811
Capital expenditures (23,589) (13,905) (14,183) (14,467) (16,499) (13,244)
Interest earned on Reserve 1,254 981 975 974 974 974
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
----------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 179,329 193,204 197,711 202,608 250,289 213,353
======================================================================
Rent for Principal & Interest on Certificates (19,900) (19,000) (19,000) (19,000) (19,000) (19,000)
Non-Deferrable Rent (18,100) (19,000) (19,000) (19,000) (19,000) (19,000)
Deferrable Rent 0 0 0 0 0 0
----------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) (38,000) (38,000) (38,000) (38,000)
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 4.72X 5.08X 5.20X 5.33X 5.40X 5.61X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
29 30 31 32 33 34
---------------------------------------------------------------------
(in thousands, except ratios) Dec-27 Dec-28 Dec-29 Dec-30 Dec-31 Dec-32
---------------------------------------------------------------------
Total Generation (GwHr) 10,131 9,879 10,131 10,102 10,059 10,021
REVENUES
NYSEG ICAP 0 0 0 0 0 0
Other capacity payments 130,250 132,854 135,512 138,222 140,986 143,806
Energy payments 418,253 416,022 435,150 442,580 449,511 456,771
Ancillary & Steam sales 2,332 2,332 2,332 2,332 2,332 2,332
---------------------------------------------------------------------
TOTAL REVENUES 550,834 551,209 572,994 583,134 592,829 602,909
OPERATING COSTS
FUEL SUBTOTAL (235,178) (234,237) (244,687) (248,811) (252,679) (256,893)
TOTAL FIXED O&M (76,562) (77,729) (78,918) (80,129) (81,363) (82,619)
TOTAL VARIABLE O&M (8,375) (7,803) (8,560) (8,305) (8,406) (8,401)
=====================================================================
GROSS CASH FLOW FROM OPERATIONS 230,719 231,439 240,829 245,888 250,382 254,995
Capital expenditures (21,065) (13,779) (14,961) (11,380) (11,608) (8,188)
Interest earned on Reserve 974 974 499 12 0 0
Interest paid on Working Cap facility (188) (188) (188) (188) (188) (188)
---------------------------------------------------------------------
CASH AVAILABLE FOR FIXED CHARGES 210,440 218,447 226,180 234,333 238,587 246,620
=====================================================================
Rent for Principal & Interest on Certificates (19,000) (19,000) 0 0 0 0
Non-Deferrable Rent (19,000) (19,000) 0 0 0 0
Deferrable Rent 0 0 0 0 0 0
---------------------------------------------------------------------
TOTAL RENT PAYMENTS (38,000) (38,000) 0 0 0 0
FIXED CHARGE COVERAGE RATIO ("FCCR") (1) (2) 5.54X 5.75X 0.00X 0.00X 0.00X 0.00X
TEN-YEAR AVERAGE FCCR (2000-2009)
AVERAGE FCCR OVER TERM OF CERTIFICATES
CONSOL. PROJ. HEAT RATE PAGE 3 OF 3
292
APPENDIX A
REFERENCES
DATE REC'D. FROM DOCUMENT
----------- ---- --------
10/19/98 Henry Aszklar Fax - executed signed contract
11/2/98 Via Fed Ex - Turbine Generator Inspection Report Hickling Station-
10/14/88 - 12/28/88
11/2/98 Via Fed Ex - High Pressure Rotor Material Test Program Hickling
Station- Unit 1 - March 1989
11/2/98 Via Fed Ex - Generator Inspection Report Unit 1 Hickling Station-
10/14/92
11/2/98 Via Fed Ex - GE Inspection Report Hickling Station- Unit 2
11/2/98 Via Fed Ex - NYSEG Interoffice Memo - Internal Inspection of Boiler
No.1 Hickling Station
11/2/98 Via Fed Ex - NYSEG Interoffice Memo - Internal Boiler Inspection Boiler
No. 3
11/2/98 Via Priority Mail - NYSEG IOM - Jennison Station Unit 1 - Internal
Inspect. Of Boiler No.1
11/2/98 Via Priority Mail - NYSEG IOM - Jennison Station Unit 1 - Internal
Inspect. Of Boiler No.2
11/2/98 Via Priority Mail - NYSEG IOM - Jennison Station Unit 1 - Internal
Inspect. Of Boiler No.3
11/2/98 Via Priority Mail - NYSEG IOM - Jennison Station Unit 2 - Internal
Inspect. Of Boiler No.4
11/2/98 Via Priority Mail - GE Inspection Report - Jennison Station Unit 1 -
Turbine 56989
11/2/98 Via Priority Mail - GE Inspection Report - Jennison Station Unit 2 -
Turbine 83657 - Fall 1989 Inspection by Power Generation Svcs. Syracuse
11/2/98 Various Inspection Reports Summaries
11/3/98 Boiler Outage Summaries - Unit 8 #13, Unit 7 #11,12 etc. - Turbine
Generator Outages
11/4/98 Via FedEx - Outage Executive Summaries
293
DATE REC'D. FROM DOCUMENT
----------- ---- --------
11/4/98 Boiler Outage Reports by New York State Electric & Gas
1997 Kintigh Station Boiler Outage Report
1995 Kintigh Station Boiler Outage Report
1992 Kintigh Station Boiler Outage Report
1991 Kintigh Station Boiler Outage Report
1990 Kintigh Station Boiler Outage Report
1989 Kintigh Station Boiler Outage Report
1988 Kintigh Station Boiler Outage Report
Outage Reports: by Kintigh Station Engineering and Maintenance Dept.
1997 Outage Report
1991- 1995 Engineering Group Outage Reports
1997 Outage Report by Engineering Group
Chimney Inspection Reports International Chimney Corp.
1997 Inspection Vol. I & Vol. II
1995 Inspection Vol. I & Vol. II
Miscellaneous Inspection Reports by GE Power Generation Services
Final report for Steam Turbine-Generator 1st Major Inspection 1990
B. Boiler Feed Pump Turbine Inspection
12/22/98 Via Mail - request to return above documents to NYSEG
12/23/98 Fax - Dave Flory Info. on historical availability and other AES plants around the world.
12/28/98 Fax - Gordon Webster Copy of Section 9 Report.
1/5/98 Fax - David Risley copy of Structural Inspection of Milliken Station (diagram attached)
1/6/99 Fax - David Risley Photos from Milliken Station Structural Inspection
1/6/99 Fax - Amy McDonough Pittsburgh Seam Market Study
1/8/99 Fax - Cristina Cardoze AES-NYSEG updated working group list
1/14/99 Fax - Gordon Webster Power Project Cost Comparison Data
1/20/99 Fax - from NYSEG 1997 Power Plant Performance Report w/ performance indexes.
1/25/99 Fax - Eric Lammers Description of AES Eastern Energy L.P. and the AES Corp.
1/26/99 Fax - Dave Flory 1997 Power Plant Performance Report
1/28/99 Fax - Dave Flory Comments on exec. Summary.
1/28/99 Fax - Christina Cordoza Updated Working Group List
294
DATE REC'D. FROM DOCUMENT
----------- ---- --------
1/29/99 Fax - Dave Flory Signed changed Terms and Conditions
295
APPENDIX B
ANALYSIS OF THE NEW YORK POWER MARKET
PREPARED FOR THE AES CORPORATION
IN ASSOCIATION WITH ITS ACQUISITION OF THE NYSEG GENERATION
PORTFOLIO
BY
LONDON ECONOMICS, INC.
296
APPENDIX B
Important Disclaimer Notice
London Economics Inc. ("London Economics") has prepared this analysis of the New
York power market at the request of The AES Corporation. The information
contained in this market analysis is by necessity incomplete, and may not fully
reflect the most recent developments in the New York market. Investors and
others should note that:
(a) the provision of a report by London Economics does not obviate the need
for potential investors to make further appropriate inquiries as to the
accuracy of the information included therein, and to undertake their own
analysis and due diligence.
(b) London Economics' report and analysis is not intended to be a complete and
exhaustive analysis of the subject issues. All factors of importance to a
potential investor have not necessarily been considered. Again, potential
investors will need to conduct their own analysis and due diligence.
(c) London Economics, its officers, employees and affiliates cannot accept
liability for loss suffered in consequence of reliance on its analysis or
report. Nothing in our report should be taken as a promise or guarantee as
to the occurrence of any future events.
(d) There can be substantial variation between the prices, assumptions and
market outcomes forecast by various consulting organizations specializing
in competitive power markets. We make no representation as to the
consistency of our analysis with that of other parties.
London Economics understands that this analysis will be used by, among others,
the prospective purchasers of the pass-through trust certificates to be issued
relative to a leveraged lease financing by AES Eastern Energy, L.P. of the
acquisition of the principal portion of the NYSEG thermal asset portfolio.
London Economics hereby consents to such use and to the reference to London
Economics under the caption "Experts" in the Offering Circular for the
pass-through trust certificates to which this analysis is appended.
London Economics, Inc. Bii
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297
APPENDIX B
ANALYSIS OF THE NEW YORK POWER MARKET
EXECUTIVE SUMMARY
London Economics has prepared this analysis of the New York power market at the
request of The AES Corporation, in support of the financing by its wholly owned
subsidiary AES Eastern Energy, L.P. (AEE) of AEE's acquisition of the principal
portion of the NYSEG thermal asset portfolio. This analysis and report includes
both an overview of the evolving New York power market and forecast energy and
capacity prices. This report also includes a summary of the analytical
methodology employed in our analysis.
MARKET SUMMARY
The New York power market is in the implementation stage. The New York
Independent System Operator (ISO) function is being created to operate the
state's transmission system and administer the separate energy and capacity
markets. The ISO will also operate a series of ancillary services markets, which
are described in an appendix. London Economics has not forecast ancillary
services prices or the resulting revenues which might be available to the AEE
portfolio.
The New York power market is divided into transmission-constrained regions. The
two primary regions (and the focus of our modeling) are the high cost Downstate
zone, which covers New York City, Long Island and the lower Hudson valley, and
the lower cost Upstate zone. The AEE plants are all located in the Upstate zone.
This two-zoned modeling approach forms a simplified representation of the
technical details of the proposed transmission congestion and pricing systems in
New York.
Load-serving entities such as retailers or distributors must demonstrate that
they have sufficient capacity to meet their peak demands plus a significant
reserve margin. These rules will give capacity in the market a tradable value,
which will vary by location. Due to the relative balance of supply and demand
for capacity, we expect that Upstate capacity prices will be lower than
Downstate prices. This pattern will persist over time, as we expect that the
majority of new entrant plants, such as gas-fired combined cycle gas turbines
(CCGT), will be built Downstate to displace high cost oil-fired generation.
Figure ES-1 illustrates the projected energy dispatch curve for the New York
power market in 2000. The system has significant nuclear and "must-run" NUG
(non-utility generator) capacity that runs at baseload when available. The AEE
coal plants are among the lowest cost thermal generators. The storage hydro
plants run at mid-merit and peaking hours and are shown "shadow-priced" against
the thermal units they displace in the merit order. Furthermore, there is a
large number of higher cost oil, gas and dual-fired steam turbine units, mostly
in the Downstate region.
London Economics, Inc. Biii
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APPENDIX B
The position of AEE's assets is slightly above the minimum statewide projected
hourly load and significantly lower than the projected average load for 2000.
Under our modeling simulations, which account for availability adjustments such
as forced outages and planned outages, these plants are almost always
dispatched. The capacity factors of the least efficient units among the AEE
assets (the non-reheat units at the Goudey station (Unit 7) and the Greendige
station (Unit 3)) are most sensitive to unfavorable changes in the model inputs
while the most efficient units (the Kintigh station and the Milliken station)
are likely not to be sensitive to such unfavorable changes.
[FIGURE ES-1: NEW YORK SUPPLY CURVE IN 2000 BASED ON BASE CASE PROJECTIONS LINE
GRAPH]
MODELING ASSUMPTIONS
London Economics' analysis was based on data from a range of published and other
sources. Demand growth data was obtained from the New York Power Pool. Fuel
prices, including gas and oil price tracks, were based on 1998 RDI forecasts.
Currently fuel oil prices and traded forward prices are below the RDI forecast
prices. London Economics performed additional analysis for the years 1999 to
2010 to determine the effects of lower oil prices, partially offset by NOX
allowance costs (which were not incorporated in the base and downside cases).
Incorporating both of these effects leads to a decrease in the Company's
revenues during 1999 through 2003. The decrease revenues during these years fall
between the base case and the downside
London Economics, Inc. Biv
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299
APPENDIX B
case revenues. A downside case fuel price scenario was also constructed. Coal
price forecasts were prepared by the John T. Boyd consulting company.
Data on the capital and operating costs of new entrant plants was obtained from
Stone & Webster and a variety of industry sources. London Economics developed
its own forecasts on the quantity and timing of new entry, which are described
in the report. Our forecasts include the construction of announced new capacity
plus a substantial amount of re-powering of the Consolidated Edison and the
KeySpan (previously owned by Long Island Lighting Company) assets in the first
years of the analysis.
A number of conservative assumptions have been used in constructing both the
base and downside scenarios. London Economics has assumed that all nuclear
capacity in New York will continue to run until its license date, with no early
retirements. We have also assumed that all generators bid into the energy market
only at variable (fuel plus variable operations & maintenance ) cost, and that
substantial new entry and re-powering will occur downstate in the early years up
to 2005.
It was also assumed that Ontario Hydro will get sufficient amounts of its
nuclear capacity back online to return to its historical level of exports to New
York. The projected level of imports from Ontario is assumed to decrease
gradually as Ontario's nuclear units meet their license expiration dates.
FORECAST ENERGY AND CAPACITY PRICES
London Economics' proprietary power markets model was used to forecast system
dispatch and operations over the study period, and the resulting energy prices.
These are shown in Table ES-1 on the next page. Energy prices and capacity
prices from 2021 through 2035 have not been modeled. We have assumed zero growth
in real prices after 2020.
We have not attributed NO(x) allowance costs to competing plants in the New York
market, which is conservative. Inclusion of these NO(x) costs would tend to
increase energy prices significantly.
Capacity prices were analyzed using a capacity balance approach. For the
downside case, capacity prices in each region were determined by the minimum
going-forward revenues required to keep sufficient installed capacity available.
This capacity requirement included the sum of regional peak demands and reserve
requirements. Costs considered under the capacity analysis included fixed
operations & maintenance costs, projected property and other taxes, and the
costs of life extension for units over 30 years old. For the base case, the
capacity analysis also included a moderate return on investment for these
existing units, based on estimated net book values. For both scenarios, capacity
prices are set to allow new entrant plants to achieve a target revenue level
when demand growth requires that new capacity be brought online.
For the Upstate region, where the AEE plants are located, capacity prices rise
as forecast energy prices fall sharply over the period 2000 to 2005. The fall in
energy prices is triggered by the level of new entry, most of it Downstate, and
the re-powering of less efficient plants. Even with these capacity changes, the
capacity balance is
London Economics, Inc. Bv
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300
APPENDIX B
projected to return to equilibrium by early in the next decade. This implies
that Downstate capacity prices must rise to trigger needed new entry, as the
fuel cost savings to new more efficient units will no longer be adequate. Note
that under the base and downside cases, London Economics has projected that
total energy and capacity prices for the Upstate region will be generally below
projected new entrant prices.
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APPENDIX B
TABLE ES-1: SUMMARY OF UPSTATE FORECAST ENERGY AND CAPACITY PRICES (1999$)
Base Case Downside Case
----------------------------------------------------- -----------------------------------------------------
Energy Capacity Total Energy Capacity Total
($/MWh) ($/kW-Year) ($/MWh) ($/MWh) ($/kW-Year) ($/MWh)
1999 $25.0 $27.0 $28.1 $23.3 $25.0 $26.2
2000 $26.2 $30.0 $29.6 $24.4 $26.0 $27.4
2001 $27.4 $37.0 $31.6 $25.4 $31.0 $29.0
2002 $28.4 $40.8 $33.1 $26.4 $36.0 $30.5
2003 $27.3 $46.2 $32.5 $25.0 $39.5 $29.5
2004 $24.9 $51.6 $30.8 $22.9 $45.3 $28.1
2005 $22.8 $57.0 $29.3 $21.0 $51.0 $26.8
2006 $23.1 $56.2 $29.5 $21.2 $50.6 $27.0
2007 $23.3 $55.4 $29.7 $21.4 $50.2 $27.2
2008 $23.6 $54.6 $29.8 $21.7 $49.8 $27.3
2009 $23.9 $53.8 $30.0 $21.9 $49.4 $27.5
2010 $24.2 $53.0 $30.2 $22.1 $49.0 $27.7
2011 $24.5 $52.6 $30.5 $22.3 $47.8 $27.8
2012 $24.8 $52.2 $30.7 $22.5 $46.6 $27.9
2013 $25.1 $51.8 $31.0 $22.8 $45.4 $27.9
2014 $25.4 $51.4 $31.3 $23.0 $44.2 $28.0
2015 $25.7 $51.0 $31.5 $23.2 $43.0 $28.1
2016 $25.3 $52.6 $31.3 $23.0 $44.8 $28.1
2017 $24.9 $54.2 $31.1 $22.7 $46.6 $28.0
2018 $24.5 $55.8 $30.8 $22.5 $48.4 $28.0
2019 $24.1 $57.4 $30.6 $22.2 $50.2 $28.0
2020 $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2021* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2022* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2023* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2024* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2025* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2026* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2027* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2028* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2029* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2030* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2031* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2032* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2033* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2034* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2035* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
* Energy prices and capacity prices from 2021 through 2035 have not been
modeled. We have assumed zero growth in real prices after 2020.
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APPENDIX B
MARKET OUTCOMES FOR THE AEE PORTFOLIO
Tables ES-2 and ES-3 summarize the forecasted energy and capacity revenues for
the base and downside cases respectively.
- --------------------------------------------------------------------------------
TABLE ES-2 : TOTAL REVENUE BY UNIT - BASE CASE
Forecasted capacity and energy revenues
(1999 $ millions)
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
Capacity (2) -------------------------------------------- --------- -------- -------- ------
Milliken 1 150 $ 31 $ 37 $ 39 $ 41 $ 41 $ 36 $ 38 $ 39 $ 38
Milliken 2 156 $ 32 $ 39 $ 41 $ 43 $ 43 $ 38 $ 39 $ 41 $ 39
Kintigh 1 675 $126 $166 $178 $184 $184 $163 $169 $175 $169
Greenidge 3 54 $ 10 $ 13 $ 14 $ 14 $ 15 $ 13 $ 14 $ 14 $ 13
Greenidge 4 105 $ 20 $ 26 $ 28 $ 29 $ 28 $ 25 $ 26 $ 27 $ 26
Goudey 7 43 $ 8 $ 10 $ 11 $ 11 $ 11 $ 10 $ 11 $ 11 $ 11
Goudey 8 83 $ 16 $ 20 $ 21 $ 23 $ 22 $ 20 $ 21 $ 22 $ 21
- ------------------------ -------------------------------------------- --------- -------- -------- ------
Portfolio Total Revenue $244 $310 $332 $345 $343 $306 $316 $329 $317
======================== ============================================ ========= ======== ======== ======
(1) 1999 figures reflect 10 months of operation
(2) Utilizing capacity figures reported for summer demonstrated capacity in
NYPP's Load & Capacity Data 1998.
All of the units are projected to run at high capacity factors for the duration
of the analysis. Kintigh and Milliken remain the lowest cost thermal units on
the system and are dispatched fully when available. Our analysis indicates that
delivered gas prices would have to be unrealistically low to allow new entrant
CCGTs to undercut these units and push them up the merit order.
TABLE ES-3: TOTAL REVENUE BY UNIT - DOWNSIDE CASE
Forecasted capacity and energy revenues
(1999 $ millions)
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
Capacity (2) -------------------------------------------- --------- -------- -------- ------
Milliken 1 150 $ 27 $ 34 $ 36 $ 38 $ 36 $ 33 $ 34 $ 35 $ 35
Milliken 2 156 $ 28 $ 35 $ 37 $ 39 $ 38 $ 34 $ 36 $ 36 $ 36
Kintigh 1 675 $116 $151 $159 $167 $162 $149 $154 $156 $154
Greenidge 3 54 $ 10 $ 12 $ 13 $ 13 $ 13 $ 12 $ 12 $ 13 $ 12
Greenidge 4 105 $ 19 $ 23 $ 25 $ 26 $ 25 $ 23 $ 24 $ 24 $ 24
Goudey 7 43 $ 8 $ 9 $ 10 $ 11 $ 10 $ 9 $ 10 $ 10 $ 10
Goudey 8 83 $ 15 $ 18 $ 19 $ 21 $ 20 $ 18 $ 19 $ 19 $ 19
- ------------------------ -------------------------------------------- --------- -------- -------- ------
Portfolio Total Revenue $222 $282 $299 $315 $305 $279 $290 $293 $290
======================== ============================================ ========= ======== ======== ======
(1) 1999 figures reflect 10 months of operation
(2) Utilizing capacity figures reported for summer demonstrated capacity in
NYPP's Load & Capacity Data 1998.
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APPENDIX B
ANALYSIS OF THE NEW YORK POWER MARKET
TABLE OF CONTENTS
1 STRUCTURE OF THE REPORT............................................................................1
2 INTRODUCTION TO THE NEW YORK POWER MARKET..........................................................2
2.1 OVERVIEW OF MARKET RESTRUCTURING................................................................2
2.2 RETAIL MARKET...................................................................................2
2.3 GENERATION ASSETS IN NEW YORK...................................................................4
2.3.1 REGIONAL DIVERSITY......................................................................4
2.3.2 GENERATION OWNERSHIP....................................................................5
2.4 SUPPLY - DEMAND BALANCE.........................................................................7
3 MARKET DRIVERS AND THE AEE GENERATION PORTFOLIO IN NEW YORK........................................9
3.1 MARKET DRIVERS..................................................................................9
3.2 DEVELOPMENT OF MARKET SCENARIOS................................................................13
3.3 AEE'S NEW YORK PORTFOLIO.......................................................................14
4 FORECASTING CAPACITY PRICES.......................................................................18
4.1 CAPACITY MODELING METHODOLOGY..................................................................19
4.2 CAPACITY PRICE FORECASTING RESULTS.............................................................20
4.2.1 DOWNSTATE CAPACITY PRICING.............................................................20
4.2.2 UPSTATE CAPACITY PRICING...............................................................22
5 SUMMARY OF MODELING RESULTS.......................................................................25
5.1 BASE CASE MODELING RESULTS.....................................................................27
5.1.1 BASE CASE ENERGY PRICES................................................................27
5.1.2 AEE PORTFOLIO IN THE BASE CASE.........................................................32
5.2 DOWNSIDE CASE MODELING RESULTS.................................................................34
5.2.1 DOWNSIDE CASE ENERGY PRICES............................................................34
5.2.2 AEE PORTFOLIO IN THE DOWNSIDE CASE.....................................................38
6 NEW ENTRY PRICES..................................................................................40
6.1 ANALYSIS OVERVIEW..............................................................................40
6.2 LONG-TERM PRICES UNDER THE BASE CASE...........................................................40
6.3 LONG-TERM PRICES UNDER THE DOWNSIDE CASE.......................................................42
7 OVERVIEW OF OPPORTUNITIES OUTSIDE THE NY MARKET...................................................45
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APPENDIX B
8 CONCLUSIONS: IMPLICATIONS FOR THE FUTURE.........................................................48
8.1 COMPETITIVE POSITION OF THE AEE PORTFOLIO......................................................49
9 APPENDIX A: DATA SOURCES AND ASSUMPTIONS FOR MARKET MODELING.....................................51
9.1 ENERGY MODEL OVERVIEW..........................................................................51
9.2 ELECTRIC TRANSMISSION WITHIN NEW YORK..........................................................51
9.3 ELECTRICITY DEMAND ASSUMPTIONS FOR NEW YORK....................................................55
9.4 IMPORT ASSUMPTIONS.............................................................................58
9.5 HYDROLOGY ASSUMPTIONS..........................................................................59
9.6 THERMAL STATION ASSUMPTIONS....................................................................61
9.6.1 PLANT PERFORMANCE CHARACTERISTICS......................................................61
9.6.2 PLANT COSTS............................................................................62
9.7 NUG CONTRACTS..................................................................................68
9.8 NEW ENTRY......................................................................................69
9.9 CAPACITY RETIREMENTS...........................................................................71
9.9.1 NUCLEAR RETIREMENTS....................................................................71
9.9.2 FOSSIL-FUEL RETIREMENTS................................................................72
9.9.3 HYDRO RETIREMENTS......................................................................75
9.9.4 CONCLUSIONS ON CAPACITY RETIREMENTS....................................................75
9.10 CAPACITY MIX...............................................................................76
10 APPENDIX B: NEW YORK MARKET RULES: ENERGY, CAPACITY & ANCILLARY SERVICES..........................79
10.1 OVERVIEW...................................................................................79
10.2 ENERGY MARKET..............................................................................79
10.3 TRANSMISSION PRICING PRINCIPLES............................................................80
10.4 CAPACITY MARKET............................................................................81
10.4.1 CAPACITY MARKET RULES...............................................................81
10.4.2 CAPACITY OUTLOOK....................................................................82
10.5 ANCILLARY SERVICES.........................................................................85
10.5.1 SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE.....................................86
10.5.2 VOLTAGE SUPPORT SERVICE.............................................................86
10.5.3 REGULATION AND FREQUENCY RESPONSE SERVICES..........................................87
10.5.4 ENERGY IMBALANCE SERVICE............................................................88
10.5.5 OPERATING RESERVE SERVICE...........................................................88
10.5.6 BLACK START CAPABILITY SERVICE......................................................89
11 APPENDIX C1: MONTHLY TIME-WEIGHTED AVERAGE ENERGY PRICES - BASE CASE (1999 $/MWH)................90
12 APPENDIX C2: MONTHLY TIME-WEIGHTED AVERAGE ENERGY PRICES - DOWNSIDE CASE (1999 $/MWH)............92
13 APPENDIX D: CORRELATION OF REGIONAL US POWER PRICES..............................................94
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APPENDIX B
FIGURES
Figure 1. Opening of retail markets in New York............................................................3
Figure 2. Demonstrated capacity by fuel in New York (1997).................................................4
Figure 3. Regional diversity in capacity...................................................................5
Figure 4. Capacity ownership versus aggregate demand.......................................................6
Figure 5. Projected dispatch curve in 2000 by owner........................................................7
Figure 6. NYPP's projections on supply and demand..........................................................8
Figure 7. Ranges for primary market drivers...............................................................10
Figure 8. Base case fuel forecasts........................................................................11
Figure 9. Ranges for secondary market drivers.............................................................12
Figure 10. Thermal plants in the Northeast - 1997.........................................................15
Figure 11. Coal plants in the Northeast...................................................................15
Figure 12. New York's thermal plants and 1997 operating costs.............................................16
Figure 13. Thermal efficiencies of Northeastern coal plants...............................................17
Figure 14. Downstate capacity supply and demand - base case for year 2000.................................21
Figure 15. Upstate capacity supply and demand - downside case.............................................23
Figure 16. Comparison of monthly energy prices over the next five years for Upstate New York..............27
Figure 17. Forecasted marginal price duration curves under the base case..................................30
Figure 18. Forecasted regional monthly energy prices for the first five years - base case.................31
Figure 19. Forecasted marginal price duration curves under the downside case..............................36
Figure 20. Forecasted regional monthly energy prices - downside case......................................37
Figure 21. Historical weekly price indices for New York and surrounding regions...........................46
Figure 22. Upstate New York: past and future energy prices................................................49
Figure 23. Average daily prices for Eastern and Western New York .........................................52
Figure 24. New York interfaces and transmission pricing zones.............................................53
Figure 25. Forecasted hourly transmission flows between Upstate and Downstate New York*...................55
Figure 26. Regional load duration curves in 1999..........................................................58
Figure 27. Historical seasonality of pumped storage facilities............................................60
Figure 28. Average five-year output variation index for conventional hydro stations.......................60
Figure 29. New York dispatch curve in 2000 based on base case projections.................................63
Figure 30. Delivered coal forecasts under the base case...................................................65
Figure 31. Comparison of base and downside coal forecasts.................................................65
Figure 32. Annual gas and oil forecasts under the base case...............................................66
Figure 33. Comparison of gas prices under base and downside cases.........................................67
Figure 34. Gas seasonality index..........................................................................67
Figure 35. Age distribution of New York fossil-fueled plant...............................................74
Figure 36. Dispatch curves over time......................................................................77
Figure 37. Outlook on installed capacity relative to peak demand..........................................78
Figure 38. Indicative internal installed capacity surplus in New York *...................................84
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TABLES
Table 1. Market driver inventory for New York power market.................................................9
Table 2. Base and downside case components................................................................14
Table 3. Forecast Downstate capacity prices, $/kW-year...................................................22
Table 4. Forecast Upstate capacity prices, $/kW-year......................................................24
Table 5. Forecast prices in base and downside cases (Upstate New York)....................................26
Table 6. Time-weighted average energy prices for the base case, 1999 $/MWh................................29
Table 7. Annual time-weighted average peak and off-peak energy prices - base case.........................32
Table 8. Unit-specific energy price forecasts - base case.................................................32
Table 9. Unit-specific performance - base case............................................................33
Table 10. Unit-specific calculated energy revenue forecasts - base case...................................33
Table 11. Total revenue by unit - base case...............................................................33
Table 12. Time-weighted average energy prices for the downside case, 1999 $/MWh...........................35
Table 13. Annual time-weighted average peak and off-peak energy prices - downside case....................38
Table 14. Unit-specific energy price forecasts - downside case............................................38
Table 15. Unit-specific performance - downside case.......................................................39
Table 16. Unit-specific calculated energy revenue forecasts - downside case...............................39
Table 17. Total revenue by unit - downside case...........................................................39
Table 18. Assumptions for CCGT new entry price calculation under the base case............................41
Table 19. New CCGT trigger prices in New York under the base case, 1999 $/MWh............................42
Table 20. Assumptions for CCGT new entry price calculation under the downside case........................43
Table 21. New CCGT trigger prices in New York under the downside case, 1999 $/MWh.........................44
Table 22. Forecasted load profile for New York............................................................57
Table 23. Normal transfer capability between regions......................................................59
Table 24. Typical start costs.............................................................................64
Table 25. NUG contracts in New York.......................................................................68
Table 26. NUG restructuring/retirement schedule (installed capacity, MW)..................................69
Table 27. Announced new build in New York.................................................................70
Table 28. Long term outlook on new entry (installed capacity, MW).........................................70
Table 29. Performance of New York's nuclear assets........................................................71
Table 30. Affected fossil-fuel capacity in New York.......................................................73
Table 31. Capacity retirement - fossil-fuel...............................................................75
Table 32. Capacity retirement - nuclear and hydro.........................................................76
Table 33. Hourly indicative transmission tariffs for each transmission district...........................81
Table 34. Summary of ancillary services...................................................................86
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1 STRUCTURE OF THE REPORT
London Economics, Inc. was retained by The AES Corporation in June 1998 to
conduct a market study on the New York region and to forecast detailed prices
for the New York power market, in support of the AEE acquisition of the NYSEG
thermal portfolio. This report is intended to give members of the financial
community an overview of the New York market, highlight the key assumptions used
in developing modeling scenarios for plant-level revenue analysis, and to
present the explicit projections for energy and capacity prices in the market.
THE REPORT IS DIVIDED INTO EIGHT FURTHER SECTIONS PLUS APPENDICES:
- - The next section, SECTION 2, discusses the current power market, including
the state of restructuring, generating unit characteristics and ownership,
and the current supply and demand balance in New York.
- - SECTION 3 considers the major market drivers in analyzing the New York
power market and the position of AEE's newly acquired assets in the market.
This section also outlines the development of the base and downside
scenarios modeled by London Economics.
- - In SECTION 4, we present our modeling analysis and methodology for the
capacity market in New York over the study period.
- - The next section, SECTION 5, provides detailed results of the modeling of
the base and downside case.
- - SECTION 6 compares the prices developed using the modeling analysis with
probable new entrant prices as an additional check on the price and revenue
forecasts obtained.
- - SECTION 7 addresses the short- to medium-term implications for New York's
power market and assesses New York's future in the context of its position
relative to neighboring regions: New England, Pennsylvania-New
Jersey-Maryland, and the Midwest.
- - The final main section, SECTION 8, concludes with an overview of London
Economics' observations and projections and considers the implications for
AEE in the New York power market.
The four appendices to this report cover: data assumptions and sources (Appendix
A), the tentative market rules proposed in New York, including the operation of
energy, capacity and ancillary services markets (Appendix B); projected regional
prices in Appendix C1 and C2, and an analysis of inter-regional price
correlation factors in Appendix D.
