Filed Pursuant to Rule 424(b)(3)
Registration Number 333-56594
Prospectus
$425,000,000
AMEREN ENERGY GENERATING COMPANY
Exchange Offer for all Outstanding
7.75% Senior Notes, Series A Due 2005
and
8.35% Senior Notes, Series B Due 2010
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The Exchange Offer will expire at 5:00 p.m., New York City
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time, on June 7, 2001, unless we extend it.
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Terms of the Exchange Offer
____________________
We are offering to exchange new registered 7.75% Senior Notes, Series C due
2005, for all of our old unregistered 7.75% Senior Notes, Series A due 2005, and
new registered 8.35% Senior Notes, Series D due 2010, for all of our old
unregistered 8.35% Senior Notes, Series B due 2010.
The terms of the new notes will be identical in all material respects to the
terms of the old notes, except that the registration rights and related
liquidated damages provisions and the transfer restrictions applicable to the
old notes will not be applicable to the new notes. The new notes will have the
same financial terms and covenants as the old notes, and will be subject to the
same business and financial risks. Any outstanding old notes not validly
tendered will remain subject to existing transfer restrictions.
Subject to the satisfaction or waiver of specified conditions, we will exchange
the new notes for all old notes that are validly tendered and not withdrawn by
you at any time prior to the expiration of the exchange offer as described in
this prospectus.
Ameren Services Company is serving as the exchange agent. If you wish to tender
your old notes, you must complete, execute and deliver, among other things, a
letter of transmittal to the exchange agent no later than 5:00 p.m., New York
City time, on the expiration date of the exchange offer.
The exchange of old notes for new notes pursuant to the exchange offer will not
be a taxable event for United States federal income tax purposes. See "Material
United States Federal Income Tax Considerations."
The new notes will not be listed on any securities exchange or included in any
automated quotation system.
Each broker-dealer that receives new notes for its own account pursuant to the
exchange offer must acknowledge that it will deliver a prospectus in connection
with any resale of those new notes. The letter of transmittal that is included
as an exhibit to the registration statement of which this prospectus is a part
states that by so acknowledging 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 of 1933, as amended, which we refer to as the Securities Act.
This prospectus, as it may be amended or supplemented from time to time, may be
used by a broker-dealer in connection with resales of new notes received in
exchange for old notes where the old notes were acquired by that broker-dealer
as a result of market-making activities or other trading activities. We have
agreed that, for a period of 270 days after the consummation of the exchange
offer, we will make this prospectus available to any broker-dealer for use in
connection with those resales. See "Plan of Distribution."
See "Risk Factors" on page 11 of this prospectus for a discussion of risks that
you should consider before participating in the exchange offer.
We are not asking you for a proxy and you are requested not to send us a proxy.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
This prospectus is dated April 18, 2001.
TABLE OF CONTENTS
Page
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Important Notice About Information in this Prospectus....................................................... i
Prospectus Summary.......................................................................................... 1
Risk Factors................................................................................................ 11
Forward-Looking Statements.................................................................................. 17
The Exchange Offer.......................................................................................... 18
Use of Proceeds............................................................................................. 28
Capitalization.............................................................................................. 29
Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 30
Our Business................................................................................................ 40
Summary of Independent Technical Review..................................................................... 58
Summary of Independent Market Consultant's Report........................................................... 61
Conversion to Generally Accepted Accounting Principles...................................................... 63
Our Management.............................................................................................. 65
Affiliate Relationships and Transactions.................................................................... 72
Description of the New Notes................................................................................ 74
Material United States Federal Income Tax Considerations.................................................... 88
Plan of Distribution........................................................................................ 92
Legal Matters............................................................................................... 93
Experts..................................................................................................... 93
Where You Can Find More Information......................................................................... 93
Index to Financial Statements............................................................................... F-1
Annex A - Independent Technical Review...................................................................... A-1
Annex B - Independent Market Consultant's Report............................................................ B-1
IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS
You should rely only on the information contained in this document or to
which we have referred you. We have not authorized anyone to provide you with
information that is different or to make any representations about us or the
transactions we discuss in this prospectus. If you receive information about
these matters that is not included in this prospectus, you must not rely on that
information. This document may only be used where it is legal to sell these
securities. The information in this document may only be accurate on the date of
this document.
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PROSPECTUS SUMMARY
This summary highlights the information contained elsewhere in this
prospectus. Because this is only a summary, it does not contain all of the
information that may be important to you. For a more complete understanding of
this exchange offer, we encourage you to read this entire prospectus and the
documents to which we refer you.
Summary of the Terms of the Exchange Offer
Old Notes...................... On November 1, 2000, we sold in a private transaction the old notes, which consist of (1)
$225 million aggregate principal amount of our 7.75% Senior Notes, Series A due 2005, and
(2) $200 million aggregate principal amount of our 8.35% Senior Notes, Series B due 2010,
to Lehman Brothers, Chase Securities Inc., Banc of America Securities LLC, Banc One Capital
Markets, Inc. and BNY Capital Markets, Inc. These initial purchasers then sold the old
notes to institutional investors. Simultaneously with the initial sale of the old notes, we
entered into a registration rights agreement with the initial purchasers under which we
agreed, among other things, to deliver this prospectus to you and to complete an exchange
offer for the old notes. See "The Exchange Offer--Purpose of the Exchange Offer."
The Exchange Offer;
New Notes..................... We are offering to exchange up to (1) $225 million aggregate principal amount of our 7.75%
Senior Notes, Series C due 2005, that have been registered under the Securities Act for a
like aggregate principal amount of our 7.75% Senior Notes, Series A due 2005, and (2) $200
million aggregate principal amount of our 8.35% Senior Notes, Series D due 2010 that have
been registered under the Securities Act for a like principal amount of our 8.35% Senior
Notes, Series B due 2010. The terms of the new notes are identical in all material
respects to the terms of the old notes, except that the registration rights and related
liquidated damages provisions and the transfer restrictions applicable to the old notes are
not applicable to the new notes.
Old notes may be tendered only in denominations of $100,000 and integral multiples of
$1,000 in excess thereof. Subject to the satisfaction or waiver of specified conditions, we
will exchange the new notes for all old notes that are validly tendered and not withdrawn
prior to the expiration of the exchange offer. We will cause the exchange to be effected
promptly after the expiration of the exchange offer.
Upon completion of the exchange offer, there may be no market for the old notes, and if you
failed to exchange the old notes, you may have difficulty selling them.
Resales of the New Notes....... Based on interpretations by the staff of the Securities and Exchange Commission, which we
refer to as the SEC, we believe that the new notes issued in the exchange offer may be
offered for resale, resold or otherwise transferred by you, without compliance with the
registration and prospectus delivery requirements of the Securities Act, if you:
. acquire the new notes in the ordinary course of your business;
. are not engaging in and do not intend to engage in a distribution of the new notes;
. do not have an arrangement or understanding with any person to participate in a
distribution of the new notes;
. are not an affiliate of ours within the meaning of Rule 405 under the Securities Act; and
. are not a broker-dealer that acquired the old notes directly from us.
If any of these conditions is not satisfied and you transfer any new notes without
delivering a proper prospectus or without qualifying for a registration exemption, you may
incur liability under the Securities Act. We do not assume or indemnify you against this
liability.
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In addition, if you are a broker-dealer seeking to receive new notes for your own account
in exchange for old notes that you acquired as a result of market-making or other trading
activities, you must acknowledge that you will deliver this prospectus in connection with
any offer to resell, resale or other transfer of the new notes that you receive in the
exchange offer. See "Plan of Distribution."
Expiration Date................ The exchange offer will expire at 5:00 p.m., New York City time, on June 7, 2001, unless we
extend it.
Withdrawal..................... You may withdraw the tender of your old notes at any time prior to the expiration of the
exchange offer. We will return to you any of your old notes that are not accepted for
exchange for any reason, without expense to you, promptly after the rejection of the tender
or the expiration or termination of the exchange offer.
Consequences of Failing to
Exchange Your Old Notes....... The exchange offer satisfies our obligations and your rights under the registration rights
agreement. After the exchange offer is completed, you will not be entitled to any
registration rights with respect to your old notes.
Therefore, if you do not exchange your old notes, you will not be able to reoffer, resell
or otherwise dispose of your old notes unless:
. you comply with the registration and prospectus delivery requirements of the Securities
Act; or
. you qualify for an exemption from those Securities Act requirements.
These conditions may adversely affect the market price of your old notes.
Interest on the New Notes
and the Old Notes............. Our Series C Notes will bear interest at the annual rate of 7.75%. Our Series D Notes will
bear interest at the annual rate of 8.35%. Interest will be payable semi-annually on the
new notes each May 1 and November 1. Interest on the new notes will accrue from the last
date through which interest was paid on the old notes (expected to be May 1, 2001) and will
first be paid on the new notes on the first May 1 or November 1 following the date the
exchange offer is completed (expected to be November 1, 2001). No interest will be paid in
connection with the exchange. No interest will be paid on the old notes following their
acceptance for exchange. See "Description of the New Notes."
Conditions to the Exchange
Offer......................... The exchange offer is subject to various conditions. We reserve the right to terminate or
amend the exchange offer at any time before the expiration date if various specified events
occur. The exchange offer is not conditioned upon any minimum principal amount of
outstanding old notes being tendered. See "The Exchange Offer--Conditions of the Exchange
Offer."
Exchange Agent................. Ameren Services Company, which we refer to as Ameren Services, is serving as exchange agent
for the exchange offer. All executed letters of transmittal should be directed to the
exchange agent as follows:
By mail:
P.O. Box 66887, St Louis, Missouri 63166-6887
Attention: Investor Services MC 1035, Personal and Confidential
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By hand or overnight courier:
1901 Chouteau Avenue, St Louis, Missouri 63103
Attention: Investor Services MC 1035, Personal and Confidential
Eligible institutions may deliver documents by facsimile at: (314) 554-2401.
Information Agent.............. Morrow & Co., Inc. is serving as information agent for the exchange offer. You should direct
all communications regarding the exchange offer, including requests for assistance or for
additional copies of this prospectus or the letter of transmittal, to the information agent
as follows:
By mail, hand or overnight courier:
445 Park Avenue, 5th floor, New York, New York 10022
You may call the information agent toll-free at: (800) 607-0088.
Banks and brokerage firms should call the information agent toll-free at: (800) 654-2468.
You may contact the information agent via e-mail at ameren.info@morrowco.com.
Procedures for Tendering
Old Notes..................... If you wish to tender your old notes, you must cause the following to be transmitted to and
received by the exchange agent no later than 5:00 p.m., New York City time, on the
expiration date of the exchange offer:
. a confirmation of a book-entry transfer of the tendered old notes into the exchange
agent's account at The Depository Trust Company, which we refer to as DTC;
. a properly completed and duly executed letter of transmittal in the form accompanying
this prospectus (with any required signature guarantees) or, at the option of the
tendering holder in the case of a book-entry tender, an agent's message instead of the
letter of transmittal; and
. any other documents required by the letter of transmittal.
The new notes are referred to as the "Exchange Notes" in the letter of transmittal.
Guaranteed Delivery
Procedures.................... If you wish to tender your old notes and you cannot complete procedures for book-entry
transfer or cause the old notes or any other required documents to be transmitted to and
received by the exchange agent before 5:00 p.m., New York City time, on the expiration
date, you may tender your old notes according to the guaranteed delivery procedures
described in this prospectus under the heading "The Exchange Offer--Guaranteed Delivery
Procedures."
Special Procedures for
Beneficial Owners............. If you are the beneficial owner of old notes that are registered in the name of your
broker, dealer, commercial bank, trust company or other nominee, and you wish to
participate in the exchange offer, you should promptly contact the person in whose name
your outstanding old notes are registered and instruct that person to tender your old notes
on your behalf. See "The Exchange Offer--Procedures for Tendering."
Representations of
Tendering Holders............. By tendering old notes pursuant to the exchange offer, you will, in addition to other
customary representations, represent to us that you:
. are not an affiliate of ours;
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. are not a broker-dealer tendering old notes acquired directly from us;
. are acquiring the new notes in the ordinary course of business;
. are not engaging in and do not intend to engage in a distribution of the new notes;
. have no arrangement or understanding with any person to participate in the distribution
of the new notes; and
. acknowledge that if you are deemed to have participated in the exchange offer for the
purpose of distributing the new notes, you will comply with the registration and
prospectus delivery requirements of the Securities Act.
Acceptance of Old Notes and
Delivery of New Notes......... Subject to the satisfaction or waiver of the conditions to the exchange offer, we will
accept for exchange any and all old notes that are properly tendered and not withdrawn
prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. We
will cause the exchange to be effected promptly after the expiration of the exchange offer.
United States Federal
Income Tax Considerations..... The exchange of old notes for new notes pursuant to the exchange offer generally will not
be a taxable event for United States federal income tax purposes. See "Material United
States Federal Income Tax Considerations."
Regulatory Approvals........... All regulatory approvals necessary for the exchange of the old notes for the new notes have
been obtained.
Appraisal or Dissenters'
Rights........................ You will have no appraisal or dissenters' rights in connection with the exchange offer.
Use of Proceeds................ We will not receive any proceeds from the issuance of new notes pursuant to the exchange
offer. We will pay expenses incident to the exchange offer to the extent indicated in the
registration rights agreement.
Summary of the Terms of the New Notes
The terms of the new notes will be identical in all material respects to
the terms of the old notes, except that the registration rights and related
liquidated damages provisions and the transfer restrictions applicable to the
old notes are not applicable to the new notes. The new notes will evidence the
same debt as the old notes. The new notes and the old notes will be governed by
the same indenture. For more complete information about the new notes, see the
"Description of the New Notes" section of this prospectus.
Issuer......................... AmerenEnergy Generating Company
New Notes...................... We will offer the new notes in two series: up to $225 million principal amount of 7.75%
Senior Notes, Series C due 2005 and up to $200 million principal amount of 8.35% Senior
Notes, Series D due 2010.
Maturity....................... Our Series C Notes will mature on November 1, 2005. Our Series D Notes will mature on
November 1, 2010.
Interest Rate.................. Interest will accrue on the Series C Notes at a rate of 7.75% per year.
Interest will accrue on the Series D Notes at a rate of 8.35% per year.
Interest Accrual............... Interest on the new notes will accrue from the last date through which interest was paid on
the old notes (expected to be May 1, 2001) and will first be paid on the new notes on the
first May 1 or November 1 following the date the exchange offer is completed (expected to
be November 1, 2001). No interest will be paid in connection with the exchange.
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Interest Payment Dates......... We will pay interest on the new notes semi-annually on May 1 and November 1, beginning on
the first May 1 or November 1 following completion of the exchange offer (expected to be
November 1, 2001).
Optional Redemption............ We may redeem the notes of each series, in whole or in part, at any time at a redemption
price equal to 100% of the principal amount of the notes to be redeemed plus accrued
interest, if any, plus a make-whole premium, calculated using a discount rate equal to the
interest rate on comparable U.S. treasury securities plus 25 basis points.
Ranking........................ The new notes will be our senior unsecured obligations and will rank equally in right of
payment with all of our other present and future senior debt, including $104 million
aggregate principal amount of tax-exempt pollution control loan obligations we expect to
assume in 2001 from our affiliate. The new notes will rank senior in right of payment to
all of our present and future subordinated debt.
Covenants...................... The indenture limits our ability to, among other things:
. sell assets;
. create liens; and
. engage in mergers, consolidations or similar transactions.
In addition, the indenture includes transitional covenants that limit our ability to incur
indebtedness and pay dividends or make other specified restricted payments, which
transitional covenants may be terminated by us on or after the date on which financial
statements for five full years of operations of our company are available and upon written
reaffirmation by each of Standard & Poor's Ratings Services, Moody's Investors Services,
Inc. and Fitch, Inc. of at least the original ratings of the old notes (after giving effect
to that termination).
See "Description of the New Notes--Covenants" and "--Transitional Covenants."
Events of Default.............. The indenture describes the circumstances that constitute events of default with respect to
the new notes. See "Description of the New Notes--Events of Default."
Form of the New Notes.......... The new notes will be represented by one or more permanent global securities in registered
form deposited with The Bank of New York, as custodian, for the benefit of DTC. You will
not receive notes in registered form unless one of the events set forth under the heading
"Description of the New Notes--Book-Entry; Delivery and Form" occurs. Instead, beneficial
interests in the new notes will be shown on, and transfers of these interests will be
effected only through, records maintained in book-entry form by DTC with respect to its
participants.
Absence of a Public Market for the
New Notes.................... There has been no public market for the old notes, and no active public market for the new
notes is currently anticipated. We do not intend to apply for a listing of the new notes on
any securities exchange or inclusion in any automated quotation system. We cannot make any
assurances regarding the liquidity of the market for the new notes, the ability of holders
to sell their new notes or the price at which holders may sell their new notes. See "Plan
of Distribution."
Trustee........................ The Bank of New York is serving as the trustee under the indenture.
AmerenEnergy Generating Company
General
We are a wholly-owned subsidiary of Ameren Corporation, which, collectively
with its subsidiaries, we refer to as Ameren. We operate the electric
generation business formerly operated by our affiliate, Central Illinois Public
Service Company d/b/a AmerenCIPS, which we refer to as AmerenCIPS. We were
incorporated in the State of Illinois in March 2000 and we acquired most
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of our generating assets from AmerenCIPS at net book value on May 1, 2000,
consisting of the coal plants described below, all related fuel, supply,
transportation, maintenance and labor agreements, approximately 45% of
AmerenCIPS' employees, and some other related rights, assets and liabilities.
Our generating business includes the following:
Coal Plants. The following stations, which we refer to as our coal plants:
Five generating stations (12 units) we acquired from AmerenCIPS (Newton,
Coffeen, Meredosia, Hutsonville and Grand Tower). We expect the majority of our
coal-fired capacity to operate at capacity factors consistent with historical
base-load dispatch in our principal market. These plants predominantly use coal
for fuel and can generate 2,860 megawatts of electricity.
Operating Combustion Turbine Units. The following stations, which we refer
to as our operating combustion turbine units: Three generating stations (Gibson
City, Pinckneyville and Joppa), consisting of nine newly acquired combustion
turbine generating units. These stations use natural gas as fuel (some have
dual fuel capability) and will be used to supply peaking power. These stations
can generate 584 megawatts of electricity.
Committed Units. The following units, which we refer to as our committed
units: We will repower one of our coal-fired plants (Grand Tower) by installing
two gas-fired combined cycle units which we expect will generate 492 total
megawatts (302 megawatts more than the plant's current capacity). This
repowered station will be used for intermediate service and is expected to be in
service around mid-2001. In addition, we plan to acquire another generating
station (Kinmundy), consisting of two units (230 megawatts of additional
capacity) by mid-2001. This additional capacity will be fueled by natural gas
and will be used to supply peaking power. Our affiliate company is completing
construction of these facilities, and we will acquire them only when they are
ready for commercial operation.
By summer 2001, we plan to have a diversified portfolio of 4,264 megawatts
of efficient, low-cost generation, consisting of the committed units described
above, as well as 288 megawatts of additional capacity from the units to be
located at Columbia, Missouri and at our Pinckneyville station discussed below
under "Recent Developments." We plan to acquire up to 1,490 megawatts of
additional capacity from planned units between mid-2002 and mid-2005. These
planned units will operate on natural gas (or dual fuel) and will be used for
intermediate and/or peaking service. These plans may change depending on future
conditions affecting us and our markets.
We will be well-positioned to be a competitive provider of electricity in
our principal market - Illinois and portions of the surrounding states
comprising the Mid-American Interconnected Network, or MAIN, and East Central
Area Reliability, or ECAR, regions. Projected summer peak demand in this market
area is about 145,000 megawatts.
Recent Developments
In addition to the information provided above under "General," we intend to
expand our generating business in the near future as follows:
Pending Additions. By summer 2001, we plan to acquire eight additional
units to be located in Columbia, Missouri and at our Pinckneyville station,
which we refer to as our pending additions. We plan to add four 36 megawatt
simple cycle combustion turbine generating units at each location. These units
will operate on natural gas and will be used for peaking service.
Anticipated Site. We are in the process of developing another site in
Elgin, Illinois, which we refer to as our anticipated site. Currently, we are
working to obtain municipal approvals for and undertaking other developmental
efforts at this location.
We advise you that neither our pending additions nor our anticipated site
were included in, or considered or analyzed in connection with the preparation
of, either the Independent Technical Review or the independent market
consultant's report described below under "Independent Consultants Reports."
Moreover, we have not included information in this prospectus regarding our
pending additions or anticipated site that is comparable to that which we have
provided for our coal plants, operating combustion turbine units or committed
units.
In March 2001, Ameren Corporation decided it would no longer pursue the
previously announced transfer of Illinois-based distribution and transmission
assets from its subsidiary, Union Electric Company d/b/a AmerenUE, which we
refer to as AmerenUE, to AmerenCIPS. This transfer would have added about 525
megawatts of demand to the AmerenCIPS load which would have been supplied by us
under our agreement to supply AmerenCIPS with power. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Liquidity and Capital Resources--Capital Expenditures."
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Ameren Corporation
St. Louis-based Ameren Corporation (NYSE: AEE) is among the nation's 25
largest investor-owned electric utilities, with $10 billion in assets. Ameren
companies provide energy services to 1.5 million electric and 300,000 natural
gas customers throughout its 44,500 square mile territory in Missouri and
Illinois. Within the MAIN region, an area that includes most of Illinois,
eastern portions of Missouri and Wisconsin, and much of peninsular Michigan,
Ameren holds the largest market share of installed generating capacity
(approximately 24 percent).
Ameren Corporation is a public utility holding company registered under the
Public Utility Holding Company Act of 1935, which we refer to as PUHCA, and does
not own or operate any significant assets other than the stock of its
subsidiaries. Ameren Corporation, directly or indirectly, owns all of the common
stock of these principal subsidiary companies:
. AmerenUE, the largest electric utility in the State of Missouri and a
supplier of electric and natural gas service in Missouri and Illinois
to about 1.1 million electric customers and 125,000 gas customers.
. AmerenCIPS, which is an electric utility in the State of Illinois that
supplies electric and natural gas service in portions of central and
southern Illinois to about 400,000 electric customers and 175,000 gas
customers.
. AmerenEnergy Resources Company, which we refer to as Resources, a
holding company for Ameren Corporation's non-regulated generation,
related marketing and fuel procurement businesses.
. AmerenEnergy, Inc., which we refer to as Ameren Energy, an energy
trading subsidiary that acts as agent for AmerenUE and our company for
the wholesale purchase and sale of electricity for terms of less than
one year.
. Ameren Services, a provider of shared support services to all of the
Ameren companies.
. AmerenEnergy Development Company, which we refer to as Development
Co., our non-regulated parent company that develops and constructs
generating facilities. Development Co. is also an exempt wholesale
generator under PUHCA and leases the Joppa units from us.
. AmerenEnergy Marketing Company, which we refer to as Marketing Co., a
non-regulated wholesale and retail energy marketing company that will
concentrate on wholesale sales of electricity for terms greater than
one year and retail sales.
. AmerenEnergy Fuels and Services Company, which we refer to as Fuels
Co., a non-regulated subsidiary that manages coal, natural gas and
fuel oil purchasing for the Ameren companies on a centralized basis.
. Our company, which is an exempt wholesale generator under PUHCA.
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Neither Ameren Corporation nor any of its direct or indirect subsidiaries,
other than our company, is liable for payments under the new notes offered in
this prospectus. The chart below depicts the simplified corporate structure of
Ameren Corporation and its direct and indirect subsidiaries.
[A diagram illustrating the organizational structure of Ameren Corporation and
its subsidiaries. Ameren Corporation is the ultimate parent company and the sole
shareholder of AmerenUE, AmerenCIPS, Resources, Ameren Energy and Ameren
Services. Resources is the sole shareholder of Development Co., Marketing Co.
and Fuels Co. Development Co. is the sole shareholder of AmerenEnergy Generating
Company, the issuer.]
Independent Consultants Reports
As independent technical consultant, Stone & Webster Consultants, Inc.
(formerly S&W Consultants, Inc.) has prepared an Independent Technical Review
concerning specific technical, environmental and economic aspects of our
electric generating facilities. We advise you that the Independent Technical
Review is dated October 25, 2000, and information contained in that report may
only be accurate as of that date. We have not requested, nor do not intend to
request, that Stone & Webster Consultants, Inc. update the information in the
Independent Technical Review. This report does not include any information
regarding, and the independent technical consultant did not consider in its
review, the units or site described above under "Ameren Energy Generating
Company--Recent Developments." We have included the Independent Technical Review
as Annex A to this prospectus.
As independent market consultant, Resource Data International, Inc. has
prepared a report that analyzes the Midwest United States electricity market and
the economic competitiveness of our electric generating facilities within that
market. The report provides an assessment of the long-term market opportunities,
including capacity and energy prices expected to be received by generators in
the region for the years 2000 through 2020. We advise you that the independent
market consultant's report is dated June 6, 2000, and information contained in
that report may only be accurate as of that date. We have not requested, nor do
not intend to request, that Resource Data International, Inc. update the
information in its report. This report does not include any information
regarding, and the independent market consultant did not consider in its review,
the units or site described above under "Ameren Energy Generating Company--
Recent Developments." A copy of the report is included as Annex B to this
prospectus.
How To Contact Us
AmerenEnergy Generating Company is incorporated in the State of Illinois.
Our principal executive offices are located at 1901 Chouteau Avenue, St. Louis,
Missouri 63103. Our telephone number is (314) 554-3922. You can find
information regarding our company on Ameren's website at
(http://www.ameren.com). The information in this website is not incorporated by
reference in this prospectus.
Summary Financial and Operating Data
Following is a summary of selected historical financial data for our
company. We have a limited operating history and, therefore, separate financial
statements with regard to our business are available only for the period since
May 1, 2000. Prior to that date, all operations of our coal plants were fully
integrated with, and therefore results of operations were consolidated into the
financial statements of, AmerenCIPS, whose business was to generate, transmit
and distribute electricity and to provide other customer support services. The
selected historical information as of December 31, 2000 and for the eight-month
period then ended
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has been derived from audited financial statements of our company included
elsewhere in this prospectus. You should read the information set forth below in
conjunction with the section of this prospectus captioned "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our audited historical financial statements and the accompanying notes beginning
on page F-1 of this prospectus. In the opinion of our management, the financial
statements from which the data set forth below were derived contain all
adjustments necessary, consisting of only normal and recurring adjustments,
necessary for a fair presentation of the information shown.
Earnings before interest, taxes, depreciation and amortization, or EBITDA,
as shown in the Income Statement Data may differ from the calculation used by
other companies and should not be considered as an alternative to net income,
cash flows or any other item calculated in accordance with U.S. generally
accepted accounting principles or as an indication of operating performance or
liquidity. Pro-forma adjustments to the balance sheet as of December 31, 2000
include the expected assumption by us of AmerenCIPS' obligations with respect to
$104 million of tax-exempt pollution control loan obligations and $1 million of
related unamortized debt issue costs. For a description of the Subordinated
Intercompany Notes referred to in the Balance Sheet Data, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources."
Historical Financial Data
(in thousands)
Income Statement Data
Eight months ended
December 31, 2000
-----------------------
Revenues.............................................................................................. $479,701
Operating Expenses.................................................................................... $376,433
Pre-Tax Income........................................................................................ $ 71,021
Net Income............................................................................................ $ 43,808
EBITDA................................................................................................ $134,179
Balance Sheet Data
Pro forma
As of as of
December 31, 2000 December 31, 2000
--------------------- ---------------------
Current Assets............................................................... $ 240,427 $ 240,427
Total Assets................................................................. $1,393,662 $1,394,662
Total Liabilities............................................................ $1,349,852 $1,350,852
Senior Debt............................................................. $ 423,676 $ 527,676
Subordinated Intercompany Notes......................................... $ 601,626 $ 498,626
Stockholders' Equity......................................................... $ 43,810 $ 43,810
9
Ratio of Earnings to Fixed Charges
(in thousands)
For the period from May 1, 2000 through December 31, 2000
Pre-tax income (loss) from
continuing operations before
adjustment for minority interests
in consolidated subsidiaries or
income or loss from equity investees................................ $ 71,021
Add - fixed charges:
Interest expense and amortization of debt
discount on third-party indebtedness............................. $ 5,344
Interest expense on intercompany
indebtedness..................................................... $ 29,537
Interest capitalized................................................ $ 803
Total fixed charges.................................................... $ 35,684
Pre-tax income (loss) from continuing
operations before adjustment for
minority interests in consolidated
subsidiaries or income or loss from
equity investees plus fixed charges................................. $106,705
Ratio of earnings to fixed charges..................................... 2.990
10
RISK FACTORS
The new notes, like the old notes, entail risk. In deciding whether to
participate in the exchange offer, you should consider the risks associated with
the nature of our business and the risk factors relating to the exchange offer
in addition to the other information contained in this prospectus. You should
carefully consider the following factors before making a decision to exchange
your old notes for new notes. The risk factors described below are not
necessarily exhaustive, and we encourage you to perform your own investigation
with respect to the new notes and our company.
If you fail to exchange your old notes, you may be unable to sell them.
Because we did not register the old notes under the Securities Act or any
state securities laws, and we do not intend to do so after the exchange offer,
the old notes may only be transferred in limited circumstances under applicable
securities laws. If the holders of the old notes do not exchange their old notes
in the exchange offer, they lose their right to have their old notes registered
under the Securities Act, subject to some limitations. As a holder of old notes
after the exchange offer, you may be unable to sell your old notes.
There is no public market for the new notes, so you may be unable to sell them.
The new notes are new securities for which there is currently no market.
Consequently, the new notes will be relatively illiquid, and you may be unable
to sell them. We do not intend to apply for listing of the new notes on any
securities exchange or for the inclusion of the new notes in any automated
quotation system. Accordingly, we cannot assure you that a liquid market for the
new notes will develop.
You must tender the old notes in accordance with proper procedures in order to
ensure the exchange will occur.
The exchange of the old notes for the new notes can only occur if you
follow the proper procedures as detailed in this prospectus. The new notes will
be issued in exchange for the old notes only after timely receipt by the
exchange agent of the old notes or a book-entry confirmation, a properly
completed and executed letter of transmittal (or an agent's message instead of a
letter of transmittal) and all other required documentation. If you want to
tender your old notes in exchange for new notes, you should allow sufficient
time to ensure timely delivery. The exchange agent is not and we are not under
any duty to give you notification of defects or irregularities with respect to
your tender of old notes for exchange. Old notes that are not tendered will
continue to be subject to the existing transfer restrictions. In addition, if
you are an affiliate of ours or you tender the old notes in the exchange offer
in order to participate in a distribution of the new notes, you will be required
to comply with the registration and prospectus delivery requirements of the
Securities Act in connection with any resale transaction. For additional
information, please refer to the sections entitled "The Exchange Offer" and
"Plan of Distribution" later in this prospectus.
Our revenues and results of operations will depend in part on market and other
forces beyond our control.
The markets for wholesale electric energy transactions in our market area
have been, or are in the process of becoming, deregulated. We and other non-
regulated owners of electric generating facilities will not have any recovery of
our costs or any specified rate of return set by a regulatory body. Therefore,
with the exception of revenue generated by contracted loads under the power
purchase agreement that we entered into with Marketing Co., which we refer to as
the Genco-Marketing Co. agreement and describe in more detail elsewhere in this
prospectus, our revenues and results of operations will depend on the prices
that we can obtain for energy and capacity in Illinois and adjacent markets.
Among the factors that could influence those prices (all of which factors are
beyond our control to a significant degree) are:
. fuel supply and price: the prevailing market prices for natural gas,
fuel oil and coal;
11
. competition: the extent of additional supplies of electric energy from
our current competitors or new market entrants;
. pricing and market development: the regulatory and pricing structures
developed for Midwest energy markets as they continue to evolve and
the pace of development of regional markets for energy and capacity
outside of bilateral contracts;
. transmission: future pricing for, and availability of, transmission
services on transmission systems, and the effect of deregulation
proposals and export energy transmission constraints, which could
limit our ability to sell energy;
. demand: the rate of growth in electricity usage as a result of
population changes, regional economic conditions and the
implementation of conservation programs;
. weather: climate conditions prevailing in the Midwest market from time
to time; and
. pace of deregulation: the potential deceleration of deregulation in
our market area or slowing of the expansion of deregulated markets.
The operation of the electric generating facilities involves risks.
Operation of electric generating facilities involves risks that can
adversely affect energy output and efficiency levels. Included among these risks
are: interruptions in fuel supply, increased prices for fuel and fuel
transportation as existing contracts expire, disruptions in the delivery of
electricity, facility shutdowns due to a breakdown or failure of equipment or
processes, labor disputes, inability to comply with regulatory or permit
requirements, operator error and catastrophic events such as fires, explosions,
floods or other similar occurrences affecting our electric generating
facilities, ourselves or third parties upon which our business may depend.
Our generating facilities will require ongoing capital expenditures.