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2. INTRODUCTION TO THE NEW YORK POWER MARKET
2.1 OVERVIEW OF MARKET RESTRUCTURING
Restructuring of the vertically-integrated utility industry in New York is
taking place on the premise of the New York Public Service Commission's order,
issued in May of 1996. Each investor-owned utility was required to file a
restructuring plan with the Public Service Commission (PSC). The approval
process for these plans addressed issues on stranded cost, retail access,
unbundling, and electricity rates.
Following unbundling, New York utilities will be largely distribution utilities,
though for the near future they will continue to own nuclear assets. It is
expected that there will be a round of consolidation among these utilities once
the restructuring plans have been implemented. Consolidated Edison's purchase of
Orange & Rockland Utilities was a harbinger of this process; recent transactions
in New England point in the same direction. Furthermore, unlike many other
states, New York has some experience with performance based ratemaking, using it
for telephone companies in recent years; greater application of PBR to electric
utilities would hasten the process of distribution consolidation.
2.2 RETAIL MARKET
The PSC-approved utility plans give electric customers access to new energy
suppliers known as energy service companies (ESCOs). Utilities are required to
allow their customers to seek another supplier of electricity and energy-related
services, according to the individual schedules included in the restructuring
plans, see Figure 1. Consumers may select to make arrangements through either
ESCO or marketer. Or, they may choose to have an agent serve as their
intermediary between the marketer and the local utility company. Lastly,
consumers may choose to retain their local utility as their electricity
provider.
Marketers, agents, and ESCOs must meet certain criteria before selling their
services in New York. All must demonstrate that they are a certified businesses
registered with the New York State Department of State and meet the criteria
established by the local utility (creditworthiness standards, procedural
standards) and the PSC (e.g. filing of their standard customer contract or
disclosure statement).
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[FIGURE 1. OPENING OF RETAIL MARKETS IN NEW YORK GRAPHIC]
The feasibility of competition in the retail market will depend upon the
differences between the shopping credit established for the local utility (the
"provider of last resort") and the rates offered by ESCOs. For example,
Consolidated Edison's shopping credit, shown in cents per kilowatt-hour on each
end-user's bill, represents the amount by which an average customer's bill will
be reduced if an ESCO is chosen to supply electricity. From March 1999 through
April 2000, the shopping credit for residential consumers is 4.72 cents/kWh.(1)
Considering that average energy prices for Downstate New York are forecasted to
be $27.2/MWh in 1999 (or 2.72 cents/kWh), competition appears to be credible in
Consolidated Edison's territory.(2) A retail supplier can potentially capture a
gross revenue margin of 2.00 cents/kWh. London Economics has estimated that
general marketing and administrative costs for a retail supplier will fall in
the range of 0.7 - 0.8 cents/kWh.(3) Factoring in these overhead costs, results
in a potential profit margin of up to 1.2 cents/kWh for these retail suppliers.
In contrast, the shopping credit for NYSEG residential customers (known as the
"back-out credit")
- --------------------------
(1) The credit includes the effects of taxes under current tax laws, which
are subject to change.
(2) A small commercial or residential customer will have a load shape more
reflective of peak hour consumption patterns. The average peak energy
prices are forecast to be approximately $32/MWh in 1999-2000. Assuming
that an ESCO's electricity costs will then be similar to this peak
forecasted energy price (rather than the average forecasted energy
price of $27/MWh), it still can capture a gross revenue margin of
$1.52 cents/KWh and a potential profit margin of up to 0.7 cents/kWh.
(3) This indicative estimate is based on London Economics' analysis of the
various business components of a retail supplier and an estimation of
the expenses associated with retail supply as well as the potential
revenues. Factors addressed in the analysis include customer
acquisition costs, multi-media advertising, staff costs, billing and
scheduling set-up costs (IT), and costs associated with customer
service/calling center, market size, market share growth, customer
retention.
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is currently set at 3.2 cents/kWh. With average energy prices forecasted to be
$25/MWh (2.5 cents/kWh) for Upstate New York, retail competition will depend on
a retail supplier's ability to purchase power more cheaply. With administrative
costs of 0.8 cents/kWh, a retail supplier will have to purchase power for less
than 2.4 cents/kWh in order to compete credibly with NYSEG's back-out credit.
2.3 GENERATION ASSETS IN NEW YORK
The existing generation portfolio in New York is fairly diverse in fuel mix.
Baseload generation (nuclear, NUG contracts and coal-fired generation) accounts
for 43% of New York's demonstrated capacity (as seen in Figure 2). Gas-fired and
oil-fired generation represents another 42% of total demonstrated capacity.
Hydro (both conventional hydro and pumped storage) represents another 15% of the
system's capacity. A majority of the hydro is considered high mid-merit/peaking
facilities, because of their running regimes and their position within the
dispatch order. Peaking generation therefore represents over 57% of New York's
capacity.
[FIGURE 2. DEMONSTRATED CAPACITY BY FUEL IN NEW YORK (1997) GRAPHIC]
2.3.1 REGIONAL DIVERSITY
Historically, there have been documented transmission constraints going West to
East in the state of New York, especially with transmission into the Long Island
and New York City area. In order to gain an understanding of the resulting
regional divisions, we systematically divided New York into two regions
paralleling the transmission
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constraints. The regional definitions are based on transmission
districts/planning areas: a Downstate region, consisting of LIPA (formerly
LILCO), ConEd, CHG&E, O&R, and an Upstate region, consisting of NYPA, NIMO,
NYSEG, and RG&E.(4) In the past, transmission constraints have resulted in
pricing differentials. These are evident in power marketers' day-ahead
contracts for "Eastern New York" and "Western New York", which loosely
correlate to our terminology of Downstate and Upstate New York.
New York's regional differentials are underlined when examining the demonstrated
capacity breakdown by region. Figure 3 illustrates the historical fuel mix by
the defined regions. The Upstate New York region is dominated by nuclear, low
cost fossil fuel and hydro generation, resulting in over 34% baseload capacity
and 28% hydro capacity. In contrast, the Downstate region lacks cheap baseload
capacity - 72% of its total capacity is represented by more expensive oil and
gas-fired generation (including NUG capacity). This disparity in the fuel mix is
a major driver behind price differentials between the two regions.
[FIGURE 3. REGIONAL DIVERSITY IN CAPACITY PIE CHARTS]
2.3.2 GENERATION OWNERSHIP
Generation ownership on a capacity basis is dispersed, as shown in Figure 4.
Competitiveness of a market can be represented by the relative size of strategic
generators (large players with flexible generation assets that are able to set
price) and residual demand (peak demand minus captive nuclear and NUG demand).
The current supply - demand balance in New York suggests a competitive outcome,
because there is no single dominant player that can capture the residual demand.
Moreover, there
- --------------------------
(4) In this regional analysis, the binding transmission constraint between
these two regions is based on the Southeast NYPP interface capability
of 4950 MW. It is important to note that this transmission contraint
appears to be binding on average, though there are certain off-peak
hours during which there is no congestion. This analysis is further
discussed in Appendix A, Section 9.2.
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will be further fragmentation of portfolios in the near term, due to the recent
acquisitions of the auctioned Consolidated Edison assets by Orion Power, NRG
Energy, and KeySpan Energy and the acquisition of NIMO's coal facilities by NRG
Energy.
Profitable capacity withdrawal behavior is not feasible given the actual
portfolios of the players. No one player has enough strategic generation in
their portfolio to benefit from these withdrawal strategies.
[FIGURE 4. CAPACITY OWNERSHIP VERSUS AGGREGATE DEMAND BAR GRAPH]
Figure 5 plots out the forecasted dispatch curve for 2000 (utilizing annualized
average variable cost assumptions derived for the simulation modeling under the
base case) by owner.(5) The graph also includes markers for minimum, average and
peak demand forecasted for the New York Control area for 2000 (as derived from
hourly data used in the simulation modeling). It is evident that the peak
generation is basically owned by NRG Energy, KeySpan Energy, and Orion Power
(all three formerly ConEd's assets), Southern (previously owned by O&R), CHG&E,
and Keyspan (formerly LILCO), due to the intrinsically high costs associated
with the oil and gas-fired technology in use at these facilities. Indeed, almost
all generation above the average demand levels is oil or
- -----------------
(5) For further detail on the underlying modeling assumptions and data
sources, see Appendix A of this report.
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gas-fired. It is important to note that the actual running position of these
assets may actually change due to the availability-driven performance of the
hydro assets (primarily NYPA and Orion). In this cost-based supply curve, the
hydro assets are shadow-priced against thermal units; however, many of these
assets will actually dispatch seasonally based on hydrology. Hydro units will
tend to displace the mid-merit, peaking facilities.
[FIGURE 5. PROJECTED DISPATCH CURVE IN 2000 BY OWNER LINE GRAPH]
* Prior to sale of certain in-city generation to KeySpan Energy, Orion Power,
and NRG Energy
2.4 SUPPLY - DEMAND BALANCE
Figure 6 depicts the supply-demand schedule forecasted by the NYPP in their Load
& Capacity Data 1998. This static analysis does not include any capacity
retirements in excess of NYPP's re-ratings/retirements of net purchases, NUGs,
and utility-owned capacity. For example, no environmentally-driven retirements
of fossil-fueled facilities or early retirements of nuclear stations is assumed
in this graph. Furthermore, this analysis assumes no significant new entry, such
as the announced projects by Sithe and USGen. According to these figures,
demonstrated capacity will not keep up with
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peak demand's growth. By 2003, the NYPP has forecast a capacity shortfall
against the 22% reserve margin. If the recently announced new entrants are
included in the calculation, then the capacity shortfall is avoided over the
ten-year timeframe considered. In our modeling analysis, we have implemented a
dynamic approach to capacity and supply, with new entry and capacity retirement
a major driver behind power market trends. Under the base and downside case
assumptions, net installed capacity remains in-line with growing demand, as
discussed in section 9.10.
[FIGURE 6. NYPP'S PROJECTIONS ON SUPPLY AND DEMAND LINE GRAPH]
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3. MARKET DRIVERS AND THE AEE GENERATION PORTFOLIO IN NEW YORK
MARKET DRIVERS
In the early stages of a market analysis, London Economics identifies a list of
market drivers which will affect the revenues of the merchant assets in
question. These drivers range from normal exogenous parameters such as demand
growth rates and fuel prices to implicit market assumptions such as the bidding
behavior of incumbents in energy and capacity markets. These are ranked by order
of significance to market prices and AEE's revenues.
- -------------------------------------------------------------------------------
TABLE 1. MARKET DRIVER INVENTORY FOR NEW YORK POWER MARKET
PRIMARY DRIVERS SECONDARY DRIVERS NON-MARKET DRIVERS
Fuel prices Plant repowering Environmental restrictions
New entry Demand growth Market design changes
Capacity pricing Nuclear retirements Regulatory intervention
Energy pricing
Import levels - pricing
Transmission
- -------------------------------------------------------------------------------
Ranges are then constructed to bound most of the primary market risk drivers -
these then form the basis for scenario and sensitivity analysis. Ranges for the
three identified primary market drivers are shown in Figure 7.
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[FIGURE 7. RANGES FOR PRIMARY MARKET DRIVERS GRAPH LINE GRAPH]
For the New York market, we believe that the market drivers that most affect the
revenues to the AEE assets are:
- - RELATIVE FUEL PRICES: Most of the energy revenues from the AEE portfolio
comes from the baseload coal units. The minimum margin for these units is
defined by relative differences in coal and gas/oil prices in many hours.
The range of gas/oil and coal prices considered in our analysis is shown in
Figure 8. RDI's BaseCase delivered natural gas and fuel oil forecasts were
used in our base case modeling. Currently fuel oil prices and traded
forward prices are below the RDI forecast prices. London Economics
performed additional analysis for the years 1999 to 2010 to determine the
effects of lower oil prices, partially offset by NOX allowance costs (which
were not incorporated in the base and downside cases). Incorporating both
of these effects leads to a decrease in the Company's revenues during 1999
through 2003. The decrease revenues during these years fall between the
base case and the downside case revenues. Coal prices were estimated using
historical transportation costs to Eastern and Western New York in
conjunction with John T. Boyd's FOB coal price forecasts for
Mid-Appalachian compliance coal and Pittsburgh seam coal. The fuel price
assumptions and data sources used are discussed further in Appendix A.
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- - NEW ENTRY ASSUMPTIONS: Over the short-term, capacity and energy prices will
be substantially affected by the level of immediate new entry. While this
should reach an equilibrium level over time, based on comparative costs and
capacity margins, experience in other markets has shown a strong tendency
for substantial new entry before market prices provide an adequate entry
signal. New entry trigger prices for CCGT were calculated using capital
costs, operations & maintenance costs, and thermal efficiency assumptions
provided by Stone & Webster, as detailed in Section 0. The dispatch and
capacity modeling analysis has implicitly incorporated new entrant pricing
by comparing the forecast price levels with the revenue requirements of a
new generator to enter the market.
- - CAPACITY PRICING: The New York ISO will operate separate markets for energy
and capacity. The operation of the latter is discussed in detail in Section
10.4. Economically, the sustainable lower bound on capacity prices is set
by the minimum revenues required by marginal units (those with low load
factors whose revenues in the energy market are only slightly larger than
their direct fuel and variable operations & maintenance costs) to stay
available. If these plants are unable to recover their going forward fixed
costs (staff costs, local taxes, and other fixed operations & maintenance
costs) at a minimum over time, they will close. This will in turn lead to
higher capacity prices in subsequent periods. The upper bound of capacity
prices is set by the prices required to trigger new entry on average, or by
the potential for regulatory intervention to prevent abuse of market power.
We discuss the capacity price forecasting methodology in detail in Section
4.1.
[FIGURE 8. BASE CASE FUEL FORECASTS LINE GRAPH]
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London Economics has also identified a range of market drivers of lesser
importance to the revenue streams. The ranges constructed for these market
drivers are shown in Figure 9.
[FIGURE 9. RANGES FOR SECONDARY MARKET DRIVERS LINE GRAPH]
The secondary market drivers of interest include:
- - THE POTENTIAL FOR PLANT RE-POWERING: Downstate New York has a large number
of oil-fired units, especially in the New York City area. We believe it
likely that many of these units may enter a re-powering process over the
short- to medium-term, in a rush to establish which plants will remain
viable after deregulation. We believe that limited re-powering of 3000 MW
is likely (our medium range) over the next five years due to the local time
horizons for permitting and construction, and that our re-powering
assumptions well reflect the economics of the Downstate market. For that
reason, we have not assumed that an even larger proportion of the Downstate
units will be immediately re-powered in our downside case. In any case, the
Upstate units are generally constrained from higher Downstate prices,
limiting the effects of re-powering on AEE's revenues.
- - DEMAND GROWTH: Changes in demand growth will gradually affect plant load
factors and revenues. This is of more limited relevance to the AEE
portfolio since the major units should remain at high load factors under
any demand growth pattern. It has therefore not been considered further.
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- - NUCLEAR RETIREMENTS: Nuclear units may exit the market due to their
inability to cover their fixed costs from market prices. However, it should
be noted that stranded cost recovery, individual utility settlements and
other corporate objectives may have a major influence on the likelihood for
early nuclear retirements. Since any nuclear retirements could lead to
higher Upstate capacity prices this market driver will be discussed further
in a later section.
- - ENERGY BIDDING: The New York ISO rules envision a market in which energy
bids reflect unit marginal costs (fuel plus variable operations &
maintenance). In a true market, however, we note that prices and costs are
not directly linked, and that substantial additional value may be obtained
in energy markets if bidding strategies of incumbents lead to higher
clearing prices. Like capacity prices, these are bounded by the potential
for regulatory intervention. Our market analysis assumes that generators
will be unable to exert any market power and therefore bid competitively.
We have not explicitly analyzed any regulatory or institutional risks, other
than the analysis of what impact that environmental restrictions might have on
New York plant operations. We note that Kintigh and Milliken are among the few
scrubbed plants in New York and are therefore less likely to be adversely
affected than other units in the state.
3.2 DEVELOPMENT OF MARKET SCENARIOS
London Economics has developed a base and downside case analysis to assist in
the development of revenue forecasts. The downside case is expected to provide a
reasonably low scenario for market prices over a relevant time period. It has
been constructed from the lower range of the significant market drivers, in
order to examine the impact from a confluence of unfavorable events.
The construction of the base and downside cases is shown in Table 2. Note that
the downside case includes the lowest range of most of the key market drivers.
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TABLE 2. BASE AND DOWNSIDE CASE COMPONENTS
- ------------------------------------------------------------------------------------------------------------------------------------
Market driver Base Case Downside Case
Range Description Range Description
- ------------------------------------------------------------------------------------------------------------------------------------
Fuel prices Medium Gas prices grow on average 1.5% per annum Low Gas prices fall by 10% in real terms
between 1999 and 2015 in real terms relative to the Base Case
New entry Low Over 3,000 MW of new entry by 2005 Low Over 3,000 MW of new entry by 2005
Capacity pricing Medium Marginal units recover fixed Low Marginal units recover only
O&M costs plus minimal going forward fixed costs
target return on capital from capacity prices
Plant repowering Low Repowering projects in downstate based on Low Repowering projects in downstate based on
economics (3000 MW by 2005) economics (3000 MW by 2005)
Demand Low 1% annual growth in Low 1% annual growth in
peak demand and energy peak demand and energy
Nuclear retirements Low No early retirements Low No early retirements
of nuclear units of nuclear units
Energy pricing Low Fuel + variable O&M + start costs only Low Fuel + variable O&M + start costs only
3.3 AEE'S NEW YORK PORTFOLIO
AEE's newly acquired coal units in Western New York are currently one of the
best portfolios of baseload generation. Traditionally, the larger units have
been operating at annual capacity factors over 80%. Going forward, these
capacity factors are expected to rise, as AEE applies its operating expertise,
and raises production efficiency through new technology and cost-saving
implementations. Figure 10 illustrates the most efficient thermal units (coal,
gas, oil, and nuclear) in the Northeast (NYPP, NEPOOL, and PJM) in 1997 by
average heat rate and total production costs.(6) AEE's units, Kintigh, Milliken,
Greenidge & Goudey, are in the bottom left corner of this matrix - where total
production costs are low and thermal efficiency is highest. Figure 11
illustrates coal plants from the Northeast with weighted-average production
costs and heat rates over the five-year period from 1993 to 1997. Again,
Kintigh's and Milliken's performance from a technological efficiency and
cost-basis perspective is high relative to its peers in New York, New England,
Pennsylvania, New Jersey, Maryland, and Delaware. On a five-year weighted
average total production cost basis, Kintigh ranks 7th, Milliken ranks 10th,
Goudey ranks 14th, and Greenidge ranks 16th out of a total of 48 coal-fired
electric utility plants in the Northeast.
- ---------------
(6) Includes the top half of all thermal plants in the PJM, NYPP, NEPOOL
regions sorted by production costs. The source of data is copyrighted
material excerpted from the Resource Data International, Inc. (RDI)
POWERdat(R) copyrighted data base. RDI is located in Boulder, Colorado.
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APPENDIX B
[FIGURE 10. THERMAL PLANTS IN THE NORTHEAST - 1997 LINE GRAPH]
[FIGURE 11. COAL PLANTS IN THE NORTHEAST LINE GRAPH]
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Figure 12 depicts New York's thermal plants and their relative production and
fuel costs. AEE's portfolio in New York appears to fall in the low cost
categories both on the fuel side and on the total production side (plant's
symbol size denotes production costs). Production costs for Kintigh, Milliken,
Greenidge, and Goudey are all in the range of $10/MWh to $30/MWh.
[FIGURE 12. NEW YORK'S THERMAL PLANTS AND 1997 OPERATING COSTS GRAPHIC]
Source: POWERdat and POWERmap
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FIGURE 13. THERMAL EFFICIENCIES OF NORTHEASTERN COAL PLANTS GRAPHIC]
Source: POWERdat and POWERmap
We believe that these assets will remain competitive in the longer term. AEE's
top units (Kintigh, Milliken, Goudey, and Greenidge) - on a variable cost basis
- - are not threatened by new CCGT entry in the region, because a real gas price
lower than $2.00/MMBtu is not forecast for New York in the long-term.(7)
Furthermore, their existing baseload competitors will be less effective in the
future: new nuclear stations are unlikely to be built in New York, and license
retirements will begin as early as 2009; other coal units will be unable to
obtain enough gains in efficiency in order to catch up to AEE's position.
Furthermore, as NUG contracts expire or become restructured in the next ten
years, they will enter the dispatch curve above the efficient AEE units.
- ------------
(7) Under base and downside case scenarios, delivered New York natural gas
forecasts do not fall below $2.5/MMBtu and $2.3/MMBtu, respectively.
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4. FORECASTING CAPACITY PRICES
The design of the New York ISO is based on a "capacity ticket" auction. Each
utility or ESCO which serves load will be allocated a capacity and reserve
requirement which must be covered by firm contracts with installed (or in some
cases imported) capacity, backed by firm generation. An ESCO, whose peak demand
(and allocation of reserves) exceeds its contracted capacity, must pay a
penalty, which is designed to prevent users from "leaning on the system" and
reducing overall reliability.
In the New York model, capacity can effectively be bought and sold ex post so
that each ESCO can meet its requirement efficiently. Such as system is designed
in effect to ensure a reliable power supply, and therefore gives firm capacity
in the market a premium value.
Capacity prices under the NY ISO's "capacity ticket" auction cannot be estimated
solely from a production cost model. The average unit revenue streams to
generators operating in markets with sufficient generation may range well below
new entrant prices. In economic terms, the actual pricing decisions of sellers
in the capacity market will be quite complex, and will reflect a range of
factors:
- - The capacity surplus/shortfall in the relevant markets;
- - The potential for strategic behavior in withholding capacity from the ICAP
market. This is made difficult in New York by the market rules (which are
explicitly designed to prevent such withholding) and the significant
fragmentation of the capacity market due to the generation auctions.
- - The effects of transitional arrangements between generators and load
serving entities (utilities and ESCOs) may make traded ICAP markets in New
York thin for some initial period.
In practice, we expect on average for capacity prices to be bounded by two
parameters:
- - THE ENTRY COST OF NEW GENERATION: This must be adjusted for the margin on
energy sales that a new plant might expect to make after it (and possibly
similar units) entered. For example, a CCGT in the higher priced Downstate
market would expect a substantial energy market margin over the high cost
units in that region. Its entry might therefore be triggered by lower
capacity payments than would be required Upstate, where the competing units
have lower costs and energy margins will be smaller. As many new plants
enter, this margin tends to erode and once again new entrants must rely on
capacity payments to cover their fixed costs and return on capital.
- - THE REVENUE REQUIREMENTS OF EXISTING PLANTS: In equilibrium, marginal units
which earn minimal infra-marginal rents (the difference between the average
energy revenues they receive and their variable costs) will require a
positive capacity payment to cover their going fixed costs. Units that are
unable to cover these costs from capacity payments will exit the market
over time. Therefore the
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difference between projected on-going fixed costs (such as staffing, local
property taxes, operations & maintenance costs, etc.) and net energy market
revenues (after fuel costs have been subtracted) for marginal units
provides a STRONG LOWER BOUND over time on how low energy prices can go,
unless generators are willing to subsidize loss-making units for some other
reason.
4.1 CAPACITY MODELING METHODOLOGY
London Economics has provided an analysis of capacity prices based on the
following methodology:
1. From the energy market model PoolMod, we developed yearly forecasts of
energy revenues and fuel costs for every unit on the system. These are
divided by the installed capacity of the unit to give a net ENERGY CREDIT
(measured in $/kW-year) for each unit. Many of these units are rarely used
for normal energy dispatch, so their net energy credit values are near
zero. Coal and hydro units may have a substantial energy credit, due to
their lower fuel costs.
2. We developed a set of target minimum fixed cost values (also in $/kW) from
various sources of data. These represent the going forward costs of
keeping a unit on-line and able to generate. These fixed operations &
maintenance costs exclude all sunk costs, such as return on capital and
debt service, and reflect only those costs which an owner must pay in the
next year to keep the plant online, such as fixed operations & maintenance
costs. This data set was gathered from various sources, including FERC
Form 1 data, RDI, and other sources. Since the FERC data (and therefore
secondary sources such as RDI) is sometimes unreliable, we removed
artificially high values, in order to avoid distortion of the capacity
pricing analysis.
3. For thermal units older than 30 years, we added the life extension costs
necessary to keep these units online and operating to the fixed cost
requirements. We assumed that life extension for these units would cost
$100/kW, amortized over a ten-year period at a WACC of 10%. This is a
relatively low figure and highly conservative for units which require any
substantial environmental capex, for example. We also added $7/kW in
non-income property and other taxes. This too appears highly conservative
from published utility data, especially for the downstate units in the New
York City metropolitan area.
4. The minimum capacity price received can be calculated for each plant as
the fixed cost requirement minus the model-generated energy credit. This
represents the minimum payment a generator would accept on average to keep
a unit available, even at a very low or zero return on capital. Using the
plant capacities from the database, a capacity supply curve was
constructed for the Upstate and Downstate territories.
5. For the base case, a minimum return on capital was added for thermal units
(excluding the nuclear units). This was calculated at an 8% minimal
average return
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on capital based on an estimate of net book value for the units.(8) Net
book values had to be estimated from historical cost data as utilities
rarely allocate accumulated depreciation on a plant basis.
6. The net demand for firm capacity was calculated for each year for Upstate
and Downstate installed capacity markets, based on projected peak demands,
NY ISO capacity reserve margin requirements, etc. These were then used in
conjunction with the capacity supply curves to generate forecast capacity
prices.
Note that this forecasting methodology is inherently conservative, as it only
attempts to establish a long-run breakeven point for marginal generators when
the system has sufficient capacity. Any form of capacity bidding gaming behavior
could raise capacity prices to new entrant levels on average, although we do not
believe that this scenario is strongly credible in New York over time, and no
assumptions on strategic behavior have been used to develop the following
capacity pricing forecasts.
4.2 CAPACITY PRICE FORECASTING RESULTS
The New York market rules include obligations on total statewide capacity, plus
firm capacity on a transmission district basis. We believe that the statewide
market is well served by New York capacity and imports, and that TD capacity
markets will provide a more substantial portion of revenues. We have therefore
performed a regional analysis of capacity prices, which recognizes that the
capacity-deficient region (Downstate) will remain a net purchaser of capacity
from the Upstate region through our modeling time horizon.
4.2.1 DOWNSTATE CAPACITY PRICING
The capacity supply curve for Downstate capacity for the Base Case is shown in
Figure 14. At present the Downstate market is relatively tight, and almost all
existing New York and Long Island capacity is needed to meet local generation
requirements. These include the many small CTs in the New York City area. Even
with these units, the system will soon require new capacity to meet reserve
requirements. By 2003 we expect that the adjusted capacity and reserve
requirement will be high enough (further right) so that new capacity will be
required. The capacity analysis in these later years is the same as described
above, except that the capital cost of the new units is not treated as sunk -
e.g. it must be recovered in the sum of capacity and energy revenues.
- --------------------
(8) This net book value is derived from the utility's historical cost
of building the plant. In recent auctions older capacity has generally
sold at some multiple of book value. This effect has not been
incorporated into the analysis. Target returns for merchant asset
acquisitions will be substantially higher than 8%; thus, our analysis is
a purposefully conservative assumption.
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[FIGURE 14. DOWNSTATE CAPACITY SUPPLY AND DEMAND - BASE CASE FOR YEAR 2000 LINE
GRAPH]
With no new entry, the Downstate system would soon be out of capacity. However,
for the purposes of establishing a downside case we consider it likely that
substantial re-powering of New York City capacity may occur, based on the
margins over existing units and the ISO's need for firm capacity to meet
transmission system reliability constraints.
The Downstate base case allows generators to earn a minimal return on capital,
and forecasts that capacity prices fall only slowly over time, as energy
revenues rise towards new entrant levels. This case is consistent with the
current capacity market in the Downstate region (excluding New York City itself,
which is the subject of special rules that tend to produce even higher capacity
prices). The winning bidder in the recent Consolidated Edison RFP, for example,
bid a capacity price of just over $41/kW-year.
Forecast downstate capacity prices are shown in the table below. Note that
revenues from capacity payments are ADDITIONAL to the energy revenues shown in
Sections 5.1.1 and 5.2.1.
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TABLE 3. FORECAST DOWNSTATE CAPACITY PRICES, $/kW-YEAR
BASE DOWNSIDE
1999 $40.0 $27.0
2000 $40.0 $35.0
2001 $45.0 $38.2
2002 $50.0 $41.4
2003 $55.0 $44.6
2004 $60.0 $47.8
2005 $65.0 $51.0
2006 $64.6 $52.2
2007 $64.2 $53.4
2008 $63.8 $54.6
2009 $63.4 $55.8
2010 $63.0 $57.0
2011 $61.0 $53.8
2012 $59.0 $50.6
2013 $57.0 $47.4
2014 $55.0 $44.2
2015 $53.0 $41.0
2016 $49.4 $36.8
2017 $45.8 $32.6
2018 $42.2 $28.4
2019 $38.6 $24.2
2020 $35.0 $20.0
4.2.2 UPSTATE CAPACITY PRICING
The AEE units will not qualify for the higher Downstate prices, although these
are important for the overall entry dynamics of the market. In the Upstate
market, most of the coal plants (including the baseload AEE coal units) receive
a large margin in most hours, and therefore can meet their fixed costs from the
energy markets. This is shown in Figure 15.
For the downside case, the marginal units in capacity terms are steam units,
which have fairly high fixed O&M and staffing costs. Competing thermal units
(such as NRG's newly acquired coal units) also face substantial life extension
costs on average, due to their age. Due to the large number of units available
at this approximate cost level this provides a strong downside case, as again
these units are required once imports (from outside New York) and capacity
exports (to Downstate) are accounted for.
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[FIGURE 15. UPSTATE CAPACITY SUPPLY AND DEMAND - DOWNSIDE CASE LINE GRAPH]
We see little prospect of Upstate capacity prices reaching open cycle GT levels
for some time. Instead, a much more likely scenario would have:
- - new entry occurring predominantly in the Downstate market, where capacity
is more tight and the competing plants have much higher costs;
- - fairly constant capacity prices over time in the downside scenario for
Upstate New York, due to a balance between reduced capacity exports to
Downstate and lower firm capacity imports from neighboring systems (such as
PJM). Note that the marginal capacity in this scenario is making LITTLE OR
NO RETURN ON CAPITAL in this case, which is a highly conservative
assumption. In the base scenario, prices will tend to stay somewhat firmer
to signal new entry in Upstate by 2010, and existing generators will
receive a more reasonable return on capital.
Any unexpected changes in the Upstate region, such as sudden retirement of
nuclear units, etc. could provide substantially higher capacity prices. These
have not been included in our analysis.
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TABLE 4. FORECAST UPSTATE CAPACITY PRICES, $/kW-YEAR
BASE DOWNSIDE
1999 $27.0 $25.0
2000 $30.0 $26.0
2001 $37.0 $31.0
2002 $40.8 $36.0
2003 $46.2 $39.5
2004 $51.6 $45.3
2005 $57.0 $51.0
2006 $56.2 $50.6
2007 $55.4 $50.2
2008 $54.6 $49.8
2009 $53.8 $49.4
2010 $53.0 $49.0
2011 $52.6 $47.8
2012 $52.2 $46.6
2013 $51.8 $45.4
2014 $51.4 $44.2
2015 $51.0 $43.0
2016 $52.6 $44.8
2017 $54.2 $46.6
2018 $55.8 $48.4
2019 $57.4 $50.2
2020 $59.0 $52.0
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5 SUMMARY OF MODELING RESULTS
This section provides the results of London Economics' market simulation.
Forecast prices are summarized in Table 5 below. Note that the energy prices
shown are average time-weighted prices across the entire year, representing the
average unit revenue to a unit running at baseload in all hours. In the third
column of each case an average baseload revenue per MWh has been calculated as
the sum of energy and capacity revenues. Ancillary services revenues are not
included. These prices are for the Upstate region only, where the AEE assets are
located. Downstate prices are significantly higher in most cases.
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TABLE 5. FORECAST PRICES IN BASE AND DOWNSIDE CASES (UPSTATE NEW YORK)
BASE CASE DOWNSIDE CASE
--------------------------------------- ----------------------------------------
ENERGY CAPACITY TOTAL ENERGY CAPACITY TOTAL
($/MWh) ($/kW-YEAR) ($/MWh) ($/MWh) ($/kW-YEAR) ($/MWh)
1999 $25.0 $27.0 $28.1 $23.3 $25.0 $26.2
2000 $26.2 $30.0 $29.6 $24.4 $26.0 $27.4
2001 $27.4 $37.0 $31.6 $25.4 $31.0 $29.0
2002 $28.4 $40.8 $33.1 $26.4 $36.0 $30.5
2003 $27.3 $46.2 $32.5 $25.0 $39.5 $29.5
2004 $24.9 $51.6 $30.8 $22.9 $45.3 $28.1
2005 $22.8 $57.0 $29.3 $21.0 $51.0 $26.8
2006 $23.1 $56.2 $29.5 $21.2 $50.6 $27.0
2007 $23.3 $55.4 $29.7 $21.4 $50.2 $27.2
2008 $23.6 $54.6 $29.8 $21.7 $49.8 $27.3
2009 $23.9 $53.8 $30.0 $21.9 $49.4 $27.5
2010 $24.2 $53.0 $30.2 $22.1 $49.0 $27.7
2011 $24.5 $52.6 $30.5 $22.3 $47.8 $27.8
2012 $24.8 $52.2 $30.7 $22.5 $46.6 $27.9
2013 $25.1 $51.8 $31.0 $22.8 $45.4 $27.9
2014 $25.4 $51.4 $31.3 $23.0 $44.2 $28.0
2015 $25.7 $51.0 $31.5 $23.2 $43.0 $28.1
2016 $25.3 $52.6 $31.3 $23.0 $44.8 $28.1
2017 $24.9 $54.2 $31.1 $22.7 $46.6 $28.0
2018 $24.5 $55.8 $30.8 $22.5 $48.4 $28.0
2019 $24.1 $57.4 $30.6 $22.2 $50.2 $28.0
2020 $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2021* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2022* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2023* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2024* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2025* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2026* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2027* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2028* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2029* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2030* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2031* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2032* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2033* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2034* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
2035* $23.7 $59.0 $30.4 $22.0 $52.0 $27.9
* Energy prices and capacity prices from 2021 through 2035 have not been
modeled.
We have assumed zero growth in real prices after 2020.
We have not attributed NOx allowance costs to competing plants in the New York
market, which is conservative. Inclusion of these NOx costs would tend to
increase energy prices significantly.
Figure 16 shows the monthly variation in energy prices in the first five years,
1999 to 2003, for Upstate New York, under both the base and the downside case.
Most of the monthly variation is due to differences in delivered gas prices.
Note that the linear trends (defined as the growth in average prices over this
five-year timeframe) begin to deviate after 1999, as downside case prices grow
at a lower rate.
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[FIGURE 16. COMPARISON OF MONTHLY ENERGY PRICES OVER THE NEXT FIVE YEARS FOR
UPSTATE NEW YORK LINE GRAPH]
The following sub-sections provide a detailed set of results for the base and
downside cases. Input parameters and fuel price forecasts are discussed in
detail in Section 9 (Appendix A). Each set of results concludes with an overview
of how the AEE assets would operate under the modeling case.
5.1 BASE CASE MODELING RESULTS
5.1.1 BASE CASE ENERGY PRICES
Regional prices under the base case are consistent with historical trends in New
York prices. Downstate New York prices are, on average, $2.5/MWh above Upstate
New York prices. Downstate prices increase initially (1999 to 2002) at a
compounded average annual rate of over 4%. Between 2002 and 2005, prices fall as
additional capacity comes on-line. After 2005, Downstate prices show slower real
growth (annualized rate of 1% on average).
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Upstate prices also grow at a real annual average rate of 4% during the initial
timeframe, 1999-2002. The major driver for price growth is the increasing gas
price forecasts and falling capacity margins. Load growth results in a tighter
supply-demand situation and the increased utilization of higher cost units.
Upstate prices fall in response to new capacity and the re-powering of plants in
the Downstate region between 2002 and 2005. Nonetheless, positive growth in
prices is achieved between 2006 and 2015, as gas prices continue to rise in real
terms through 2015. This results in an upward pressure on energy prices, as can
be seen in Figure 17 and Table 6 post 2005. As nuclear facilities retire in
Downstate New York (Indian Point), additional baseload CCGTs enter the capacity
mix, replacing the retired baseload and displacing more expensive oil-fired and
gas-fired units. By 2015, these CCGTs have higher thermal efficiencies, which
translate into lower costs and a more competitive position within Downstate New
York's baseload. Upstate baseload generation sees a decrease in export
opportunities to Downstate, resulting in a downward pressure on Upstate regional
prices post-2015.
[FIGURE 17. REGIONAL TIME-WEIGHTED AVERAGE ENERGY PRICES FOR THE BASE
CASE, 1999 $/MWh LINE GRAPH]
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[TABLE 6. TIME-WEIGHTED AVERAGE ENERGY PRICES FOR THE BASE
CASE, 1999 $/MWh LINE GRAPH]
UP DN
1999 $25.0 $27.2
2000 $26.2 $28.2
2001 $27.4 $29.4
2002 $28.4 $30.4
2003 $27.3 $28.5
2004 $24.9 $26.6
2005 $22.8 $24.8
2006 $23.1 $25.1
2007 $23.3 $25.4
2008 $23.6 $25.7
2009 $23.9 $26.0
2010 $24.2 $26.3
2011 $24.5 $26.5
2012 $24.8 $26.8
2013 $25.1 $27.0
2014 $25.4 $27.2
2015 $25.7 $27.5
2016 $25.3 $27.9
2017 $24.9 $28.3
2018 $24.5 $28.7
2019 $24.1 $29.1
2020 $23.7 $29.5
2021* $23.7 $29.5
2022* $23.7 $29.5
2023* $23.7 $29.5
2024* $23.7 $29.5
2025* $23.7 $29.5
2026* $23.7 $29.5
2027* $23.7 $29.5
2028* $23.7 $29.5
2029* $23.7 $29.5
2030* $23.7 $29.5
2031* $23.7 $29.5
2032* $23.7 $29.5
2033* $23.7 $29.5
2034* $23.7 $29.5
2035* $23.7 $29.5
* Energy prices and capacity prices from 2021 through
2035 have not been modeled. We have assumed
zero growth in real prices after 2020.
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The price duration curves, in Figure 18, for both Upstate and Downstate New
York, indicate a fairly steady marginal price, reflective of the cost margins
associated with baseload coal and CCGT units.
[FIGURE 18. FORECASTED MARGINAL PRICE DURATION CURVES UNDER THE BASE
CASE LINE GRAPH]
The Downstate region reaches a peak in monthly prices in the late summer (due to
air conditioning load) and in the deep wintertime (due to the marginality of the
oil-fired
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generation, and its winter-peaking fuel price). In contrast, the peak
monthly price for Upstate occurs mostly in the wintertime (heating load).
Seasonal gas and fuel oil prices (winter-peak), as well as the time-adjusted
performance of the peaking facilities are additional determinants of this
winter-peaking energy price pattern in Upstate New York. Forecast regional
monthly prices through 2020 are included in Appendix C1 in tabular form.
[FIGURE 19. FORECASTED REGIONAL MONTHLY ENERGY PRICES FOR THE FIRST FIVE YEARS -
BASE CASE LINE GRAPH]
($ 1999/MWh)
On-peak and off-peak prices estimated from half-hourly price forecasts under the
base case are detailed in Table 7. Average on-peak prices are assumed to occur
during the 16 hours between 7 AM to 11 PM during the weekdays (Monday through
Friday). Average off-peak prices are calculated from all other hours, excluding
weekends. This methodology was used so as to make LE forecasts comparable (in
method) to published benchmarks of historical prices (such as Megawatt Daily and
Power Markets Week).
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- --------------------------------------------------------------------------------
TABLE 7. ANNUAL TIME-WEIGHTED AVERAGE PEAK AND OFF-PEAK ENERGY PRICES -
BASE CASE
UPSTATE NEW YORK (1999 $/MWh)
1999(1) 2000 2001 2002 2003
--------------------------------------------------
ON-PEAK 28.4 29.1 31.5 33.0 31.8
OFF-PEAK 20.9 21.6 22.7 23.3 21.8
DOWNSTATE NEW YORK (1999 $/MWh)
1999(1) 2000 2001 2002 2003
--------------------------------------------------
ON-PEAK 31.6 32.0 34.4 35.6 33.7
OFF-PEAK 21.3 22.0 23.0 23.7 22.0
- -------------------
(1) 1999 prices reflect February - December 1999 forecasts only
- --------------------------------------------------------------------------------
5.1.2 AEE PORTFOLIO IN THE BASE CASE
The AEE portfolio consists of baseload coal-fired generation. These assets are
well-positioned to take advantage of their high availability, as they are among
the first non-nuclear assets to be dispatched on a variable cost basis. This is
due to the inherent thermal efficiency of these coal units coupled with their
low fuel cost. Unit-specific average energy prices and average annual load
factors are summarized in Table 8 and Table 9, respectively. Under our modeling
assumptions, AEE portfolio average load factors are constant at 92% after 2004,
as assumed availability stabilizes at 92% post-2003. The unit-specific prices
increase in real terms through 2002, then decline through 2005. This pattern is
a function of initial supply balance pressures and new build. Increasing gas
prices (in real terms) along with growing demand induce energy prices to recover
after 2005. The trend in unit-specific prices mirrors the regional and system
dynamics of new entry and plant retirement.
- --------------------------------------------------------------------------------
TABLE 8. UNIT-SPECIFIC ENERGY PRICE FORECASTS - BASE CASE
AVERAGE SMP WHEN RUN (1999 $/MWh)
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
-------------------------------------------------- ------- ------- ------- ------
MILLIKEN 1 $25.2 $26.4 $27.3 $28.6 $27.2 $22.9 $24.4 $26.0 $23.8
MILLIKEN 2 $25.2 $26.3 $27.5 $28.7 $27.4 $22.9 $24.2 $25.9 $23.7
KINTIGH 1 $25.2 $26.3 $27.5 $28.2 $27.4 $22.9 $24.4 $25.7 $23.7
GREENIDGE 3 $25.5 $26.3 $27.8 $28.4 $27.6 $22.9 $24.4 $25.6 $23.4
GREENIDGE 4 $25.2 $26.4 $27.9 $28.7 $27.1 $22.9 $24.2 $26.0 $23.7
GOUDEY 7 $25.3 $26.2 $27.7 $28.6 $27.2 $22.8 $24.4 $26.0 $23.6
GOUDEY 8 $25.0 $26.8 $27.5 $28.6 $27.2 $22.9 $24.4 $25.9 $23.7
- -------------------------- ------------------------------------------------- ------- ------- ------- ------
AVERAGE SMP FOR PORTFOLIO $25.2 $26.4 $27.6 $28.5 $27.3 $22.9 $24.4 $25.9 $23.7
========================== ================================================= ======= ======= ======= ======
(1) 1999 figures reflect 10 months of operation
- --------------------------------------------------------------------------------
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- --------------------------------------------------------------------------------
TABLE 9. UNIT-SPECIFIC PERFORMANCE - BASE CASE
AVERAGE ANNUAL LOAD FACTOR
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
---------------------------------------------- -------- -------- -------- -------
MILLIKEN 1 96% 94% 92% 94% 94% 92% 92% 92% 92%
MILLIKEN 2 96% 94% 94% 92% 94% 92% 92% 92% 92%
KINTIGH 1 86% 94% 94% 94% 94% 92% 92% 92% 92%
GREENIDGE 3 88% 92% 90% 90% 92% 92% 92% 92% 92%
GREENIDGE 4 90% 92% 92% 92% 92% 92% 92% 92% 92%
GOUDEY 7 88% 86% 92% 90% 90% 90% 90% 90% 92%
GOUDEY 8 90% 88% 92% 92% 92% 92% 92% 92% 92%
- ------------------------------- ---------------------------------------------- -------- -------- -------- -------
AVERAGE PORTFOLIO LOAD FACTOR 91% 92% 92% 92% 93% 92% 92% 92% 92%
=============================== ============================================== ======== ======== ======== =======
(1) 1999 figures reflect 10 months of operation
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
TABLE 10. UNIT-SPECIFIC CALCULATED ENERGY REVENUE FORECASTS - BASE CASE
DERIVED GROSS ENERGY REVENUE (1999 $ MILLIONS)
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
CAPACITY(2) ------------------------------------------------------- ------- ------- --------- ------
MILLIKEN 1 150 $26.7 $32.7 $33.1 $35.4 $33.7 $27.8 $29.7 $31.5 $28.8
MILLIKEN 2 156 $27.8 $33.9 $35.3 $36.2 $35.3 $28.9 $30.5 $32.7 $30.0
KINTIGH 1 675 $107.6 $146.1 $153.2 $156.8 $152.6 $124.9 $132.9 $140.4 $129.5
GREENIDGE 3 54 $8.9 $11.4 $11.9 $12.1 $12.0 $10.0 $10.7 $11.2 $10.2
GREENIDGE 4 105 $17.6 $22.4 $23.6 $24.2 $23.0 $19.4 $20.6 $22.1 $20.2
GOUDEY 7 43 $7.0 $8.5 $9.6 $9.7 $9.3 $7.7 $8.3 $8.8 $8.2
GOUDEY 8 83 $13.8 $17.2 $18.4 $19.2 $18.2 $15.4 $16.4 $17.4 $15.9
- ------------------------ ------------------------------------------------------- ------- ------- --------- ------
PORTFOLIO ENERGY REVENUE $209 $272 $285 $294 $284 $234 $249 $264 $243
======================== ======================================================= ======= ======= ========= ======
(1) 1999 figures reflect 10 months of operation
(2) Utilizing capacity figures reported for summer demonstrated capacity in
NYPP's Load & Capacity Data 1998.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
TABLE 11. TOTAL REVENUE BY UNIT - BASE CASE
FORECASTED CAPACITY AND ENERGY REVENUES
(1999 $ MILLIONS)
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
CAPACITY(2) ----------------------------------------------------- ------ ------ ------ ---------
MILLIKEN 1 150 $31 $37 $39 $41 $41 $36 $38 $39 $38
MILLIKEN 2 156 $32 $39 $41 $43 $43 $38 $39 $41 $39
KINTIGH 1 675 $126 $166 $178 $184 $184 $163 $169 $175 $169
GREENIDGE 3 54 $10 $13 $14 $14 $15 $13 $14 $14 $13
GREENIDGE 4 105 $20 $26 $28 $29 $28 $25 $26 $27 $26
GOUDEY 7 43 $8 $10 $11 $11 $11 $10 $11 $11 $11
GOUDEY 8 83 $16 $20 $21 $23 $22 $20 $21 $22 $21
- ----------------------- ----------------------------------------------------- ------ ------ ------ --------
PORTFOLIO TOTAL REVENUE $244 $310 $332 $345 $343 $306 $316 $329 $317
======================= ===================================================== ====== ====== ====== ========
(1) 1999 figures reflect 10 months of operation
(2) Utilizing capacity figures reported for summer demonstrated capacity in
NYPP's Load & Capacity Data 1998.
- --------------------------------------------------------------------------------
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5.2 DOWNSIDE CASE MODELING RESULTS
In the downside case, changes were made to the system generation profile and to
the fuel prices. Natural gas and fuel oil prices under the downside case are
based on a 10% decrease in all fuel prices as compared to RDI's base case
forecasts for gas and oil-based products. These assumptions are further detailed
in Section 9 (Appendix A).
5.3.1 DOWNSIDE CASE ENERGY PRICES
In the downside case, the average annual differential between regional prices is
$2.8/MWh over the modeling time horizon; however, the differential widens from
$1.6/MWh in 1999 to $7.3/MWh in 2020. Both Downstate and Upstate average prices
grow at approximately 4% from 1999 to 2002. As in the base case, both regions
witness a decline in prices as the system attempts to resolve its supply-demand
balance in the years of market transition, 2003 - 2005, as seen in Figure 20.
Post 2005, energy prices recover and grow at an annual average real rate of 1%
through 2015 (with the exception of the Upstate energy prices in the late
years). Forecast monthly time-weighted prices through 2020 under the downside
case are summarized in Appendix C2.
- --------------------------------------------------------------------------------
FIGURE 20. REGIONAL TIME-WEIGHTED AVERAGE ENERGY PRICES FOR THE DOWNSIDE
CASE, 1999 $/MWH
[LINE GRAPH]
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- --------------------------------------------------------------------------------
TABLE 12. TIME-WEIGHTED AVERAGE ENERGY PRICES FOR THE DOWNSIDE CASE, 1999 $/MWH
UP DN
1999 $23.3 $24.9
2000 $24.4 $25.7
2001 $25.4 $27.1
2002 $26.4 $28.1
2003 $25.0 $26.0
2004 $22.9 $24.3
2005 $21.0 $22.7
2006 $21.2 $23.0
2007 $21.4 $23.4
2008 $21.7 $23.7
2009 $21.9 $24.1
2010 $22.1 $24.4
2011 $22.3 $24.7
2012 $22.5 $25.0
2013 $22.8 $25.3
2014 $23.0 $25.6
2015 $23.2 $25.9
2016 $23.0 $26.5
2017 $22.7 $27.2
2018 $22.5 $27.9
2019 $22.2 $28.6
2020 $22.0 $29.3
2021* $22.0 $29.3
2022* $22.0 $29.3
2023* $22.0 $29.3
2024* $22.0 $29.3
2025* $22.0 $29.3
2026* $22.0 $29.3
2027* $22.0 $29.3
2028* $22.0 $29.3
2029* $22.0 $29.3
2030* $22.0 $29.3
2031* $22.0 $29.3
2032* $22.0 $29.3
2033* $22.0 $29.3
2034* $22.0 $29.3
2035* $22.0 $29.3
* Energy prices and capacity prices from 2021 through
2035 have not been modeled. We have assumed
zero growth in real prices after 2020.
- -------------------------------------------------------------------------------
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- --------------------------------------------------------------------------------
FIGURE 21. FORECASTED MARGINAL PRICE DURATION CURVES UNDER THE
DOWNSIDE CASE
[LINE GRAPH]
[LINE GRAPH]
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A seasonal price pattern emerges in the downside case, as it did in the base
scenario. For 2000, the peaking prices occur in the summer for the Downstate
region and during the winter for the Upstate region. One note of interest is the
increase in magnitude of both regions' winter peaks between 2000 and 2002 (see
Figure 22). The underlying reason for this change is due in part to the heating
load and to the implicit fuel costs associated with marginal gas and oil-fired
generators.
- --------------------------------------------------------------------------------
FIGURE 22. FORECASTED REGIONAL MONTHLY ENERGY PRICES-
DOWNSIDE CASE
[LINE GRAPH]
- --------------------------------------------------------------------------------
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- --------------------------------------------------------------------------------
TABLE 13. ANNUAL TIME-WEIGHTED AVERAGE PEAK AND OFF-PEAK ENERGY PRICES -
DOWNSIDE CASE
UPSTATE NEW YORK (1999 $/MWh)
1999 (1) 2000 2001 2002 2003
--------------------------------------------------
ON-PEAK 26.3 26.9 28.9 30.2 28.8
OFF-PEAK 19.5 20.2 21.3 21.7 20.3
DOWNSTATE NEW YORK (1999 $/MWh)
1999 (1) 2000 2001 2002 2003
--------------------------------------------------
ON-PEAK 28.7 28.8 31.4 32.7 30.4
OFF-PEAK 19.7 20.5 21.6 22.0 20.4
----------------
(1) 1999 prices reflect February - December 1999 forecasts only
- --------------------------------------------------------------------------------
5.2.2 AEE PORTFOLIO IN THE DOWNSIDE CASE
In the downside case, the relative decrease in regional average prices causes a
decrease in revenue for the overall AEE portfolio. For all plants, there is also
a reduced level of operation as compared to the base case, due to the
conservative availability figures assumed (92% versus 96% under base case).
- --------------------------------------------------------------------------------
TABLE 14. UNIT-SPECIFIC ENERGY PRICE FORECASTS - DOWNSIDE CASE
AVERAGE SMP WHEN RUN (1999 $/MWh)
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
-------------------------------------------- ------------ ----------- ----------- ------------ ---------
MILLIKEN 1 $23.4 $24.7 $25.9 $26.6 $25.2 $21.1 $22.2 $23.3 $22.1
MILLIKEN 2 $23.4 $24.6 $25.7 $26.6 $25.2 $21.0 $22.4 $23.3 $22.1
KINTIGH 1 $23.3 $24.5 $25.4 $26.3 $24.9 $21.0 $22.2 $23.3 $21.9
GREENIDGE 3 $23.6 $24.5 $25.7 $26.7 $24.9 $21.1 $22.0 $23.5 $22.1
GREENIDGE 4 $23.5 $24.5 $25.5 $26.6 $25.1 $21.1 $22.4 $23.4 $22.0
GOUDEY 7 $23.5 $24.8 $25.7 $26.8 $25.1 $21.3 $22.3 $23.4 $22.2
GOUDEY 8 $23.5 $24.6 $25.3 $26.6 $25.0 $21.1 $22.4 $23.4 $22.1
- -------------------------- -------------------------------------------------------- ------------ ----------- ----------- ---------
AVERAGE SMP FOR PORTFOLIO $23.5 $24.6 $25.6 $26.6 $25.1 $21.1 $22.3 $23.4 $22.1
========================== ======================================================== ============= ========= =========== ==========
(1) 1999 figures reflect 10 months of operation
- --------------------------------------------------------------------------------
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- --------------------------------------------------------------------------------
TABLE 15. UNIT-SPECIFIC PERFORMANCE - DOWNSIDE CASE
AVERAGE ANNUAL LOAD FACTOR
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
--------------------------------------- ---------- ----------- ----------- ----------- --------
MILLIKEN 1 90% 92% 92% 92% 92% 92% 92% 92% 92%
MILLIKEN 2 90% 92% 92% 92% 92% 92% 92% 92% 92%
KINTIGH 1 86% 92% 92% 92% 92% 92% 92% 92% 92%
GREENIDGE 3 87% 92% 90% 90% 92% 92% 92% 92% 92%
GREENIDGE 4 90% 92% 92% 92% 92% 92% 92% 92% 92%
GOUDEY 7 87% 85% 91% 90% 90% 89% 90% 90% 90%
GOUDEY 8 89% 87% 91% 92% 92% 91% 92% 92% 92%
- ------------------------------ --------------------------------------- ---------- ----------- ----------- ----------- ----------
AVERAGE PORTFOLIO LOAD FACTOR 88% 90% 91% 91% 92% 92% 92% 92% 92%
============================== ======================================= ========== =========== =========== =========== ==========
(1) 1999 figures reflect 10 months of operation
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
TABLE 16. UNIT-SPECIFIC CALCULATED ENERGY REVENUE FORECASTS - DOWNSIDE CASE
DERIVED GROSS ENERGY REVENUE (1999 $ MILLIONS)
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
----------------------------------------------------- -------- ------- ------- -------
CAPACITY(2)
MILLIKEN 1 150 $23.3 $29.9 $31.3 $32.3 $30.5 $25.6 $26.9 $28.3 $26.8
MILLIKEN 2 156 $24.2 $31.0 $32.3 $33.5 $31.7 $26.4 $28.3 $29.4 $27.7
KINTIGH 1 675 $99.1 $133.6 $138.2 $143.1 $135.7 $114.4 $121.1 $127.0 $119.4
GREENIDGE 3 54 $8.2 $10.6 $10.9 $11.4 $10.8 $9.1 $9.6 $10.2 $9.6
GREENIDGE 4 105 $16.3 $20.6 $21.6 $22.5 $21.3 $17.8 $19.0 $19.9 $18.7
GOUDEY 7 43 $6.5 $8.0 $8.8 $9.0 $8.5 $7.1 $7.6 $8.0 $7.6
GOUDEY 8 83 $12.8 $15.6 $16.9 $17.7 $16.7 $14.0 $15.0 $15.7 $14.9
- ------------------------ ----------------------------------------------------- -------- ------- ------- --------
PORTFOLIO ENERGY REVENUE $190 $249 $260 $269 $255 $215 $228 $239 $225
======================== ===================================================== ======== ======= ======= ========
(1) 1999 figures reflect 10 months of operation
(2) Utilizing capacity figures reported for summer demonstrated capacity in
NYPP's Load & Capacity Data 1998.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
TABLE 17. TOTAL REVENUE BY UNIT - DOWNSIDE CASE
FORECASTED CAPACITY AND ENERGY REVENUES
(1999 $ MILLIONS)
1999(1) 2000 2001 2002 2003 2005 2010 2015 2020
------------------------------------------------- ------- -------- -------- -------
CAPACITY(2)
MILLIKEN 1 150 $27 $34 $36 $38 $36 $33 $34 $35 $35
MILLIKEN 2 156 $28 $35 $37 $39 $38 $34 $36 $36 $36
KINTIGH 1 675 $116 $151 $159 $167 $162 $149 $154 $156 $154
GREENIDGE 3 54 $10 $12 $13 $13 $13 $12 $12 $13 $12
GREENIDGE 4 105 $19 $23 $25 $26 $25 $23 $24 $24 $24
GOUDEY 7 43 $8 $9 $10 $11 $10 $9 $10 $10 $10
GOUDEY 8 83 $15 $18 $19 $21 $20 $18 $19 $19 $19
- ------------------------ --------------------------------------- --------- ------- -------- -------- --------
PORTFOLIO TOTAL REVENUE $222 $282 $299 $315 $305 $279 $290 $293 $290
======================== ================================================= ======= ======== ======== ========
(1) 1999 figures reflect 10 months of operation
(2) Utilizing capacity figures reported for summer demonstrated capacity in
NYPP's Load & Capacity Data 1998.
- --------------------------------------------------------------------------------
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APPENDIX B
6 NEW ENTRY PRICES
New entry prices provide a benchmark for overall capacity and energy market
prices over the longer-term. The dispatch and capacity modeling analysis has
implicitly incorporated new entrant pricing by comparing the forecast price
levels with the revenue requirements of a new generator to enter the market. A
market scenario over the longer-term must be consistent with the prices required
to trigger new entry (generally at high load factors for new CCGTs) and those
necessary to keep existing generating assets available to meet installed
capacity requirements (at low load factors). In this section, we provide an
overview of our new entry pricing analysis and compare the results with our
modeling results as a check on their robustness.
6.1 ANALYSIS OVERVIEW
In developing long-term forecasts, we base the going forward price on expected
new entrant prices, which are a function of fuel prices and technological costs.
CCGTs are likely to remain the preferred expansion candidate for some time in
New York. New plant will enter the system only if the long-term post entry price
provides a sufficient return on capital.
Stone & Webster have provided specific New York projections on capital cost and
plant performance and cost parameters, as summarized in Table 18.9 Real capital
costs and operating costs are not expected to change over time. In addition,
thermal efficiency gains are projected by Stone & Webster. Financial parameters
(leverage, financial lifetime, and interest rate) were based on commonly
accepted standards in the industry. The average annual natural gas price
forecast for New York (based on RDI's planning area forecasts from BaseCase) was
used as the fuel cost parameter.
6.2 LONG-TERM PRICES UNDER THE BASE CASE
Using the fundamental assumptions in Table 18, we believe REAL long-term prices
will reflect the new entry-level prices of approximately $33/MWh in New York
over time. In the longer term, it is important to realize that thermal
efficiencies will increase, resulting in downward pressure on new entry trigger
levels. However, this downward pressure will be offset by rising natural gas
prices over time.
- --------------------
9 It is important to realize the potential for probable capital cost
differentials for new build in Upstate versus Downstate New York. Capital
costs will tend to be higher in Downstate, due to land costs, environmental
compliance issues, property taxes, transmission rights and other siting
parameters. However, we have not explicitly modeled this differential.
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TABLE 18. ASSUMPTIONS FOR CCGT NEW ENTRY PRICE CALCULATION UNDER THE BASE CASE
2005-2009 Post-2009
--------- ---------
POST-TAX ROE 15% 15%
INTEREST RATE 8.0% 8.0%
CAPITAL COST, 1999 $/KW $550 $550
CORPORATE TAX RATE 35% 35%
PROJECT FINANCE LIFE (YEARS) 25 25
LEVERAGE 60% 60%
HEAT RATE (Btu/kWh) 6,800 6,300
FIXED COSTS ($/kW/YEAR) $25 $25
VARIABLE NON-FUEL COSTS ($/MWh) $1.5 $1.5
LOAD FACTOR 90% 90%
Table 19 highlights the sensitivity of new entry trigger prices to capital cost,
fuel cost, and thermal efficiency. The first matrix in the table illustrates the
medium-term dynamics, with thermal efficiency relative to current statistics
(6,800 Btu/kWh heat rate). Gas prices for 2005 are projected to be approximately
$2.8/MMBtu under the base case. This results in a trigger price level of
$32.8/MWh. Even though capital costs remain constant in real terms, heat rates
should fall to approximately 6,300 Btu/kWh by 2010, with natural gas prices
forecasted to be $3.0/MMBtu. The resulting trigger price is $32.7/MWh.
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- --------------------------------------------------------------------------------
TABLE 19. NEW CCGT TRIGGER PRICES IN NEW YORK UNDER THE BASE CASE, 1999 $/MWH
NATURAL GAS PRICE CAPITAL COST (1999 $/kW)
(1999 $/MMBtu) $450 $475 $500 $525 $550 $575 $600 $625 $650
-----------------------------------------------------------------------------------------------
$2.40 $28.4 $28.9 $29.3 $29.7 $30.1 $30.5 $30.9 $31.3 $31.8
$2.50 $29.1 $29.5 $30.0 $30.4 $30.8 $31.2 $31.6 $32.0 $32.4
$2.60 $29.8 $30.2 $30.6 $31.0 $31.5 $31.9 $32.3 $32.7 $33.1
$2.70 $30.5 $30.9 $31.3 $31.7 $32.1 $32.6 $33.0 $33.4 $33.8
$2.80 $31.2 $31.6 $32.0 $32.4 $32.8 $33.2 $33.7 $34.1 $34.5
$2.90 $31.8 $32.3 $32.7 $33.1 $33.5 $33.9 $34.3 $34.7 $35.2
$3.00 $32.5 $32.9 $33.4 $33.8 $34.2 $34.6 $35.0 $35.4 $35.8
* Assuming Heat Rate is 6,800 Btu/kWh
- -------------------------------------------------------------------------------
NATURAL GAS PRICE CAPITAL COST (1999 $/kW)
(1999 $/MMBtu) $450 $475 $500 $525 $550 $575 $600 $625 $650
-----------------------------------------------------------------------------------------------
$2.40 $27.2 $27.7 $28.1 $28.5 $28.9 $29.3 $29.7 $30.1 $30.6
$2.50 $27.9 $28.3 $28.7 $29.1 $29.5 $29.9 $30.4 $30.8 $31.2
$2.60 $28.5 $28.9 $29.3 $29.7 $30.2 $30.6 $31.0 $31.4 $31.8
$2.70 $29.1 $29.6 $30.0 $30.4 $30.8 $31.2 $31.6 $32.0 $32.4
$2.80 $29.8 $30.2 $30.6 $31.0 $31.4 $31.8 $32.3 $32.7 $33.1
$2.90 $30.4 $30.8 $31.2 $31.6 $32.1 $32.5 $32.9 $33.3 $33.7
$3.00 $31.0 $31.4 $31.9 $32.3 $32.7 $33.1 $33.5 $33.9 $34.3
* Assuming Heat Rate is 6,300 Btu/kWh
- --------------------------------------------------------------------------------
6.3 LONG-TERM PRICES UNDER THE DOWNSIDE CASE
Decline in the natural gas prices drive the changes in the market under the
downside case. We assume other parameters decline as well. Table 20 summarizes
the major assumptions for CCGT trigger price calculations under this scenario.
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TABLE 20. ASSUMPTIONS FOR CCGT NEW ENTRY PRICE CALCULATION UNDER THE DOWNSIDE
CASE
2005-2009 POST-2009
----------- -----------
POST-TAX ROE 15% 15%
INTEREST RATE 8.0% 8.0%
CAPITAL COST, 1999 $/KW $525 $525
CORPORATE TAX RATE 35% 35%
PROJECT FINANCE LIFE (YEARS) 25 25
LEVERAGE 60% 60%
HEAT RATE (BTU/KWH) 6,800 6,300
FIXED COSTS ($/KW/YEAR) $15 $15
VARIABLE NON-FUEL COSTS ($/MWH) $1.3 $1.3
LOAD FACTOR 90% 90%
The new entry trigger prices decrease by approximately 12% in the downside case
as compared to the trigger prices under the base case, which is more than the
decrease inherent in the natural gas forecast between the two cases. The
decrease in new entry trigger prices also stems from our operations &
maintenance and capital cost assumptions. For example, the new entry trigger
price is $29.2/MWh in 2006 (assuming gas price of $2.55/MMBtu and a heat rate of
6,800 Btu/kWh) and $28.9/MWh in 2009 (assuming a gas price of $2.69/MMBtu and a
heat rate of 6,300 Btu/kWh). Other combinations are summarized in Table 21.