Our coal plants, like generating facilities of similar age, will require
additional capital expenditures. The units comprising the Newton facility and
the Coffeen facility were installed between 1965 and 1982. The remaining coal
plants were installed prior to 1965. Generating equipment of this age, even if
well maintained, will require additional capital expenditures to maintain
reliable levels of operations. We plan significant capital projects at our coal
plants over the next ten years, including the addition of environmental
compliance equipment and refurbishment or replacement of major station
components. The average capital expenditures we project to make are $53 million
per year from 2001 through 2010. We cannot assure you that additional capital
expenditures will not be required; that our cost estimates are accurate; or
that, if necessary, we will be able to obtain financing at reasonable rates to
pay for these expenditures. The indenture for the notes may limit our ability to
incur future indebtedness.
The price and availability of fuel will have a significant effect on our
profitability.
Our coal plants depend principally upon mid- and low-sulfur coal as their
fuel supply, and our environmental compliance strategy also relies on low-sulfur
coal to a significant extent. A substantial portion of our operating expenses
for these plants will consist of the costs of obtaining this fuel supply. We
will have to buy less than 10% percent of the required coal for our coal plants
for 2001 in the spot market. In addition, 36% of the coal requirements through
2005, and at least 55% of those requirements through 2010 are not covered by
long-term contracts. We expect to continue to use the spot market to satisfy
some portion of our annual coal requirements for the foreseeable future. Our
revenues from our coal plants may not keep pace with our coal costs if market
prices for coal escalate more rapidly than market prices for sales of energy. In
addition, we have recently experienced some delays in our coal deliveries due to
various transportation and operating constraints in the system. We are working
closely with the transportation companies and monitoring operating practices in
order to maintain adequate levels of coal inventory for future operating
purposes.
12
The new combined cycle and simple cycle combustion turbine units that we
recently acquired and expect to acquire depend upon natural gas for their fuel
supply, and a significant portion of our operating expenses for these units will
consist of costs of gas supply and delivery. Demand for natural gas for power
plant fuel and other uses has been increasing and we expect this trend to
continue. Moreover, natural gas prices have risen significantly and reached
record levels since last summer. We expect to utilize a combination of term
supply contracts and short-term purchases utilizing both fixed and market-based
pricing as part of our natural gas strategy. We also expect to employ embedded
price hedges, storage and balancing agreements and futures and basis contracts.
We cannot assure you that these strategies will be successful in reducing gas
price volatility or that we will be able to procure gas at prices assumed in the
financial projections included in the Independent Technical Review included as
Annex A to this prospectus.
The new combined cycle and simple cycle combustion turbine units at Gibson
City, Pinckneyville, Kinmundy and Grand Tower are or will be connected to
Natural Gas Pipeline Company of America, or NGPL, which is a major interstate
natural gas pipeline serving the Midwest markets. We have in place various
capacity agreements with NGPL to deliver natural gas to these new facilities on
demand. Although a portion of the capacity supporting our combustion turbine
generating units utilizes firm transportation and firm storage under agreements
with terms extending to 2004 (extendable at our option to 2008), a significant
amount of capacity will be interruptible or released capacity and thus subject
to risk of curtailment by the interstate pipeline or by the primary capacity
holder.
The coal plants were not operated historically on a competitive basis and some
of the coal plants were not operated at the capacity factors we project.
Substantially all of our business consists of owning and operating our
electric generating facilities. Although the coal plants had a significant
operating history at the time we acquired them, they had been operated as an
integrated part of a regulated utility under the coal supply contracts then in
place prior to their acquisition by us. Our business plan assumes, among other
things, that some of our coal plants will be operated more of the time than they
had been historically due to renegotiated coal supply contracts which have made
operation of these plants more economically attractive. The energy generated by
our coal plants before we acquired them was sold by AmerenCIPS based upon rates
set by regulatory authorities. We cannot assure you that we will be able to
operate the coal plants at the capacity factors we project or that these plants
will compete successfully in an environment in which electricity prices will be
set by market forces.
We are subject to substantial environmental regulation.
We believe that we have obtained all material environmental-related
approvals required as of the date of this prospectus to operate the coal plants
and the additional electric generating facilities we recently acquired or that
those approvals have been applied for and will be issued in a timely manner.
These approvals concern, among other things, the protection of the environment
and the health and safety of employees and the public. Failure to comply with
any applicable statutes, regulations and ordinances could have a material
adverse effect on us, including potential civil or criminal liability,
imposition of clean-up liens and fines and expenditures of funds to bring the
coal plants and other plants that we own or acquire into compliance.
We plan to comply with current nitrogen oxide (NO\\X\\) and sulfur dioxide
(SO\\2\\) emissions limitations through a combination of the purchase of
emissions credits and the future addition of additional pollution control
equipment at our coal plants. The laws and regulations governing emissions from
coal-burning plants, particularly NO\\X\\, are in the process of being revised
by federal and state authorities, and substantially more stringent limitations
than those currently applicable may be imposed. We cannot assure you that our
compliance strategy, although reasonable based upon the information available to
us today, will successfully address the relevant standards in the future, or
that the strategy can be executed at the costs we project.
Potential soil and groundwater contamination exists at the sites of each of
our coal plants. When we acquired the coal plants from AmerenCIPS, AmerenCIPS
indemnified us from and against any and all environmental damages arising from
the presence, use, generation, storage, treatment, discharge, release or
disposal (including off-site disposal) of hazardous materials upon, about, from
or beneath the property transferred to us or migrating to or from that property,
or arising in any manner whatsoever out of the violation of any environmental
13
requirements pertaining to that property and the activities on that property, in
each case to the extent that the environmental damages or violation of any
environmental requirements are attributable to, or the result of, any act or
omission by AmerenCIPS prior to the date of transfer. This indemnity will be
subject to interpretation as specific circumstances arise, and will not apply to
remediation which may be required in respect of actions we take (or omit
to take) after the transfer date. To the extent the AmerenCIPS indemnity does
not protect us, future remediation costs could be substantial.
By 2005, we may face significant competition.
We do not expect competition in the electric industry to have a material
effect on us until the power purchase agreement between Marketing Co. and
AmerenCIPS, which we refer to as the Marketing Co.-CIPS agreement and describe
in more detail elsewhere in this prospectus, which we service through our Genco-
Marketing Co. agreement, expires on December 31, 2004. At that time, we will
potentially be subject to competition to a larger degree from major national and
international power suppliers who we expect will target our Midwest markets as
well as other national markets. The independent market consultant has projected
that at least 6,400 megawatts of additional capacity will be added in MAIN by
2004, not counting our planned additions. Some of our competitors may have
greater financial, marketing, trading and generating resources than we do to
bring to bear in our target markets.
The new generating facilities we recently acquired and expect to acquire may
experience operating problems.
The combustion turbine generating units that we recently acquired and
expect to acquire over the next several years are new or refurbished units with
no site-specific operating history. Operation of these combustion turbine
generating units could be affected by many factors, including start-up problems,
the breakdown or failure of equipment or processes, the performance of these
combustion turbine generating units below expected levels of output or
efficiency, failure to operate at design specifications, labor disputes, changes
in law and failure to meet environmental and other permit conditions. The
occurrence of these events could significantly reduce or eliminate revenues or
significantly increase the expenses related to those facilities. The proceeds of
any available insurance and limited warranties may not be adequate to cover our
lost revenues or increased costs.
We rely upon affiliates and third parties to conduct important parts of our
business.
Our non-management employees are principally engaged in operating our coal
plants. Most of the balance of our business is operated by affiliates and third
parties with the participation of our management. In particular:
. Marketing Co. and Ameren Energy market our energy and capacity;
. Fuels Co. is responsible for our fuel supply;
. Ameren Energy administers and coordinates the dispatch of our plants
jointly with AmerenUE's plants on the bases set forth in the amended
joint dispatch agreement described in this prospectus;
. Development Co. will complete construction of the committed units and
deliver them to us; and leases the Joppa combustion turbine generating
units from us;
. Siemens Westinghouse Operating Services Company will operate and
maintain the Gibson City, Kinmundy and Pinckneyville generating
stations for us under a long-term contract; and
. Ameren Services provides support services to us.
We would require substantial additional resources to perform any of these
important functions ourselves if that were to become necessary or desirable due
to changes in law or regulation, any substandard performance by one or more of
these parties or other factors.
14
Our business is subject to substantial energy regulatory requirements.
Our business could be materially and adversely affected as a result of
legislative or regulatory changes or judicial or administrative interpretations
of existing energy regulatory laws, regulations or licenses that impose more
comprehensive or stringent requirements on us. See "Our Business--Regulation."
We believe that we have obtained all material energy-related approvals
required as of the date of this prospectus to operate the coal plants and the
operating combustion turbine units, and we are in the process of obtaining
necessary approvals for the committed units. We may be required to obtain
additional regulatory approvals, including, without limitation, licenses,
renewals, extensions, transfers, assignments, reissuances or similar actions. We
cannot assure you that we will be able to:
. obtain all required regulatory approvals that we do not yet have or
that we may be required to obtain in the future,
. obtain any necessary modifications to existing regulatory approvals,
or
. maintain all required regulatory approvals.
Delay in obtaining or failure to obtain and maintain in full force and
effect any of those regulatory approvals, or delay or failure to satisfy any
applicable regulatory requirements, could prevent operation of our plants, or
the sale of electricity from those assets, or could result in potential civil or
criminal liability or additional costs to us.
We are responsible for price risk management activities conducted on our behalf
by affiliates.
Ameren Energy and Fuels Co. engage in price risk management activities
related to our sales of electricity and purchases of fuels. These activities are
for our account. Ameren Energy and Fuels Co. may use forward contracts and
derivative financial instruments, such as futures contracts and options, to
manage market risks and exposure to fluctuating electricity, coal and natural
gas prices. We cannot assure you that these strategies will be successful in
managing our pricing risks, or that they will not result in net liabilities to
us as a result of future volatility in electricity and fuel markets.
Conflicts of interest may arise between us and our affiliates.
We and the affiliates we rely on for important parts of our business and
sales, such as Marketing Co., Ameren Energy and Development Co., are all
directly or indirectly wholly-owned by Ameren Corporation. Conflicts of interest
may arise if we need to enforce the terms of agreements between us and any of
our affiliates. For example, we expect to rely on a contractual indemnity from
AmerenCIPS in the event that we incur remediation costs at the sites of our coal
plants on account of pre-existing environmental contamination. Because of these
affiliate relationships, it is possible that decisions concerning the
interpretation or operation of these agreements could be made from perspectives
other than the interests solely of our company or its creditors.
Although it is Ameren's intention that we will own and operate the
additional generating facilities planned beyond mid-2001, it is possible that
other Ameren entities could acquire or participate in the ownership of those
facilities and compete with us.
We are relying on projections of the future performance of our electric
generating facilities.
The projected operating and financial results contained in the Independent
Technical Review included as Annex A to this prospectus are predicated upon
various assumptions and forecasts of our electric generating facilities' revenue
generating capacity and the costs associated with that revenue generating
capacity. The assumptions made with respect to future market prices for energy
are based upon a comprehensive market analysis prepared by the independent
market consultant and included as Annex B to this prospectus. This market
forecast served as a basis for the revenue assumptions incorporated in the
projected operating results beyond the revenue
15
assumptions based on fixed price contractual commitments described in this
prospectus. The independent technical consultant has reviewed the technical
operating parameters of our electric generating facilities. The independent
technical consultant has also evaluated the operations and maintenance budgets
of our facilities and the related assumptions and forecasts contained therein
based on a review of various technical, environmental, economic and permitting
aspects of the facilities. The independent technical consultant prepared the
projected operating and financial results contained in Annex A to this
prospectus with information that was available as of October 25, 2000.
The independent market consultant prepared the market analysis contained in
Annex B to this prospectus, which served as a basis for some assumptions made in
preparing the projected operating and financial information, with information
that was available as of June 6, 2000. We have not requested, nor do we intend
to request, that either the independent technical consultant or the independent
market consultant update their reports with information that is currently
available. Moreover, we cannot assure you that we will provide comparable
projected operating or financial information in the future.
The projected operating and financial results included in this prospectus
are our responsibility and have been prepared on the basis of assumptions that
we and the persons who have provided them believe to be reasonable. Our
independent auditors, PricewaterhouseCoopers LLP, have not examined, reviewed or
compiled the projected operating and financial results and, accordingly, do not
express an opinion or any other form of assurance with respect to them. The
report of PricewaterhouseCoopers LLP included in this prospectus relates to our
historical financial statements for the period May 1, 2000 through December 31,
2000. It does not extend to our projected financial data and should not be read
to do so. We do not intend to provide the holders of the new notes with any
revised or updated projected operating results or analysis of the differences
between the projected operating results and actual operating results.
Accordingly, the projected operating and financial results are not
necessarily indicative of our future performance and neither we, the independent
market consultant, the independent technical consultant nor any other person
assumes any responsibility for their accuracy. 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 sensitivities included in the projected
operating results prove to be incorrect, our ability to pay our operating
expenses and other obligations may be materially adversely affected.
16
FORWARD-LOOKING STATEMENTS
Specific 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 of those terms or other
variations on those terms or comparable terminology, or by discussions of
strategy. Although we believe these statements are based upon reasonable
assumptions, no assurance can be given that the future results covered by the
forward-looking statements will be achieved. Forward-looking statements are
subject to risks, uncertainties and other factors that may be outside of our
control and that could cause actual results to differ materially from future
results expressed or implied by the forward-looking statements. In connection
with the "Safe Harbor" provisions of the Private Securities Litigation Reform
Act of 1995, we are providing this cautionary statement to identify important
factors that could cause results to differ materially from those anticipated.
The most significant of the risks, uncertainties and other factors are :
. fuel prices and availability;
. generation plant construction, installation and performance;
. the impact of current environmental regulations on generating
companies and the expectation that more stringent requirements will be
introduced over time, which could potentially have a negative
financial effect;
. wholesale and retail pricing for electricity in the Midwest;
. the effects of regulatory actions, including changes in regulatory
policy;
. changes in laws and other governmental actions;
. future wages and employee benefits costs;
. competition from other generating facilities, including new facilities
that may be developed in the future;
. cost and availability of transmission capacity for energy that we
generate at our facilities or energy that other parties use to satisfy
sales they make on our behalf; and
. legal and administrative proceedings.
17
THE EXCHANGE OFFER
Purpose of the Exchange Offer
We initially sold the old notes in a private offering on November 1, 2000
to Lehman Brothers, Chase Securities Inc., Banc of America Securities LLC, Banc
One Capital Markets, Inc. and BNY Capital Markets, Inc. pursuant to a note
purchase agreement dated October 25, 2000 between us and them. These initial
purchasers of the old notes resold them to qualified institutional buyers in
reliance on, and subject to the restrictions imposed under, Rule 144A under the
Securities Act. As of the date of this prospectus, $425 million aggregate
principal amount of old notes are outstanding.
In connection with the private offering of the old notes, we entered into a
registration rights agreement dated November 1, 2000 with the initial purchasers
under which we agreed, among other things, to:
(1) prepare and file with the SEC an exchange offer registration
statement under the Securities Act relating to an exchange offer for
the old notes;
(2) use our reasonable best efforts to cause the exchange offer
registration statement to be declared effective under the Securities
Act on or before June 9, 2001;
(3) upon the effectiveness of the registration statement, commence the
exchange offer and offer the holders of the old notes the opportunity
to exchange their old notes for a like principal amount of new notes
and to 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 the holders of the old notes; and
(4) use our reasonable best efforts to complete the exchange offer and
issue the new notes on or prior to July 29, 2001.
We are making this exchange offer to satisfy our obligations and your
registration rights under the registration rights agreement. If, among other
things, we do not satisfy the conditions described under (4) above within the
time period required, we must pay you, as a holder of outstanding old notes,
additional interest at a rate of 0.5% per annum until all registration defaults
have been cured, at which time any increase in the interest rate described in
this paragraph will cease to be effective.
Each broker-dealer that receives new notes for its own account in exchange
for old notes that were acquired by that broker-dealer as a result of market-
making activities or other trading activities must acknowledge that it will
deliver a prospectus in connection with any resale of those new notes. See
"Plan of Distribution."
Effect of the Exchange Offer
Based on several no-action letters issued by the staff of the SEC to third
parties in unrelated transactions, we believe that you may offer for resale,
resell or otherwise transfer any new notes issued to you in the exchange offer
without further registration under the Securities Act or delivery of a
prospectus if you:
. are acquiring the new notes in the ordinary course of your business;
. are not participating, do not intend to participate and have no
arrangement or understanding with any person to participate, in a
distribution of the new notes;
. are not an affiliate of ours as defined in Rule 405 under the
Securities Act; and
. are not a broker-dealer who acquired old notes from us.
18
If you do not satisfy these criteria:
. you will not be able to rely on the interpretations of the staff of
the SEC in connection with any offer for resale, resale or other
transfer of new notes; and
. you must comply with the registration and prospectus delivery
requirements of the Securities Act, or have an exemption available to
you, in connection with any offer for resale, resale or other transfer
of the new notes.