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TABLE 21. NEW CCGT TRIGGER PRICES IN NEW YORK UNDER THE DOWNSIDE CASE, 1999
$/MWH
CAPITAL COST (1999 $/KW)
$450 $475 $500 $525 $550 $575 $600 $625 $650
------------------------------------------------------------------------------------------------------
$2.00 $24.3 $24.7 $25.1 $25.5 $25.9 $26.3 $26.7 $27.2 $27.6
$2.20 $25.6 $26.0 $26.4 $26.9 $27.3 $27.7 $28.1 $28.5 $28.9
NATURAL GAS PRICE $2.40 $27.0 $27.4 $27.8 $28.2 $28.6 $29.0 $29.5 $29.9 $30.3
(1999 $/MMBTU) $2.60 $28.3 $28.8 $29.2 $29.6 $30.0 $30.4 $30.8 $31.2 $31.7
$2.80 $29.7 $30.1 $30.5 $30.9 $31.4 $31.8 $32.2 $32.6 $33.0
$3.00 $31.1 $31.5 $31.9 $32.3 $32.7 $33.1 $33.5 $34.0 $34.4
$3.20 $32.4 $32.8 $33.2 $33.7 $34.1 $34.5 $34.9 $35.3 $35.7
(*) Assuming Heat Rate is 6,800 Btu/kWh
- --------------------------------------------------------------------------------
CAPITAL COST (1999 $/KW)
$450 $475 $500 $525 $550 $575 $600 $625 $650
------------------------------------------------------------------------------------------------------
$2.00 $23.3 $23.7 $24.1 $24.5 $24.9 $25.3 $25.7 $26.2 $26.6
$2.20 $24.5 $24.9 $25.3 $25.8 $26.2 $26.6 $27.0 $27.4 $27.8
NATURAL GAS PRICE $2.40 $25.8 $26.2 $26.6 $27.0 $27.4 $27.8 $28.3 $28.7 $29.1
(1999 $/MMBTU) $2.60 $27.0 $27.5 $27.9 $28.3 $28.7 $29.1 $29.5 $29.9 $30.4
$2.80 $28.3 $28.7 $29.1 $29.5 $30.0 $30.4 $30.8 $31.2 $31.6
$3.00 $29.6 $30.0 $30.4 $30.8 $31.2 $31.6 $32.0 $32.5 $32.9
$3.20 $30.8 $31.2 $31.6 $32.1 $32.5 $32.9 $33.3 $33.7 $34.1
(*) Assuming Heat Rate is 6,300 Btu/kWh
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APPENDIX B
7 OVERVIEW OF OPPORTUNITIES OUTSIDE THE NY MARKET
To the south, New York borders the evolving PJM (Pennsylvania-New
Jersey-Maryland) power market. PJM has east-west transmission constraints,
resulting in limited price differentials, especially at peak when oil-fired New
Jersey units are marginal. Coal units in Pennsylvania are marginal at off-peak
periods, typically at low $12-15/MWh prices. Peak prices in PJM over the last
year have been driven off netback prices from ECAR (East Central Area
Reliability Coordinating Council in the Midwest) and the remainder of the
Midwest. This is not typical of historical Midwest-PJM pricing patterns and
power flows.
Recent Midwest prices illustrate effects of a market structure in transition:
- A high level of competition in a fragmented generation market
with similar coal-fired technologies. This tends to produce low
and stable prices for most hours in the year, as the supply
curve at typical levels of demand is very flat. This produces
an "L-shaped" price duration curve with value concentrated in a
small number of hours.
- Very low prices continue until the system is deficit in
capacity, at which time long generators can extract massive
rents as utilities are anxious to cover peak native demands. It
has been hypothesized that vertically-integrated utilities
withheld capacity from the wholesale market during the summer
of 1998 due to their uncertainty over their ability to serve
native load. This contributed to the capacity deficit and
soaring peak prices, as illustrated in Figure 23.
Regulatory and market uncertainty continues to restrain major new entry over the
short term in the Midwest, creating potential for repetition of last summer's
price spikes next summer. There may be potential for generators in Upstate New
York to capture windfalls from exports to the Midwest during summer stress
periods in the short term. This situation is not expected to continue
indefinitely. New York and Midwest prices have only been partially correlated
historically. This is due to the transmission constraints between ECAR and
western PJM. Power flows are generally west to east across this interface,
reflecting the lower fuel costs in the Midwest as compared to PJM.
New England's current circumstance can be summarized by its tight capacity
market. High cost marginal plant at present gives substantial margin for CCGTs
in New England. However this will not continue in the long term, as new entry
will flatten the price duration curve over time, reducing the price margin for
export power from New York. Currently there is over 25 GW of announced new entry
in New England, although much of this is not credible given the projected impact
on New England prices. The potential overbuild of CCGT new entry in New England
may undermine the ISO NE capacity market for substantial periods. We expect new
entry in the region to be limited to 9 GW by gas availability and the ability to
close financing.
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The ability to access higher New England prices and capacity payments is limited
by the transmission constraints from the New York system into New England, and
ISO NE's different rules for its capacity markets. These constraints have
prevented substantial arbitrage between New York and New England prices, as
shown in the statistical correlation analysis presented in Appendix D.
[FIGURE 23. HISTORICAL WEEKLY PRICE INDICES FOR NEW YORK AND SURROUNDING
REGIONS(10) LINE GRAPH]
Neighboring states with slower reform process and long position against native
load may offer threat to cost recovery, as generators in these states can
recover their fixed costs from ratebase, rather than from the market. This may
be relevant when considering New York's proximity to the Midwest, where some
states have not advanced far in restructuring (Kentucky, West Virginia,
Indiana).(11) However, after
- --------------------
(10) Price Index Database. Power Markets Week.
(11) Our modeling analysis does not include above cost energy bidding by New
York generators. Therefore competition from outside the state would
not be expected to put any further downward pressure on NY prices, over
the conservative assumptions used in the analysis.
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deregulation, there will be a substantial expansion of marketing (to
retail) opportunities for generators located in the East. The total retail
load in New England, New York, PJM, and the Midwest currently represents
over 1000 GWh per annum (historically over 30% of the entire U.S. market).
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8 CONCLUSIONS: IMPLICATIONS FOR THE FUTURE
The expected development of the New York power market will be driven by a range
of factors: economic, regulatory and technological. For the short to medium-term
market dynamics will be dominated by the initial conditions at the start of
competition:
- - HIGH DOWNSTATE PRICES DUE TO LACK OF INVESTMENT IN NEW GENERATION
TECHNOLOGIES: The urban utilities downstate, especially Consolidated
Edison and the former Long Island Lighting Company, were slow to invest in
new technologies and to replace old generating units. While this helped
keep down rates for a while (as their older units were already partially
depreciated in the ratebase) downstate New York is now stuck with high
operating costs, low thermal efficiencies and a preponderance of higher
cost oil and gas-fired units. The implementation of competition will both
allow new entry and remove some regulatory uncertainty. We have therefore
predicted that substantial new entry and re-powering will occur downstate
as long as high cost units can be displaced.
- - A SHIFT BETWEEN ENERGY AND CAPACITY PRICES TO SIGNAL NEW ENTRY: Energy
prices generally reflect the variable cost-basis of the most expensive
unit dispatched. In the early years, new entrant CCGTs can cover much of
their capital costs in addition to their variable costs from their energy
market profits because energy prices are reflecting the higher cost basis
of the downstate units. As more of these CCGT units enter the market,
marginal prices (energy prices at a particular hour) will decline,
especially at higher levels of demand. This will tend to shift value into
a limited number of peak hours and into the capacity market. This effect
is reflected in the results of London Economics' modeling analysis.
- - UPSTATE PRICES WILL REMAIN LOWER DUE TO TRANSMISSION CONSTRAINTS: the
transmission constraints which block the free flow of power from lower
cost upstate units to downstate will not be removed quickly. For this
reason, prices in the upstate region remain lower than downstate prices
over time in our forecasts, generally below new entry trigger levels.
- - PRICES IN GENERAL MUST RISE FROM THOSE REPORTED IN THE CURRENT WHOLESALE
SPOT MARKET: the existing wholesale power markets in the United States are
heavily distorted by the presence of large numbers of
vertically-integrated ratebase utilities. These utilities are able to
recover the majority of their fixed and capital costs from their captive
customers under ratebase, and will often sell power at little over
variable cost. Experience in other markets (in foreign markets and
California, for example) has shown that prices must eventually rise over
time for generators to recover full costs from the market, once the
distorting effects of ratebase and transitional contracts are removed.
Figure 24 shows recent upstate wholesale prices and our forecast prices
out to October 2003. Note that our price rise trends are below the
short-term price trend in reported prices.
- - ENVIRONMENTAL RESTRICTIONS WILL PRODUCE SUBSTANTIAL UPWARD PRESSURE ON
PRICES: AEE's Kintigh and Milliken plants are currently the only scrubbed
coal-fired plants in New York state. Other coal-fired units in New York
will have to add
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APPENDIX B
emissions controls or switch to low sulfur compliance coals in order to
meet federal environmental restrictions. This will add to their fixed or
variable costs or both. Since the capital expenditure required to meet
even existing environmental laws is high, we expect that many older units
will instead be closed.
[FIGURE 24. UPSTATE NEW YORK: PAST AND FUTURE ENERGY PRICES LINE GRAPH]
* Power Markets Week's Price Index Database was used as a source of
historical prices. 1998 Western NY Prices were inflated by 3% in order to
represent them in 1999 $ terms.
8.1 COMPETITIVE POSITION OF THE AEE PORTFOLIO
We believe that the AEE assets are likely to maintain a competitive advantage
over the most likely form of new generating plants, CCGTs, during the study
period. The intrinsic value of the coal-fired assets lies in their competitive
cost structure, which will remain economic in comparison to other known
generation technologies. Based on RDI's and John T. Boyd's fuel forecasts, Stone
& Webster's thermal efficiency appraisal, and projected variable operations &
maintenance costs, it is projected that the the cost efficiency of these plants
relative to their peers (other coal-fired generation) in the New York Power
Market is projected to remain high going forward.
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We do not find a scenario credible at this time that involves the construction
of substantial new nuclear, run-of-river hydro or coal generation in New York.
It is unlikely that new gas or oil-fired generation will be able to compete with
the AEE units on a variable cost basis (at forecast gas and oil prices). This
will limit the risk that the AEE assets will be displaced in the energy dispatch
order by new generating plants.
Beyond the competitive position of the AEE assets in the New York merit order,
there are other factors of interest in terms of future performance:
- - Revenue stability is another advantage accruing to the asset portfolio,
due to its projected high capacity factors. This, combined with relatively
stable coal purchase costs, provides realtively stable operating margins
for AEE, which may become increasingly valuable as the market develops and
prices become more volatile and unpredictable. The profitability of the
coal plants will tend to be positively correlated with gas and oil prices
in the future. This could provide a hedge against gas and oil price
fluctuations and could have a positive value in the electricity contract
market.
- - The AEE assets are also positioned well to take advantage of potential
market developments in and outside New York. The western New York market
has traditionally been low cost in comparison to most neighboring markets.
This may allow for additional export earnings over time.
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APPENDICES
9 APPENDIX A: DATA SOURCES AND ASSUMPTIONS FOR MARKET MODELING
9.1 ENERGY MODEL OVERVIEW
London Economics has used its proprietary power markets model PoolMod to model
pricing outcomes in the New York energy market based on the relevant input
assumptions from the market scenario, as illustrated in Table 2. Full details on
the price and demand growth tracks and other inputs to the model are given in
Appendix A. Capacity pricing in New York, and the methodology used to forecast
capacity prices, are described in Section 4.
The LE model utilizes detailed information on thermal and hydro resources, fuel
prices, and hourly demand data. PoolMod simulates hourly commitment and dispatch
of available resources in an economically efficient manner for each region
studied. This process begins by determining the amount and flexibility of hydro
resources, and scheduling these for the hours of peak demand, to the extent
possible. Any residual demand is met by thermal generators, in strict merit
order subject to plant dynamic constraints and regional transmission
constraints. The regional hourly price is set by the most expensive local
generator operating in the hour.
One important feature of PoolMod is its ability to simulate hydro generation
within a system, through the use of shadow pricing and seasonal availability. If
a unit is available, based on its seasonal daily energy release schedule, then
it will be considered within the merit order as an energy-constrained unit. The
initial price used to commit hydro is always zero (reflective of zero fuel
costs). As soon as part of a unit is committed, its shadow price is calculated.
That price is then used for the commitment price from then on. The shadow price
is calculated by finding the price of the next available thermal unit above it
in the merit order and taking the price of that unit. Essentially the model
calculates "if the energy constrained unit was not available, what would have to
be used to replace it." If a hydro unit does not run in any given day, or at
least does not use its full energy availability, any energy left unused may be
stored in the reservoir, up to the limit of the reservoir size specified in the
station database. The maximum energy that a unit can have available during any
one day is thus its seasonal daily availability plus the maximum reservoir
capacity.
9.2 ELECTRIC TRANSMISSION WITHIN NEW YORK
In New York, there have been documented transmission constraints going West to
East, especially with transmission into the Long Island and New York City area.
In the past, these transmission constraints have resulted in pricing
differentials. These differentials are evident in a weighted-average of power
marketers' week-ahead contracts for "Eastern New York" and "Western New York",
as exhibited in Figure 25. It is important to note that transmission constraints
appear to be binding on average,
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though there are certain off-peak hours during which there is no congestion. We
foresee that transmission constraints will not be ameliorated in the short and
medium term, as there are no significant transmission augmentation plans.
Furthermore, approval and construction lag time for any new projects arising in
the next few years will result in at least a five-year time horizon prior to
operation. More importantly, it will be difficult to get rights-of-way in the
constrained areas of metropolitan New York.
[FIGURE 25. AVERAGE DAILY PRICES FOR EASTERN AND WESTERN NEW YORK(12) LINE
GRAPH]
New York is served by a 345-kV back-bone and some long-distance 230-kV
transmission lines. A 765-kV transmission line parallels a double-circuit 230-kV
line north from Quebec. Some of the other 345-kV lines were originally built for
765-kV rating but have been operated at the 345-kV level. Transmission data was
obtained
- --------------------------
(12) Power Markets Week's daily off-peak and peak prices from the Price
Index Database were used to derive a daily average index based on the
standard peak vs. off-peak breakdown (16 hours vs. 8 hours). Power
Markets Week started publishing daily regional peak and off-peak prices
for New York in February 1998.
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from the Annual Transmission Planning & Evaluation Report (FERC Form 715)
published by the NYPP in April 1998.
Figure 26 illustrates the New York interfaces and pricing zones. In addition,
this map details the interface thermal limits, as established by the New York
Power Pool in the Summer 1997 Operating Study, assuming base case system power
flows under emergency conditions. It is important to note that the interfaces
are not actual transmission lines, but mathematical cuts across the transmission
system that are utilized by the New York Power Pool (and future NY ISO) to
monitor facility loading. Historically, the greatest amount of congestion in
Western New York has occurred along the Central-East transmission interface
transfer, with a thermal transfer limit set at 2,850 MW under normal conditions,
a portion of the Total East interface. Market intelligence indicates that flows
along this transfer were within 5% of the limit for a majority of the hours.
[FIGURE 26. NEW YORK INTERFACES AND TRANSMISSION PRICING ZONES GRAPHIC]
In order to capture the West-East transmission constraint, the modeling divides
the load and generation profile of New York into a "Downstate NY" region and a
"Upstate NY" region. We defined the regions based on market area and
transmission capability, pricing relevance, and modeling feasibility. The
binding transmission constraint between these two regions is based on the most
relevant pricing interface in New York,
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the Southeast NYPP interface capability of 4950 MW, with the loss of the
Leeds-Pleasant Valley 345 kV line as a limiting contingency.(13) This is
effectively a parallel constraint to the Central East interface; however there
is very limited non-baseload generation between Central East and the Southeast
NYPP constraint. The use of this interface has the additional advantage of
avoiding load data distortion.(14) This analysis provides a similar
presentation to the information provided by NYSEG in reference to the Central
East constraint. Modeling indicates that power flows are on average over 80% of
the defined transmission thermal interface size at any hour of the day. Defined
transmission constraints are binding over 30% of the time; therefore, isolating
Downstate New York load from Upstate New York generation.(15) Transmission
flows are typically within 20% of the transfer limit over 60% of the time
during the year. For example, Figure 27, shows that average half-hourly flows
between Downstate and Upstate New York during the year 2000, as well as the
maximum half-hourly flows (in any day) in that year.
- -------------------------------
(13) Source: NYPP's Load & Capacity Data 1998 manual, Total East Transmission
Study Progress Report - Base Case Limits (February 1996).
(14) If any other transmission interface was chosen, there would a large
distortionary effect in matching hourly load and generation, as hourly
load is compiled on a utility control area basis. Both NYSEG and NIMO
have extensive non-contiguous loads. For example, a NYSEG load center is
located within NIMO's service territory in the Northeast, near
Plattsburgh. In addition, NYPA has generating assets, which are located
in many of these pricing regions in Figure 26. It is important to note
that transmission constraints will exist even within each of these
pricing regions, and within a utility control area.
(15) In the modeling simulation, half-hourly power flows will vary year to
year, case to case. This ratio was derived using 1999-2002 analysis from
the base case simulations.
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[FIGURE 27. FORECASTED HOURLY TRANSMISSION FLOWS BETWEEN UPSTATE AND DOWNSTATE
NEW YORK* LINE GRAPH]
* Under base case modeling (calculated over 2000); average defined as
the time-weighted average flow for the hour (any day of the year) as a % of
maximum capability; maximum defined as the maximum flow in the hour (any day of
the year) as a % of maximum capability.
9.3 ELECTRICITY DEMAND ASSUMPTIONS FOR NEW YORK
Electricity demand in the short-term is a function of weather patterns. In the
longer term, demand for electricity is driven by the end-user - residential and
industrial/commercial. Approximately 30% of annual historical electricity sales
have been made to residential consumers in New York. Another 40% of generated
electricity is sold to commercial customers and 20% to industrial customers. The
remaining power is generally sold to public authorities in New York
(street/highway lighting, railroads, and railways). All indicators appear to
reflect a settled market for electricity in New York - as population growth and
the state economy have already stabilized.
Population growth in New York is projected to be 0.3% per annum through 2025 by
the U.S. Census Bureau. Only three other states in the U.S. have lower annual
growth rates. In comparison, the average annual growth rate among the 50 states
is 0.75%. In total, the national population growth rate is 0.81% per annum for
the United States over the same timeframe. The percentage of people living
inside metropolitan areas has remained constant in the last ten years, at
approximately 92%.
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The U.S. Bureau of Economic Analysis estimates gross state products ["GSP"] by
attempting to account for all of the economic activity by component occurring in
the state. In the five years, 1991 to 1996, the New York GSP has grown at real
annual rate of 3.5%. However, manufacturing and other large
electricity-intensive industries have grown at an average 1% per annum over this
time-frame.
Average and peak demands are estimated to grow at approximately 1% per annum
over the next ten years, according to the New York Power Pool forecasts, as
detailed in NYPP's Load & Capacity 1998 manual. This modest growth rate is a
result of a mature economy and a stable, low population growth rate, as
discussed above. The Downstate region is projected to have a total demand of 74
TWh in 1999, while Upstate is projected to have a total annual demand of 77 TWh
in 1999. In the same year, the peak hourly demand in Downstate is estimated at
15.9 GW MW, while for Upstate it is forecasted at 12.6 GW as detailed in Table
22. These estimates are gathered from projected hourly data used in Poolmod.(16)
- ----------------------
(16) Hourly load data for each utility control areas was derived from 1994-96
FERC Form 714 filings and projected through 2020 using annual NYPP
forecasts for system load growth and historical implied growth rates from
1994 to 1997, as presented in NYPP's Load & Capacity Data 1997.
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TABLE 22. FORECASTED LOAD PROFILE FOR NEW YORK
NEW YORK CONTROL AREA(1) UPSTATE NEW YORK(2) DOWNSTATE NEW YORK(2)
--------------------------- ------------------------------- -----------------------------
PEAK HOURLY ANNUAL PEAK HOURLY TOTAL ENERGY PEAK HOURLY TOTAL ENERGY
LOAD (GW) GROWTH RATE LOAD (GW) (TWh) LOAD (GW) (TWh)
1997 28.7 12.2 74.9 15.5 72.0
1998 28.0 -2.5% 12.4 76.0 15.7 73.1
--------------------------- ------------------------------- -----------------------------
1999 28.3 1.1% 12.6 77.1 15.9 74.1
2000 28.5 0.8% 12.7 78.2 16.1 75.1
2001 28.8 1.1% 12.9 78.8 16.3 75.7
2002 29.1 0.8% 13.0 79.6 16.5 76.5
2003 29.4 1.2% 13.1 80.4 16.6 77.3
2004 29.7 0.8% 13.3 81.5 16.8 78.3
2005 30.0 0.9% 13.4 82.2 17.0 78.9
2006 30.2 0.9% 13.5 82.9 17.1 79.7
2007 30.5 0.9% 13.7 83.7 17.3 80.4
2008 30.7 0.8% 13.8 84.3 17.4 81.0
2009 31.0 0.9% 13.9 85.1 17.6 81.7
2010 31.3 0.9% 14.0 85.8 17.7 82.4
2011 31.6 0.9% 14.1 86.6 17.9 83.2
2012 31.8 0.8% 14.3 87.2 18.0 83.8
2013 32.1 0.8% 14.4 88.0 18.2 84.5
2014 32.3 0.8% 14.5 88.6 18.3 85.2
2015 32.6 0.8% 14.6 89.3 18.5 85.8
2016 32.8 0.7% 14.7 89.9 18.6 86.4
2017 33.0 0.8% 14.8 90.6 18.7 87.1
2018 33.4 1.0% 15.0 91.5 18.9 87.9
2019 33.7 1.0% 15.1 92.4 19.1 88.8
2020 34.0 1.0% 15.3 93.4 19.3 89.7
(1) Peak load is non-DSM, non-coincident actual peak/forecasted summer peak,
projected by the NYPP.
(2) Regional load extrapolated from utility filings (FERC Form 714)
It is interesting to note the differences in load profile across the Downstate
and Upstate region, as graphed in Figure 28. Clearly, average load in Upstate
New York is higher than average load in Downstate. However, Downstate appears to
have a larger proportion of peak load hours, as well as a higher overall peak.
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[FIGURE 28. REGIONAL LOAD DURATION CURVES IN 1999 LINE GRAPH]
9.4 IMPORT ASSUMPTIONS
Import transfer capabilities and levels are analyzed annually by the NYPP in its
Annual Transmission Planning and Evaluation Report. We also utilized NERC's
assessment of transmission capability into and out of New York. Normal power
flows tend to flow from Canada to New York. Net imports into New York from Hydro
Quebec are very seasonal: the directional flow is into New York during the
spring and autumn, when hydro availability is high in Quebec. Flows stop and at
times reverse; during the wintertime, Hydro Quebec becomes a net importer due to
the lack of hydro availability. Historically, New York has been a net importer
of cheap nuclear-generated power from Ontario Hydro; however, due to the current
nuclear outage, there have been very little imports coming from Ontario. New
York is a net exporter in its relationship with New England; however, the New
York exports are small relative to the amount of power that is wheeled across
New York into New England. Power flows from PJM into New York, with a normal
transfer rate of approximately 725 MW. Table 23 summarizes the
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underlying import assumptions used in the modeling, based on NYPP and NERC's
standards on inter-regional transfer capability.(17)
TABLE 23. NORMAL TRANSFER CAPABILITY BETWEEN REGIONS
Normal Transfer Capability from (MW)
- ------------------------------------------------------------------------------------------------------
New York PJM NEPOOL Ontario Quebec
-------------------------------------------------------------------------------------
New York - 2,000 1,575 1,825 2,470
-------------------------------------------------------------------------------------
Normal PJM 725 - - - -
Transfer -------------------------------------------------------------------------------------
Capability NEPOOL 1,675 - - - 1,700
into (MW) -------------------------------------------------------------------------------------
Ontario 1,600 - - - 1,150
-------------------------------------------------------------------------------------
Quebec 1,000 - 1,350 2,150 -
Based on these general observations, the modeling analysis assumes Ontario Hydro
imports are bid in at baseload levels ($14/MWh) and at mid-merit levels
($23/MWh). The net capacity of these imports is assumed to be only 80% of
incremental transfer capability due to the reduced nuclear output capability of
Ontario Hydro's nuclear fleet.(18) Hydro Quebec's imports are bid at a higher
prices ($17/MWh). In the longer term, net imports from Canada are reduced in our
modeling analysis by 8%, reflecting the declining export capability of Ontario
Hydro relative to its ability to meet its internal demand with an aging nuclear
fleet (over 50% of its nuclear capacity reaches license expiration by 2020).
Imports from PJM are bid at the historical regional peak prices for 1998-97
(~$30/MWh), with a constant transfer limit of 725 MW.
9.5 HYDROLOGY ASSUMPTIONS
Average five-year historic monthly hydro energy output from NYPA's units was
used to establish a daily energy release schedule for NYPA's hydro units.(19)
The station-specific seasonality used for the pumped storage facilities was
based on net generation figures
- ----------------------------
(17) NYPP. Load & Capacity Data 1998.
North American Electric Reliability Council. Winter 1997/98 Assessment
Study.
(18) Ontario Hydro's Bruce A and Pickering A nuclear units are currently
shutdown, due to a poor operational record. According to the Ontario
Hydro's Nuclear Recovery Plan, Bruce B2-B4 units are not planned to come
back on-line until after our five-year modeling timeframe. Bruce A1 is
planned to come back on-line in 2003. Pickering A units are also planned
to come back on-line in stages, from 2000 to 2002. Market intelligence
suggests that the Pickering A units will not come back on-line according
to this schedule and may be effectively retired, as their license
expirations are approaching (2010-2012).
(19) Monthly generation for every hydro facility from 1993 - 1997 was made
available to London Economics by NYPA. As a benchmark, historical monthly
generation for 1997 for all other units was compiled from EIA's serial
publication, Electric Power Monthly.
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from 1993-1997, as summarized in Figure 29. The daily energy release schedule
for non-NYPA hydro stations was developed using a seasonal index derived from
monthly historical output from NYPA's run-of-river stations (NYPA's stations
account for 83% of installed hydro capacity in New York), as portrayed in
Figure 30.
[FIGURE 29. HISTORICAL SEASONALITY OF PUMPED STORAGE FACILITIES LINE GRAPH]
[FIGURE 30. AVERAGE FIVE-YEAR OUTPUT VARIATION INDEX FOR CONVENTIONAL HYDRO
STATIONS LINE GRAPH]
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9.6 THERMAL STATION ASSUMPTIONS
Bidding by the thermal units is assumed to take place under competitive market
conditions, where marginal production costs set the merit order. Dispatch is
determined by maintenance schedules, plant flexibility, and relative position in
the merit order.
9.6.1 PLANT PERFORMANCE CHARACTERISTICS
9.6.1.1 CAPACITY
PoolMod utilizes demonstrated maximum capacity, which was collected from EIA's
Inventory of Power Plants and NYPP's Load & Capacity Data 1998. Minimum
capability (minimum stable generation) is also a required input. This was
calculated based on technology class. For example, steam generators (coal and
large CCGT) are estimated to have a minimum capability that is 45% of their
demonstrated maximum capacity. Small units (such as OCGTs) were estimated to
have a minimum stable generation equal to 25% of their maximum capacity. Nuclear
units were forecast to have a minimum stable generation level of 95% of their
demonstrated capacity.
9.6.1.2 AVAILABILITY: MAINTENANCE & EFOR
At the beginning of each year's processing, PoolMod determines when plant will
be available. There are three areas to consider:
- a unit may not have been commissioned yet, or may have been
decommissioned;
- a unit may be on a planned outage (e.g. on maintenance); or
- a unit may suffer an unplanned outage.
Commissioning and decommissioning are handled by the dates supplied in the
station database. For on-line plants, net availability is a function of forced
outages and maintenance schedules in PoolMod. Historically, forced outage rates
have varied significantly for the New York Power Pool, with rates as high as
17% and as low as 9%, depending on the month analyzed and the particular
combination of plant outages in the NYPP.(20) We have estimated a forced outage
rate component - applied randomly throughout the year by PoolMod - for each
plant on the basis of technology, ranging from approximately 5% (gas turbines)
to 10% (steam units). Maintenance schedules were also estimated by technology
class and size (varying from 1 to 6 weeks). PoolMod allows planned outages to
be allocated on a weekly basis. The allocation of planned outages is determined
automatically, using a constrained stochastic algorithm (which
- ----------------------
(20) Source: RDI. Power Markets in the U.S.
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is efficient in distributing maintenance to off-peak seasons). In our modeling,
net availability for plant vary from a low of 80% to a high of 94%. For nuclear
generators, availability is capped at 87% for every year. These availability
figures factor in across-the-board improvements in annual availability as
compared to historical records. This improvement is credible on the basis of
increased thermal plant utilization due to the incentives inherent in the
market transition to competition. The station-specific availabilities for the
AEE plants were developed in conjunction with AEE' engineering team and
independent engineers from Stone & Webster, reflecting pro forma technical
upgrades and extended maintenance outage schedules.
9.6.1.3 PLANT FLEXIBILITY
Plant flexibility was defined using standard technology/fuel-based minimum on
and off times. Generally, minimum on and off times for larger steam-generation
units was 6 hours and 6 to 12 hours, respectively. This was validated through
market intelligence and technical/operations data supplied by NYSEG. For IC
units and other small fuel-oil powered units, the minimum on and off time was
estimated at 1 hour.
9.6.2 PLANT COSTS
Marginal production costs are modeled utilizing historical average heat rates
for each unit (compiled from FERC Form 1, RDI's Energy Insight, FERC Form 860)
and fuel prices forecasts by RDI (gas and oil) and Boyd (coal), as well as
estimated operations & maintenance costs and start costs. Figure 31 depicts the
New York supply curve for 2000 based on estimated variable operation &
maintenance costs and forecasted 2000 fuel costs. Hydro is shadow-priced against
mid-merit and peaking thermal units.
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[FIGURE 31. NEW YORK DISPATCH CURVE IN 2000 BASED ON BASE CASE PROJECTIONS LINE
GRAPH]
9.6.2.1 O&M AND START COSTS
Indicative operation & maintenance costs were estimated for each unit using
historical production costs, fuel costs and total O&M costs (compiled from UDI's
Production Costs: Operating Steam Electric Plants database, and RDI's Energy
Insight, and RDI's Powerdat database). Start costs were estimated by prime-mover
category and plant size. An example of typical start costs is detailed in Table
24.
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TABLE 24. TYPICAL START COSTS
UNIT TYPE UNIT CAPACITY (MW) HOT START COSTS ($/START)
- ------------- ---------------------- -----------------------------
Coal (Steam) 500 $13,500
Oil (Steam) 250 $3,000
Oil (GT) 50 $500
Gas (CC) 750 $6000
Gas (GT) 250 $2000
9.6.2.2 COAL FORECASTS
We utilized John T. Boyd Company's FOB coal forecasts for Pittsburgh seam coal
(various grades of sulfur content) and Mid-Appalachian compliance (low-sulfur)
coal. These forecasts were commissioned by AEE for purposes of market analysis.
Boyd provided us with both a base case and a downside case forecast of FOB coal
prices through 2010.(21) In estimating total delivered fuel costs for coal
plants, a constant transportation margin was added to the FOB coal forecasts,
representing historical trends in delivery costs over the last eight years for
the utilities. Transportation costs for Upstate New York were estimated at
$0.46/MMBtu for NRG's plants (formerly NIMO's) and $0.47/MMBtu for the AEE
plants (formerly NYSEG's stations); while for Southern (formerly O&R's plants)
and for CHG&E, we used a weighted-average transportation component of
approximately $0.76/MMBtu.
In our going-forward analysis, it was assumed that plants in Downstate New York
would continue using a low-sulfur, compliance coal; thus, we utilized Boyd's
compliance coal forecasts for these plants. Analysis of NRG's coal plants showed
a deteriorating environmental position relative to Phase II of the EPA's Acid
Rain program. This led us to utilize a compliance coal price track for these
plants, as well. The AEE coal price track was based on a mixture of high and
medium sulfur coal from the Pittsburgh seam, as these plants will be able to
meet environmental regulation with their newly installed FGD technology. Figure
32 illustrates the base case forecasts for delivered coal prices. Downside case
FOB coal forecasts exhibit a steeper declining trend (in real terms), as
compared in Figure 33.
- ----------------------
(21) In our simulation modeling, coal prices were held constant in real terms
post 2010.
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[FIGURE 32. DELIVERED COAL FORECASTS UNDER THE BASE CASE LINE GRAPH]
[FIGURE 33. COMPARISON OF BASE AND DOWNSIDE COAL FORECASTS LINE GRAPH]
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9.6.2.3 GAS AND OIL PRICE FORECASTS
We utilized RDI's BaseCase delivered natural gas forecasts to utilities in New
York and fuel oil forecasts for NYPP.(22) Annual gas and oil forecasts by RDI
show a positive real growth trend throughout our modeling time horizon, as
illustrated in Figure 34. Currently fuel oil prices and traded forwards prices
are below RDI forecast prices. London Economics performed additional analysis
for the years 1999 to 2010 to determine the effects of lower oil prices,
partially offset by NOX allowance costs (which were not incorporated in the
base and downside cases). Incorporating both of these effects leads to a
decrease in the Company's revenues during 1999 through 2003. The decrease
revenues during these years fall between the base case and the downside case
revenues.
[FIGURE 34. ANNUAL GAS AND OIL FORECASTS UNDER THE BASE CASE LINE GRAPH]
Under the downside case, gas and oil prices are assumed to be 10% lower than the
base case forecasts, as summarized in Figure 35.
- -------------------
(22) The source of data is copyrighted material excerpted from the Resource
Data International, Inc. (RDI) BaseCase(R) copyrighted data base. RDI is
located in Boulder, Colorado.
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[FIGURE 35. COMPARISON OF GAS PRICES UNDER BASE AND DOWNSIDE CASES LINE GRAPH]
Seasonality of natural gas is assumed to remain constant across the base and
downside case, based on five-year monthly average index of Henry Hub
seasonality, as depicted in Figure 36.
[FIGURE 36. GAS SEASONALITY INDEX LINE GRAPH]
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9.6.2.4 OTHER FUELS
Nuclear prices were based on average historical delivered costs to nuclear
plants in New York State, at approximately $0.50/MMBtu. Going forward, nuclear
fuel was kept constant in real terms.
9.7 NUG CONTRACTS
The New York system has 5.4 GW of NUG generation, representing 15% of the
system's total generation.(23) Due to falling fuel price pressures and other
market realities, many of these QF contracts left utilities with out-of-the
market power purchase contracts. NIMO was the first utility to restructure its
NUG obligations, under the Master Restructuring Agreement. IPPs agreed to
terminate, restate, or amend their contracts with NIMO in exchange for 25% pro
forma interest NIMO and over $3.6 billion in cash. Other utilities have followed
suit and restructured their NUG obligations, for example: NYSEG [Binghamton
plant - 50MW] and RG&E [Allegheny - 65 MW]. In order to correctly profile the
New York power market, we have separated the aggregate installed NUG capacity
into two categories: "restructured" (dispatchable according to plant economics)
and "original contract" (must-run plant). These categories were then sub-divided
by fuel type and utility ownership into composite groups, as shown in Table 25.
TABLE 25. NUG CONTRACTS IN NEW YORK
NAMEPLATE
CAPACITY
GROUP OWNER (MW) PRIMARY FUEL
NUG Composite - Natural Gas ConEd 1,433 Natural Gas (NUG)
NUG Composite - Natural Gas LILCO 109 Natural Gas (NUG)
NUG Composite - Methane Gas IC LILCO 11 Methane Gas
NUG Composite - Solid Waste & Wood LILCO 117 Solid Waste & Wood
NUG Composite - Natural Gas NYPA 102 Natural Gas (NUG)
NUG Composite - Natural Gas NYSEG 456 Natural Gas (NUG)
NUG Composite - Natural Gas - Restructured NYSEG 50 Natural Gas (NUG)
NUG Composite - Methane Gas IC NYSEG 7 Methane Gas
NUG Composite - Natural Gas - Restructured NIMO 1,661 Natural Gas (NUG)
NUG Composite - Solid Waste & Wood - Restructured NIMO 167 Solid Waste & Wood
NUG Composite - Methane Gas IC - Restructured NIMO 4 Methane Gas
NUG Composite - Natural Gas O&R 20 Natural Gas (NUG)
NUG Composite - Natural Gas -Restructured RG&E 65 Natural Gas (NUG)
It is expected that the non-restructured NUG contracts (i.e. LILCO's contracts,
O&R's contracts, ConEd's contracts) will not be re-classified or re-structured
in the short-
- ---------------------
(23) New York Power Pool. Load & Capacity Data 1997.
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term, as these contracts represent a relatively small financial burden on the
respective utility contract holders. Many of these contracts will expire only
in the long-term (see schedule below). By 2011, almost all "must-run" NUGs have
been retired or restructured in our base case outlook. When they expire, some
projects will be shutdown, but most will enter the dispatch curve as
competitive generators. Clearly, most of the NUGs will enter - on a variable
cost basis - above the highly competitive coal units that AEE has acquired.
Furthermore, most of the NUGs are within the Downstate region. This will
further limit the impact of potential NUG restructuring on AEE' revenues.
TABLE 26. NUG RESTRUCTURING/RETIREMENT SCHEDULE (INSTALLED CAPACITY, MW)
2000 2005 2010 2015 2020
Must-run NUG 2,255 2,128 1,535 102 0
Restructured NUGs 1,936 1,936 1,894 3,294 3,294
9.8 NEW ENTRY
Thus far, announced new entry in New York has been limited. The current
announcement schedule is detailed in Table 27. Developers may be waiting to see
the outcome of asset auctions, or planning to bid on the assets themselves,
before committing to new development in a slow-growing market. Portfolios to be
sold include several potential development sites, which would be favorable to
greenfield sites; some of the sites include preliminary permitting and other
site preparation.
The two developers who have announced projects to date are expanding rapidly in
the Northeast. Sithe purchased the Boston Edison plants in New England and the
GPU plants in PJM; it already runs the 1000 MW Independence facility in upstate
New York. Its development plans will give it over 3000 MW of New York capacity.
To date, Sithe has shown little interest in power marketing or retail markets,
preferring to stick to operation and maintenance of its facilities. It has
entered into tolling deals for some of its plants.
USGen has a substantial presence in New England due to its purchase of the
former NEES assets. Its parent, PG&E, does have a large trading and competitive
retail operation; it also has the balance sheet to pursue further asset
acquisitions in New York.
Several other aggressive IPP developers have a presence in New York. CalEnergy
controls the 240 MW Saranac project in upstate New York; it made an unsuccessful
attempt to take over NYSEG in mid-1997, prompting that company's restructuring.
CalPine has recently consolidated its holdings in a Long Island IPP; it acquired
the IPP portfolio developed by KeySpan predecessor Brooklyn Union Gas. Enron
acquired the 715 MW Cogen Technologies facility in Linden, New Jersey in fourth
quarter 1998 in one of the highest $/kW transactions to date; it plans to use
the facility to access
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metropolitan New York City markets. El Paso Energy is also rumored to be
looking at developing a plant in upstate New York.
TABLE 27. ANNOUNCED NEW BUILD IN NEW YORK
OPERATION PLANT
COMPANY PLANT SITE FUEL DATE CAPACITY (MW)
- --------------------------------------------------------------------------------------------------------------
SITHE NEW SCRIBA, NY GAS-FIRED 2001 1790
ENERGIES, INC CONSTRUCTION
SITHE NEW RAMAPO, GAS-FIRED 2001 750
ENERGIES, INC CONSTRUCTION NY
U.S. NEW ATHENS, NY GAS-FIRED 2001 1080
GENERATING CONSTRUCTION
The construction by Sithe in Scriba, New York is an addition to the Independence
Station. The Ramapo facility is a green-field development, proposed to be
between 700 and 800 MW; with an estimated cost of $500 million. All three
facilities are currently 100% merchant.
Over the short-term, capacity and energy prices will be substantially affected
by the level of immediate new entry. While this should reach an equilibrium
level over time, based on comparative costs and capacity margins, experience in
other markets has shown a strong tendency for substantial new entry before
market prices provide an adequate entry signal. In the base and downside case,
we allowed for modest new entry, over 1000 MW in Upstate New York by 2004 and
over 3000 MW of CCGT in Downstate under the "re-powering" classification. In the
longer term, new entry will enter the market in order to support growing demand
and to replace capacity retirements. In our simulation modeling, over 20 GW of
new CCGT enter the New York market by 2020.
TABLE 28. LONG TERM OUTLOOK ON NEW ENTRY (INSTALLED CAPACITY, MW)
2000 2005 2010 2015 2020
Upstate 0 3,109 6,109 10,609 11,609
Downstate (+ re-powering) 29 3,000 3,600 5,100 10,100
------------------------------------------------------------
29 6,109 9,709 15,709 21,709
------------------------------------------------------------
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9.9 CAPACITY RETIREMENTS
9.9.1 NUCLEAR RETIREMENTS
New York's nuclear capacity totals 5,600 MW of baseload capacity (representing
approximately 27% of New York's generation in 1997). As new baseload CCGTs come
on-line, there may be opportunity for early retirement of some of the state's
nuclear capacity. The earliest nuclear license expirations in New York are set
to occur in 2009 for RG&E's Ginna facility and NIMO's Nine Mile Point 1 unit.
Performance and restructuring incentives may drive some nuclear generation
operators to retire their facilities earlier; however, there are no clear
candidates for early retirement currently. Of all the New York nuclear
facilities, Indian Point 3 and Nine Mile Point 1 have fairly lackluster
performance records - low average capacity factors and an extended "Watch List"
rating by the Nuclear Regulatory Commission. However, it is not probable that
these "under-performers" will be retired early, especially those units owned by
the NYPA (Indian Point 3 and Fitzpatrick). Furthermore, NIMO will be unlikely to
retire Nine Mile Point 2 early. NMP2 has the advantage of a relatively long
remaining lifetime (prior to license expiration), even though it had extended
performance problems in the late 80's. Fitzpatrick and Ginna have lifetime
average capacity factors that are above the national average (69%), see Table
29. Moreover, over the three-year period 1995-97, Ginna had the third lowest
average fuel cost of all nuclear power plants in the nation.
TABLE 29. PERFORMANCE OF NEW YORK'S NUCLEAR ASSETS
PLANT LICENSE HISTORICAL CAPACITY PLANT EVALUATIONS (NRC) (b)
EXPIRATION FACTOR (a)
- ------------------------------------------------------------------------------------------------------------------------------
Ginna 2009 76% -
Fitzpatrick 2014 70% February 1993 - June 1993 on Watch List Category 2
Indian Point 2 2013 66% -
Indian Point 3 2016 50% January 1994 - January 1997 on Watch List Category 2
Nine Mile Point 1 2009 60% December 1988 - January 1991 on Watch List Category 2
Nine Mile Point 2 2026 67% July 1988 - January 1991 on Watch List Category 2
- ------------------------------------------------------------------------------------------------------------------------------
- -----------------------------
(a) Lifetime Average (as of 1996)
(b) Watchlist Category 2: Plants are authorised to operate, but the NRC will
monitor closely because of weak performance.
Watchlist Category 3: Plants are in a shutdown condition due to
significant weaknesses, until the licensee can
demonstrate to the NRC that improvememnts have
been implemented.
Declining Performance Category: Category established in June 1993; Plants
with safety perfomance trending
downwards.
As a conservative assumption, we have assumed that all New York nuclear assets
will improve their net availability values sharply. We have assumed an average
availability (and therefore capacity factor) of 87% for the New York nuclear
portfolio on average. This is substantially better than their historical average
performance.
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In conclusion, we foresee a limited likelihood of early retirement of nuclear
generation in the scope of the initial period modeling simulation (1999 through
2003).
9.9.2 FOSSIL-FUEL RETIREMENTS
The decision to retire fossil-fuel plants is driven by fundamental economics. In
general, there will be two cost-imposing catalysts to retirement - costs
associated with environmental changes and costs associated with a declining
market share due to lack of competitiveness.
9.9.2.1 ENVIRONMENTAL DECISIONS
The Clean Air Act Amendments of 1990 established the Acid Rain program. The goal
of the program was to reduce sulfur dioxide and nitrogen oxide emissions, with
an overall 2 million ton reduction in NO(X) and 10 million ton reduction in
SO(2) from 1980 levels. The reductions were set up to occur in two phases (Phase
1 began in 1995 and Phase 2 will begin in 2000).
In order to evaluate the effect of these limits on power plants in New York, we
have analyzed each plant's 1997 emissions as compared to the limits established
under the program. There were no explicit levels for sulfur dioxide for each
plant, as the quantitative reduction would be implicitly achieved on a regional
basis through the marketable emission allowance program.(24) In order to examine
each individual plant, we have analyzed their emissions levels as compared to
their allowance allocation.(25) Utilizing this methodology, nearly 8% of New
York's fossil fuel capacity does not meet the target levels afforded it through
its allocated allowances. However, all these units can avoid penalties by
acquiring more allowances in the over-the-counter market or through
technological applications. Currently, only a few units in New York have
installed scrubbers (SO(2) - mitigating devices).
- -----------------------
(24) One allowance is equivalent to 1000 tons of SO(2).
(25) The SO(X) requirement is a bubble requirement, covering a whole portfolio,
rather than one plant; thus, it allows for a level of cross-subsidization
and internal trade. The methodology we applied in this analysis is
static; thus, it does not capture the dynamics of intra-portfolio,
intra-regional and inter-regional trade.
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TABLE 30. AFFECTED FOSSIL-FUEL CAPACITY IN NEW YORK
ACID RAIN ACID RAIN OZONE
PROGRAM - PROGRAM - PROGRAM-
SO(2)(P. 2) NO(X) (P. 2) NO(X)
AFFECTED CAPACITY 8% 0% 37%
SCOPE FOR IMPROVEMENT 8% 0% 11%
----------------------------------------------
NET AFFECTED CAPACITY 0% 0% 26%
Under the Acid Rain program, NO(X) regulation was set according to boiler
specifications: Phase 1 limits were set for tangential and dry bottom wall-fired
boilers (0.45 lbs./MMBtu to 0.50 lbs./MMBtu). Phase 2 limits were set for all
other boilers (cyclone, wet bottom, cell burners, vertically-fired) at
approximately 0.68 lbs./MMBtu to 0.86 lbs./MMBtu. Compliance for Phase 2 limits
will be mandatory after 2000. Under 1997 emissions, no plants in New York were
affected by either Phase 1 or Phase 2 limits placed on them through the NO(X)
regulations under the Acid Rain program in the short-term. However, there may be
long-term repercussions as additional annual emissions reductions become
required (the 1997 average NO(X) emissions rate was 0.28 lbs./MMBtu for
fossil-fuel capacity in New York, with some plants' emissions as high as 0.75
lbs./MMBtu).
Proposed NO(X) standards for the Northeast region from the Ozone Transport
Assessment Group's ["OTAG"] recommendations are stringent - 0.15 lbs./MMBtu -
due to the target levels devised by the EPA for the region. This limit, if
applied to New York facilities, would result in penalties for 37% of New York's
fossil fuel capacity. There is still some scope for improvement, as nearly 11%
of capacity has not installed any NO(X) emissions mitigating device (therefore
classified as "uncontrolled" NO(X) emitters). After accounting for those units
who have "uncontrolled" NO(X) emissions, approximately 26% of New York's
fossil-fuel capacity appears to be net affected capacity under the Ozone
program. These are the plants that already have some form of NO(X) emissions
reduction controls (e.g. installed LNBs or LNCs), but do not meet the stringent
OTAG levels. On average this group's NO(X) emissions rate for 1997 was 0.36
lbs./MMBtu. However, their emissions levels can potentially be further reduced
with more rigorous application of technological options; for example, the use of
SCRs and hybrid technology (SCRs in addition to LNBs). Alternatively, these
plants can buy NO(X) allowances.
9.9.2.2 ECONOMIC DECISIONS
Due to expected new entry, low load factor units may be displaced by more
efficient technology in the merit order. This can result in significant changes
in plant profitability and may lead to unit mothballing and retirement. Even
though announced new build in New York is typically baseload, it is expected
that it will affect the mid-merit and peaking capacity most. This is especially
true for the Western part
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of New York, where there is a larger amount of lower cost generation (coal). We
have studied the result of new entry on the performance of installed capacity
by simulating competitive dispatch of generation to meet demand over the next
several years. We then screened for candidates for retirement by analyzing
several factors: forecasted variable cost versus revenue, load factor trends,
and age.
New York's fossil-fueled assets can be considered vintage. A majority of all
coal units (69%) are 40-50 years old. Much of the coal-fired generation appears
to be fairly competitive; however, there are certain units that have had less
than average performance, due to high delivered coal costs. The kerosene-fueled
capacity is all approximately 30 years old, built primarily by LILCO in the
early 1970s to replace even older coal units (now owned by KeySpan). Similarly,
52% of all gas-fired units, and 49% of all oil-fired units are between 25 to 30
years old, as seen in Figure 37. In the constrained Downstate region, retirement
of inefficient, expensive plant (i.e. fuel-oil and kerosene fired units) will
occur under the auspices of re-powering, as the reliability rules call for a
minimum amount of in-city generation capacity.
[FIGURE 37. AGE DISTRIBUTION OF NEW YORK FOSSIL-FUELED PLANT LINE GRAPH]
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9.9.3 HYDRO RETIREMENTS
The Federal Energy Regulatory Commission is responsible for licensing
non-federal hydroelectric power projects. It issues licenses for hydroelectric
projects for periods up to 50 years. When a license issued to a private entity
expires, the Commission may issue a new license (re-license) to the original
licensee, or to a new licensee. The Commission may also recommend federal
takeover, if it determines that such action would better serve the public
interest (this has never occurred).
Between 1995 and 1999, 35 licenses will expire across the U.S. Moreover, in the
years 2000 and 2001, 69 licenses will expire. For the first time in history,
FERC has required removal of dams in New England [Edwards Manufacturing]- as
part of the re-licensing program, justifying the decision on conservation
grounds. In New York, hydro power re-licensing is not a substantial threat to
any of the significant hydro assets, as their current licenses will last for
another 10-20 years.
9.9.4 CONCLUSIONS ON CAPACITY RETIREMENTS
In conclusion, no environmentally-induced fossil-fuel retirements were assumed
in the simulation modeling of the New York power market in the next five years,
as the outcome of the stringent regulatory proposals is uncertain. However, its
is assumed that in the longer term, many of the in-city oil-fired generation
will be re-powered. Re-powering is triggered by the sale of ConEd's in-city
generation, as well as the low utilization levels of many of these peaking
units. By 2020, nearly 40% of fossil-fuel fleet formerly owned by ConEd's and
LILCO's will have been retired/re-powered in our modeling. The timing of other
economic-driven retirements of fossil-fueled plants is assumed to occur only in
the medium to long-term, due to loss of competitive position and limited site
value. Financial unbundling of generation, distribution, and transmission assets
and retail competition will eliminate the corporate strategic value in retaining
capacity, especially for smaller IOUs. This pattern of re-powering has been
observed elsewhere in the United States, in announcements from Massachusetts and
California.
TABLE 31. CAPACITY RETIREMENT - FOSSIL-FUEL
CAPACITY FORMERLY OWNED BY CONED/LILCO (MW)
------------------------------------------------------
2000 2005 2010 2015 2020
Current fleet 11,279 11,279 8,170 7,368 6,921
Re-powerings (CCGT) 0 3,000 3,600 5,100 10,100
OTHER FOSSIL FUEL CAPACITY (MW)
------------------------------------------------------
2000 2005 2010 2015 2020
Fuel Oil/Gas 6,163 5,242 5,112 4,136 4,134
Coal 4,030 3,859 3,696 3,696 3,696
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Furthermore, license retirement dates for the state's nuclear units were used as
the effective closure date. Accordingly, over 75% of New York's nuclear capacity
would be retired by 2020. In contrast, very little hydro generation is retired,
as many license expiration dates are beyond the time scope of this modeling and
license extension is highly likely for hydro plants.
TABLE 32. CAPACITY RETIREMENT - NUCLEAR AND HYDRO
NUCLEAR CAPACITY (MW)
- -----------------------------------------------------
2000 2005 2010 2015 2020
5,578 5,578 4,419 2,227 1,214
HYDRO CAPACITY (MW)
- -----------------------------------------------------
2000 2005 2010 2015 2020
5,869 5,642 5,704 5,659 5,659
9.10 CAPACITY MIX
In the longer term, new technology will enter the market and displace the aging
generation fleet. The entry of this lower cost and higher efficiency technology
results in a decline in energy prices as it replaces more expensive capacity
along the supply curve. Figure 38 illustrates the resulting shift in the
dispatch curve over time as new CCGT enter the market in both Upstate (according
to current announcements and market dynamics) and Downstate (due to re-powering
of retired fuel-oil units, in order to meet in-city capacity rules and energy
demand). Additional drivers to this inter-temporal transition are the retirement
of the nuclear fleet (assumed to take place according to license expiration),
and the retirement/restructuring of the must-run NUG contracts (decisions timed
according to retail market development, economics and contract expiration). It
is also important to note that there are additional retirements based on
economics and environmental regulation of other fossil fuel-fired units, which
also affect the market-clearing energy price. Figure 39 summarizes the state's
installed capacity by fuel type, as assumed in our simulation modeling.
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[FIGURE 38. DISPATCH CURVES OVER TIME LINE GRAPH]
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[FIGURE 39. OUTLOOK ON INSTALLED CAPACITY RELATIVE TO PEAK DEMAND BAR GRAPH]
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10 APPENDIX B: NEW YORK MARKET RULES: ENERGY, CAPACITY & ANCILLARY SERVICES
On January 31, 1997 the first Comprehensive Proposal to replace the New York
Power Pool (NYPP) was filed with the FERC. The market structure in the proposal
included several new institutions (ISO, New York State Reliability Council, New
York Power Exchange) and a market structure operated on open access principles.
The New York ISO and its complementary institutions were approved by the FERC in
June of 1998. It is important to understand the proposed market rules, as they
will shape the analysis that London Economics has performed in assessing the
future market dynamics and forecasting prices for New York's power market.
10.1 OVERVIEW
The ISO will be a non-profit New York corporation subject to FERC jurisdiction
and, to the extent applicable, PSC jurisdiction. It will be governed by a Board
of Directors comprised of representatives from all market participants:
- buyers [those entities which purchase power in the wholesale
market],
- sellers [representing those entities which provide power in the
wholesale market],
- consumer and environmental groups [members who will represent the
perspectives of those who are not direct market participants], and
- transmission providers.
Each class will be represented on the Board of Directors, where each board
member will get one vote. A vote of seventeen of the twenty-eight members will
be needed to pass any measure. There will be three standing ISO committees: an
Operating Committee [coordinator of day-to-day operation of the bulk power
system], a Business Issues Committee [establishes new rules and provides a
discussion forum for arising issues], and a Dispute Resolution Committee.
Under the current proposed model, most transactions in the day-ahead market and
many in the real-time market will be scheduled through a power exchange
(including energy, capacity and ancillary services).
10.2 ENERGY MARKET
The NYPP was a conventional shared savings pool, characterized by energy prices
that basically reflected fuel cost. This approach fit well with the traditional
electric industry structure, as all capital, fixed costs, and variable non-fuel
costs were recovered by utilities under ratebase from their franchise customers.
Restructuring in New York will now introduce a market place with both
utility-owned generation and facilities owned by independent power producers.
Generation will be unbundled from regulated retail tariffs, ending ratebase cost
recovery mechanisms. Therefore, it will be
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essential that generators recover all their costs from the resources available:
energy, capacity, and ancillary services. Competitive - unconstrained -
generation will have to recover fuel costs, AND start-up costs AND variable
non-fuel costs from wholesale energy prices.(26) Potentially, fixed costs and
capital costs may be recovered through revenue streams associated with the
capacity and ancillary services markets. At the minimum, generators will
introduce variable O&M costs - in addition to fuel costs - in their bidding
strategy into the power exchange, resulting in a shift in market clearing
prices. This transitional phenomenon is a major driver in our price forecasts,
creating a substantial real price increase in the wholesale energy market over
the next year.
The New York ISO proposes a market structure that is best described as a
residual pool structure with centralized dispatch. Buyers and sellers are
permitted to enter into bilateral trades. The power exchange(s) will facilitate
transactions and make available day-ahead and real-time locational energy
prices. Generators will be able to bid some or all of their unit's output into
the market, through multi-part bids (start up costs, minimum generation level
and cost, and incremental energy above minimum). The real-time market will serve
a balancing role and will be determined using a security-constrained dispatch.
The locational market-clearing price (LBMP) will be paid to generators.
10.3 TRANSMISSION PRICING PRINCIPLES
A core objective of the NY ISO is to formulate a competitive and efficient
wholesale market. One element in this move towards efficiency is the reform of
the transmission-pricing scheme. All parties wheeling power through and/or into
the state will have access to the entire transmission system, with their tariff
determined by the embedded cost of the provider at the destination.
Location-based pricing will be used to account for congestion.
The wheeling parties will pay the ISO a Transmission Service Charge (TSC) to
cover the revenue requirements of the transmission owner; thus, these TSCs may
differ by transmission district. A transmission owner that continues to offer
transmission service to the franchise retail customers will collect a
transmission revenue requirement for that service through a separate approved
retail rate. A party engaging in bilateral transactions will pay the applicable
TSC and a congestion charge (when the system is congested). The TSC will be
based on the FERC-approved transmission provider tariffs, as detailed in Table
33, based on the final destination point. A party procuring energy through the
centralized market will in effect also pay these transmission usage charges
(charges for transmission, congestion, and marginal losses) through the
locational energy prices. The transmission usage charge will represent the
difference in the locational-based marginal prices between the generator's
location and the load bus.
- -----------------------
(26) This excludes generation located within load pockets such as the
generation in New York City.
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TABLE 33. HOURLY INDICATIVE TRANSMISSION TARIFFS FOR EACH TRANSMISSION DISTRICT
Central Hudson Gas & Electric $7.64/MWh
Consolidated Edison $10.59/MWh
Long Island Power Authority $8.64/MWh
New York Power Authority $6.00/MWh
New York State Electric & Gas $8.17/MWh
Niagara Mohawk Power $6.00/MWh
Orange & Rockland Utilities $7.73/MWh
Rochester Gas & Electric $5.73/MWh
These congestion charges will then be remitted to the owners of the
Transmission Congestion Contracts (TCCs). The TCCs will be sold periodically by
the ISO (through a biannual auction) and the revenues will be remitted to the
owners of the transmission assets (and will be credited against the TSC of the
transmission owner). Owners of divested New York generation assets will
typically receive a permanent allocation of TCCs relative to the generation
assets. TCCs may also be available directly from the transmission owners and in
a secondary market. Individuals may purchase the TCCs in order to hedge against
fluctuations in the congestion charges.
10.4 CAPACITY MARKET
An installed capacity (ICAP) market will be established to ensure that there is
sufficient generation capacity to cover energy bids and ancillary services bids.
ICAP requirements will be established at the beginning of each capability year,
which will run May 1 to April 30, divided into a summer and winter period.
Requirements will apply on a non-discriminatory basis to all Load Serving
Entities (LSEs), companies serving retail load in New York. Requirements may
differ by transmission districts, as required by sub-regional constraints and
generation characteristics. The NYSRC will base its determination of the
statewide installed reserve margin on the amount of resource capability
necessary to avoid a loss of load probability of more than once in ten years.
10.4.1 CAPACITY MARKET RULES
LSEs may secure commitments for the required amount of installed capacity
through bilateral arrangement with a resource provider, including their own
affiliates, or through a power exchange, such as the NYPE. LSE's may claim all
of the following as qualifying capacity: ICAP purchases, interruptible load, and
capacity of owned or contracted units adjusted for demonstrated dependability.
Sixty days before the start of the capability year, the NY ISO will establish
reserve requirements for each transmission district and LSE. The requirement for
all transmission districts is currently set at 18% - reflecting target
availabilities by prime
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mover class. For the New York Control Area, the reliability margin will be 22%,
as derived by aggregating the individual margins of the Transmission Districts.
In addition, there will be procurement requirements, specifying the minimum
ICAP that must be procured internally by the LSE in its own locality, the
maximum total installed capacity that may be procured by the LSE from other
zones within the New York, and the maximum ICAP that may be procured by the LSE
externally (imports). The external allotments will need to be in the form of
firm import contracts and will be limited locationally. More importantly,
external capacity must prove that it does not violate transmission constraints
in order to qualify for the ICAP requirement. Thereafter, an LSE must submit
documentation satisfying these requirements, based on NY ISO-compiled
forecasted peak load.
During the current capability period, LSE's may procure additional ICAP (or sell
existing ICAP, provided it is not forecast to be ICAP deficient) if desired. At
the conclusion of the capability period, the NY ISO will take account of each
LSE's actual ICAP requirements based upon its actual demand, in order to take
into account LSE load transfers that occurred during the capability period. When
an LSE fails to satisfy its actual ICAP requirement at the end of a capability
period, that LSE will be subject to a deficiency payment. For all zones, with
the exception of Long Island and New York City, the ICAP deficiency penalty is
set at $52.5/kW-Year for the first year of NY ISO operations.(27) The ISO has
proposed that the in-city deficiency payment be $150/kW-Year. LSEs can mitigate
or avoid the deficiency payment by purchasing additional installed capacity
within 30 days from the end of the capability period. Purchases can be made from
LSEs which had surplus ICAP during the same capability period, or from other
qualified ICAP suppliers, who have met target availabilities for their class or
have adjusted capacities reflecting their actual availability.
According to engineers at the New York Public Service Commission and members of
the NY ISO committee, the current capacity rule will be used during the
transition period for ISO implementation. The ISO, and specifically the NYSRC,
will potentially make changes to these rules in the future, when they set
locational-based requirements for NY.
10.4.2 CAPACITY OUTLOOK
In the short term, as transitions take place across New York, the market rules
require that all LSEs prove that they have capacity coverage for their load.
However, it is these same LSEs that are divesting their generation assets.
Therefore, it will be required that they enter into capacity contracts with
generation owners. The risks involved with regulatory reprisal and penalties, as
well as demand uncertainty will certainly create value in capacity contracts in
the short-term. Furthermore, the illiquidity of the current bilateral contract
markets adds significant transaction costs to the capacity contract, which
translates into higher $/kW capacity payments. The
- -----------------------
(27) In the second year, the penalty will rise to $57/kW and, in the third
year, to $62.5/kW.
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transition agreements that have recently been seen in New York reflect these
transitory market risks and costs of capacity contracts.(28)
More importantly, as each LSE will have its set of specific procurement
requirements, these capacity values will tend to differ by region. In Downstate
New York, due to load pocket and transmission constraints, capacity will be
valued at a greater premium. Nonetheless, even Upstate New York capacity is
likely to have a non-zero value over time, reflecting the costs of capacity
contract transactions and the inherent risks of not meeting regulatory
requirements.
It is estimated that there will be a surplus in installed capacity(29) over the
next five years based on the established control area reliability margin of 22%
over aggregated peak demand and forecasted capacity. Under these assumptions
(which are not adjusting for external capacity, availability and outages in
excess of class target availabilities), it is clear that capacity is not scarce.
In a market where there is a surplus of capacity, competition will tend to push
down equilibrium prices for capacity to a low level. Indeed, Figure 40,
illustrates that even in the worst hour, New York State will have a forecasted
capacity surplus of over 1,250 MW in 2003, representing 4% of forecasted peak
demand for the year. Even though actual capacity surplus may be smaller after
adjusting for forced outages and maintenance, it can be assumed that during the
worst hours, capacity owners will earnestly try to make all capacity available.
Furthermore Figure 40 does not capture potential external capacity (import
capability) that can be used in meeting requirements.
If the LSEs do not meet their reliability margin, they will be penalized,
through the deficiency rate ($53/kW in 1999 and $57/kW in 2000 for New York
State, excluding NYC and Long Island). In the long-term, LSEs will choose to
contract for capacity or construct new capacity, at a levelized indicative cost
of $53/kW-Year.(30) Thus, the maximum value of capacity would be defined by new
entrant costs (as the deficiency rate is set relative to levelized new entrant
cost). The capacity market-clearing price will allow developers to recover their
capital costs of new build, resulting in an optimum level of entry, as required
by New York's preferences for reliability.
Higher capacity values in the ICAP market could be created by
- ---------------------------
(28) AEE's transition agreement with NYSEG includes a payment for capacity
valued at $68/MW-day ($25/kW-Year) until April 2001. In November 1998,
ConEd announced an out-of-city RFP (20% of peak in-city load), which
resulted in a $41.3/kW-Year settled capacity price.
(29) Surplus is defined as [Forecasted New York Capacity - {Forecasted Peak
Load*(1 + NYCA Reliability Margin)}], where forecasted capacity
represents both current installed capacity and planned new entry, and
forecasted peak load is defined as the peak load established from the
aggregation of forecasted utility control area data.
(30) A capital cost of $250/kW (OCGT), with 30% leverage (8% interest rate), a
15% post-tax ROE, and fixed O&M cost of $8/kW-Year financed over 25 years
would result in a levelized cost of approximately $53/kW-Year. A similar
project with 100% equity financing would result in a levelized cost of
$66/kW-Year.