Each broker-dealer that receives new notes for its own account in exchange
for old notes it acquired as a result of market-making or other trading
activities, may be a statutory underwriter and must acknowledge that it will
deliver a prospectus in connection with any resale of its new notes. This will
not be an admission by the broker-dealer that it is an underwriter within the
meaning of the Securities Act. See "Plan of Distribution."
Shelf Registration Statement
If (1) we determine that applicable laws or the applicable interpretations
of the staff of the SEC do not permit us to effect the exchange offer; (2) the
exchange offer registration statement is not effective on or before June 9,
2001; (3) the exchange offer is not consummated on or before July 29, 2001; (4)
we receive a request from any initial purchaser with respect to any old notes
held by it that are not eligible to be exchanged for new notes in the exchange
offer after the completion of the exchange offer; or (5) any holder of old notes
is not permitted pursuant to applicable law or applicable policies of the SEC to
participate in the exchange offer and thereby receive new notes, or any holder
that participates in the exchange offer does not receive freely tradeable new
notes upon valid tender of old notes, we have agreed that we will promptly
notify the holders of the old notes and will, at our cost:
. use our reasonable best efforts to cause to be filed with the SEC a
shelf registration statement relating to a shelf registration of the
old notes covering resales of the old notes;
. use our reasonable best efforts to cause the shelf registration
statement to be declared effective under the Securities Act as soon as
practicable; and
. use all reasonable efforts to keep effective the shelf registration
statement until the earlier of the date that is two years (or another
period as may after the date of this prospectus be referred to in Rule
144(k) under the Securities Act) after the date of issuance of the old
notes and the date all old notes eligible to be sold under the shelf
registration statement have been so sold or cease to be outstanding.
We will provide to each relevant holder of the old notes copies of the
prospectus that is a part of the shelf registration statement, notify each
holder when the shelf registration statement has become effective and take
various other actions as are required to permit unrestricted resales of the
relevant old notes. A holder of old notes that sells its old notes pursuant to
the shelf registration statement generally will be required to be named as a
selling security holder in the related prospectus and to deliver a prospectus to
purchasers, will be subject to some of the civil liability provisions under the
Securities Act in connection with those sales and will be bound by the
provisions of the registration rights agreement that are applicable to that
holder, including some indemnification and contribution obligations. In
addition, a holder of old notes will be required to deliver information to be
used in connection with the shelf registration statement in order to have that
holder's notes included in the shelf registration statement.
If the shelf registration statement is not filed as promptly as
practicable, and in any event within 45 days after we become obligated to file
the shelf registration statement or, if after the shelf registration statement
is declared effective, either it ceases to be effective during the required time
period or the shelf registration statement or related prospectus ceases to be
usable to resell the old notes for various reasons, we must pay you as a holder
of outstanding old notes, additional interest at a rate of 0.5% per annum until
all registration defaults have been cured.
The foregoing is a summary description of the material provisions of the
registration rights agreement. Because it is a summary, it does not include all
of the information that is included in the registration rights
19
agreement. We encourage you to read the entire text of the registration rights
agreement carefully because it, and not this description, defines your rights as
a holder of the old notes. The registration rights agreement is included as an
exhibit to the registration statement of which this prospectus is a part. You
may request a copy of the registration rights agreement at our address set forth
under "Where You Can Find More Information."
Terms of the Exchange Offer
We will accept all old notes validly tendered and not withdrawn prior to
5:00 p.m., New York City time, on the expiration date of the exchange offer. You
should read "--Expiration Date; Extensions; Amendments" below for an explanation
of how the expiration date may be amended.
Holders may exchange some or all of their old notes in denominations of
$100,000 and integral multiples of $1,000 in excess thereof. We will issue and
deliver $100,000 principal amount of new notes in exchange for each $100,000
principal amount of outstanding old notes, and $1,000 principal amount of new
notes in exchange for each $1,000 of outstanding old notes, accepted in the
exchange offer.
By tendering old notes in exchange for new notes and by signing the letter
of transmittal (or delivering an agent's message instead of a letter of
transmittal), you will be representing that, among other things:
. you are not our affiliate (as defined in Rule 405 under the Securities
Act);
. you are not a broker-dealer who acquired old notes directly from us;
. any new notes to be received by you will be acquired in the ordinary
course of your business;
. you are not engaging in and do not intend to engage in a distribution
of the new notes;
. you have no arrangement or understanding with any person to
participate in the distribution of the new notes; and
. you acknowledge that if you are deemed to have participated in the
exchange offer for the purpose of distributing the new notes, you will
comply with the registration and prospectus delivery requirements of
the Securities Act to the extent applicable.
The terms of the new notes are identical in all material respects to the
terms of the old notes, except that the registration rights and related
liquidated damages provisions and the transfer restrictions applicable to the
old notes are not applicable to the new notes. The new notes will evidence the
same debt as the old notes and will be entitled to the benefits of the indenture
governing the old notes.
In connection with the exchange offer, holders of the old notes do not have
any appraisal or dissenters' rights under law or the indenture governing the old
notes.
We are sending this prospectus and the letter of transmittal to all
registered holders of old notes as of the close of business on April 16, 2001.
We are not conditioning the exchange offer upon the tender of any minimum
amount of old notes.
We have provided for customary conditions, which we may waive in our
discretion. See "--Conditions of the Exchange Offer."
We may accept tendered old notes by giving oral or written notice to the
exchange agent. The exchange agent will act as your agent for the purpose of
receiving the new notes from us and delivering them to you.
20
You will be required to pay brokerage commissions or fees and transfer
taxes with respect to the exchange of old notes. We will pay charges and
expenses in connection with the exchange offer to the extent indicated in the
registration rights agreement.
Expiration Date; Extensions; Amendments
The exchange offer will expire at 5:00 p.m., New York City time, on June 7,
2001, unless we, in our sole discretion, extend it. We may extend the exchange
offer at any time and from time to time by giving oral (promptly confirmed in
writing) or written notice to the exchange agent and by making a public
announcement of the extension before 9:00 a.m., New York City time, on the next
business day after the previously scheduled expiration date. We may also accept
all properly tendered old notes as of the expiration date and extend the
expiration date in respect of the remaining outstanding old notes. We may, in
our sole discretion,
. amend the terms of the exchange offer in any manner;
. delay acceptance of, or refuse to accept, any old notes not previously
accepted;
. extend the exchange offer; or
. terminate the exchange offer.
We will give prompt notice of any amendment to the registered holders of
the old notes. If we materially amend the exchange offer, we will promptly
disclose the amendment in a manner reasonably calculated to inform you of the
amendment and we will extend the exchange offer to the extent required by law.
Procedures for Tendering
Only a holder of old notes may tender them in the exchange offer. For
purposes of the exchange offer, the term "holder" or "registered holder"
includes any participant in DTC whose name appears on a security position
listing as a holder of old notes.
To tender in the exchange offer, you must cause the following items to be
transmitted to and received by the exchange agent no later than 5:00 p.m., New
York City time, on the expiration date:
. a confirmation of the book-entry transfer of the tendered old notes
into the exchange agent's account at DTC;
. a properly completed and duly executed letter of transmittal in the
form accompanying this prospectus (with any required signature
guarantees) or, at the option of the tendering holder in the case of a
book-entry tender, an agent's message instead of that letter of
transmittal; and
. any other documents required by the letter of transmittal.
If you wish to tender your old notes and your old notes are not available,
you cannot complete the procedures for book-entry transfer or you cannot cause
the old notes or any other required documents to be transmitted to and received
by the exchange agent before 5:00 p.m., New York City time, on the expiration
date, you may tender your old notes according to the guaranteed delivery
procedures described in this section under the heading "--Guaranteed Delivery
Procedures."
Any beneficial owner of old notes that are registered in the name of a
broker, dealer, commercial bank, trust company or other nominee who wishes to
participate in the exchange offer should promptly contact the person through
which it beneficially owns its old notes and instruct that person to tender old
notes on behalf of the beneficial owner. See "Instructions to Registered Holder
and/or Book-Entry Transfer Facility Participant From Owner" in the form
accompanying this prospectus, which is included as an exhibit to the
registration statement of which this prospectus is a part. If the beneficial
owner wishes to tender on his or her own behalf, the owner must,
21
prior to completing and executing the letter of transmittal and delivering the
beneficial owner's old notes, either make appropriate arrangements to register
ownership of the old notes in the owner's name or obtain a properly completed
bond power from the registered holder. The transfer of registered ownership may
take considerable time.
The tender by a holder of old notes will constitute an agreement between
the holder and us in accordance with the terms and subject to the conditions
specified in this prospectus and in the letter of transmittal. If a holder
tenders less than all the old notes held, the holder should fill in the amount
of old notes being tendered in the appropriate box on the letter of transmittal.
The exchange agent will deem the entire amount of old notes delivered to it to
have been tendered unless the holder has indicated otherwise.
The method of delivery of the letter of transmittal or agent's message and
all other required documents to the exchange agent is at your election and risk.
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 ensure
delivery to the exchange agent prior to the expiration date. Do not send your
letter of transmittal or other required documents to us.
Each broker-dealer that receives new notes for its own account in exchange
for old notes, that were acquired by that broker-dealer as a result of market-
making activities or other trading activities, must acknowledge that it will
deliver a prospectus in connection with any resale of those new notes. See
"Plan of Distribution."
Signature Requirements and Signature Guarantee
You must arrange for an "eligible institution" to guarantee your signature
on the letter of transmittal or a notice of withdrawal, unless the old notes are
tendered:
. by a registered holder of the old notes who has not completed the box
entitled "Special Issuance Instructions" or "Special Delivery
Instructions" in the letter of transmittal (see "Instructions to
Registered Holder and/or Book-Entry Transfer Facility Participant from
Beneficial Owner" in the letter of transmittal); or
. for the account of an eligible guarantor institution.
The following are "eligible institutions":
. a member firm of a registered national securities exchange or of the
National Association of Securities Dealers, Inc.;
. a commercial bank or trust company having an office or correspondent
in the United States; or
. an "eligible guarantor institution" within the meaning of Rule 17Ad-15
under the Securities Exchange Act of 1934, as amended, which we refer
to as the Exchange Act.
If a letter of transmittal is signed by a person other than the registered
holder of any old notes listed in the letter of transmittal, the old notes must
be endorsed or accompanied by a properly completed bond power and signed by the
registered holder as the registered holder's name appears on the old notes.
If trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, sign or endorse any required documents, they should so indicate when
signing and must submit evidence satisfactory to us of their authority to so act
with the letter of transmittal.
Book-Entry Transfer
The exchange agent will make a request promptly after the date of this
prospectus to establish an account with respect to the old notes in DTC's book-
entry system. Subject to the establishment of the account, any financial
institution that is a participant in DTC's system may make book-entry delivery
of old notes by causing DTC to transfer them into the exchange agent's account
with respect to the old notes. However, the exchange agent will only
22
exchange the old notes so tendered after a timely confirmation of their book-
entry transfer into the exchange agent's account, and timely receipt of an
agent's message and any other documents required by the letter of transmittal.
The term "agent's message" means a message, transmitted by DTC to, and
received by, the exchange agent and forming part of the confirmation of a book-
entry transfer, which states that:
. DTC has received an express acknowledgment from a participant
tendering old notes stating that the participant agrees to participate
in the automated tender option program;
. the participant has received the letter of transmittal and agrees to
be bound by its terms; and
. we may enforce that agreement against the participant.
Although you may effect delivery of old notes through book-entry transfer
into the exchange agent's account at DTC, unless the exchange agent receives an
agent's message in compliance with the automated tender option program, you must
provide the exchange agent a completed and executed letter of transmittal with
any required signature guarantee (or an agent's message instead of a letter of
transmittal) and all other required documents prior to the expiration date. If
you comply with the guaranteed delivery procedures described below, you must
provide the letter of transmittal (or an agent's message instead of a letter of
transmittal) to the exchange agent within the time period provided under those
procedures. Delivery of documents to DTC does not constitute delivery to the
exchange agent.
Guaranteed Delivery Procedures
If you wish to tender your old notes and your old notes are not immediately
available, you cannot deliver your old notes, the letter of transmittal or any
other required documents to the exchange agent prior to the expiration date or
you cannot complete the procedure for book-entry transfer on a timely basis, you
may instead effect a tender if:
. you make the tender through an eligible guarantor institution;
. prior to the expiration date of the exchange offer, the exchange agent
receives from that eligible guarantor institution a properly completed
and duly executed notice of guaranteed delivery (by facsimile
transmittal, mail or hand delivery) specifying the name and address of
the holder and the principal amount of your old notes tendered,
stating that the tender is being made by delivery of the notice of
guaranteed delivery, and guaranteeing that, within three New York
Stock Exchange trading days after the expiration date, the old notes
being tendered, a properly completed and duly executed letter of
transmittal or a confirmation of a book-entry transfer into the
exchange agent's account at DTC and an agent's message and any other
documents required by the letter of transmittal, will be deposited by
the eligible guarantor institution with the exchange agent; and
. the exchange agent receives your old notes being tendered and letter
of transmittal, properly completed and duly executed, with any
required signature guarantees, or confirmation of a book-entry
transfer into its account at DTC and an agent's message and all other
documents required by the letter of transmittal within three New York
Stock Exchange trading days after the expiration date.
Withdrawal of Tenders
Except as otherwise provided in this prospectus, you may withdraw tendered
old notes at any time before 5:00 p.m., New York City time, on the expiration
date. To do so, you must provide the exchange agent with a written or facsimile
transmission notice of withdrawal before 5:00 p.m., New York City time, on the
expiration date.
Any notice of withdrawal must:
. specify the name of the person having deposited who desires to
withdraw;
23
. identify the old notes to be withdrawn, including the certificate
numbers and principal amount of the old notes and the name and number
of the account at DTC to be credited; and
. be signed by you in the same manner as the original signature on your
letter of transmittal (including any required signature guarantee) or
be accompanied by documents of transfer sufficient to permit the
trustee to register the transfer of the withdrawn old notes into your
name or any other name in which old notes are to be registered, if so
specified.
We will determine all questions as to the validity, form and eligibility,
including time of receipt, of all withdrawal notices. Our determination will be
final and binding on all parties. We will not deem any old notes withdrawn to be
validly tendered for purposes of the exchange offer and will not issue new notes
for them unless the holder of old notes withdrawn validly retenders them. You
may retender withdrawn old notes by following one of the procedures described
above under "--Procedures for Tendering" at any time prior to the expiration
date.
Determination of Validity
We will determine all questions as to the validity, form, eligibility,
including time of receipt, acceptance and withdrawal of the tendered old notes
in our sole discretion. Our determination will be final and binding. We may
reject any and all old notes that are not properly tendered or any old notes of
which our acceptance would, in our opinion or the opinion of our counsel, be
unlawful. We also may waive any irregularities or conditions of tender as to
particular old notes. Our interpretation of the terms and conditions of the
exchange offer, including the instructions in the letter of transmittal, will be
final and binding on all parties. Unless waived, you must cure any defects or
irregularities in connection with tenders of old notes within a time period
determined by us.
Although we intend to notify tendering holders of defects or irregularities
with respect to tenders of old notes, neither we nor anyone else has any duty to
do so. Neither we nor the exchange agent shall incur any liability for failure
to give that notification. Your old notes will not be deemed tendered until you
have cured or we have waived any irregularities. As soon as practicable
following the expiration date, the exchange agent will return any old notes that
we reject due to improper tender or otherwise unless you cured all defects or
irregularities or we waive them.
We reserve the right in our sole discretion:
. to purchase or make offers for any old notes that remain outstanding
subsequent to the expiration date;
. to terminate the exchange offer, as set forth in "--Conditions of the
Exchange Offer"; and
. to the extent permitted by applicable law, to purchase old notes in
the open market, in privately negotiated transactions or otherwise.
The terms of any of those purchases or offers may differ from the terms of
the exchange offer.
Conditions of the Exchange Offer
We will not be required to accept for exchange, or to issue new notes for,
any old notes, and we may terminate, waive any conditions to or amend the
exchange offer if, in our sole judgment, the exchange offer would violate
applicable law or any applicable interpretation of the staff of the SEC.
These conditions are for our sole benefit and may be asserted by us
regardless of the circumstances giving rise to any of these conditions. We may
waive these conditions in our reasonable discretion in whole or in part at any
time and from time to time. The failure by us at any time to exercise any of the
above rights will not be deemed a waiver of that right and that right will be
deemed an ongoing right that may be asserted at any time and from time to time.