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APPENDIX B
- Substantial plant retirements in the New York control area.
However, the high cost units in the New York control area are
primarily located Downstate, in the ConEd service territory. We
expect that many of these units may be re-powered, as they are
required to meet local demand. The AEE units are located in a
region with relatively low-cost generation, so retirement should
be limited.
- Collusive ICAP capacity withholding strategies by generators. This
is likely to be unsustainable over the medium-term due to the
fragmented generation market structure, stringent regulatory
oversight, and the ICAP market design.(31)
We have therefore forecast fairly competitive conditions in the ICAP market over
the medium-term and low capacity values for that period, once transitional
effects are excluded. Specific forecasts for capacity are detailed in Section 4.
[FIGURE 40. INDICATIVE INTERNAL INSTALLED CAPACITY SURPLUS IN NEW YORK* LINE
GRAPH]
*Utilizing the 22% control area margin requirement, using base case
assumptions on capacity and new entrants; excludes all import capability
- -----------------------
(31) To be available for sale in the "buy-back" period, capacity must have
been offered in the energy markets over the preceding capability period.
This will tend to undermine ICAP withholding strategies by generators.
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APPENDIX B
10.5 ANCILLARY SERVICES
Ancillary services are the unbundled services that are necessary to facilitate
market operations, by supporting the transmission of energy from generation
resources to loads, while maintaining reliable operations of the New York power
system. Some ancillary services will be provided solely by the NY ISO while
others will be provided either by the NY ISO or procured independently by
transmission customers and suppliers. Furthermore, some ancillary services will
be provided at market-based prices while others will be considered under
embedded-cost methodologies. Table 34 presents a summary of NY ISO Ancillary
Services, their characteristics and the pricing methodologies applied to each
service.(32)
Due to uncertainty over the actual rules to be implemented by the NY ISO we have
not attempted to forecast ancillary services revenue for the AEE portfolio. It
is important to note that the acquired generation is generally less well-placed
than much New York generation to provide spinning reserve and other ancillary
services.
AEE may acquire limited revenue from ancillary services from the smaller, less
efficient units - Hickling and Jennison, including operating reserves and
voltage support. However, ancillary service revenues will accrue at the expense
of actual generation revenue; therefore, making it an uneconomic option for
baseload units such as Kintigh. Due to a load pocket agreement with the NYPP,
Milliken has been needed in the past for local voltage support. This has
occurred for approximately 11% of the time during high load periods. Usually
this has not impeded Milliken from running competitively during those periods.
However, if Milliken cannot run competitively and is needed for local voltage
support, the contract stipulates that under these circumstances NYSEG is allowed
to operate the units at minimum level and will be compensated for above-market
costs of operation through the terms of the agreement. The additional revenue
streams for this service have been insignificant historically, because Milliken
has traditionally run competitively during those specific periods.
- -----------------------------
(32) KEMA Consulting. NYISO Manual for Ancillary Services. June 1998. Section
1, page 1.
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APPENDIX B
TABLE 34. SUMMARY OF ANCILLARY SERVICES
PRODUCT IS THE SERVICE WHO PROVIDES WHO CAN WHAT IS THE PRICING
LOCATION- THE SERVICE? SCHEDULE THE METHOD FOR THE
SPECIFIC? SERVICE? SERVICE?
- -------------------------------------------------------------------------------------------------------------
SCHEDULING, SYSTEM CONTROL No NY ISO NY ISO Embedded
AND DISPATCH SERVICE
- -------------------------------------------------------------------------------------------------------------
VOLTAGE SUPPORT SERVICE Yes NY ISO NY ISO Embedded
- -------------------------------------------------------------------------------------------------------------
REGULATION AND FREQUENCY Yes NY ISO or NY ISO Market-based
RESPONSE SERVICE Third Party and/or self-
supplied
- -------------------------------------------------------------------------------------------------------------
ENERGY IMBALANCE SERVICE No NY ISO NY ISO Market-based and
Energy Payback
- -------------------------------------------------------------------------------------------------------------
OPERATING RESERVE SERVICE Yes NY ISO or NY ISO Market-based
Third Party and/or self-
supplied
- -------------------------------------------------------------------------------------------------------------
BLACK START CAPABILITY Yes NY ISO NY ISO Embedded
SERVICE
10.5.1 SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE
This service includes management of real-time functions such as tie-line
regulation, time error and system restoration, as well as management of capacity
functions such as operating reserve and generator outage scheduling. It includes
all of the NY ISO's costs for scheduling, system control and dispatch. The NY
ISO will levy this service's charge on all transmission services provided,
pursuant to the NY ISO Tariff. The rate will be computed monthly for the
previous month.
10.5.2 VOLTAGE SUPPORT SERVICE
The NY ISO will coordinate reactive power supply and voltage support facilities.
Because of the dynamic nature of the electric power network, it is not always
possible to associate a required voltage support service with a specific
transaction or load; however, voltages on the New York transmission system must
be maintained within acceptable limits. Transmission customers engaged in power
wheeling through the state and all LSEs must purchase voltage support services
from the NY ISO.
Owners of generating resources will submit their reactive power bid information
in the form of piecewise linear capability curves with associated high and low
MVAr capacity limits. The NY ISO will schedule generating resources to operate
within their reactive capability curves. Suppliers of voltage support service
that fail to comply with NY ISO procedures are assessed charges that escalate
with each new failure to comply.
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APPENDIX B
Transmission providers will be responsible for the local control of the
reactive power resources that are connected to their networks.
Suppliers of voltage support service will receive payments monthly, according to
embedded cost calculations. Suppliers whose resources are under contract to
supply ICAP will generally receive the full embedded cost payment for voltage
support while suppliers whose generators are not under contract will receive an
embedded cost payment, prorated by the number of hours operated in that month.
For non-utility generators that are operating under existing power purchase
agreements, the NY ISO will call upon the entity that is engaged in transmission
of the energy or is purchasing energy and/or capacity under such an agreement
for voltage support service. The NY ISO pays this entity for such resources,
based on the NY ISO average $/MVAr rate and the MVAr capacity of the generator.
When existing power purchase agreements are terminated or expire, non-utility
generators may then supply the required embedded cost data to the NY ISO and
receive payments, as these generators are entitled to "Lost Opportunity Cost."
These are the potential costs incurred in the event that the NY ISO directs the
generator to reduce its real power output in order to allow the unit to absorb
or produce more reactive power.
10.5.3 REGULATION AND FREQUENCY RESPONSE SERVICES
Regulation and frequency response services are necessary for the continuous
balancing of resources with load. The NY ISO will establish regulation and
frequency response requirements consistent with criteria established by the
NYSRC, as well as resource performance measurement criteria and procedures for
bidder qualification.
Owners of generating resources that have AGC capability will be able to, but
will not be obligated to, bid on regulation service in the market. The NY ISO
will select regulation service providers from qualified bidders in the day-ahead
market or in the balancing market. For those cases where a unit has been
contracted to supply regulation but is unable to meet the obligation, owners of
the unit will be allowed to execute an agreement whereby another pre-qualified
unit provides regulation. Alternatively, owners of a unit that fails to meet its
obligation may request the NY ISO to purchase regulation in the second
settlement market or supplemental market. In both cases, increases in the cost
to purchase regulation will be paid by the original contract holder. The payment
to providers will based on (1) an hourly availability payment for reserving
capability to provide regulation service; (2) an energy payment based on the
amount of regulation; and (3) a financial penalty based on poor performance as
measured against expectations.
Those electricity suppliers and generators not providing regulation service will
pay the NY ISO a charge based upon regulation needs and market clearing prices
for this ancillary service in the supplemental market and/or the day-ahead
market. In addition, LSEs will pay a charge for regulation service on all
bilateral transactions aimed at serving load in New York. The NY ISO will
calculate charges hourly, based on each LSE's share of the load on the net of
charges to suppliers and payments to suppliers. In all hours where charges to
suppliers exceed payments to suppliers, no
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APPENDIX B
charges will be assessed against LSEs and surpluses will be applied in the
following hour as an offset to subsequent payments.
10.5.4 ENERGY IMBALANCE SERVICE
Energy imbalance is usually reflected in the difference between scheduled and
actual withdrawals and injections into the system due to real-time changes. All
internal energy imbalances (those due to updated data) will be addressed through
the real-time market and through the real-time settlement process. External
energy imbalances occur when there are mismatches between scheduled and actual
flows between the New York control area and other regions. External imbalances
will be accounted for according to NERC guidelines. Any increase or decrease in
costs resulting from inadvertent interchange is included in the NY ISO
Scheduling, System Control and Dispatch Service Charge.
10.5.5 OPERATING RESERVE SERVICE
This service provides backup generation in the event that major generating
resources trip off-line due to either a power system contingency or equipment
failure. In order for the NY ISO to respond in a timely fashion, most of the
reserves must be available from units within specific regions, as required by
the NYSRC. The three types of operating reserves are described below.
1. 10-Minute Spinning Reserves - reserves provided by generators and
interruptible load resources located within the New York control area that
are already synchronized to the New York Power System and can respond to
instructions to change output levels within 10 minutes.
2. 10-Minute Non-Synchronized Reserves - reserves that can be started,
synchronized and loaded within 10 minutes.
3. 30-Minute Reserves - reserves that can produce energy within 30 minutes
Operating Reserves will be traded in the day-ahead market and in the real-time
market. Suppliers offering resources in the day-ahead market will submit
availability bids for each hour of the upcoming day. In the event that suppliers
have uncommitted resources, they may also submit availability bids to provide
operating reserve in the real-time market, where bids can be adjusted from one
hour to the next.
Suppliers that are scheduled day-ahead will be paid the hourly day-ahead
availability price for the type of reserve offered, multiplied by the amount of
that type of reserve scheduled in that hour. When the NY ISO requests, and
suppliers provide, more reserves than are scheduled, suppliers will be paid the
hourly real-time availability price for the type of reserve provided, multiplied
by the amount of that type of reserve provided in that hour. In addition,
suppliers will receive the real-time LBMP for all electricity generated in
accordance with NY ISO instructions. Suppliers of spinning reserve whose output
in the real-time dispatch has been reduced for the purpose of creating spinning
reserve will also be paid for the lost opportunity cost of the
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APPENDIX B
reduction. Non-delivery and poor performance will be penalized. Furthermore,
generators that repeatedly fail to provide operating reserve when called upon
by the NY ISO may be precluded from providing operating reserve in the future.
Payments to suppliers of operating reserve are offset by a monthly charge levied
on LSEs and transmission customers engaged in power export. This charge will be
based on each transmission customer's and each LSE's share of the NY ISO's cost
of providing operating reserves for the month.
10.5.6 BLACK START CAPABILITY SERVICE
Black start capability refers to those generators that, following a system-wide
blackout, can start without the availability of any outside electric supply and
are available to participate in system restoration activities. The NY ISO will
select the generating resources with black start capability by considering the
following characteristics: location, startup time, maximum response rate above
minimum output, and maximum power output. The NY ISO will make black start
capability payments to those selected suppliers who have appropriate equipment
available, based on the embedded costs of the equipment made available. These
payments are adjusted annually. Any generator that has been awarded black start
capability payment and fails a NY ISO black start capability test will forfeit
all of its black start capability receipts since its last successful test. LSEs
will pay the NY ISO a monthly Black Start Capability charge on all transactions
that supply load in New York.
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APPENDIX B
11 APPENDIX C1: MONTHLY TIME-WEIGHTED AVERAGE ENERGY PRICES - BASE CASE (1999
$/MWh)
JAN-99 FEB-99 MAR-99 APR-99 MAY-99 JUN-99 JUL-99 AUG-99 SEP-99 OCT-99 NOV-99 DEC-99 10-MONTH AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP - - 24.1 23.2 21.7 24.0 25.1 26.6 24.3 27.4 26.1 27.5 25.0
DN - - 24.8 27.5 23.8 28.1 31.0 27.2 25.2 27.4 28.1 28.7 27.2
JAN-00 FEB-00 MAR-00 APR-00 MAY-00 JUN-00 JUL-00 AUG-00 SEP-00 OCT-00 NOV-00 DEC-00 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 30.6 31.1 25.8 25.2 21.6 25.0 25.7 26.3 26.9 25.6 25.1 26.1 26.2
DN 30.7 32.1 27.9 27.3 24.0 29.3 30.9 27.2 28.0 26.4 27.2 27.8 28.2
JAN-01 FEB-01 MAR-01 APR-01 MAY-01 JUN-01 JUL-01 AUG-01 SEP-01 OCT-01 NOV-01 DEC-01 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 34.0 37.4 27.0 24.2 24.4 27.3 25.7 24.7 25.7 25.9 26.8 25.9 27.4
DN 34.9 37.7 28.5 26.7 25.2 31.7 31.9 26.1 26.3 27.2 28.2 28.9 29.4
JAN-02 FEB-02 MAR-02 APR-02 MAY-02 JUN-02 JUL-02 AUG-02 SEP-02 OCT-02 NOV-02 DEC-02 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 36.8 36.3 26.0 24.4 22.9 27.0 27.5 27.1 26.1 27.8 29.5 30.1 28.4
DN 37.3 37.4 27.5 26.0 26.2 32.6 32.8 27.9 26.6 29.4 29.6 31.4 30.4
JAN-03 FEB-03 MAR-03 APR-03 MAY-03 JUN-03 JUL-03 AUG-03 SEP-03 OCT-03 NOV-03 DEC-03 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 32.5 31.5 25.9 27.9 22.1 26.0 27.0 25.1 25.0 27.6 28.5 28.4 27.3
DN 33.2 31.7 26.6 27.9 24.0 29.4 30.4 26.1 26.9 27.6 29.6 29.3 28.5
===============================================================================================================================
JAN-05 FEB-05 MAR-05 APR-05 MAY-05 JUN-05 JUL-05 AUG-05 SEP-05 OCT-05 NOV-05 DEC-05 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 25.3 25.3 23.3 21.7 20.1 20.9 21.4 22.7 22.4 22.7 23.5 24.3 22.8
DN 25.6 25.3 24.0 24.2 22.8 27.3 27.4 23.9 23.9 24.6 23.5 25.4 24.8
JAN-10 FEB-10 MAR-10 APR-10 MAY-10 JUN-10 JUL-10 AUG-10 SEP-10 OCT-10 NOV-10 DEC-10 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 27.1 29.9 23.5 23.0 22.2 21.7 23.0 22.0 22.8 23.4 26.3 25.6 24.2
DN 28.0 33.3 24.9 24.2 24.9 28.2 28.0 25.2 23.9 23.4 26.3 25.7 26.3
JAN-15 FEB-15 MAR-15 APR-15 MAY-15 JUN-15 JUL-15 AUG-15 SEP-15 OCT-15 NOV-15 DEC-15 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 28.8 30.6 25.9 24.7 21.7 24.6 24.6 21.9 22.7 25.2 28.6 29.6 25.7
DN 28.9 30.7 27.0 26.6 24.4 30.3 28.5 25.5 24.5 25.2 28.6 29.6 27.5
JAN-20 FEB-20 MAR-20 APR-20 MAY-20 JUN-20 JUL-20 AUG-20 SEP-20 OCT-20 NOV-20 DEC-20 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 25.4 28.9 22.9 21.8 20.7 23.0 22.5 20.6 20.8 23.8 26.8 27.1 23.7
DN 25.9 39.5 24.8 24.5 28.9 35.4 33.1 31.3 28.0 27.1 28.3 27.7 29.5
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APPENDIX B
12 APPENDIX C2: MONTHLY TIME-WEIGHTED AVERAGE ENERGY PRICES - DOWNSIDE CASE
(1999 $/MWh)
JAN-99 FEB-99 MAR-99 APR-99 MAY-99 JUN-99 JUL-99 AUG-99 SEP-99 OCT-99 NOV-99 DEC-99 10-MONTH AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP - - 20.0 22.8 21.3 22.9 24.2 23.5 25.5 24.1 23.9 25.1 23.3
DN - - 21.3 24.1 23.1 26.7 28.2 24.4 25.5 24.4 24.9 26.5 24.9
JAN-00 FEB-00 MAR-00 APR-00 MAY-00 JUN-00 JUL-00 AUG-00 SEP-00 OCT-00 NOV-00 DEC-00 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 27.9 29.0 23.6 23.8 21.0 23.6 23.9 24.1 24.4 23.6 23.2 24.8 24.4
DN 28.6 29.7 24.6 24.2 21.9 26.7 28.1 25.3 24.6 24.6 24.0 26.9 25.7
JAN-01 FEB-01 MAR-01 APR-01 MAY-01 JUN-01 JUL-01 AUG-01 SEP-01 OCT-01 NOV-01 DEC-01 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 30.3 30.9 24.3 20.4 20.7 24.7 24.4 26.6 25.1 25.2 27.0 25.9 25.4
DN 30.5 31.4 24.6 25.3 23.4 28.2 28.9 27.2 25.2 26.2 28.3 26.9 27.1
JAN-02 FEB-02 MAR-02 APR-02 MAY-02 JUN-02 JUL-02 AUG-02 SEP-02 OCT-02 NOV-02 DEC-02 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 33.9 32.6 24.3 24.8 21.7 24.8 25.9 24.8 23.9 25.5 25.3 29.4 26.4
DN 33.9 33.2 25.1 26.5 23.8 29.0 29.9 26.8 27.2 25.9 27.5 29.5 28.1
JAN-03 FEB-03 MAR-03 APR-03 MAY-03 JUN-03 JUL-03 AUG-03 SEP-03 OCT-03 NOV-03 DEC-03 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 29.3 29.0 24.4 22.2 21.0 24.8 25.3 23.1 24.5 25.0 25.0 26.7 25.0
DN 29.3 29.9 25.7 24.6 21.7 27.2 27.7 23.9 24.5 25.2 26.0 27.2 26.0
===============================================================================================================================
JAN-05 FEB-05 MAR-05 APR-05 MAY-05 JUN-05 JUL-05 AUG-05 SEP-05 OCT-05 NOV-05 DEC-05 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 23.9 23.3 20.6 20.5 19.2 19.3 19.4 18.9 20.3 20.9 22.2 23.4 21.0
DN 24.4 23.7 22.7 20.6 21.2 24.2 24.3 21.6 21.5 22.4 22.4 23.7 22.7
JAN-10 FEB-10 MAR-10 APR-10 MAY-10 JUN-10 JUL-10 AUG-10 SEP-10 OCT-10 NOV-10 DEC-10 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 25.0 26.2 21.9 21.9 19.1 20.2 20.3 20.1 21.4 21.3 23.6 24.7 22.1
DN 25.0 26.7 23.5 23.3 22.2 26.2 26.2 24.0 24.1 22.8 24.1 24.9 24.4
JAN-15 FEB-15 MAR-15 APR-15 MAY-15 JUN-15 JUL-15 AUG-15 SEP-15 OCT-15 NOV-15 DEC-15 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 26.0 26.6 23.5 22.7 20.3 22.2 21.3 19.8 20.3 24.1 25.8 26.0 23.2
DN 26.4 28.2 24.3 23.9 23.6 29.6 27.5 25.0 22.4 24.7 27.2 28.3 25.9
JAN-20 FEB-20 MAR-20 APR-20 MAY-20 JUN-20 JUL-20 AUG-20 SEP-20 OCT-20 NOV-20 DEC-20 ANNUAL AVERAGE
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ----------------
UP 24.8 25.2 21.5 20.2 19.6 21.3 20.9 18.7 19.7 22.2 24.1 26.1 22.0
DN 26.6 27.9 25.9 30.4 29.7 34.0 33.9 30.4 28.2 27.2 27.6 29.2 29.3
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APPENDIX B
13 APPENDIX D: CORRELATION OF REGIONAL US POWER PRICES
This appendix provides some simple calculations of correlation coefficients for
key US markets, from day ahead contract prices reported by Power Markets
Week.(33) Markets that show positive correlation - generally those which are
close geographically - present opportunities for increasing the diversity of
transactions and to gain a better understanding of inter-market relationships.
Markets which show strong negative correlation would present opportunities for
enhanced risk management.
- -----------------------------------------------------------------------------------------------------------
Matrix of Correlation Coefficients - selected NERC sub-regions
- -----------------------------------------------------------------------------------------------------------
ECAR ERCOT FLGEO PJM MAIN MAPP NYE NEPOOL
- -----------------------------------------------------------------------------------------------------------
ECAR 1 0.3538 0.9301 0.6883 0.9357 0.7978 0.683 0.2371
ERCOT 0.3538 1 0.3332 0.5807 0.3011 0.355 0.4835 0.1695
FLGEO 0.9301 0.3332 1 0.6014 0.991 0.8769 0.6083 0.2064
PJM 0.6883 0.5807 0.6014 1 0.6258 0.7039 0.9378 0.3181
MAIN 0.9357 0.3011 0.991 0.6258 1 0.8877 0.6389 0.2173
MAPP 0.7978 0.355 0.8769 0.7039 0.8877 1 0.6682 0.2126
NYE 0.683 0.4835 0.6083 0.9378 0.6389 0.6682 1 0.4652
NEPOOL 0.2371 0.1695 0.2064 0.3181 0.2173 0.2126 0.4652 1
NYW 0.7489 0.5424 0.6868 0.9124 0.695 0.7025 0.9138 0.4924
ENTINTO 0.9526 0.3799 0.9351 0.7568 0.9575 0.8936 0.7446 0.2303
SEEXFL 0.9814 0.4218 0.9291 0.7668 0.9306 0.8122 0.7578 0.2425
SWPP 0.9578 0.3453 0.9815 0.6616 0.9826 0.8975 0.6586 0.2188
COB -0.0903 -0.1671 -0.098 -0.0569 -0.0808 -0.0393 -0.0521 -0.0701
FRCOR -0.0537 0.0377 -0.042 0.0276 -0.05 0.0003 -0.048 -0.0935
MIDCOL -0.0567 -0.1459 -0.066 -0.0765 -0.0515 -0.0221 -0.067 -0.1402
PALOVER -0.0517 0.0375 -0.0401 0.0173 -0.0477 -0.0038 -0.0649 -0.1125
- -----------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------
Matrix of Correlation Coefficients - selected NERC sub-regions
- ----------------------------------------------------------------------------------------------------------------
ENT- SE MID PALO
NYW INTO EXFL SWPP COB FRCOR COL VER
- ----------------------------------------------------------------------------------------------------------------
ECAR 0.7489 0.9526 0.9814 0.9578 -0.0903 -0.0537 -0.0567 -0.0517
ERCOT 0.5424 0.3799 0.4218 0.3453 -0.1671 0.0377 -0.1459 0.0375
FLGEO 0.6868 0.9351 0.9291 0.9815 -0.098 -0.042 -0.066 -0.0401
PJM 0.9124 0.7568 0.7668 0.6616 -0.0569 0.0276 -0.0765 0.0173
MAIN 0.695 0.9575 0.9306 0.9826 -0.0808 -0.05 -0.0515 -0.0477
MAPP 0.7025 0.8936 0.8122 0.8975 -0.0393 0.0003 -0.0221 -0.0038
NYE 0.9138 0.7446 0.7578 0.6586 -0.0521 -0.048 -0.067 -0.0649
NEPOOL 0.4924 0.2303 0.2425 0.2188 -0.0701 -0.0935 -0.1402 -0.1125
NYW 1 0.7586 0.8074 0.7143 -0.0058 0.0313 -0.0469 0.0272
ENTINTO 0.7586 1 0.9503 0.9736 -0.0806 -0.0433 -0.0522 -0.043
SEEXFL 0.8074 0.9503 1 0.9489 -0.1006 -0.0532 -0.0699 -0.0496
SWPP 0.7143 0.9736 0.9489 1 -0.0933 -0.0401 -0.0617 -0.0406
COB -0.0058 -0.0806 -0.1006 -0.0933 1 0.7697 0.9443 0.7745
FRCOR 0.0313 -0.0433 -0.0532 -0.0401 0.7697 1 0.6445 0.9693
MIDCOL -0.0469 -0.0522 -0.0699 -0.0617 0.9443 0.6445 1 0.6305
PALOVER 0.0272 -0.043 -0.0496 -0.0406 0.7745 0.9693 0.6305 1
- ----------------------------------------------------------------------------------------------------------------
- ------------------------
(33) The calculations were performed for the past twelve months (October 1997
through September 1998). Expanding the focus to longer time periods, or
narrowing it to look at seasonal relationships, may reveal different
patterns.
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APPENDIX B
[PAGE LEFT BLANK INTENTIONALLY]
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Appendix C
PITTSBURGH SEAM
MARKET STUDY
Prepared For
AES EASTERN ENERGY, L.P.
By
JOHN T. BOYD COMPANY
MINING AND GEOLOGICAL CONSULTANTS
Pittsburgh, Pennsylvania
[JTB LOGO]
Report No. 2723.1E
APRIL 1999
401
[JOHN T. BOYD COMPANY LETTERHEAD]
April 1, 1999
File: 2723.1E
AES Eastern Energy, L.P.
1001 North 19th Street
Arlington, VA 22209
Subject: Pittsburgh Seam Market Study
Gentlemen:
This report presents our findings relative to the availability and projected
market prices for Pittsburgh Seam coals which may be employed in AES Eastern
Energy, L.P. fuel strategies.
Our regional study area covers the northern portion of the Appalachian Coalfield
(eastern Ohio, western Pennsylvania, and northern West Virginia). A discussion
of specific potential suppliers and estimated f.o.b. mine prices are included.
Price forecasts are expressed in both current dollars and constant mid-1998
dollars for the period 1999 through 2010. An overview of District 1 (central
Pennsylvania) production is also included.
We believe this report will provide a useful guide to AES Eastern Energy, L.P.
in assessing coal supply alternatives and developing a near- and mid-term coal
supply strategy for their coal-fired stations.
Respectfully submitted,
JOHN T. BOYD COMPANY
By: /s/James W. Boyd
James W. Boyd
President
402
TABLE OF CONTENTS
Page
----
LETTER OF TRANSMITTAL
TABLE OF CONTENTS
EXECUTIVE SUMMARY ............................................................. 1-1
GENERAL STATEMENT ............................................................. 2-1
Figure
2.1: Map of Northern Appalachian Coalfield Showing Coal
Producing Districts and Approximate Limit of Coal
Measures ......................................................... 2-3
COAL SUPPLY ................................................................... 3-1
DEMAND ......................................................................... 4-1
Tables
4.1: 1997 Utility Deliveries by Sulfur Dioxide Content from
Selected Mines in the Study Region ............................... 4-16
4.2: District 1 Utility Distribution by Receiving State (1994-1997) ..... 4-17
4.3: Operating Scrubbed Stations East of the Mississippi River .......... 4-18
4.4: Estimated FOB Mine Coal Price for Pittsburgh Seam
Suppliers (Constant Mid-1998 Dollars) ............................ 4-19
4.5: Estimated FOB Mine Coal Price for Pittsburgh Seam
Suppliers (Current Year's Dollars) ............................... 4-20
4.6: Pittsburgh Seam Coal, Estimated Term Coal Prices ................... 4-21
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EXECUTIVE SUMMARY
The AES Corporation (AES) has retained John T. Boyd Company (BOYD) to
analyze the market for coals supplied to northeastern U.S. utilities from
Maryland, eastern Ohio, Pennsylvania, and northern West Virginia, to support an
offering of pass-through trust certificates and lease equity to be issued
relative to a leveraged lease financing by AES Eastern Energy, L.P. (AEE) of the
acquisition of coal-fired electric generating stations from New York State
Electric and Gas Corporation (NYSEG). These areas are defined as coal producing
Districts 2, 3, 4, and 6. This analysis includes a review of supply sources,
supply availability, demand, and impacts of the Clean Air Act Amendments (CAAA).
Our study focuses primarily on major Pittsburgh Seam producers (within
Districts 2, 3, 4, and 6). In 1997, Districts 2, 3, 4 and 6, delivered
approximately 6.9 million tons of the 8.4 million tons delivered to coal-fired
stations located in New York. This represents approximately 82% of the total
coal purchased by New York generating stations.
We have also completed an overview of District 1 which includes central
Pennsylvania, western Maryland, and three counties in northern West Virginia.
Coals from District 1 were examined due to their regional proximity to the NYSEG
stations; however, only minimal quantities of these coals (218,000 tons or about
3% of total New York coal consumption) were shipped to New York stations in
1997.
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CURRENT PRODUCTION
In 1997, Districts 1, 2, 3, 4, and 6 produced approximately 152 million
tons. The five largest producers in 1997 were Consolidation Coal Company (CONSOL
Inc.), American Electric Power Company (AEP), Cyprus Amax Coal Company (Cyprus
Amax), Ohio Valley Coal Co. (Ohio Valley), and Peabody Holding Company
(Peabody). These five operators produced approximately 78 million tons from the
Pittsburgh Seam during 1997.
Pittsburgh Seam Operations
Pittsburgh Seam mines account for approximately 50% of Districts 1, 2,
3, 4 and 6 production (70% of the underground production), and include most of
the low cost, high volume supply sources delivering to utilities in New York
State. Following are selected Pittsburgh Seam producing mines along with 1997
production, sulfur (content (expressed as lbs SO(2)/MM Btu), and estimated
production cost range:)
1997 Estimated
Production Production
(Tons Lbs SO(2)/ Cost Range
Company Mine District millions) MM Btu ($/Ton)
------- ---- -------- --------- ------ -------
CONSOL Inc. Bailey 2 7.5 2.35 14 - 17
Blacksville No. 2 3 3.4 4.50 20 - 22
Enlow Fork 2 8.4 2.35 14 - 17
Loveridge 3 4.8 4.50 21 - 23
McElroy 6 5.2 6.30 19 - 21
Robinson Run 3 4.8 5.80 21 - 23
Shoemaker 6 4.8 6.30 19 - 21
Cyprus Amax Coal Co. Cumberland 2 6.3 4.50 19 - 22
Emerald 2 4.7 2.25 22 - 23 *
Peabody Coal Co. Federal No. 2 3 4.1 3.60 19 - 21
R & P Coal Co. Mine 84 ** 2 4.8 2.75 22 - 25
(CONSOL Inc.)
Ohio Valley Coal Co. Powhatan No. 6 4 5.1 6.50 18 - 21
* Based on projected operations in 1999 and beyond where a new longwall
installed nearer the slope and sealing of abandoned areas will reduce
operating costs.
** Full production was scheduled for 6.7 million tons; however, in 1998
CONSOL Inc. purchased the mine and significantly reduced the workforce.
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FUTURE SUPPLY
BOYD believes that decreases in supply caused by closing of existing
mining operations or increases in demand caused by additional generating
stations installing flue gas desulfurization (FGD) systems will be primarily met
by incremental production from existing Pittsburgh Seam mines and by development
of brownfield sites. Ohio Valley Coal Company is currently seeking re-permitting
of the former Youghiogheny & Ohio Coal Company's Allison Mine (idled in 1980)
with the intent to produce 6 million tons per year (tpy) of high sulfur coal
utilizing the existing mine slope. CONSOL Inc. is increasing capacity in Bailey
and Enlow Fork Mines for a combined 20 million tpy production increase.
It is our opinion the recoverable reserves at active Pittsburgh Seam
operations are sufficient to support production at their 1997 production levels
for a significant period of time. Pittsburgh Seam coal producers (CONSOL Inc.,
Peabody Coal Co., and Cyprus Amax Coal Co.) have stated in filings with the
Securities and Exchange Commission (SEC), that there are nearly 1.9 billion
assigned or accessible recoverable reserves associated with their active mines.
The 1997 production from these mines was 58.8 million tons. At 1997 production
levels, these active Pittsburgh Seam operations have sufficient reserves to
sustain mining for the next 32 years. Existing mines will develop/acquire
additional reserves to expand operations if demand increases and as existing
reserves are exhausted.
COAL PRODUCING DISTRICT 1
District 1 includes mines located in central Pennsylvania, Maryland,
and a portion of northeastern West Virginia. The region is characterized by
numerous smaller mining operations. Of the 251 mines operating in 1997, only 16
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(approximately 6%) produced more than 500,000 tons. These 16 mines produced a
total of 15 million tons, or 44% of all coal produced in District 1. We expect
the number of operating mines to continue to decline due to coal quality and
cost of production. Pittsburgh Seam production from District 2 will primarily
provide the replacement tonnages. However, many of these mines will continue to
be viable coal supply sources for high sulfur coal, particularly to local
generating facilities.
SULFUR DIOXIDE LIMITATIONS
Sulfur dioxide (SO(2)) limitations have impacted regional coal supply
patterns and increased demand for lower sulfur coals. Of the 261 units in the
United States affected by CAAA Phase 1, SO(2) restrictions, an estimated 173
units (66%) either have been switched to lower sulfur coals or a blend of
various quality coals, while 28 units (11%) have been or are being equipped with
FGD systems. Currently, there are 55 coal-fired generating stations (103 units)
east of the Mississippi River utilizing FGD systems. These units purchased 146
million tons of coal in 1997. BOYD believes the coal market to stations equipped
with FGD systems will expand due to installation of additional FGD systems to
meet the requirements of CAAA Phase 2 SO(2) restrictions. BOYD also believes
that the imposition of CAAA Phase 2 SO(2) restrictions will increase demand
for low sulfur coal by plants that do not install FGD systems.
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FOB MINE PRICE FORECAST
The price of Pittsburgh Seam coals has been declining in real terms.
BOYD projects that this trend will continue, as shown in the following summary
of projected f.o.b. mine steam coal prices:
Contract Price Spot Price
------------------------- -------------------------
District: 2 & 3 4 & 6 2 & 3 4 & 6
---------------- ------ ---------------- ------
lbs SO2/MM Btu: <2.5 2.5-4.0 >4.0 <2.5 2.5-4.0 >4.0
Btu/lb: 12,800 12,800 12,500 12,800 12,800 12,500
Constant Mid-1998 Dollars
-------------------------
1999 25.30 23.85 20.25 24.00 22.70 19.20
2000 25.05 23.70 20.10 23.80 22.50 19.10
2005 24.00 23.00 19.40 23.60 22.35 19.00
2010 23.50 21.90 18.40 23.30 21.70 18.20
Current Year's Dollars
----------------------
1999 25.70 24.20 20.55 24.35 23.05 19.50
2000 26.00 24.60 20.85 24.70 23.35 19.80
2005 28.80 27.60 23.30 28.35 26.80 22.80
2010 32.70 30.45 25.60 32.40 30.20 25.30
BOYD has also projected low and high case contract coal f.o.b. mine
prices. The following shows a summary of BOYD's low and high case prices in
constant mid-1998 dollars per ton:
FOB Mine Prices (Constant Mid-1998
--------------------------------------
$/Ton)
------
District: 2 & 3 4 & 6
------------------- ------
lbs SO2/MM Btu: <2.5 2.5 - 4.0 >4.0
Btu/lb: 12,800 12,800 12,500
Low
---
1999 21.50 19.50 18.50
2000 21.50 19.20 18.35
2005 20.90 18.98 18.20
2010 20.45 18.00 17.00
High
----
1999 26.55 25.05 21.25
2000 26.55 25.10 21.30
2005 26.65 25.55 21.55
2010 26.30 24.55 20.60
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GENERAL STATEMENT
The objective of this study is to evaluate market prices and
availability for coals in the northern portion of the Appalachian Coalfield from
1999 through 2010. Coals at three sulfur dioxide levels (less than 2.5 lbs/MM
Btu, 2.5 to 4.0 lbs/MM Btu, and greater than 4.0 lbs/MM Btu) were analyzed. Coal
pricing is expressed in both constant mid-1998 and current year's dollars.
This report reviews potential coal supply areas within four bituminous
coal-producing districts:
District Geographical Description
-------- ------------------------
2 Western Pennsylvania
3 Northern West Virginia, excluding Panhandle Region
(District 6) and Grant, Mineral, and Tucker Counties
(portion of District 1)
4 (Eastern) Ohio
6 West Virginia Panhandle (Brooke, Hancock, Marshall,
and Ohio Counties)
Districts are defined per The Bituminous Coal Act of 1937. Figure 2.1, following
this text, shows the approximate location of the producing districts within the
regional study area.
The Pittsburgh Seam is of special interest because of its supply
dominance (volume and competitive economics), large in-place production
capacity, and proximity to river-borne and rail transportation. Coal supply of
District 1 (Central Pennsylvania, Maryland, and Grant, Mineral and Tucker
Counties, West Virginia) is also examined in brief.
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This market analysis is based on BOYD's extensive knowledge of the coal
industry within the regional study area and our numerous databases of published
information on coal production, coal reserves, coal prices, etc. Price forecasts
represent BOYD's professional judgment using available market conditions.
Unforeseen changes or new developments (e.g., environmental regulation) could
substantially affect future coal demand, quality needs, and prices. For this
reason, we do not warrant the conclusions of this report in any manner, but we
believe our conclusions can be used to assist in fuel supply planning.
BOYD understands this report will be:
- Used by, among others, the prospective purchasers of the
pass-through-trust certificates in evaluating the market for coal
supplied to northeastern U.S. utilities from the Pittsburgh Seam.
- Included in reliance upon our authority as experts in coal supplied to
northeastern U.S. utilities from the Pittsburgh Seam as an appendix to
the prospectus relating to an exchange offer for the pass-through-trust
certificates.
Respectfully submitted,
JOHN T. BOYD COMPANY
By:
/s/Frank A. Hilty
-----------------
Frank A. Hilty
Mining Engineer
/s/Robert M. Quinlan
--------------------
Robert M. Quinlan
Senior Vice President
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[MAP OF NORTHERN APPALACHIAN COAL FIELD]
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COAL SUPPLY
INTRODUCTION
The study area includes Coal Producing Districts 1, 2, 3, 4, and 6
(western and central Pennsylvania, northern West Virginia and eastern Ohio).
The U.S. coal industry has historically experienced little market
discipline, generally subscribing to the principle that more tons produced with
concurrent sales (even at lower incremental pricing) is the appropriate
strategy. When demand is equal to or exceeds supply, new producers typically
enter the marketplace and existing producers increase output. This trend should
lessen as industry consolidation continues and the number of mining operations
declines.
One of the effects of the CAAA was the consolidation of the high sulfur
coal industry. Lower prices, combined with other competitive pressures, resulted
in the closure of many higher sulfur mines, particularly in Pennsylvania, Ohio,
and northern West Virginia (as well as Illinois and western Kentucky in the
Midwest). The effects
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of this consolidation are seen in the following combined statistics for the
regional study area (Districts 2, 3, 4, and 6) and including District 1:
Surface Underground Total
------------------- ------------------- -------------------
District Year Mines Tons (000) Mines Tons (000) Mines Tons (000)
-------- ---- ----- ---------- ----- ---------- ----- ----------
1 1997 207 18,427 44 15,924 251 34,351
1996 216 17,806 36 16,663 252 34,469
1995 256 16,765 43 16,527 299 33,292
1994 263 18,513 49 17,192 312 35,705
2 1997 21 1,370 14 39,682 35 41,052
1996 27 1,354 13 36,094 40 37,448
1995 28 1,073 15 30,977 43 32,050
1994 30 1,563 21 27,577 51 29,140
3 1997 29 5,259 50 29,032 79 34,291
1996 37 5,047 58 29,377 95 34,424
1995 47 7,124 59 30,574 106 37,698
1994 52 8,352 73 33,311 125 41,663
4 1997 79 13,846 9 16,892 88 30,738
1996 85 12,628 9 15,908 94 28,536
1995 97 12,581 8 12,910 105 25,491
1994 104 15,993 10 13,595 114 29,588
6 1997 - - 3 11,543 3 11,543
1996 1 10 3 10,070 4 10,080
1995 - - 3 8,986 3 8,986
1994 2 105 4 8,912 6 9,017
Region 1997 336 38,902 120 113,073 456 151,975
1996 366 36,845 119 108,112 485 144,957
1995 428 37,543 128 99,974 556 137,517
1994 451 44,526 157 100,587 608 145,113
Source: Mine Safety and Health Administration Form 7000-2.
Since 1994, the number of surface and underground mines in this region
has declined by 25% and 24%, respectively. Some of the mine losses occurred in
response to the CAAA provisions. Another significant factor was the continuing
pressure on operating margins due to real decreases in market prices offset only
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partially by productivity gains. Although there are approximately 25% fewer
mines (608 mines in 1994 as compared with 456 mines in 1997), total coal
production has increased from 145 million tons in 1994 to approximately 152
million tons in 1997 (5% increase). Underground mines increasingly account for a
greater portion of the region's production, replacing lost surface mine
production capacity. A lesser number of mines producing more coal is due in part
to higher production from individual longwall-equipped Pittsburgh Seam mines.
Most Pittsburgh Seam mines have a production capacity of 3.0 million tpy or
more, with the largest producer approaching 10 million tpy. Pittsburgh Seam
mines dominate the study region and will be the focus of this report. These
mines produce approximately 50% of the region's production (70% of the
underground production) and include some of the lowest cost supply sources
producing at volume.
PITTSBURGH SEAM
The Pittsburgh Seam is one of the major coal deposits in the eastern
U.S. Pittsburgh Seam coal producers have stated in filings with the SEC that
there are nearly 1.9 billion assigned or accessible recoverable reserves
associated with their current mines. Depending on location, there are wide
variations in characteristics of the Pittsburgh Seam coal; for example:
- Depth varies from outcropping to over 2,000 ft.
- Thickness varies from under 4 ft to over 8 ft.
- Sulfur content (washed) varies from under 1 percent to over 4
percent.
Stage of development varies from undeveloped, speculative acreage having no
prospect for mining in the foreseeable future, to coals actively mined as part
of the
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most productive and valuable mines in the U.S. These underground mines employ
similar mining techniques and are equipped with longwall faces.
Following are selected Pittsburgh Seam producing mines along with 1997
production, sulfur content (expressed in lbs SO(2)/MM Btu), and estimated
production cost range:
1997 Estimated
Production Production
(Tons Lbs SO(2) Cost Range
Company Mine District millions) MM Btu ($/Ton)
- --------------- ----------------- -------- ----------- -------- ----------
CONSOL Inc. Bailey 2 7.5 2.35 14 - 17
Blacksville No. 2 3 3.4 4.50 20 - 22
Enlow Fork 2 8.4 2.35 14 - 17
Loveridge 3 4.8 4.50 21 - 23
McElroy 6 5.2 6.30 19 - 21
Robinson Run 3 4.8 5.80 21 - 23
Shoemaker 6 4.8 6.30 19 - 21
Cyprus Amax Coal Co. Cumberland 2 6.3 4.50 19 - 22
Emerald 2 4.7 2.25 20 - 23 *
Peabody Coal Co. Federal No. 2 3 4.1 3.60 19 - 21
R & P Coal Co. Mine 84 ** 2 4.8 2.75 22 - 25
(CONSOL Inc.)
Ohio Valley Coal Co. Powhatan No. 6 4 5.1 6.50 18 - 21
* Based on projected operations in 1999 and beyond where a new longwall
installed nearer the slope and sealing of abandoned areas will reduce
operating costs.
** Full production was scheduled for 6.7 million tons; however, in 1998
CONSOL Inc. purchased the mine and significantly reduced the work
force.
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The lowest sulfur mines are located in eastern and southern Washington
and northern Greene Counties, Pennsylvania (District 2). Pittsburgh Seam sulfur
content increases toward the south and west, with mines in southern Greene
County, Pennsylvania (District 2), and Monongalia and Marion Counties, West
Virginia (District 3), exhibiting a higher sulfur content than those in District
2. Highest sulfur mines are located in the West Virginia panhandle counties of
Brooke and Marshall (District 6) and eastern Ohio (District 4).
In 1997 the study region (excluding District 1) produced approximately
116 million tons (99 million tons from mines producing in excess of 500,000
tpy). In 1997 the five largest producers were Consolidation Coal Company (CONSOL
Inc.), American Electric Power Company (AEP), Cyprus Amax Coal Company (Cyprus
Amax), Ohio Valley Coal Co. (Ohio Valley), and Peabody Holding Company
(Peabody). The five largest operators produced approximately 78 million tons
from the Pittsburgh Seam. The following shows historic production within the
study region covering production from mines having an annual output of more than
500,000 tpy:
Tons Produced (000)
--------------------------------------------
1997 1996 1995 1994
--------------------------------------------
CONSOL Inc. 48,145 45,835 45,429 46,222
AEP 9,694 8,931 6,830 6,771
Cyprus Amax 11,070 8,558 8,365 7,428
Ohio Valley 5,012 4,741 3,946 4,450
Peabody 4,067 4,580 5,098 5,659
All Other Mines Producing Greater
Than 500,000 tpy 20,657 20,976 16,947 16,594
Total Production of Mines Producing
Greater Than 500,000 tpy 98,755 93,621 86,615 87,124
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The long-term future of the AEP mines is uncertain with likely phased closure
due to their higher cost under pending utility deregulation.
NEW CAPACITY
Market analysis must consider the potential impact of new mining
capacity on the long-term coal price structure. There are sufficient undeveloped
Pittsburgh Seam reserves to enable the development of numerous new Pittsburgh
Seam longwall mines. However, based on BOYD's analysis, current and foreseeable
market prices do not justify the capital investment required to develop new
greenfield capacity.
Mine development risk has increased considerably in recent years with
the prominence of shorter term contracts and contracts which permit wide
latitude on shipment volume. Pittsburgh Seam underground longwall mines are
large-scale projects that require considerable lead time from project
authorization to first production. Since commitments for contract sales are of
typically shorter durations, mine development requires major capital commitment
before knowing the sales environment that will exist when the mine reaches full
production. Utilities also find themselves in a high risk environment with the
advent of power market deregulation and are unable to commit to longer term
supply and/or pricing agreements that could support the development of major new
mine production capacity.
Coal prices required for a viable new mining project exceed current
Pittsburgh Seam prices by approximately $5 to $10 per ton. CONSOL Inc. has
publicly indicated that realizations approaching $30 per ton FOB mine
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are necessary to justify opening a new Pittsburgh Seam mine having the
production economics of Bailey or Enlow Fork.
BOYD believes that decreases in supply caused by closing of existing
mining operations or increases in demand caused by additional generating
stations installing FGD systems will be met by incremental production from
existing mines and by development of brownfield sites. Ohio Valley Coal Company
is currently seeking to re-permit the closed Allison Mine (Belmont County, Ohio,
formerly owned and operated by Youghiogheny & Ohio Coal Company). The longwall
mine will produce 6 million tpy of high sulfur coal accessed through the
existing slope. CONSOL Inc. is also adding capacity in Bailey and Enlow Fork
Mines to increase production of the combined mines to the
20-million-ton-per-year level.
BOYD has examined the recoverable reserves of the major Pittsburgh Seam
mines as reported in the respective companies' filings with the SEC. The
following is a list of the major Pittsburgh Seam mines and their remaining
assigned and accessible recoverable reserves as of January 1, 1999:
Estimated
Assigned and Accessible
Recoverable Reserve
Company Mine Tons (millions)
- ------------------------ ------------------- -----------------------
CONSOL Inc. Bailey 204
Blacksville No. 2 144
Dilworth 20
Enlow Fork 207
Loveridge No. 22 156
McElroy 227
Mine 84 155
Robinson Run No. 95 148
Shoemaker 142
Eastern Assoc. Coal Corp. Federal No. 2 62
Maple Creek Mining Co. Maple Creek NA
Mon-View Mining Co. Mathies NA
Ohio Valley Coal Co. Powhatan No. 6 NA
Cyprus Amax Coal. Cumberland 423
-----
Emerald
1,888
NA=Not available.
Based on the 1997 production (approximately 58.8 million tons for mines with
identified reserves) and recoverable reserves at these Pittsburgh Seam
operations, there are sufficient coal reserves available to sustain production
of current levels for more than 32 years. There
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are significant reserves located in properties adjacent to those controlled by
operating mines which could be acquired and developed as brownfield sites.
In our opinion, approximately 70% of the demonstrated reserve base is
of the mid to high sulfur quality (i.e., greater than 3.3 lbs SO(2)/MM Btu).
Major producers of +4.0 lbs SO(2)/MM Btu coal include:
Tons
(millions)
----------
CONSOL Inc. 23.0
Cyprus Amax 6.3
Ohio Valley 5.1
Central/Southern Ohio Coal Co. 8.0
There are numerous smaller coal producers capable of producing a high
sulfur product for delivery to AEE.
Due to the availability of +4.0 lbs SO(2)/MM Btu reserves and
suppliers, it is our opinion the closure of any one longwall operation in the
study region will have minimal effect on regional pricing in the market study
area.
OVERVIEW OF DISTRICT 1
District 1 includes mines located in central Pennsylvania, Maryland,
and a portion of northeastern West Virginia. The region is characterized by
numerous smaller mining operations. Of the 251 mines operating in 1997, only 16
(approximately 6%) produced more than 500,000 tons. These 16 mines
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produced a total of 15 million tons, or 44% of all coal produced in District 1.
Following is a summary of District 1 production (1994 through 1997):
Mines Producing over
All Producing Mines 500,000 tpy
------------------- ---------------------
Total Total
Production Production
Year Number Tons (000) Number Tons (000)
---- ------ ---------- ------ ----------
1997 251 34,351 16 14,989
1996 252 34,469 13 16,368
1995 299 33,292 14 14,880
1994 312 35,705 16 16,935
The eastern portion of District 1 is medium and low volatile rank coals, with a
substantial portion of the coals throughout District 1 high in sulfur content,
which limit their marketability for the most part to local generating
facilities.
RAILROAD ACCESS
Norfolk Southern (NS) and CSX Transportation (CSXT) are currently
purchasing portions of Consolidated Rail Corporation (Conrail). As a result of
the merger, most Pittsburgh Seam producers will have dual access to the NS and
CSXT (Powhatan No. 6 and Mine 84 will have only NS carrier service). Producers
and coal buyers will benefit from increased potential markets opened up by
Conrail's dissolution. The new markets will increase the demand for Pittsburgh
Seam coals which may increase prices if suppliers do not increase capacity to
compensate. BOYD believes new capacity will be installed as prices justify
economic development.
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Conrail was the rail carrier that served all of the NYSEG stations.
With the sale of Conrail, the Kintigh (Somerset) station will now be served by
the CSXT while the Greenidge, Goudey, and Milliken stations will be served by
the NS. Both the CSXT and NS will have joint access to some of the Pittsburgh
Seam mines. Additionally, the NS has the right to transport some quantities
(about 600,000 tons) on CSXT lines as part of the Surface Transportation Board
ruling on the sale.
The Conrail sale should increase rail competition in the study region
and could lead to lower rail rates to the AEE stations. Additionally, AEE is
evaluating access to the stations from various shortline railroads, which may
provide other alternative delivery options. The sale of Conrail does not appear
to provide any transport disadvantages to AEE and could lead to service
improvements.
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DEMAND
------
This report divides the study region into three categories defined by
sulfur content (expressed in SO(2)/MM Btu). For the purposes of this report,
high sulfur coal is greater than 4.0 lbs SO(2)/MM Btu, medium sulfur coal
contains between 2.5 and 4.0 lbs SO(2)/MM Btu, and low sulfur contains less than
2.5 lbs SO(2)/MM Btu. A distribution of recent sales in the steam coal market
from the supply region of interest is summarized by lbs SO(2)/MM Btu as follows:
Tons (000)
Lbs SO(2)/MM Btu: <2.5 2.5-4.0 >4.0 Total
------- ------- ------ -------
District Year
1 1997 6,359 20,140 2,973 29,472
1996 7,223 21,006 1,556 29,785
1995 9,656 17,265 2,372 29,293
1994 7,601 19,260 2,626 29,487
2 1997 14,474 12,457 1,045 27,976
1996 10,918 11,453 948 23,319
1995 12,734 6,117 528 19,379
1994 9,068 9,361 1,748 20,177
3 1997 7,612 10,638 7,826 26,076
1996 7,185 10,771 7,259 25,215
1995 6,114 10,899 6,425 23,438
1994 7,223 11,778 6,669 25,670
4 1997 5 1,346 23,894 25,245
1996 194 782 23,815 24,791
1995 269 579 20,477 21,325
1994 246 961 26,622 27,829
6 1997 399 204 12,343 12,946
1996 - - 10,518 10,518
1995 - 3 9,361 9,364
1994 - 3 9,127 9,130
Region 1997 28,848 44,785 48,080 121,713
1996 25,520 44,011 44,096 113,628
1995 28,773 34,863 39,161 102,797
1994 24,139 41,363 46,792 112,294
Source: Federal Energy Regulatory Commission (FERC) Form 423.
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Based on analysis of 1997 FERC records, approximately 78% (93 million
tons) of the tons produced in Districts 1, 2, 3, 4, and 6, and delivered to
electric utilities, were greater than 2.5 lbs SO(2)/MM Btu. The preceding table
shows a large quantity of District 2, mostly Pittsburgh Seam, coal less than 2.5
lbs SO(2)/MM Btu and may not be representative of the available tons at that
quality. The following shows District 2 tons between 2.3 and 2.5 lbs SO(2)/MM
Btu as compared with the total less than 2.5 lbs SO(2)/MM Btu.
Tons (000) % of <2.5
By SO(2)/MM Btu Level in 2.3 to
Year 2.3 to 2.5 <2.5 2.5 Range
---- ---------- ------ ---------
1997 6,307 14,474 43.5
1996 4,787 10,918 43.8
1995 6,536 12,734 51.3
1994 3,974 9,068 43.8
A contract sulfur dioxide specification for less than 2.5 lbs SO(2)/MM Btu may
be difficult for Pittsburgh Seam suppliers to guarantee. In 1997 approximately
44% of all coal less than 2.5 lbs SO(2)/MM Btu was in the narrow band of 2.3 to
2.5 lbs SO(2)/MM Btu.
Table 4.1, following this text, summarizes tons delivered in 1997 to
utilities sorted by District and sulfur level. All mines shown delivered more
than 0.5 million tons to the utility sector.
BOYD has also analyzed the coal markets of the producers in District 1.
The size of the utility market for District 1 coals is approximately 30 million
tpy. Approximately 77% of utility deliveries from District 1 are consumed by
utilities in Pennsylvania. Table 4.2, following this text, shows quantity and
quality of District 1
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coal deliveries by receiving state for 1994-1997. In 1997 nearly 69% of all
deliveries were classified contract by FERC. The amount of contract coal has
increased 18% since 1995.
Average sulfur dioxide content for coals produced in District 1 is
approximately 3.0 lbs SO(2) per million Btu. Nearly 80% (23 million tons) of the
1997 District 1 coal sold to electric utilities is greater than 2.5 lbs SO(2)/MM
Btu.
District 1 mines will continue to serve a niche market. The number of
mines will continue to decline, consolidating the market. Currently, less than
7% of the mines produce 44% of coal in District 1. Requirements of Phase 2 of
the CAAA will make it difficult for many smaller, higher cost mines to compete
(average 3.0 lbs SO(2)/MM Btu.)
CAAA
Acid rain provisions of CAAA that limit the emissions of sulfur dioxide
and oxides of nitrogen (NO(x)) affect the purchasing strategy of coal-burning
electrical generating units. A summary of the major acid rain provisions of the
CAAA is as follows:
- January 1, 1995: Phase 1 SO(2)control, 110 specifically
identified high emitting utility stations were required to reduce
their emissions to less than 2.5 lbs of sulfur dioxide SO(2) per
million Btu multiplied by the unit's baseline fossil fuel
consumption (average of 1985-1987).
- January 1, 1996: Phase 1 NO(x) control, 256 Group 1 boilers
dry- bottom wall-fired and tangentially-fired were required to
reduce their emissions to less than 0.50 lbs NO(x) per million
Btu for dry-bottom wall-fired boilers and less than 0.45 lbs
NO(x) per million Btu for tangentially-fired boilers.
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- January 1, 2000: Phase 2 NO(x) control, requires lower emission
limits for Group 1 boilers and initial limits for Group 2
boilers. Group 2 includes wet-bottom wall-fired (greater than 65
MW), cyclone-fired (greater than 155 MW), vertically-fired, cell
burner boilers, and remaining dry-bottom wall-fired and
tangentially-fired boilers excluded from Phase 1.
- January 1, 2000: Phase 2 SO(2) control, all utility units with
nameplate generating capacity equal to or greater than 75 MW are
required to reduce their emissions to a level not greater than
1.2 lbs of SO(2) per million Btu multiplied by the unit's
baseline fossil fuel consumption (average of 1985-1987).
Sulfur Dioxide
Sulfur dioxide limitations have impacted regional coal supply patterns
and increased demand for lower sulfur coals. The CAAA permits flexibility in the
approach used to achieve total emission compliance including the purchase and
trading of SO(2) emission allowances. Each SO(2) allowance permits the emission
of one ton of SO(2) into the atmosphere. The utility industry, overall,
overcomplied with Phase 1 provisions primarily by fuel switching and, to a
lesser extent, by the installation of FGD systems. Of the 261 units in the
United States affected by Phase 1, an estimated 173 units (66%) either have been
switched to lower sulfur coals or a blend of various quality coals while 28
units (11%) have been or are being equipped with FGD systems.
The extent of SO(2) overcompliance can be measured by the amount of
available excess SO(2) credits as reflected in the price of emission allowances
since their introduction in 1995. Following passage of the CAAA in 1990,
SO(2) emission allowance prices were forecast to range from $300 to $1,000 per
allowance. However, allowance prices by mid-1995 were approximately $130 for
Phase 1 and
425
4-5
$125 for Phase 2. Allowance prices subsequently declined to approximately $70
for Phase 1 and $65 for Phase 2 in early 1996. Since then, allowance prices have
rebounded and are currently in the $190 to $210 range.
Utility plans for compliance with Phase 2 SO(2) emission limitations
are evolving and may include one or more of the following:
- Switching to lower sulfur coal sources or coal blending
- Installing flue gas desulfurization (scrubber) systems
- Gas co-firing
- Purchasing or bundling SO(2) emission allowances
- Retiring noncompliant units and replacing retired generation from
compliant units
BOYD anticipates that the use of FGD systems will increase during Phase
2 as prices for lower sulfur coals and SO(2) emission allowances increase.
Initially, during Phase 2, utilities will utilize their banks of allowances
created by overcompliance and purchase of excess allowances at current low
prices. The extent to which new FGD systems are installed for burning higher
sulfur coals and the relative pricing of SO(2) allowances will largely determine
the future trend of regional spot prices after the year 2000. It is our opinion
that allowance prices will increase as the bank of available credits is depleted
(beyond 2000-2003).
Currently, there are 55 coal-fired generating stations (103 units) east
of the Mississippi River utilizing FGD systems as shown in Table 4.3, following
this text. Following is an analysis of the 1997 Federal Energy Regulatory
Commission (FERC) data for deliveries to the above FGD-equipped stations:
Tons (000)
--------------------------------------------------------------
Type of Less Than Greater Than
Delivery 2.5 lbs SO(2)/MM Btu 2.5 lbs SO(2)/MM Btu Total
-------- ---------------------- ---------------------- -------
Contract 25,389 77,500 102,889
Spot 12,318 30,518 42,836
------ ------- -------
Total 37,707 108,018 145,725
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4-6
In 1997 the size of the overall coal market to stations equipped with FGD
systems (located east of the Mississippi River) was approximately 146 million
tons. The study region supplied a total of 50 million tons to these stations in
1997 (93% of these deliveries were greater than 2.5 lbs SO(2)/MM Btu). BOYD
believes this market will expand due to installation of additional FGD systems
to meet the requirements of CAAA Phase 2 SO(2)restrictions. BOYD also believes
that the imposition of CAAA Phase 2 SO(2)restrictions will increase demand for
low sulfur coal by plants that do not install FGD systems.
Coal-fired generating stations equipped with or installing FGD systems
are the primary market for the Pittsburgh Seam coal production. Only two
additional generating stations, Homer City (one unit) and Mt. Storm (one
additional unit), have announced plans to install FGD systems.
NO(x) Emission Reductions
Title IV of the CAAA establishes reductions in NO(x) emissions for
coal-fired generating stations. Title IV specifies a two-stage strategy for NO
(X) emission reductions. The first stage is expected to reduce U.S. NO(x)
emissions by over 400,000 tons per year (tpy) during Phase 1 (1996-1999).
Beginning in year 2000 (Phase 2), NO (x) emissions will be reduced by
approximately 1.17 million tpy according to EPA estimates from baseline levels.
Phase 1 affects 256 dry-bottom, wall-fired and tangentially-fired
boilers known as Group 1. Phase 2 of the NO(x) reduction program sets lower
emissions limits for Group 1 and establishes emission limits for several other
types of coal-
JOHN T. BOYD COMPANY
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fired boilers (Group 2). Group 2 includes a total of 145 wet-bottom boilers,
cyclones, cell burner boilers, and vertically-fired boilers. Additionally, Group
2 includes 607 dry-bottom, wall-fired and tangentially-fired boilers not
included in Phase 1. Phase 2 units must comply by January 1, 2000, at which time
tangentially-fired boilers must reduce emissions to an average rate of less than
0.40 lbs NO(x)/MM Btu, and wall-fired units must emit less than 0.46 lbs
NO(x)/MM Btu.
The following shows Phases 1 and 2 NO(x) emission limits by boiler
type:
NO(x)Emission Limits (lbs/MM Btu)
---------------------------------
Phase 1 Phase 2
------- -------
Group 1 Boilers
Dry-bottom Wall-Fired 0.50 0.46
Tangentially-Fired 0.45 0.40
Group 2 Boilers
Wet-bottom Wall-Fired >65 MW - 0.84
Cyclone-Fired >155 MW - 0.86
Vertically-Fired - 0.80
Cell Burner - 0.68
Fluidized Bed - Exempt
Stoker - Exempt
NO(x) reduction also falls under Title I of the CAAA which addresses
ozone nonattainment. The Ozone Transport Commission (OTC) was created by the
CAAA to devise strategies for achieving federal ozone standards in a 12-state,
plus the District of Columbia, ozone transport region.
The thirteen voting members of the OTC signed a Memorandum of
Understanding (MoU) to reduce NO(x) emissions in the Ozone Transport Region
(OTR). Implementation of the MoU is based on a three-phase program. Phase 1,
which is already in effect, provides for implementation of reasonably available
JOHN T. BOYD COMPANY
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control technology (RACT). Phase 2 requires affected units in most of the OTR
except the northern and central eastern portions to reduce NO(x) emissions by
55% of the 1990 baseline or meet a 0.20 lbs NO(x)/MM Btu maximum limit by May 1,
1999, during the ozone season. Phase 3 requires further NO(x) reductions by 75%
of the 1990 baseline, or 0.15 lbs NO(x)/MM Btu maximum, limit by May 1, 2003,
during the ozone season. The ozone season extends from May 1 to September 30.
On September 24, 1998, the EPA announced a final rule requiring NO(x)
emission reductions to reduce ozone transport. The measure requires 21 states
east of the Mississippi River (excluding Florida, Maine, Mississippi, New
Hampshire, and Vermont), Missouri and the District of Columbia to reduce their
NO(x) emissions by upwards of 85%. For each of the twenty-three (23)
jurisdictions, EPA has calculated a NO(x) budget which must be achieved by 2007.
States are required to implement controls by May 1, 2003. States are free to
choose their own mix of control for implementation purposes as well as the
sources subject to control as long as the total budget is achieved. EPA has
recommended a NO(x) emission rate of 0.15 lb/MMBtu for utility sources (fossil
fuel burning electric utility units serving electricity generators of 25 MW or
more). The final rule includes an interstate cap and trade program that could be
used to implement the fixed tonnage NO(x) budget, and the final rule allows
states to achieve most of the mandated NO(x) reductions through a regional
trading program administered by EPA. Utilities and large nonutility point
sources are the most likely candidates for NO(x) reductions.
JOHN T. BOYD COMPANY
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4-9
Utility strategies for compliance with NO(x) regulations may include
one or more of the following:
- Fuel switching to high volatile coal
- Installation of low NO(x) burners
- Staged combustion reducing percentage of excess air
- Selective catalytic or noncatalytic reduction
Pittsburgh Seam coal provides a high volatile matter (32% to 34%) substitute for
lower volatile coals. High volatile fuel switching to FGD-equipped stations may
be a means of attaining compliance with Phase 2 NO(x) requirements for some
stations.
EXPORT MARKETS
A small portion of the Pittsburgh Seam production coal is exported,
primarily to Canada and Europe. The majority of exports are lower sulfur
(typically less than 1.5%). Export prices have been declining over the past
several years. Many producers are not willing to sell into the export market at
current prices. Therefore, more Pittsburgh Seam coal will be available for sale
in the domestic market resulting in a short-term decline in prices.
POWDER RIVER BASIN COALS
Coals from the Powder River Basin (PRB) in the western United States
may have an impact on eastern coal prices. Although PRB coal shipments to
stations east of the Mississippi River between 1994 and 1997 have increased from
53 million to 85 million tons (60% increase), there have been no significant
deliveries to stations in the northeast (east of Ohio).
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Future PRB infiltration will be dependent on the individual utility's
CAAA compliance plans. In 1997, FGD systems (east of the Mississippi River)
purchased approximately 110 million tons of coal greater than 2.5 lbs SO(2)/MM
Btu. The Pittsburgh Seam delivered approximately 42 million tons to
FGD-equipped stations (92 million tons to the utility market) in 1997.
FGD-equipped stations are a substantial market for Pittsburgh Seam suppliers,
allowing little competition with PRB producers.