If we determine in our reasonable discretion that any of the conditions are not
satisfied, we may:
24
. refuse to accept any old notes and return any old notes that have been
tendered to the tendering holders;
. extend the exchange offer and retain all old notes tendered prior to
the expiration date of the exchange offer, subject to the rights of
the holders of the tendered old notes to withdraw those old notes; or
. waive the termination event with respect to the exchange offer and
accept the properly tendered old notes that have not been withdrawn.
If we determine that a waiver constitutes a material change in the exchange
offer, we will promptly disclose the change in a manner reasonably calculated to
inform the holders of the change and we will extend the exchange offer to the
extent required by law.
Acceptance of Old Notes for Exchange; Delivery of New Notes
Upon satisfaction or waiver of all of the conditions to the exchange offer,
we will accept, as soon as practicable after the expiration date, all old notes
that have been validly tendered and not withdrawn, and will issue the applicable
new notes in exchange for those old notes promptly after our acceptance of those
old notes. For purposes of the exchange offer, we will be deemed to have
accepted validly tendered old notes for exchange when, as and if we have given
written and oral notice of acceptance to the exchange agent.
For each old note accepted for exchange, the holder of the old note will
receive a new note having a principal amount equal to that of the surrendered
old note. Interest will be payable semi-annually on the new notes each May 1
and November 1. Interest on the new notes will accrue from the last date
through which interest was paid on the old notes (expected to be May 1, 2001)
and will first be paid on the new notes on the first May 1 or November 1
following the date the exchange offer is completed (expected to be November 1,
2001). No interest will be paid in connection with the exchange. Old notes
accepted for exchange will cease to accrue interest from and after the date on
which they are accepted for exchange. Holders whose old notes are accepted for
exchange will not receive any payment for accrued interest on the old notes
otherwise payable on any interest payment date and will be deemed to have waived
their rights to receive the accrued interest on the old notes.
If any tendered old notes are not accepted for any reason or if old notes
are submitted for a greater principal amount than the holder desires to
exchange, those unaccepted or non-exchanged old notes will be returned without
expense to the tendering holder of the old notes or, if the old notes were
tendered by book-entry transfer, the non-exchanged old notes will be credited to
an account maintained with the book-entry transfer facility. In either case, the
return of old notes will be effected promptly after the expiration or
termination of the exchange offer.
Exchange Agent
We have appointed Ameren Services as the exchange agent for the exchange
offer. You should send all executed letters of transmittal to the exchange
agent as follows:
Delivery to: Ameren Services Company, Exchange Agent
By mail:
P.O. Box 66887
St. Louis, Missouri 63166-6887
Attention: Investor Services MC 1035
Personal and Confidential
25
By hand or overnight courier:
1901 Chouteau Avenue
St. Louis, Missouri 63103
Attention: Investor Services MC 1035
Personal and Confidential
Eligible institutions may deliver documents by facsimile at: (314) 554-2401.
For facsimile confirmation only, you may call the exchange agent at: (314)
554-3502 or (800) 255-2237 (toll-free).
If you deliver the letter of transmittal to an address other than as set
forth above or transmit instructions by facsimile other than as set forth above,
that delivery or those instructions will not be effective.
Information Agent
We have appointed Morrow & Co., Inc. as the information agent for the
exchange offer. You should direct all communications regarding the exchange
offer, including requests for assistance or for additional copies of this
prospectus or of the letter of transmittal, as follows:
Delivery to: Morrow & Co., Inc., Information Agent
By mail, hand or overnight courier:
445 Park Avenue, 5th Floor
New York, New York 10022
For information, you can call the information agent toll-free at:
(800) 607-0088
Banks and brokerage firms should call the information agent toll-free
at: (800) 654-2468.
You may contact the information agent via e-mail at
ameren.info@morrowco.com.
Fees and Expenses
We will bear expenses of the exchange offer to the extent indicated in the
registration rights agreement. We are making the principal solicitation pursuant
to the exchange offer by mail. Our officers and employees and those of our
affiliates may also make solicitations in person, by telegraph, telephone or
facsimile transmission.
We have not retained any dealer-manager in connection with the exchange
offer and will not make any payments to brokers, dealers or other persons
soliciting acceptances of the exchange offer. We, however, will pay the exchange
agent reasonable and customary fees for its services and will reimburse its
reasonable out-of-pocket costs and expenses and will indemnify the exchange
agent for all losses and claims incurred by it as a result of the exchange
offer. We may also pay brokerage houses and other custodians, nominees and
fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding
copies of this prospectus, letters of transmittal and related documents to the
beneficial owners of the old notes and in handling or forwarding tenders for
exchange.
Transfer Taxes
We will not pay any transfer taxes applicable to the exchange of old notes
pursuant to the exchange offer.
In addition to transfer taxes imposed with respect to the exchange of old
notes pursuant to the exchange offer, the tendering holder will pay transfer
taxes, if:
26
. new notes for principal amounts not tendered, or accepted for exchange
are to be registered or issued in the name of any person other than
the registered holder of the old notes tendered; or
. tendered old notes are registered in the name of any person other than
the person signing the letter of transmittal.
If you do not submit satisfactory evidence of payment of taxes for which
you are liable or exemption from those taxes with your letter of transmittal, we
will bill you for the amount of these transfer taxes directly.
Accounting Treatment
We will record the new notes at the same carrying value as the old notes,
which is the principal amount as reflected in our accounting records on the date
of the exchange. Accordingly, we will not recognize any gain or loss for
accounting purposes. We will capitalize the expenses of the exchange offer for
accounting purposes. We will classify these expenses as debt issuance costs and
include them in other assets on our balance sheet. We will amortize these
expenses on a straight line basis over the life of the new notes.
Consequences of Failure to Exchange Old Notes
Holders of old notes who do not exchange their old notes for new notes
pursuant to the exchange offer will continue to be subject to the restrictions
on transfer of those old notes. The old notes were originally issued in a
transaction exempt from registration under the Securities Act, and may be
offered, sold, pledged or otherwise transferred only:
. in the United States to a person whom the seller reasonably believes
is a qualified institutional buyer, as defined in Rule 144A under the
Securities Act;
. outside the United States in an offshore transaction in accordance
with Rule 904 under the Securities Act;
. pursuant to an exemption from registration under the Securities Act
provided by Rule 144, if available; or
. pursuant to an effective registration statement under the Securities
Act.
The offer, sale, pledge or other transfer of old notes must also be made in
accordance with any applicable securities laws of any state of the United
States, and the seller must notify any purchaser of the old notes of the
restrictions on transfer described above. We do not currently anticipate that we
will register the old notes under the Securities Act.
Appraisal or Dissenters' Rights
Holders of the old notes will not have appraisal or dissenters' rights in
connection with the exchange offer.
27
USE OF PROCEEDS
The exchange offer is intended to satisfy our obligations under the
registration rights agreement that we entered into in connection with the
private offering of the old notes. We will not receive any cash proceeds from
the issuance of the new notes. The old notes that are surrendered in exchange
for the new notes will be retired and canceled and cannot be reissued. As a
result, the issuance of the new notes will not result in any increase or
decrease in our indebtedness. We have agreed to bear the expenses of the
exchange offer to the extent indicated in the registration rights agreement. No
underwriter is being used in connection with the exchange offer.
Sources and Uses of Funds
We received proceeds of $423,642,500 from the sale of the old notes. We
used those proceeds to: (1) repay intercompany debt incurred in connection with
the acquisition of the operating combustion turbine units, (2) prefund a portion
of the estimated acquisition cost of the committed units, (3) pay for a portion
of capital expenditures of our coal plants for year 2000 and (4) pay for the
costs of issuing the old notes, including initial purchasers' commissions.
The following table sets forth the approximate sources and uses of funds in
connection with the sale of the old notes.
(in thousands)
------------------
Sources of Funds
Proceeds of old notes......................................................................... $423,643
========
Uses of Funds
Acquisition cost of operating combustion turbine units........................................ $273,000
Prefunding a portion of the acquisition cost of committed units............................... $125,000
Funding of a portion of capital expenditures on our coal plants for year 2000................. $ 19,022
Cost of issuance.............................................................................. $ 6,621
--------
Total Uses of Funds........................................................................ $423,643
========
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CAPITALIZATION
The following table sets forth the actual consolidated capitalization of
our company as of December 31, 2000 and the pro forma capitalization of our
company as of December 31, 2000 after giving effect to the expected assumption
by us of AmerenCIPS' obligations with respect to $104 million of tax-exempt
pollution control loan obligations and $1 million of related unamortized debt
issue costs. The pro forma capitalization is presented for illustrative purposes
only and is not necessarily indicative of the capitalization of our company as a
result of the assumption of the pollution control loan obligations.
As of
December 31, 2000 Pro Forma
------------------- -------------
(in thousands)
Debt:
Senior debt
Loan obligations for tax-exempt bonds................................... $ -- $ 104,000
Senior Notes............................................................ $ 423,676 $ 423,676
Total senior debt.......................................................... $ 423,676 $ 527,676
Subordinated intercompany notes(1)......................................... $ 601,626 $ 498,626
Total debt................................................................. $1,025,302 $1,026,302
Total shareholder equity................................................... $ 43,810 $ 43,810
Total capitalization....................................................... $1,069,112 $1,070,112
__________
(1) See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources."
29
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
Ameren Corporation is a registered holding company under PUHCA that was
formed in December 1997 upon the merger of AmerenUE and CIPSCO Incorporated, the
former parent company of AmerenCIPS. In conjunction with the Illinois Electric
Service Customer Choice and Rate Relief Law of 1997, on May 1, 2000, following
the receipt of all required state and federal regulatory approvals, AmerenCIPS
transferred its electric generating assets and related liabilities, at
historical net book value, to a newly created non-regulated company,
AmerenEnergy Generating Company, referred to as the company, in exchange for a
subordinated promissory note in the amount of $552 million from the company and
1,000 shares of the company's common stock.
Resources is a holding company for Ameren's non-regulated electric
generation business whose principal subsidiaries include the company,
Development Co., Fuels Co. and Marketing Co. Fuels Co. acts as the company's
agent and manages the company's coal, natural gas and fuel oil procurement and
supply. Development Co. develops and constructs generation assets for the
company, and the company purchases generation assets from Development Co. when
the assets are available for commercial operation. Marketing Co. focuses on
selling at wholesale, energy, capacity and other energy products for terms in
excess of one year and retail transactions. In addition, Ameren Energy, Ameren
Corporation's energy trading and marketing subsidiary, acts as agent for the
company and enters into contracts for the wholesale purchase and sale of energy
on its behalf for terms less than a year. The company qualifies as an exempt
wholesale generator under PUHCA and acts as Resources' primary vehicle for the
ownership and operation of its non-regulated electric generation assets.
The company's financial statements include charges for services that Ameren
Services, a wholly-owned subsidiary of Ameren Corporation, provides to the
company. Ameren Services provides shared support services for all Ameren
companies. Charges are based upon the actual costs incurred by Ameren Services
as required by PUHCA.
On May 1, 2000, the company and Marketing Co. entered into the Genco-
Marketing Co. agreement (and amended August 14, 2000) under which Marketing Co.
is entitled to purchase all of the company's energy and capacity. Any energy
which Marketing Co. does not purchase will be released to Ameren Energy, which
will seek to market it on the company's behalf. Also on May 1, 2000, Marketing
Co. and AmerenCIPS entered into the Marketing Co.-CIPS agreement to supply
sufficient power to meet AmerenCIPS' native load requirements. A portion of the
capacity and energy supplied by the company to Marketing Co. is resold to
AmerenCIPS for resale to native load customers at rates specified by the
Illinois Commerce Commission (ICC) (which approximate the historical regulated
rates for generation) or to those retail customers allowed choice of an electric
supplier under state law at fixed market-based prices. Other capacity and
energy purchased by Marketing Co. from the company will be used by Marketing Co.
to serve its obligations under various long-term wholesale contracts it assumed
from AmerenCIPS and other long-term wholesale and retail contracts it may enter
into. The company's plants and AmerenUE's plants will continue to be jointly
dispatched under the amended joint dispatch agreement. The Marketing Co.-CIPS
agreement expires December 31, 2004 and the Genco-Marketing Co. agreement may be
terminated upon at least one year's notice given by either party, but in no
event can it be terminated prior to December 31, 2004.
The Illinois Electric Service Customer Choice and Rate Relief Law of 1997
provides for retail direct access, which allows customers to choose their
electric generation supplier, to be phased in over several years. The phase-in
of retail direct access began on October 1, 1999, with large industrial and
commercial customers principally comprising the initial group. The remaining
commercial and industrial customers in Illinois were offered choice on December
31, 2000. Retail direct access will be offered to residential customers on May
1, 2002. The company is unable to predict the ultimate impact that retail
direct access in Illinois will have on its future financial condition, results
of operation or liquidity.
The assets transferred to the company in May 2000 included the coal plants
located in Newton, Coffeen, Meredosia, Grand Tower and Hutsonville, Illinois
along with other rights, assets and liabilities related to the
30
generation of electricity by AmerenCIPS. These electric generating facilities
have a combined total generating capacity of 2,860 megawatts. Seven hundred and
fifty employees, or approximately 45 percent of AmerenCIPS' workforce, were also
transferred to the company as part of the transfer of the coal plants.
In June and July of 2000, the company acquired combustion turbine
generating units at Pinckneyville and Gibson City, Illinois from Development Co.
at Development Co.'s historical net book value. The total installed cost of
these combustion turbine generating units is approximately $200 million. In
September 2000, the company also acquired three combustion turbine generating
units at the Joppa, Illinois site from an affiliate at the affiliate's
historical net book value. The total installed cost of these combustion turbine
generating units is approximately $73 million. The company has entered into an
operating lease agreement with Development Co. for these units at the Joppa
site. The three combustion turbine generating units have been leased to
Development Co. for a minimum term of fifteen years. The company receives
rental payments under the lease in fixed monthly amounts that vary over the term
of the lease and range in amount from $0.8 - $1.0 million. Development Co. is
entitled to all of the output produced from the three units and will be
responsible for all operating expenses. Development Co. intends to enter into
an agreement with Midwest Electric Power, Inc., an affiliate, under which
Midwest Electric Power, Inc. will provide operations and maintenance services.
On November 1, 2000, Development Co. and Marketing Co. entered into an electric
power supply agreement, referred to as the Development Co.-Marketing Co.
agreement. The Development Co.-Marketing Co. agreement entitles Marketing Co.
to all of the output from the Joppa site. The Development Co.-Marketing Co.
agreement contains a monthly capacity charge that approximates the lease payment
obligation Development Co. incurs from the company and an energy charge equal to
the variable costs of operating the combustion turbine generating units.
The company's combustion turbine generating units at Pinckneyville, Gibson
City and Joppa represent 584 megawatts of capacity, which, including the
capacity from the company's coal plants, gives the company 3,444 megawatts of
total generating capacity at December 31, 2000. In the near term, the company
expects to increase its generating capacity to 4,264 megawatts by summer 2001.
With the addition of these units and other planned new combined cycle and simple
cycle combustion turbine generating units, the company expects to have a total
net electric generating capacity of up to 5,754 megawatts by mid-2005. These
future plans are subject to change, including increasing or decreasing planned
or installed future generating capacity, based on market conditions, regulatory
approvals for additions, the company's results of operations and financial
condition, availability of financing and other factors determined by management.
Results of Operations
The company has a limited operating history. Separate financial statements
with regard to the company's business are available only for the period since
May 1, 2000. Prior to that, all operations of the coal plants were fully
integrated with, and therefore results of operations were consolidated into the
financial statements of, AmerenCIPS, whose business was to generate, transmit
and distribute electricity and to provide other utility customer support
services.
Earnings
Earnings for the period May 1, 2000 through December 31, 2000 totaled $44
million. The earnings were primarily driven by sales associated with the Genco-
Marketing Co. agreement, as well as sales of available generation by Ameren
Energy. For the period May 1, 2000 through December 31, 2000, the company's
electric revenue was $477 million of which $341 million was derived under the
Genco-Marketing Co. agreement. Electric revenues from Ameren Energy's marketing
efforts for the period from May 1, 2000 through December 31, 2000, were $105
million. Electric revenues from sales of available generation to AmerenUE
through the amended joint dispatch agreement for the period May 1, 2000 through
December 31, 2000, were $31 million.
31
Operating Costs
Operating expenses for the period May 1, 2000 through December 31, 2000
were $376 million. The operating expenses consisted of the following:
(in millions)
Fuel and purchased power $ 235
Other operating expenses 54
Maintenance 46
Depreciation & amortization 28
Other taxes 13
---------
$ 376
Other operating expenses consist primarily of employee benefits,
professional services and expenses associated with support services that are
provided by Ameren Services. The support services provided by Ameren Services
are based upon the actual costs incurred.
During the period May 1, 2000 through December 31, 2000, major maintenance
expenditures included boiler maintenance, precipitator inspection and outage
maintenance at the Coffeen station and boiler maintenance, turbine inspection
and overhaul and replacement of precipitator controls at the Newton station.
Depreciation consists of that from the coal plants and the new combustion
turbine generating units. For the period from May 1, 2000 through December 31,
2000, depreciation was $28 million. The net plant and equipment transferred
from AmerenCIPS totaled $635 million.
Interest Expense
For the period from May 1, 2000 through December 31, 2000, interest expense
was $35 million. Of this amount, $26 million is from the $552 million
subordinated intercompany note payable to AmerenCIPS. Interest expense on the
old notes in this period was $5 million. The interest rates of the outstanding
debt ranged from 6.16% to 8.35%. Interest capitalized totaled $0.8 million for
the period May 1, 2000 through December 31, 2000 and related to construction in
progress at the company's coal plants.
Liquidity and Capital Resources
Cash provided by operating activities totaled $97 million, for the period
from May 1, 2000 through December 31, 2000.
Cash flows used in investing activities totaled $570 million, for the
period from May 1, 2000 through December 31, 2000 and related primarily to the
purchase of new combustion turbine generating units and capital expenditures at
the coal plants of $345 million, advances to Development Co. for the purchase of
committed units of $125 million and loans to Ameren Corporation's non-utility
money pool of $100 million.
For the period May 1, 2000 through December 31, 2000, nine combustion
turbine generating units were placed in commercial operation at Pinckneyville,
Gibson City and Joppa, Illinois. These units provide additional generating
capacity of 584 megawatts and cost approximately $273 million.
Cash flows provided by financing activities totaled $467 million for the
period from May 1, 2000 through December 31, 2000 and related to the issuance of
a $50 million subordinated intercompany note payable to Ameren Corporation and
the issuance of 7.75% Senior Notes, Series A due 2005, referred to as Series A
Notes, and 8.35% Senior Notes, Series B due 2010, referred to as Series B Notes.
The $50 million subordinated intercompany note payable to Ameren Corporation
bears interest at 7% per annum, has a 10-year amortization and 5-year maturity.
Series A Notes totaled $225 million. Interest accrues on the Series A Notes at
a rate of 7.75% per year and is
32
payable semiannually in arrears on May 1 and November 1 of each year
commencing on May 1, 2001. Principal of the Series A Notes will be payable on
November 1, 2005. Series B Notes totaled $200 million. Interest accrues on the
Series B Notes at a rate of 8.35% per year and is payable semiannually in
arrears on May 1 and November 1 of each year commencing on May 1, 2001.
Principal of the Series B Notes will be payable on November 1, 2010. The
proceeds received by the company from the old notes were $423.6 million. With
the proceeds of the old notes, the company repaid $220 million of short-term
intercompany borrowings, prefunded $125 million of combustion turbine generating
units expected to be available for commercial operation in 2001 and funded
approximately $19 million of capital expenditures incurred in 2000. The
remainder of the proceeds after transaction costs were loaned to Ameren
Corporation's non-utility money pool until such time as the company needs the
proceeds for working capital or capital expenditures.
The company's capital structure includes a $552 million subordinated
intercompany note which it issued to AmerenCIPS as part of the purchase price
for the transfer of the coal plants. The AmerenCIPS subordinated note bears
interest at 7% per annum, has a 10-year amortization schedule and a 5-year
maturity. Debt service during the term of the AmerenCIPS subordinated note will
be payable solely from ''available cash,'' defined as cash available after
payment of all operating and maintenance expenses, debt service, capital
expenditures, taxes and reasonable reserves for working capital and other
corporate purposes as determined by the company in its discretion. Any
installment payment amount which is not paid when due because of the available
cash limitation will be payable when available cash becomes sufficient to permit
the payment, or else carried forward until maturity. The company may not prepay
the AmerenCIPS subordinated note in whole or in part prior to the stated
maturity, May 1, 2005, without the prior written consent of the holders of a
majority of the outstanding notes issued under the indenture and such approvals
as are required under the terms of any other senior indebtedness. However, the
outstanding principal amount of the AmerenCIPS subordinated note will be reduced
by the amount of tax-exempt pollution control loan obligations the company
assumes from AmerenCIPS, as discussed below. In addition, with the consent of
AmerenCIPS, the company may also prepay the AmerenCIPS subordinated note in
whole or in part with proceeds derived from other debt or equity securities it
may issue which rank subordinate and junior to senior indebtedness on terms
comparable to those of the AmerenCIPS subordinated note. The AmerenCIPS
subordinated note may not be transferred by AmerenCIPS except to another wholly-
owned subsidiary of Ameren Corporation. Resources has agreed with the company
that, in the event that upon maturity the AmerenCIPS subordinated note has not
been paid in full or refinanced with other subordinated intercompany
indebtedness with terms at least as subordinate, then Resources will assume the
company's obligations under the AmerenCIPS subordinated note (subject to
regulatory approval), with no further liability to the company, or contribute
sufficient funds to the company as equity or subordinated debt to enable the
company to pay in full the remaining balance of the AmerenCIPS subordinated
note.
Capital Expenditures
Capital expenditures at the company's coal plants are expected to
approximate $160 million in total for the period 2001 through 2005, excluding
capital expenditures required to comply with nitrogen oxide (NO\\X\\) emissions
standards. The timing of these capital expenditures may be modified by
management based upon working capital needs, available financing and future
environmental regulations.
In July 1997, the United States Environmental Protection Agency (USEPA)
issued regulations revising the National Ambient Air Quality Standards for ozone
and particulate matter. In May 1999, the U.S. Court of Appeals for the District
of Columbia remanded the regulations back to the USEPA for review. The USEPA
appealed the decision to the U.S. Supreme Court. On February 27, 2001, the U.S.
Supreme Court reversed and remanded the case to the U.S. Court of Appeals for
the District of Columbia for further evaluation and opinion. The U.S. Supreme
Court ruled that Congress, in enacting Clean Air Act provisions that authorized
the USEPA to determine air quality standards, did not unconstitutionally
delegate legislative power to the agency. The U.S. Supreme Court also rejected
industry arguments that the USEPA should have considered implementation costs in
setting air quality standards. The ruling reaffirms the USEPA's authority to
establish uniform air quality standards at a level that is sufficient to protect
public health. However, the manner in which the USEPA proposed to implement the
proposed air quality standard for ozone was ruled unlawful and the U.S. Supreme
Court ordered the remand of the USEPA's implementation policy to the agency for
further consideration. When the proposed ambient standards are ultimately
enacted, such standards will require significant additional reductions in sulfur
dioxide (SO\\2\\) and NO\\X\\ emissions from the company's power plants. At this
time, the company is unable to predict the ultimate impact of these revised air
quality standards on its future financial condition, results of operations or
liquidity.
33
In an attempt to lower ozone levels across the eastern United States, the
USEPA issued regulations in September 1998 to reduce NO\\X\\ emissions from
coal-fired boilers and other sources in 22 states, including Illinois (where all
of the company's coal-fired power plant boilers are located). The regulations
were challenged in a U.S. District Court. In March 2000, the court upheld the
regulations pertaining to Illinois and further delayed the compliance date until
2004. The regulations mandate a 75% reduction in NO\\X\\ emissions from utility
boilers in Illinois by the year 2004. The NO\\X\\ emissions reductions already
achieved on several of the company's coal-fired power plants will help to reduce
the costs of compliance with these regulations. However, the regulations will
require the installation of selective catalytic reduction technology on some of
the company's units, as well as other additional controls.
Currently, the company estimates that its additional capital expenditures
to comply with the final NO\\X\\ regulations could range from $125 million to
$150 million in total over the period 2001 to 2004. Associated operations and
maintenance expenditures could increase $5 million to $8 million annually,
beginning in 2005. The company will explore alternatives to comply with these
new regulations in order to minimize, to the extent possible, its capital costs
and operating expenses. The company is unable to predict the ultimate impact of
these standards on its future financial condition, results of operations or
liquidity.
The company has several sources potentially available to fund such capital
expenditures, including cash from operations, borrowings from Ameren
Corporation's non-utility money pool and any additional funding which might
become available from Resources or Ameren.
The company believes that cash flow from operations will be sufficient to
cover aggregate interest payments under outstanding borrowings as they come due
and to cover expected capital expenditure requirements discussed above.
Future Capacity Additions
The company intends to purchase from Development Co. combustion turbine
generating units at Kinmundy and Grand Tower, Illinois, Columbia, Missouri and
at the existing Pinckneyville station for approximately $452 million in 2001,
once they are available for commercial operation. These simple cycle and
combined cycle combustion turbine generating units will provide incremental
capacity of 820 megawatts.
The company also intends to purchase from Development Co. additional
combustion turbine generating units at undetermined sites. These combustion
turbine generating units are expected to cost up to approximately $736 million,
provide additional capacity of up to 1,490 megawatts and be available for
commercial operation between mid-2002 and mid-2005. The following is a summary
of the company's planned additions of combustion turbine generating units.
Year Megawatts Estimated Cost
(in millions)
----------- -------------- ----------------
2001 820 $452
2002 515 $250
2003 325 $206
2004 325 $140
2005 325 $140
The company anticipates securing additional permanent financing during
2001-2004 to fund the purchase of completed combustion turbine generating
facilities. At this time, the company is unable to determine the amount of the
additional permanent financing, as well as the additional financing's impact on
the company's financial position, results of operation or liquidity.
The company has the ability to borrow up to $463 million from Ameren
Corporation through a non-utility money pool agreement. However, the total
amount available to the company at any given time is reduced by the amount of
borrowings from the non-utility money pool by other Ameren non-regulated
companies but increased to the extent other Ameren non-regulated companies have
surplus funds and the availability of other external
34
borrowing sources. The non-utility money pool was established to coordinate and
provide for short-term cash and working capital requirements of Ameren's non-
regulated activities and is administered by Ameren Services. Interest is
calculated at varying rates of interest depending on the composition of internal
and external funds in the non-utility money pool. For the period May 1, 2000
through December 31, 2000, the average interest rate for the non-utility money
pool was 6.52%. At December 31, 2000, the company had loaned $100 million to the
non-utility money pool and at least $296 million was available through the non-
utility money pool subject to reduction for borrowings by other Ameren non-
regulated companies.
During the course of Ameren Corporation's resource planning, several
alternatives are being considered to satisfy load requirements for AmerenUE,
AmerenCIPS, Marketing Co. and the company for 2001 and beyond. One of these
alternatives was for AmerenUE to transfer its Illinois-based electric and
natural gas businesses and certain of its Illinois-based distribution and
transmission assets and personnel to AmerenCIPS. The assets and related
liabilities were proposed to be transferred from AmerenUE to AmerenCIPS at
historical net book value. In March 2001, Ameren Corporation decided it will no
longer pursue this transfer and will be taking the necessary action to withdraw
pending requests for regulatory approvals. This transfer would have added about
525 megawatts of demand to the AmerenCIPS load that would have been supplied by
the company under the Marketing Co.-CIPS agreement. At this time, management is
unable to predict which course of action it will pursue to satisfy these
requirements and their ultimate impact on the company's financial position,
results of operation or liquidity.
Subject to certain approvals, the company intends to become primarily
liable for $104 million of tax-exempt pollution control loan obligations to be
transferred from AmerenCIPS during 2001. Upon the transfer of these obligations
to the company, the amount of the company's liability to AmerenCIPS under the
$552 million subordinated intercompany note will be reduced by a similar amount.
The pollution control loan obligations referred to above have maturity dates
ranging from 2014 to 2028 and bear interest at variable rates. At December 31,
2000, the interest rate on the pollution control loan obligations was 4.95%.
However, concurrent with the transfer of these variable rate obligations to the
company, the company expects to convert these to fixed interest rate obligations
based on market conditions at that time.
In the ordinary course of business, the company explores opportunities to
reduce its costs in order to remain competitive in the marketplace. Areas where
the company focuses its review include, but are not limited to, labor costs and
fuel supply costs. In the labor area, the company has reached agreements with
all of its major collective bargaining units which will permit it to manage its
labor costs and practices effectively in the future. The company also explores
alternatives to effectively manage the size of its workforce. These
alternatives include utilizing hiring freezes, outsourcing and offering employee
separation packages. In the fuel supply area, the company, working with its
affiliate, Fuels Co., explores alternatives to effectively manage its overall
fuel costs. These alternatives include diversifying fuel and transportation
sources for the company's fossil power plants (e.g. utilizing low-sulfur versus
high-sulfur coal), as well as restructuring or terminating existing contracts
with suppliers.
Certain of these reduction alternatives could result in additional
investments being made at the company's power plants in order to utilize
different types of coal, or could require nonrecurring payments of employee
separation benefits or nonrecurring payments to restructure or terminate
existing fuel contracts with suppliers. Management is unable to predict which
(if any), and to what extent, these alternatives to reduce its overall cost
structure will be executed, as well as determine the impact of these actions on
the company's future financial position, results of operations or liquidity.
35
Market Risk Related to Financial Instruments and Commodity Instruments
Market risk represents the risk of changes in value of a physical asset or
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g., interest rates, commodity prices, etc.). The following
discussion of the company's risk management activities includes "forward-
looking" statements that involve risks and uncertainties. Actual results could
differ materially from those projected in "forward-looking" statements. The
company handles market risks in accordance with established policies, which may
include entering into various derivative transactions. In the normal course of
business, the company also faces risks that are either non-financial or non-
quantifiable. Such risks principally include business, legal and operational
risks and are not represented in the following analysis.
The company's risk management objective is to optimize its physical
generating assets within prudent risk parameters. Risk management policies are
set at the Ameren Corporation level by a Risk Management Steering Committee,
which is comprised of senior-level Ameren officers. Although the policies are
set at the Ameren Corporation level, they are applicable to the company, as well
as Ameren Corporation's other subsidiaries.
Interest Rate Risk
The company is exposed to market risk through changes in interest rates
through its issuance of both variable rate and fixed rate debt. The company
manages its interest rate exposure by controlling the amount of these
instruments it holds within its total capitalization portfolio and by monitoring
the effects of market changes in interest rates. At December 31, 2000, the
company had no variable rate debt outstanding.
Commodity Price Risk
The company is exposed to changes in market prices for electricity and
fuel. Several techniques are utilized to mitigate the company's risk, including
utilizing derivative financial instruments. A derivative is a contract whose
value is dependent on, or derived from, the value of some underlying asset. The
derivative financial instruments that the company uses (primarily forward
contracts, futures contracts and option contracts) are dictated by risk
management policies.
The Emerging Issues Task Force of the Financial Accounting Standards Board
(EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities" became effective on January 1, 1999. EITF 98-10 provides guidance
on the accounting for energy contracts entered into for the purchase or sale of
electricity, natural gas, capacity and transportation. The EITF reached a
consensus in EITF 98-10 that sales and purchase activities being performed need
to be classified as either trading or nontrading. Ameren Energy enters into
contracts for the sale and purchase of energy on behalf of the company. The
company is ultimately responsible for the performance of these contracts. As of
December 31, 2000, virtually all of Ameren Energy's transactions were considered
nontrading activities and were accounted for using the accrual or settlement
method, which represents industry practice.
Electricity Price Risk
The company measures its electricity position as total generating resources
available, given historical forced outage rates, planned outages and forward
market prices, less projected fixed price load requirements. The company
considers the contracts in place through the end of 2004 to supply full
requirements to AmerenCIPS' native load and fixed price market-based retail
customers plus Marketing Co.'s wholesale contract commitments transferred to
Marketing Co. from AmerenCIPS to be load requirements. The company's
electricity and capacity price risks are primarily mitigated by the Genco-
Marketing Co. agreement, the Marketing Co.-CIPS agreement, and Marketing Co.'s
fixed-price wholesale contract commitments. For the period May 1, 2000 through
December 31, 2000, these agreements accounted for 71% of total operating
revenues and are therefore the largest single protection against falling
electricity and capacity prices.
The portion of the company's capacity which is not covered by the
agreements and contracts discussed above will be managed either by Marketing Co.
(generally for wholesale transactions over one year and retail sales)
36
or Ameren Energy (generally for wholesale transactions under one year). The
company's strategy is to continue to utilize Marketing Co. to offer most of its
output under long-term wholesale contracts as more of the company's capacity and
energy becomes available for resale as existing contracts expire. Ameren Energy
will extract additional value from the generating facilities by selling energy
in excess of the needs of Marketing Co. Also, Ameren Energy will purchase power
on the company's behalf when power is available for purchase at lower cost than
the company's cost of generation. Such power would be purchased to satisfy the
company's delivery requirements under its agreement with Marketing Co., which
Marketing Co. will use to meet its obligations under the load requirements
discussed above.
The amended joint dispatch agreement includes a sharing mechanism which
provides the company a benefit when it is able to use relatively low-cost
generation available from AmerenUE to meet its long-term fixed price sales
obligations as an alternative or supplement to its own generating resources.