If Phase 2 compliance includes installation of additional FGD systems,
the Pittsburgh Seam suppliers are the most likely source of high quality, low
cost of production coals. Low sulfur levels in PRB coals may add a premium to
the price of these coals after January 2000 (Phase 2). Transportation of PRB
coals to eastern stations contemplating fuel switching (instead of installing
FGD systems) adds significantly to the delivered coal costs. Rail transportation
from Montana or Wyoming to the northeast will require one or more rail switches
or rail-to-lake barge transfers. Lake transloading capability would have to be
either significantly upgraded or installed. Since lake shipping is not possible
during the entire year, it would be necessary for utilities to make provisions
for additional stockpile space. PRB coal prices will most likely experience
upward pressure after Phase 2 becomes effective.
Alternate Fuels
Northeastern utilities utilize a combination of coal, gas, and nuclear
generating capacity. The impact of gas and nuclear operations on the coal
segment
JOHN T. BOYD COMPANY
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is expected to be minimal. Most large coal-fired units are base load units. BOYD
believes the price of natural gas will primarily affect new stations to be
developed domestically in the U.S. such that near-term development will rely on
natural gas-fired units. Overall, for existing coal-fired stations, the price of
natural gas will have no significant impact on coal prices.
During 1997 and 1998, the nuclear units of Ontario-Hydro experienced
problems, thus the utility increased its coal purchases from Pittsburgh Seam
suppliers. These additional sales led to reduced availability of Pittsburgh Seam
coals and higher prices. However, this was a short-term occurrence. Had it been
perceived as a long-term occurrence, producers most likely would have increased
production capacity and the tight supply would have diminished, resulting in
lowering of prices.
Price Forecast
This report presents estimated FOB mine prices in constant mid-1998 and
current year's dollars. Conversion between constant and current dollars is based
on the following projected inflation rates:
1999 2.0%
2000 2.5%
2001-2016 3.0%
During the near- to mid-term (through 2008), BOYD believes enough
reserves remain to continue production of low, medium and high sulfur coal at
current levels. Beyond 2008, it is questionable if reserves of coal having a
sulfur
JOHN T. BOYD COMPANY
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content of less than 2.5 lbs SO(2)/MM Btu are available in the study region to
maintain current production levels. Only a small portion (approximately 3%, 3
million to 4 million tpy) of the production from Districts 1, 2, 3, 4, and 6
meet CAAA Phase 2 sulfur dioxide requirements. For utilities opting to install
FGD units or purchase sulfur dioxide allowances, the study region has a large
reserve base of higher sulfur coals. Since Pittsburgh Seam coals at lower sulfur
levels are scarce, they would most likely be used as a blend constituent to meet
a 1.2 lbs SO(2)/MM) Btu specification.
With limited prospects of opening new mines, the present trend for
Pittsburgh Seam producers with mines that have large accessible reserve bases is
to upgrade current longwall capacity. This is done in tandem with upgrading
haulage capacity to permit extending the reach of the underground workings and
accommodating higher tonnages. While this may not be the most efficient method
of operating from a long-term cash cost perspective (due to the cost of
installing and operating additional infrastructure), it avoids large front-end
capital expenditures for new mine development and surface facilities (railroad,
preparation plant, etc.).
Mine selling prices are contingent upon negotiated contract terms and
conditions, special quality characteristics required by the buyer, mine
location, individual mine production costs, and market dynamics. The price of
Pittsburgh Seam coals has been declining in real terms, and we anticipate the
price of Pittsburgh Seam coals will continue to decline in real terms. We have
projected prices on a contract and spot basis through 2010.
JOHN T. BOYD COMPANY
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Projected base case f.o.b. mine steam coal prices are summarized below:
Contract Price Spot Price
------------------------ -------------------------
District: 2 & 3 4 & 6 2 & 3 4 & 6
---------------- ----- ---------------- -------
lbs SO(2)/MM Btu: <2.5 2.5-4.0 >4.0 <2.5 2.5-4.0 >4.0
Btu/lb: 12,800 12,800 12,500 12,800 12,800 12,500
Constant Mid-1998 (Dollars)
---------------------------
1999 25.30 23.85 20.25 24.00 22.70 19.20
2000 25.05 23.70 20.10 23.80 22.50 19.10
2005 24.00 23.00 19.40 23.60 22.35 19.00
2010 23.50 21.90 18.40 23.30 21.70 18.20
Current Year's (Dollars)
------------------------
1999 25.70 24.20 20.55 24.35 23.05 19.50
2000 26.00 24.60 20.85 24.70 23.35 19.80
2005 28.80 27.60 23.30 28.35 26.80 22.80
2010 32.70 30.45 25.60 32.40 30.20 25.30
Detailed annual estimates follow in Tables 4.4 and 4.5, following this text.
BOYD has also prepared a low and high case contract coal price
forecast. Price projections for the base, low, and high cases are shown in Table
4.6 and summarized below:
FOB Mine Prices (Constant Mid-1998
$/Ton)
District: 2 & 3 4 & 6
-------------------------------- ---------
lbs SO(2)/MM Btu: <2.5 2.5 - 4.0 >4.0
Btu/lb: 12,800 12,800 12,500
Base
1999 25.30 23.85 20.25
2000 25.05 23.70 20.10
2005 24.00 23.00 19.40
2010 23.50 21.90 18.40
Low
1999 21.50 19.50 18.50
2000 21.50 19.20 18.35
2005 20.90 19.00 18.20
2010 20.45 18.00 17.00
High
1999 26.55 25.05 21.25
2000 26.55 25.10 21.30
2005 26.65 25.55 21.55
2010 26.30 24.55 20.60
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The low and high cases represent an 80% confidence level. BOYD's
analysis is based on the criteria that there is less than a 10% probability the
price will be greater than the high case price estimate and less than 10%
probability the price will be less than our low case price estimate. We project
coal prices to continue to increase at a rate lower than the general inflation
rate (as measured by the Gross Domestic Product Implicit Price Deflator) during
the period 2010 through 2020 (i.e., we anticipate coal prices will decrease in
real terms throughout this period).
A contract being finalized by AEE substantiates the foregoing price
projections. AEE is currently finalizing negotiations with Pittsburgh Seam
producers for a two-year commitment with the following average quality and fixed
pricing:
Ash (%) 7
Sulfur (%) 2.25
Btu/lb 13,200
lbs SO(2)/MM Btu 3.41
Year $/Ton
---- -----
1999 19.83
The pricing being negotiated by AEE falls near the low end of our
projection but within our 80% confidence range.
BOYD's high sulfur coal (>.0 lbs SO(2)/MM Btu) price forecast assumes
only moderate growth in the use of FGD systems. Phase 2 compliance is projected
to be a combination of fuel switching, use of emission allowances, increase in
gas-fired and co-fired generation and FGD systems. If a large scale
installation of FGD
JOHN T. BOYD COMPANY
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systems occurs (e.g., due to a break-through in technology), then high sulfur
coal prices shown in the forecast are likely to be understated.
Following this page are:
Tables
4.1: 1997 Utility Deliveries by Sulfur Dioxide Content from Selected
Mines in the Study Region
4.2: District 1 Utility Distribution by Receiving State (1994-1997)
4.3: Operating Scrubbed Stations East of the Mississippi River
4.4: Estimated FOB Mine Coal Price for Pittsburgh Seam Suppliers
(Constant Mid-1998 Dollars)
4.5: Estimated FOB Mine Coal Price for Pittsburgh Seam Suppliers
(Current Year's Dollars)
4.6: Pittsburgh Seam Coal, Estimated Term Coal Prices
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TABLE 4.1
1997 UTILITY DELIVERIES BY SULFUR DIOXIDE CONTENT
FROM SELECTED MINES IN THE STUDY REGION
For
AES EASTERN ENERGY, L.P.
BY
John T. Boyd Company
Mining and Geological Consultants
March 1999
Delivered Tons (000) By Sulfur Dioxide lbs/MM Btu level:
------------------------------------------------------------------------
Company Mine <2.30 2.31-2.50 2.51-2.80 2.81-4.00 >4.00 Total
- ---------------------- ------------------------ ---------- --------- --------- --------- ---------- ---------
DISTRICT 1
----------
Canterbury Coal Co. Dianne -- -- -- 1,097.4 111.4 1,208.8
E. P. Bender Coal Co. EPB Strip -- -- -- 667.0 -- 667.0
Amerikohl Mining, Inc. Fayette Co. Strips -- 21.5 98.8 492.5 82.0 694.8
Pennsylvania Mines Corp. Greenwich Collieries No. 1 303.0 -- 1,594.0 -- -- 1,897.0
Elton Coal Co. Huskin Run Siding 55.0 7.0 22.0 545.0 54.0 683.0
Keystone Coal Mining Corp. Keystone Cleaning Plant -- -- 201.0 380.0 18.0 599.0
Power Operating Co., Inc. Leslie Tipple 7.0 80.0 40.0 486.0 -- 613.0
Helvetia Coal Co. Lucerne Nos. 6, 8 & 9 -- -- -- 1,804.2 -- 1,804.2
Mapco Coal, Inc. Mettiki 282.8 159.0 966.7 1,184.3 -- 2,592.8
Mincorp, Inc. P B S No. 1 -- 20.0 59.0 1,317.5 -- 1,396.5
Mears Enterprises, Inc. Penn Run -- 23.0 -- 163.0 364.8 550.8
Consol Coal Group Potomac 623.1 22.7 -- 16.1 -- 661.9
Willesley Clay Ltd. Rosebud Nos. 2 and 3 -- -- 2.3 443.9 120.3 566.5
Mincorp, Inc. Shade Creek Tipple 542.0 15.0 23.4 24.0 -- 604.4
Tanoma Coal Co. Tanoma 1,554.6 133.6 278.1 555.5 520.6 3,042.4
------- ------- ------- ------- ------- --------
3,367.5 481.8 3,285.3 9,176.4 1,271.1 17,582.1
DISTRICT 2
----------
Amerikohl Mining, Inc. Amerikohl No. 1 0.2 1.9 274.0 513.0 -- 789.1
Consol Coal Group Bailey/Enlow Fork 1,649.9 4,188.4 3,537.8 675.1 79.8 10,131.0
Cyprus Amax Coal Co. Cumberland 69.2 -- 37.0 3,216.6 68.6 3,391.4
Consol Coal Group Dilworth 655.9 332.5 644.7 1,247.4 6.2 2,886.7
Cyprus Amax Coal Co. Emerald No. 1 2,713.5 602.0 422.0 542.9 -- 4,280.4
Rochester & Pittsburgh Coal Co. Livingston No. 84 2,167.3 773.4 168.5 9.1 -- 3,118.3
Consol Coal Group Robena Prep Plant 177.9 53.7 54.0 81.9 637.8 1,005.3
------- ------- ------- ------- ----- --------
7,433.9 5,951.9 5,138.0 6,286.0 792.4 25,602.2
DISTRICT 3
----------
American Natural Resources Co. Albright Prep Plant 119.0 365.7 236.9 43.8 -- 765.4
Anker Energy Corp. Amos Run No. 2 951.0 -- -- -- -- 951.0
Anker Energy Corp. Anker Rail & River Term 178.9 9.5 -- 179.0 480.9 848.3
Consol Coal Group Blacksville No. 2 -- 28.6 68.7 1,299.9 1,654.2 3,051.4
Zeigler Coal Co. Cowen 1,197.9 -- -- 78.1 -- 1,276.0
Mepco, Inc. Crafts Run 130.9 136.9 59.3 278.1 -- 605.2
Coastal States Energy Corp. D & K No. 4A Portal No. 2 744.2 -- -- -- -- 744.2
Peabody Holding Co. Federal No. 2 4.2 -- 97.3 3,096.3 243.2 3,441.0
Consol Coal Group Humphrey No. 7 189.9 -- 261.4 1,689.0 17.6 2,157.9
Consol Coal Group Loveridge No. 22 96.9 46.9 237.5 1,872.4 -- 2,253.7
Consol Coal Group Robinson Run No. 95 -- -- -- 5.3 4,385.8 4,391.1
Philippi Development, Inc. Sentinel 947.0 30.0 -- -- -- 977.0
Amvest Minerals Corp. Terry Eagle No. 1 Pit 708.8 -- -- 22.8 -- 731.6
------- ----- ----- ------- ------- --------
5,268.7 617.6 961.1 8,564.7 6,781.7 22,193.8
JOHN T. BOYD COMPANY
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TABLE 4.1 -- Continued
4-16b
Delivered Tons (000) by Sulfur Dioxide lbs/MM Btu level*
------------------------------------------------------------------------
(less than) (greater than)
Company Mind 2.30 2.31-2.50 2.51-2.80 2.81-4.00 4.00 Total
- ------------------------------ ----------------------- ------------ --------- --------- --------- -------------- --------
District 4
----------
Waterloo Coal Co., Inc. Bowmen Strip -- -- -- -- 789.4 789.4
Columbus & Southern Power Co. Conesville Prep Plant -- -- -- -- 2,370.4 2,370.4
Keller Group, Inc. Kensington Prep Plant -- -- -- 466.4 48.9 515.3
Consol Coal Group Mahoning Valley No. 36 -- -- -- -- 822.0 822.0
Ohio Power Co. Meigs No. 2 -- -- -- -- 3,119.9 3,119.9
Ohio Power Co. Meigs No. 31 -- -- -- -- 3.119.9 3,119.9
Ohio Power Co. Muskingum -- -- -- -- 1,150.4 1,150.4
Quaker Coal Co., Inc. Neims Cadiz Portel 4.8 -- 34.9 423.2 674.0 1,136.9
B & N Coal, Inc. Orange Strip -- -- -- -- 737.5 737.5
Consol Coal Group Powhatan No. 4 -- -- -- -- 1,878.5 1,878.5
Ohio Valley Resources, Inc. Powhatan No. 6 -- -- -- -- 4,573.7 4,573.7
Sands Hill Coal Co., Inc. Sands Hill Strip -- -- -- -- 1,105.0 1,105.0
-------- ------- ------- -------- -------- --------
4.8 -- 34.9 889.6 20,389.6 21,318.9
District 6
----------
Consol Coal Group McElroy 194.9 -- -- -- 1,222.6 1,417.5
Consol Coal Group Shoemaker 194.9 -- -- 203.9 8,379.6 8,778.4
Ohio Power Co. Windsor -- -- -- -- 1,520.8 1,520.8
-------- ------- ------- -------- -------- --------
389.8 -- -- 203.9 11,123.0 11,716.7
16,464.7 7,051.3 9,419.3 25,120.6 40,357.8 98,413.7
438
TABLE 42
DISTRICT 1 UTILITY DISTRIBUTION BY
RECEIVING STATE (1994-1997)
For
AES EASTERN ENERGY, L.P.
--------------------------------
By
John T. Boyd Company
Mining and Geological Consultants
March 1999
---------------------------
Spot Deliveries Contract Deliveries
---------------------------------------------------- --------------------------------------------------
Delivered Price Delivered Price
Delivery Tons Ash Sulfur --------------- Tons Ash Sulfur ---------------
State (000) (%) (%) Btu/lb $/ton (cent)/MM Btu (000) (%) (%) Btu/lb $/ton (cent)/MM Btu
- -------- -------- ----- ------ ------ ----- ------------- ------- ----- ------ ------ ----- -------------
1997
----
DE 16.3 10.97 0.57 10,724 32.38 151.0 160.8 9.17 1.46 13,158 38.89 147.8
KY 0.3 29.70 1.00 7,000 12.14 86.7 -- -- -- -- -- --
MD 828.5 9.99 1.37 12,871 40.03 155.5 1,394.0 9.39 1.42 13,098 44.48 169.8
NH 73.0 8.20 1.38 12,913 41.43 160.4 -- -- -- -- -- --
NY 218.3 10.68 1.64 12,495 36.25 145.1 -- -- -- -- -- --
OH 202.6 13.87 1.53 11,752 25.11 106.8 -- -- -- -- -- --
PA 7,529.5 14.35 2.06 12,191 29.81 122.3 15,160.6 15.05 1.91 12,093 31.42 129.9
VA 59.1 15.29 1.56 12,899 37.84 146.7 -- -- -- -- -- --
WV 256.5 12.63 1.41 12,548 28.97 115.4 3,571.8 15.35 1.70 12,246 27.18 111.0
------- ----- ---- ------ ----- -------- -------- ----- ---- ------ ----- -----
9,184.1 13.76 1.95 12,267 30.91 126.0 20,287.2 14.67 1.84 12,197 31.63 129.7
1996
----
DE 32.5 8.44 1.00 13,122 43.44 165.5 251.7 9.50 1.42 13,121 39.01 148.7
MD 1,889.6 9.45 1.38 13,011 40.69 156.4 1,383.0 9.33 1.42 13,071 43.37 165.9
NH 72.2 8.70 1.35 13,110 40.54 154.6 -- -- -- -- -- --
NY 232.7 11.49 1.36 12,381 34.82 140.6 4.0 14.20 0.89 11,263 27.23 120.9
OH 16.0 24.56 1.26 9,589 15.57 81.2 -- -- -- -- -- --
PA 7,780.3 13.59 1.95 12,261 30.67 125.1 13,533.0 15.00 1.87 12,142 33.02 136.0
VA 18.6 12.00 1.63 12,935 38.78 149.9 -- -- -- -- -- --
WV 1,660.5 14.39 1.70 12,305 26.35 107.1 2,911.2 14.16 1.67 12,328 31.50 127.7
-------- ----- ---- ------ ----- ----- -------- ----- ---- ------ ----- -----
11,702.4 12.96 1.80 12,396 31.85 128.5 18,082.9 14.35 1.80 12,256 33.65 137.3
1995
----
DE 44.7 9.93 1.08 13,164 41.52 157.7 228.6 9.82 1.32 13,103 39.45 150.5
MD 1,663.3 9.52 1.36 13,114 39.45 150.4 1,628.0 9.56 1.40 13,196 42.15 159.7
NH 9.2 6.20 1.44 13,345 42.65 159.8 -- -- -- -- -- --
NY 591.8 11.85 1.61 12,399 33.89 136.7 10.4 11.52 1.02 12,696 39.24 154.5
OH 60.8 7.63 1.45 12,949 33.54 129.5 -- -- -- -- -- --
PA 9,012.5 14.09 2.02 12,267 27.94 113.9 11,531.7 14.69 1.76 12,212 34.73 142.2
WV 710.2 21.54 2.00 10,872 21.97 101.0 3,802.5 14.18 1.66 12,414 32.49 130.9
-------- ----- ---- ------ ----- ----- -------- ----- ---- ------ ----- -----
12,091.7 13.74 9.90 12,316 29.55 120.0 17,201.2 14.03 1.70 12,362 35.00 141.6
Total Deliveries
-----------------------------------------------------
Delivered Price
Delivery Tons Ash Sulfur ---------------
State (000) (%) (%) Btu/lb $/ton (cent)/MM Btu
- -------- -------- ----- ------ ------ ----- -------------
DE 177.1 9.33 1.37 12,933 38.29 148.0
KY 0.3 29.70 1.00 7,000 12.14 86.7
MD 2,222.5 9.61 1.40 13,014 42.82 164.5
NH 73.0 8.20 1.38 12,913 41.43 160.4
NY 218.3 10.68 1.64 12,495 36.25 145.1
OH 202.6 13.87 1.53 11,752 25.11 106.8
PA 22,690.0 14.82 1.96 12,125 30.89 127.4
VA 59.1 15.29 1.56 12,899 37.84 146.7
WV 3,828.3 15.17 1.68 12,266 27.30 111.3
-------- ----- ---- ------ ----- -----
29,471.2 14.39 1.87 12,219 31.41 128.5
DE 284.2 9.38 1.37 13,121 39.52 150.6
MD 3,272.6 9.40 1.40 13,036 41.83 160.4
NH 72.2 8.70 1.35 13,110 40.54 154.6
NY 236.7 11.54 1.35 12,363 34.69 140.3
OH 16.0 24.56 1.26 9,589 15.57 81.2
PA 21,313.3 14.48 1.90 12,186 32.16 132.0
VA 18.6 12.00 1.63 12,935 38.78 149.9
WV 4,571.7 14.24 1.68 12,320 29.63 120.2
-------- ----- ---- ------ ----- -----
29,785.3 13.80 1.80 12,312 32.94 133.8
DE 273.3 9.84 1.28 13,113 39.79 151.7
MD 3,291.3 9.54 1.38 13,155 40.79 155.0
NH 9.2 6.20 1.44 13,345 42.65 159.8
NY 602.2 11.84 1.60 12,404 33.99 137.0
OH 60.0 7.83 1.45 12,949 33.54 129.5
PA 20,544.2 14.43 1.87 12,236 31.75 129.8
WV 4,512.7 15.34 1.71 12,172 30.84 126.7
-------- ----- ---- ------ ----- -----
29,292.9 13.91 1.78 12,343 32.75 132.7
439
TABLE 4.2 - Continued
Spot Deliveries Contract Deliveries
--------------------------------------------------------- ---------------------------------------------------------
Delivered Price Delivered Price
Delivery Tons Ash Sulfur ----------------- Tons Ash Sulfur -----------------
State (000) (%) (%) Btu/lb $/ton c/MM Btu (000) (%) (%) Btu/lb $/ton c/MM Btu
- -------- ----- --- ------ ------ ----- -------- ----- --- ------ ------ ----- --------
1994
DE 145.8 9.92 1.37 13,147 39.57 150.5 199.7 9.43 1.27 12,991 42.56 163.8
MD 875.3 10.14 1.35 12,916 40.04 155.0 2,338.0 10.77 1.57 12,930 44.37 171.6
NY 1,085.2 12.58 1.61 12,102 35.04 144.8 -- -- -- -- -- --
OH 170.0 8.46 1.65 12,919 32.02 123.9 -- -- -- -- -- --
PA 7,481.1 13.29 1.90 12,364 30.94 125.1 12,588.3 14.45 1.87 12,227 35.39 144.7
WV 698.6 14.67 1.76 12,279 26.69 108.7 3,905.0 13.76 1.76 12,460 33.25 133.4
-------- ----- ---- ------ ----- ----- -------- ----- ---- ------ ----- -----
10,456.0 12.92 1.80 12,397 31.98 129.0 19,031.0 13.80 1.80 12,369 36.13 146.0
Total Deliveries
---------------------------------------------------------
Delivered Price
Delivery Tons Ash Sulfur -----------------
State (000) (%) (%) Btu/lb $/ton c/MM Btu
- -------- ----- --- ------ ------ ----- --------
DE 345.5 9.64 1.31 13,057 41.30 158.2
MD 3,213.3 10.60 1.51 12,926 43.19 167.1
NY 1,085.2 12.58 1.61 12,102 35.04 144.8
OH 170.0 8.46 1.65 12,919 32.02 123.9
PA 20,069.4 14.02 1.88 12,278 33.73 137.4
WV 4,603.6 13.90 1.76 12,433 32.25 129.7
-------- ----- ---- ------ ----- -----
29,487.0 13.49 1.80 12,379 34.66 140.0
440
TABLE 4.3 4-18
OPERATING SCRUBBED STATIONS
EAST OF THE MISSISSIPPI RIVER
For
AES EASTERN ENERGY, L.P.
By
John T. Boyd Company
Mining and Geological Consultants
March 1999
1997
Station Coal Burn
Utility Station (Unit No.) State Id. No. (Tons-000)
- --------------------------------- ------------------------ ----- ------- ----------
Alabama Electric Coop. Lowman (2 & 3) AL 0056 1,465
Atlantic City Electric England (2) NJ 2378 580
Big Rivers Electric Corp. D.B. Wilson KY 6823 1,254
Big Rivers Electric Corp. Green (1 & 2) KY 6639 1,492
Central Illinois Light Co. Duck Creek (1) IL 6016 860
Central Illinois Public Service Newton (1) IL 6017 2,327
Cincinnati Gas & Electric Co. East Bend (2) KY 6018 1,790
Cincinnati Gas & Electric Co. W.H. Zimmer OH 6019 3,253
Columbus and Southern Ohio Elec. Conesville (5 & 6) OH 2840 4,055
Duquesne Light Co. Elrama (1 - 4) PA 3098 1,000
East Kentucky Power Co. Spurlock (2) KY 6041 2,314
Grand Haven Light & Power J.B. Sims (3) MI 1825 174
Hoosier Energy Merom (1 & 2) IN 6213 3,510
Indianapolis Power and Light Petersburg (1, 2, 3 & 4) IN 0994 5,314
Jacksonville Electric Auth. St. Johns River (1 & 2) FL 0207 3,755
Kentucky Utilities Ghent KY 1356 4,793
Kentucky Utilities Green River (1 - 3) KY 1357 345
Louisville Gas & Electric Co. Cane Run (4, 5 & 6) KY 1363 1,430
Louisville Gas & Electric Co. Mill Creek (1, 2, 3 & 4) KY 1364 3,710
Louisville Gas & Electric Co. Trimble County KY 6071 1,654
Marquette Board of Light & Power Shiras (3) MI 1843 144
Monongahela Power Harrison (1, 2 & 3) WV 3944 5,279
Monongahela Power Pleasants (1 & 2) WV 6004 3,519
New York State Gas & Electric Kintigh NY 6082 1,635
New York State Gas & Electric Milliken (1 & 2) NY 2535 776
Northern Ind. P.S. Bailly (7 & 8) IN 0995 1,311
Northern Ind. P.S. Schahfer (17 & 18) IN 6085 4,816
Ohio Power Gevin (1 & 2) OH 8102 7,061
Orlando Utilities Comm. Stanton (1 & 2) FL 0564 2,309
Owensboro Municipal Utilities Smith (1 & 2) KY 1374 1,347
Pennsylvania Power Co. Bruce Mansfield (1, 2 & 3) PA 6094 5,961
Pennsylvania Electric Co. Conemaugh (1 & 2) PA 3118 4,702
Philadelphia Electric Cromby (1) PA 3159 403
Philadelphia Electric Eddystone (1 & 2) PA 3161 1,214
P.S. Company of Indiana Gibson (4 & 5) IN 6113 7,905
Sanannah Electric and Power Mcintosh (3) FL 6124 379
Sanannah Electric and Power Mcintosh (3) FL 0676 940
Seminole Electric Coop. Seminole (1 & 2) FL 0136 3,940
Southern Illinois Power Coop. Marion (4) IL 0976 851
Southern Ind. Gas & Elec. A.B. Brown (1 & 2) IN 6137 1,233
Southern Ind. Gas & Elec. Culley (2 & 3) IN 1012 944
Springfield Water, Light & Power Dallman (3) IL 0963 1,100
S. Carolina P.S. Auth. Cross (1 & 2) SC 0130 2,707
S. Carolina P.S. Auth. Winyah (2, 3 & 4) SC 6249 2,619
Tampa Electric Big Bend (4) FL 0645 7,280
Tennessee Valley Auth. Cumberland (1 & 2) AL 3399 8,027
Tennessee Valley Auth. Paradise (1 & 2) KY 1378 8,406
Tennessee Valley Auth. Shawnee (9) KY 1379 3,352
Tennessee Valley Auth. Widows Creek (7 & 8) AL 0050 2,857
Virginia Electric Power Co. Clover VA 7213 1,904
Virginia Electric Power Co. Mt. Storm (3) VA 3954 3,957
West Penn Power Mitchell (3) PA 3181 1,775
------
145,726
JOHN T. BOYD COMPANY
441
TABLE 4.4
---------
4-19
ESTIMATED FOB MINE COAL PRICE
FOR PITTSBURGH SEAM SUPPLIERS
(Constant Mid-1998 Dollars)
For
AES EASTERN ENERGY, L.P.
-----------------------------
By
John T. Boyd Company
Mining and Geological Consultants
March 1999
-----------------------------
Contract Spot
-------------------------------------------- --------------------------------------------
District: 2 & 3 2 & 3 4 & 6 2 & 3 2 & 3 4 & 6
lbs SO(2)/MM Btu: <2.5 2.5 - 4.0 >4.0 <2.5 2.5 - 4.0 >4.0
Btu/lb: 12,800 12,800 12,500 12,800 12,800 12,500
Year Base Case Price ($/Ton)
---- -----------------------------------------------------------------------------------
1999 25.30 23.85 20.25 24.00 22.70 19.20
2000 25.05 23.70 20.10 23.80 22.50 19.10
2001 24.85 23.55 19.95 23.60 22.40 19.00
2002 24.65 23.40 19.80 23.60 22.40 19.00
2003 24.40 23.25 19.65 23.60 22.40 19.00
2004 24.20 23.10 19.50 23.60 22.40 19.00
2005 24.00 23.00 19.40 23.60 22.35 19.00
2006 23.90 22.75 19.20 23.60 22.35 19.00
2007 23.80 22.50 19.00 23.60 22.30 18.80
2008 23.70 22.30 18.80 23.50 22.10 18.60
2009 23.60 22.10 18.60 23.40 21.90 18.40
2010 23.50 21.90 18.40 23.30 21.70 18.20
JOHN T. BOYD COMPANY
442
TABLE 4.5 4-20
ESTIMATED FOB MINE COAL PRICE
FOR PITTSBURGH SEAM SUPPLIERS
(Current Year's Dollars)
For
AES EASTERN ENERGY L.P.
------------------------------
By
John T. Boyd Company
Mining and Geological Consultants
March 1999
------------------------------
Contract Spot
------------------------- --------------------------
District: 2 & 3 2 & 3 4 & 6 2 & 3 2 & 3 4 & 6
lbs SO(2)/MM Btu: <2.5 2.5-4.0 >4.0 <2.5 2.5-4.0 >4.0
Btu/lb: 12,800 12,800 12,500 12,800 12,800 12,500
Year Base Case Price ($/Ton)
---- -----------------------
1999 25.70 24.20 20.55 24.35 23.05 19.50
2000 26.00 24.60 20.85 24.70 23.35 19.80
2001 26.50 25.10 21.25 25.15 23.90 20.25
2002 27.05 25.70 21.75 25.90 24.60 20.85
2003 27.60 26.30 22.25 26.70 25.35 21.50
2004 28.20 26.90 22.70 27.50 26.10 22.15
2005 28.80 27.60 23.30 28.35 26.80 22.80
2006 29.55 28.10 23.75 29.15 27.65 23.50
2007 30.30 28.65 24.20 30.05 28.40 23.95
2008 31.10 29.25 24.65 30.80 29.00 24.40
2009 31.90 29.85 25.15 31.60 29.60 24.85
2010 32.70 30.45 25.60 32.40 30.20 25.30
JOHN T. BOYD COMPANY
443
TABLE 4.6 4-21
PITTSBURGH SEAM COAL
ESTIMATED TERM COAL PRICES
CONSTANT 1998 $/TON
For
AES EASTERN ENERGY, L.P.
---------------------------------
By
John T. Boyd Company
Mining and Geological Consultants
March 1999
---------------------------------
District: 2 & 3 2 & 3 4 & 6
lbs SO(2)/MM Btu: < 2.5 2.5 - 4.0 > 4.0
Btu/lb: 12,800 12,800 12,500
BASE CASE PRICE ($/TON)
-----------------------
1999 25.30 23.85 20.25
2000 25.05 23.70 20.10
2001 24.85 23.55 19.95
2002 24.65 23.40 19.80
2003 24.40 23.25 19.65
2004 24.20 23.10 19.50
2005 24.00 23.00 19.40
2006 23.90 22.75 19.20
2007 23.80 22.50 19.00
2008 23.70 22.30 18.80
2009 23.60 22.10 18.60
2010 23.50 21.90 18.40
LOW CASE PRICE ($/TON)
----------------------
1999 21.50 19.50 18.50
2000 21.20 19.20 18.35
2001 20.90 19.05 18.20
2002 20.90 19.05 18.20
2003 20.90 19.05 18.20
2004 20.90 19.05 18.20
2005 20.90 19.00 18.20
2006 20.90 19.00 18.20
2007 20.90 18.90 17.90
2008 20.75 18.60 17.60
2009 20.60 18.30 17.30
2010 20.45 18.00 17.00
HIGH CASE PRICE ($/TON)
-----------------------
1999 26.55 25.05 21.25
2000 26.55 25.10 21.30
2001 26.60 25.20 21.35
2002 26.60 25.25 21.40
2003 26.60 25.35 21.40
2004 26.60 25.40 21.45
2005 26.65 25.55 21.55
2006 26.75 25.50 21.50
2007 26.65 25.20 21.30
2008 26.55 25.00 21.05
2009 26.45 24.75 20.85
2010 26.30 24.55 20.60
JOHN T. BOYD COMPANY
444
[AES Earstern Energy, L.P. Logo]
UNTIL MAY 18, 2000, ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE
SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO
DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE DEALERS' OBLIGATION TO DELIVER
A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNUSED
ALLOTMENTS OR SUBSCRIPTIONS.