Conversely, the company forgoes some of the potential gain that would arise from
high peak power prices in short-term or spot markets because AmerenUE has the
right to use the company's available energy (i.e., energy not sold by the
company to Marketing Co.) to the extent such energy is less expensive than
energy produced from AmerenUE's next economically dispatchable generating unit.
The price payable to the company in these circumstances would likely be lower
than peak market prices. Under the amended joint dispatch agreement, the company
and AmerenUE also share revenues when sales are made from AmerenUE's or the
company's generating facilities to third parties on a short-term or spot basis.
Fuel Price Risk
The company forecasts forward fuel exposure based on historical unit
availability, load requirements, forward fuel prices and forward electricity
prices. This practice substitutes market purchases to supply load requirements
when the price to purchase electricity is less than the cost to produce
electricity, and creates forecasted fuel exposure when generation will be used
to cover forecasted electricity sales.
Natural gas and coal price risks will be managed by Fuels Co. acting as the
company's agent. Fixed price forward contracts, as well as futures and options,
are all instruments which may be used to manage these risks. The majority of
the company's fuel supply contracts are physical forward contracts.
Over 90% of the required coal for the company's coal plants has been
acquired at fixed prices for 2001. As such, the company has minimal coal price
risk for 2001. In addition, at least 64% of the coal requirements through 2005
and at least 45% of such requirements through 2010 are covered by long-term
contracts. Under the existing requirements contracts, the capacity and energy
requirements can be substantially satisfied by operation of the company's coal
plants and accordingly, the fuel position with respect to such contracts is
covered. However, the company has recently experienced some delays in its coal
deliveries due to certain transportation and operating constraints in the
system. The company is working closely with the transportation companies and
monitoring its operating practices in order to maintain adequate levels of coal
inventory for future operating purposes.
The company's natural gas procurement strategy is designed to ensure
reliable and immediate delivery of natural gas to its intermediate and peaking
units by optimizing transportation and storage options and minimizing cost and
price risk by structuring various supply agreements to maintain access to
multiple gas pools and supply basins and reduce the impact of price volatility.
For the period from May 1, 2000 through December 31, 2000, natural gas costs
were $5 million.
Although the company cannot completely eliminate the effects of elevated
gas prices and price volatility, its strategy is designed to dampen the effect
of these market conditions on the results of its operations. The company's gas
procurement strategy includes procuring natural gas under a portfolio of
agreements with price structures including fixed price, indexed price and
embedded price hedges such as caps and collars. The company's strategy also
utilizes physical assets through storage, operator and balancing agreements to
dampen price volatility.
37
Other Matters
Accounting Matters
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS
133 defines and establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities and requires recognition of all
derivatives as either assets or liabilities on the balance sheet measured at
fair value. The intended use of the derivatives and their designation as either
a fair value hedge, a cash flow hedge, or a foreign currency hedge will
determine when the gains or losses on the derivatives are to be reported in
earnings and when they are to be reported as a component of other comprehensive
income in stockholders' equity. In June 1999, the FASB issued SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities--Deferral of the
Effective Date of FASB Statement No. 133," which delayed the effective date of
SFAS 133 to all fiscal quarters of all fiscal years, beginning after June 15,
2000. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - an amendment of FASB
Statement No. 133," which amended certain accounting and reporting standards of
SFAS 133. The company is adopting SFAS 133 in the first quarter of 2001. The
impact of this standard to the company resulted in a cumulative charge as of
January 1, 2001 of $2 million after income taxes to the income statement and a
cumulative adjustment of $3 million to other comprehensive income which
decreased stockholders' equity. However, the Derivatives Implementation Group
(DIG), a committee of the FASB responsible for providing guidance on the
implementation of SFAS 133, has not reached a conclusion regarding the
appropriate accounting treatment of certain types of energy contracts under SFAS
133. The company is unable to predict when this issue will ultimately be
resolved and the impact the resolution will have on the company's future
financial position, results of operations or liquidity. Implementation of SFAS
133 will likely increase the volatility of the company's earnings in future
periods.
Other
Certain employees of the company and its affiliated companies are
represented by the International Brotherhood of Electrical Workers and the
International Union of Operating Engineers. These employees comprise
approximately 75% of the company's workforce. Labor agreements covering
virtually all represented employees of the company expired in 1999 and were
renewed for a term expiring in 2002.
The company is involved in legal and administrative proceedings before
various courts and agencies with respect to matters arising in the ordinary
course of business. The company believes that the final disposition of these
proceedings will not have a material adverse effect on its financial position,
results of operations or liquidity.
Safe Harbor Statement
Specific statements contained in this registration statement are forward-
looking statements. Such 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 thereof or other variations
thereon or comparable terminology, or by discussions of strategy. Although the
company believes these statements are based upon reasonable assumptions, no
assurance can be given that the future results covered by the forward-looking
statements will be achieved. Forward-looking statements are subject to risks,
uncertainties and other factors that may be outside of the company's control and
that could cause actual results to differ materially from future results
expressed or implied by the forward-looking statements. In connection with the
"Safe Harbor" provisions of the Private Securities Litigation Reform Act of
1995, the company is providing this cautionary statement to identify important
factors that could cause actual results to differ materially from those
anticipated. The most significant of the risks, uncertainties and other factors
are fuel prices and availability; generation plant construction, installation
and performance; the impact of current environmental regulations on generating
companies and the expectation that more stringent requirements will be
introduced over time, which could potentially have a negative financial effect;
wholesale and retail pricing for electricity in the Midwest; the effects of
regulatory actions, including changes in regulatory policy; changes in laws;
other governmental actions; future wages and employee benefits costs;
competition from other generating facilities, including new facilities that may
be developed in the future; cost and
38
availability of transmission capacity for the energy generated by the company's
generating facilities or required to satisfy energy sales made on the company's
behalf; and legal and administrative proceedings.
39
OUR BUSINESS
Our Market
Our coal plants, operating combustion turbine units and committed units are
located in Illinois within MAIN. MAIN also includes portions of Eastern
Missouri, where our affiliate AmerenUE has generation capacity, Eastern
Wisconsin and Michigan's Upper Peninsula. Energy use by sector for the combined
Ameren electric system is 26% industrial, 37% commercial, 35% residential and 2%
wholesale (municipals and cooperatives). Within the MAIN region, Ameren holds
the largest market share of installed generating capacity (approximately 24%).
According to the independent market consultant, the regional Midwest
electricity market is characterized by:
. sustained energy and peak demand growth that is expected to continue
at an annual average rate of 1.4% per year over the next twenty years,
compared to a weather-normalized growth rate of 2.8% over the past
five years;
. a well-developed electrical transmission system capable of
transferring high volumes of electricity throughout the Midwest;
. ready access to competitively priced gas and coal supplies from a
diversified range of sources;
. a significant amount of base-load generation resources, with more than
80% of the capacity in the region currently consisting of coal and
nuclear base-load facilities;
. a shortage of generating capacity that has recently resulted in
electricity price spikes that are above the long-run marginal cost of
constructing new generating facilities; and
. a need for as much as 24,000 megawatts of new generation capacity
between 2000 and 2020.
Illinois is one of the principal markets in which the output of our
facilities will be sold. In December 1997, the Governor of Illinois signed the
Illinois Electric Service Customer Choice and Rate Relief Law of 1997 providing
for electric utility restructuring in the State of Illinois. This legislation
introduces competition into the supply of electric energy at retail in Illinois.
Major provisions of this legislation include the phasing-in through 2002 of
retail direct access which allows customers to choose their electric generation
suppliers. The phase-in of retail direct access began on October 1, 1999 with
large commercial and industrial customers principally comprising the initial
group that is entitled to choose suppliers. Retail direct access was offered to
the remaining commercial and industrial customers on December 31, 2000 and will
be offered to residential customers by May 1, 2002.
Our Strategy
Generation Strategy/Capacity Expansion
Our company, together with the other subsidiaries of Resources, form the
vehicle through which Ameren intends to expand its non-regulated energy
business. Our strategy is to aggregate a critical mass of generating assets with
the appropriate mix of base-load, intermediate and peaking capacity to meet the
needs of the markets we have targeted and, therefore, optimize our financial and
operational performance. We expect to increase our generating capacity from
3,444 megawatts currently to 4,264 megawatts by summer 2001, including our
committed units, as well as 288 megawatts of additional capacity from our
pending additions to be located at Columbia, Missouri and our Pinckneyville
station.
Between mid-2002 and mid-2005, we expect to add up to an additional 1,490
megawatts of generating capacity from planned units. Capacity and energy from
new generation projects will be targeted at
40
. providing sufficient power to meet anticipated load growth in
Illinois,
. serving areas with supply shortages where Resources would have a
competitive advantage, and
. serving new contracts with large customers in need of dedicated
generating assets. To react quickly to market conditions, Development
Co. has procured a supply of critical equipment scheduled for delivery
at key intervals and relies on a team of development personnel to
assess and obtain sites and complete the necessary permitting
activities. We will acquire the Kinmundy, Columbia and additional
Pinckneyville simple cycle and Grand Tower combined cycle units from
Development Co. through summer 2001 when they are ready for commercial
operation, thereby separating us from the associated development and
construction risks.
These future plans are subject to change, including increasing or
decreasing planned or installed future generating capacity, based on market
conditions, regulatory approvals for additions, the company's results of
operations and financial condition, availability of financing and other factors
determined by management.
Portfolio Diversification
Our generation strategy is based on operating a diversified generating
asset portfolio "anchored" by a sizeable base of low-cost coal-fired assets.
Currently, our coal plants represent the majority of our generation revenues and
our generating capacity, to which we will add intermediate and peaking
generating capacity over the next few years. These intermediate and peaking
capacity additions are intended to balance our portfolio, capture potential
benefits of peak period pricing, and provide us with additional operational
flexibility and potential ancillary services revenue.
Asset Optimization
Our strategy depends on our ability to extract maximum value from our
generating facilities. Ameren has a successful track record as an efficient and
low-cost power producer. We seek to maximize the value of our generating
facilities by combining this core competency with a diversified asset portfolio,
the ability to dispatch throughout the price curve, our marketing strategy
described below, an integrated fuel procurement strategy and conservative risk
management practices. Our objective is to sell a significant portion of our
generation under term contracts in excess of one year. At the same time, the
sale of a portion of our output into short-term markets is designed to mitigate
price risk and enable us to maintain appropriate reserve resources while still
providing the ability to capitalize on market pricing opportunities and market
inefficiencies.
Fuel Management and Procurement
Ameren's fuel management and procurement strategy is managed by Fuels Co.
which coordinates fuel and gas supply for AmerenUE, AmerenCIPS and us on a
centralized basis. We believe this functional centralization increases buying
power, improves negotiation of transportation arrangements and reduces
administrative costs. Ameren has substantial background in fuel and gas
procurement in our region.
Our coal procurement strategy concentrates on ensuring the fuel needs of
our coal plants are met while minimizing cost, both of the commodity and
transportation. We seek to fix the price of coal and mitigate commodity price
exposure through term contractual arrangements. Through a combination of long-
term and short-term contracts, we have fixed the price of coal for more than 90%
of our requirements through 2001. In addition, 64% of our coal requirements
through 2005 and 45% of our requirements through 2010 will be met through long-
term fixed price contracts. Though we have a significant portion of our coal
requirements contracted, we intend to continue to purchase some portion of our
requirements on a spot basis to allow for operational flexibility in terms of
more readily adjusting coal inventories and allowing ourselves to be responsive
to the operating strategies applicable to our generating facilities. We manage
coal transportation costs by establishing multiple means of delivery of coal to
our coal plants or using different transporters in one form of conveyance.
41
Our natural gas procurement strategy is designed to ensure reliable and
immediate delivery of natural gas to our intermediate and peaking facilities by
optimizing transportation and storage options. We address gas supply cost and
price risk by structuring agreements to maintain access to multiple gas pools
and supply basins and reduce the impact of price volatility. Although we cannot
completely eliminate the effects of elevated gas prices and price volatility,
our strategy is designed to dampen the effect of these market conditions on our
financial results.
Natural gas storage and transportation agreements include firm and
interruptible services structured to allow our facilities operational
flexibility while minimizing fixed costs for capacity. Our transportation
agreements give us access to natural gas production basins in the Gulf of
Mexico, East Texas/Oklahoma, South Texas, Louisiana and Canada. Our gas purchase
agreements are arranged with both indexed and fixed price structures and with
embedded financial products designed to limit exposure to price volatility.
Marketing Strategy
The output of our generating facilities is sold by Marketing Co. and Ameren
Energy. Marketing Co.'s objective is to be a leading wholesale and retail energy
marketing company in our region. Marketing Co.'s strategy:
. targets the industrial, municipal and large commercial customers and
retail aggregators who seek price stability;
. optimizes new and existing generating assets on an integrated basis
with its affiliates; and
. differentiates its strategy from competitors by offering term
contracts supported by generating resources.
Marketing Co. has obtained regulatory certification in Illinois which
allows it to market to retail customers and it is currently pursuing similar
certification in Ohio. Marketing Co.'s experience base and resources should be
scalable as retail competition expands to a meaningful degree in our markets.
Marketing Co. has initially focused on customers in Missouri, Illinois,
Indiana and Ohio where there is the greatest opportunity for success in the
wholesale markets. Secondarily, it will pursue opportunities in other Midwest
markets. It will continue to capitalize on our current and planned generation
capacity by focusing on customers with a need for price certainty and an
aversion to supply risk. Marketing Co. offers products such as full requirements
contracts, on-peak and off-peak service and physically settled power supply
options to provide value to customers. Target customers for the wholesale market
include municipals, electric membership cooperatives, investor-owned utilities,
aggregators and marketers.
Retail market activity will be initially focused on Illinois and Ohio,
where markets are soon to be open to competition. The most attractive market
segments will include large commercial and industrial customers, or aggregated
loads that have similar buying characteristics to Marketing Co.'s wholesale
targets.
Competitive Advantages
We believe that we are well positioned to compete successfully in the
markets in which we serve or intend to serve in the future. Our low-cost coal-
fired generation provides the greatest advantage. Our reliance on a mix of coal
and natural gas provides diversification of fuel risk and allows optimization of
assets. The peaking and combined cycle additions, both those installed recently
and those planned in the near term, allow us to meet a broad range of customer
requirements. Our personnel provide valuable expertise in operations and cost
management. We believe that experience in developing plants and in navigating
the regulatory and permitting processes in Illinois makes us a competitive force
in our region.
42
Other key strengths of our company include:
. Our revenues are largely derived from low-cost, high capacity factor
coal-fired plants, while our portfolio is diversified by fuel type
among coal, gas and oil.
. We have contracts for much of our output through the end of 2004.
. We have a key strategic location; we have access to MAIN and ECAR, two
of the largest regions in the country, with 145,000 megawatts of
demand.
. Ameren has a strong track record of keeping fuel costs low through its
purchasing strategy, its ability to utilize a range of transportation
options, and its gas storage options.
. Marketing Co. benefits from Ameren's extensive market knowledge and
strong customer relationships, based on providing cost-effective
service to its native load customers.
. The separation of construction risk (with respect to the committed
units and other planned units) and trading operations away from our
company enables us to focus our capabilities and resources on
optimizing the operations of our generating asset portfolio.
. Resources offers a team of industry professionals who bring project
development, financial, engineering, marketing, risk management and
fuel procurement experience to each project.
Our Electric Generating Facilities
On the basis of generating capacity, the diversification of our asset
portfolio, with respect to the coal plants, the operating combustion turbine
units and the committed units, is illustrated in the table below.
Capacity (MW)
---------------------------------------
Unit Base-Load Intermediate Peaking
---- --------- ------------ -------
Newton 1.................. 555
Newton 2.................. 555
Coffeen 1................. 340
Coffeen 2................. 560
Meredosia 1............... 62
Meredosia 2............... 62
Meredosia 3............... 215
Meredosia 4............... 168
Hutsonville 3............. 76
Hutsonville 4............. 77
Grand Tower 1/3........... 239
Grand Tower 2/4........... 253
Joppa 1................... 62
Joppa 2................... 62
Joppa 3................... 62
Gibson City 1............. 115
Gibson City 2............. 115
Pinckneyville 1........... 42
Pinckneyville 2........... 42
Pinckneyville 3........... 42
Pinckneyville 4........... 42
Kinmundy 1................ 115
Kinmundy 2................ 115
--------- ------------ -------
2010 984 982
43
We expect to generate the bulk of our revenues from our high capacity
factor coal-fired plants and, accordingly, we expect to generate more revenue
from these units as compared to our intermediate and peaking facilities.
The following are brief summaries of the coal plants that we acquired from
AmerenCIPS and the operating combustion turbine units and committed units that
we financed using a portion of the proceeds from the sale of the old notes.
Coal Plants Acquired from AmerenCIPS
The table below is derived from information set forth in the Independent
Technical Review included as Annex A to this prospectus and depicts selected
characteristics of each of our coal plants. As indicated in the Independent
Technical Review, some of our coal plants are expected to be dispatched more of
the time than they had been historically, due to renegotiated coal supply
contracts which have made operation of these plants more economically
attractive.
Rated Projected Twenty
----- ----------------
Capacity Year Average
-------- ------------
Year (net Capacity Factor Heat Rate
----- ---- --------------- ---------
Facility Built MW) (%) (Btu/kWh)
-------- ----- --- --- ---------
Newton Unit 1......... 1977 555 82.8 10,107
Newton Unit 2......... 1982 555 84.3 10,306
Coffeen Unit 1........ 1965 340 63.6 10,871
Coffeen Unit 2........ 1972 560 67.6 10,407
Meredosia Unit 1...... 1948 62 30.6 13,209
Meredosia Unit 2...... 1949 62 29.8 13,209
Meredosia Unit 3...... 1960 215 44.1 10,461
Meredosia Unit 4...... 1975 168 0.4 25,502
Hutsonville Unit 3.... 1953 76 20.3 11,006
Hutsonville Unit 4.... 1954 77 23.0 10,921
Grand Tower Unit 3.... 1951 85 N/A* N/A*
Grand Tower Unit 4.... 1958 105 N/A* N/A*
* These units are being repowered with two gas-fired combustion turbines
described below under "--Committed Units--Grand Tower Station (repowered)."
Newton Station
The Newton station is located outside the town of Newton, Illinois, and
will operate as a base-load facility. The station consists of two essentially
identical steam-electric generating units. The units are equipped with
electrostatic precipitators for control of particulate emissions. Unit 1 uses
low NO\\X\\ burners for NO\\X\\ control. Unit 2 currently has no special
provisions for NO\\X\\ control, but we expect to install a low NO\\X\\ burner
system in 2001. SO\\2\\ is controlled on units 1 and 2 by burning low-sulfur
coal, which is currently acquired from the Powder River Basin.
Coffeen Station
The Coffeen station is located just outside the town of Coffeen, Illinois
and will operate as a base-load facility. The station consists of two steam-
electric generating units. Units 1 and 2 are equipped with electrostatic
precipitators for particulate control. Units 1 and 2 have no special provisions
for SO\\2\\ control. Both units employ cyclone burners with over fire air
systems installed during 1999 and 2000. Selective catalytic reduction systems,
or SCRs, are planned for both units in the 2001-2003 time frame.
44
Meredosia Station
The Meredosia station is located on the Illinois River, in the town of
Meredosia, Illinois. The station consists of four steam-electric generating
units. Units 1, 2 and 3 are coal-fired units. Units 1, 2 and 3 will operate as
intermediate facilities. Unit 4 is a peaking facility and is a pressurized,
reheat, oil-fired unit. Units 1, 2 and 3 are equipped with electrostatic
precipitators for control of particulates; unit 4 has no precipitator. Units 1
and 2 have no special provisions for NO\\X\\ control. Unit 3 has ABB-CE level 1
low NO\\X\\ burners installed in 1997. The unit 4 boiler is equipped with over-
fire air and gas recirculation to allow NO\\X\\ control. None of the units have
provisions for control of SO\\2\\ emissions.
Hutsonville Station
The Hutsonville station is located along the Wabash River, outside of
Hutsonville, Illinois, and will operate as an intermediate facility. The station
currently consists of two steam-electric generating units (units 1 and 2 were
retired in place in 1982). Units 3 and 4 are identical coal-fired steam-electric
generating units. The units are equipped with electrostatic precipitators for
control of particulate emissions. The units have no special provisions for
NO\\X\\ or SO\\2\\ control.
Grand Tower Station
The Grand Tower station is located on the Mississippi River outside the
town of Grand Tower, Illinois. The station previously consisted of two coal-
fired steam-electric generating units. The coal-fired boilers are no longer
being operated. The station is in the process of being repowered as a gas-fired
combined cycle facility scheduled to go into commercial operation in 2001.
Combustion Turbine Simple Cycle and Combined Cycle Units
The table below depicts select characteristics of our operating combustion
turbine generating units and committed units.
Projected Net
-------------
Heat Rate
---------
Commercial (natural gas)
---------- -------------
Operation No. Capacity per Unit
--------- --- -------- --------
Site/Facility Date Units (megawatts) Fuel Configuration (Btu/kWh)
------------- ---- ----- ----------- ---- ------------- ---------
Pinckneyville (Units 1-4)..... 6/00 4 168 natural gas simple cycle 8,811
Gibson City................... 6-7/00 2 230 dual fuel simple cycle 10,061
Joppa(1)...................... 9/00 3 186 natural gas simple cycle N/A
Kinmundy...................... 6/01(2) 2 230 dual fuel simple cycle 10,056
Grand Tower (repowered)....... 8/01(2) 2 492 natural gas combined cycle 9,326
__________
(1) We have leased the Joppa units to Development Co., and will receive fixed
lease payments which are not based on actual output or performance of the
units.
(2) Expected final commercial operation date.
Operating Combustion Turbine Units
Pinckneyville Station
The Pinckneyville station, a 168 megawatt simple cycle plant, is located
approximately three miles northeast of Pinckneyville, Illinois. The station is a
peaking plant and was commissioned for commercial operation in June 2000. This
station has four GE LM6000 combustion turbine generating units each rated at 44
megawatts and fired on natural gas. Coolers and mechanical chillers are used to
increase the rated capacity during peak days. The plant was utilized during 2000
to meet peak demand requirements and to sell energy into the wholesale market.
45
Gibson City Station
The Gibson City station, a 230 megawatt simple cycle peaking facility, is
located within the Jordan Industrial Park in Gibson City, Illinois. The station
consists of two Siemens Westinghouse (SWPC) W501D5A gas combustion turbines
operating on simple cycle. The gas combustion turbines are equipped with dual
fuel combustors and have dry low NO\\X\\ while burning natural gas and water
injection for NO\\X\\ control while burning fuel oil. Construction of the Gibson
City project began on August 2, 1999. The units became available for commercial
operation in June and July 2000. The units are equipped with the most advanced
noise-muffling system available for combustion turbines.
Joppa Station
We own three combustion turbine generating units which we are leasing on a
long-term basis to Development Co. Lease revenues commenced in October 2000. The
three combustion turbines had been in operation since 1974 at another location,
and have been refurbished and relocated to the Joppa, Illinois site. Each
combustion turbine generating unit set utilizes a General Electric model MS7001B
combustion turbine rated at approximately 62 megawatts. The refurbishment
included increasing the gas turbine firing temperature, increasing the inlet
airflow by upgrading the variable inlet guide vanes, adding an inlet fog cooling
system and converting the combustion system from fuel oil to natural gas. All
units became operational in September 2000.
Committed Units
Kinmundy Station
The Kinmundy station, a 230 megawatt simple cycle plant, is located
approximately three miles east of Patoka, Illinois. The station is expected to
be a peaking facility and will consist of two Siemens Westinghouse W501D5A gas
turbines operating on simple cycle. The gas combustion turbines will be equipped
with dual fuel combustors and will have water injection for NO\\X\\ control
while burning fuel oil. Project construction began on September 13, 1999 and we
expect that both units 1 and 2 will be operational by June 2001.
Grand Tower Station (repowered)
The Grand Tower station, a 492 megawatt (net) repowered combined cycle
plant, is located in southern Illinois on the Mississippi River approximately 90
miles southwest of Carbondale, Illinois. The repowered project configuration
will be an intermediate load facility and includes two Siemens Westinghouse
501FD gas turbine generators to re-power the existing steam turbines for
combined cycle operation. New heat recovery steam generators with duct firing
capability will be installed to produce steam from the hot gas combustion
turbine exhaust gases. The steam will be used to power the existing steam
turbines for power production. The gas combustion turbines will burn only
natural gas. We expect that the commercial operation date of the repowered unit
1 will be July 2001 and the repowered unit 2 will be August 2001.
Our Principal Agreements
The following agreements have been entered into by us and our affiliates
relating to the sale and marketing of power generated by our facilities. We have
agreed to sell our output to Marketing Co. AmerenCIPS has agreed to purchase all
of its tariffed and market-based retail sales requirements through 2004 from
Marketing Co. In addition, Marketing Co. will sell power to unaffiliated
customers. Marketing Co. will remit to us the proceeds of all of its sales,
other than its sales of power from sources other than us.
Electric Power Supply Agreement with Marketing Co.
We have entered into an electric power supply agreement (originally dated
May 1, 2000 and amended on August 14, 2000), the Genco-Marketing Co. agreement,
with our affiliate, Marketing Co., under which we agree to sell, and Marketing
Co. agrees to buy, power generated by our facilities, including the coal plants
transferred from
46
AmerenCIPS and any other generating facilities owned by us. This agreement will
remain in effect until terminated by either party on one year's notice but may
not be terminated prior to December 31, 2004.
Marketing Co. will pay for the energy delivered under the Genco-Marketing
Co. agreement as follows:
. For energy supplied to Marketing Co. for resale at other than market
prices, Marketing Co. will pay:
(1) a fixed annual capacity charge (payable in monthly installments)
of approximately $70,000 per megawatt of peak demand, and
(2) a fixed energy charge of $21.81 per megawatt hour.
Peak demand is the greater of Marketing Co.'s highest forecasted peak
demand for the following year for sales at other than market prices or its
actual annual peak demand for that year. The monthly capacity charge payment is
adjusted at the end of each year in the event actual peak demand for power
resold at other than market prices for that year exceeded forecasted peak demand
for that power.
. For energy supplied to Marketing Co. for resale at market prices,
Marketing Co. will pay to us the same price Marketing Co. receives for
its sale. Marketing Co. will remit these proceeds to us monthly.
The Genco-Marketing Co. agreement provides that, subject to the amended
joint dispatch agreement described below, any power which Marketing Co. does not
purchase may be released by it and sold on our behalf by Ameren Energy under the
agency agreement described below. The Genco-Marketing Co. agreement also
requires Marketing Co. to coordinate with Ameren Energy regarding the scheduling
and dispatch of our facilities as required under the amended joint dispatch
agreement.
We will be relieved of our obligation to sell power to Marketing Co. in the
event of "force majeure"--an event or circumstance which prevents us from
performing which is not within our reasonable control. Force majeure does not
include a situation where we could sell energy to a customer other than
Marketing Co. at a more advantageous price.
Disputes under the Genco-Marketing Co. agreement will be submitted to
arbitration. Each party will select one arbitrator and those two arbitrators
will select a neutral arbitrator. The arbitration will be conducted in
accordance with the commercial arbitration rules of the American Arbitration
Association.
Marketing Co.-CIPS Electric Power Supply Agreement
Marketing Co. and AmerenCIPS are parties to an electric power supply
agreement (dated May 1, 2000), the Marketing Co.-CIPS agreement, which provides
that Marketing Co. will supply electric capacity and energy necessary to enable
AmerenCIPS to meet its obligations as a public utility through December 31,
2004. Marketing Co. provides to AmerenCIPS all the firm electric capacity and
energy that AmerenCIPS needs to serve its native load, to operate its
transmission and distribution system, to perform transmission and distribution
services, to fulfill its obligations under all applicable federal and state
tariffs and contracts, to satisfy regional reliability requirements and for any
other purpose related to the provision of wholesale or retail electric service.
Marketing Co. is the exclusive provider to AmerenCIPS. The Marketing Co.-CIPS
agreement terminates on December 31, 2004.
AmerenCIPS pays an annual capacity charge (payable monthly) under the
Marketing Co.-CIPS agreement based on the greater of:
. AmerenCIPS' forecasted peak demand (megawatts) reported to MAIN for
the year, or
. AmerenCIPS' actual annual peak demand (megawatts).
47
The monthly capacity charge payment is adjusted at the end of each year in
the event actual peak demand for that year exceeded forecasted peak demand. In
any case, the forecasted or actual peak demand, as applicable, is reduced by the
amount of peak demand represented by sales at market-based rates. The fixed
annual capacity charge is approximately $70,000 per megawatt.
Energy charges are based on a fixed rate of $21.81 per megawatt hour
(except for the energy supplied for resale by AmerenCIPS at fixed price market-
based rates). In addition, AmerenCIPS will pay Marketing Co. the amount that
AmerenCIPS receives from retail customers for capacity and energy sold at fixed
price market-based rates.
Marketing Co. is not liable for failure to deliver energy to AmerenCIPS in
the event of "force majeure"--an event or circumstance which prevents Marketing
Co. from performing which is not within the reasonable control of Marketing Co.
Force majeure does not include a situation where Marketing Co. could sell energy
to another customer at a more advantageous price. Marketing Co. is not excused
from delivering energy to AmerenCIPS because of a failure of transmission
capacity unless that failure is due to a force majeure or uncontrollable force
or similar event under the transmission provider's tariff.
Disputes under the Marketing Co.-CIPS agreement will be submitted to
arbitration. Each party will select one arbitrator and those two arbitrators
will select a neutral arbitrator. The arbitration will be conducted in
accordance with the commercial arbitration rules of the American Arbitration
Association.
Marketing Co. and AmerenCIPS may seek to extend the Marketing Co.-CIPS
agreement upon its termination on December 31, 2004. The ability to extend the
Marketing Co.-CIPS agreement may be subject to public bidding and other
regulatory requirements applicable to AmerenCIPS at that time. No assurance can
be given that the parties will be able to extend all or any portion of the
Marketing Co.-CIPS agreement upon its termination.
Amended Joint Dispatch Agreement
Prior to AmerenCIPS' transfer of its generating assets to us in May 2000,
AmerenCIPS and AmerenUE jointly dispatched their generation pursuant to a joint
dispatch agreement dated December 18, 1995. In connection with the asset
transfer, AmerenCIPS assigned its electric generation rights and obligations
under this agreement to us and it was amended accordingly to reflect the fact
that we now own and operate the generation assets previously owned by
AmerenCIPS. As a result, we jointly dispatch generation with AmerenUE under a
new amended joint dispatch agreement, dated May 1, 2000. The amended joint
dispatch agreement may be terminated by any of the parties on one year's notice,
but may not be terminated prior to December 31, 2004.
The amended joint dispatch agreement provides a basis upon which we can
participate with AmerenUE in the coordinated operation of Ameren's transmission
facilities with our generating facilities and AmerenUE's generating facilities
in order to achieve economies consistent with the provision of reliable electric
service and an equitable sharing of the benefits and costs of that coordinated
operation. Under the agreement, each company is entitled to serve its "load
requirements" (essentially, requirements customers and unit participation
customers) from its own least-cost generation first, and then will allow the
other company first priority access to any available generation if necessary to
serve its load requirements. Conversely, a company has no call on the other
company's resources until the other company has first served its load
requirements. All of our sales to Marketing Co. are considered "load
requirements." Sales made by us to other customers by Ameren Energy as our agent
are not considered load requirements. Under the amended joint dispatch
agreement, a party receiving energy from another party to satisfy its load
requirements pays to the supplying party the marginal cost of generating the
energy. Also, any demand charges associated with off-system purchases made by
the agent to meet the parties' combined load requirements are assigned to the
parties pro rata based on their respective load requirements over the period of
the purchase.
For off-system energy sales made by Ameren Energy with power generated by
our plants, the amended joint dispatch agreement provides that we first recover
our marginal cost related to those sales. The additional net proceeds are then
subject to the sharing mechanism under the amended joint dispatch agreement and
are allocated to us and AmerenUE pro rata based on our respective load
requirements at the time of the sale. Likewise we share in the revenues produced
when Ameren Energy sells energy from AmerenUE's resources.
48
Although AmerenCIPS assigned its electric generation rights and obligations
to us, AmerenCIPS is a party to the amended joint dispatch agreement because it
also governs the allocation of transmission costs and revenues associated with
third party transmission transactions. AmerenCIPS continues to own the
transmission facilities that it owned prior to the transfer of the generating
assets, and is entitled to a share of transmission revenues associated with
third-party sales made across the Ameren transmission system by Marketing Co.
Agency Agreement
We have entered into an agency agreement with AmerenUE, Marketing Co. and
Ameren Energy (dated May 1, 2000). Under this agreement, Ameren Energy provides
wholesale power trading services relating to sales of energy for periods of less
than one year to us, AmerenUE and Marketing Co., referred to as the client
companies. Ameren Energy also provides the client companies with capacity
management; business reporting; transaction administration; contract and
counterparty administration; regulatory reporting, support and compliance;
negotiation, execution and administration of contracts and other related
services. Each of the client companies appoints Ameren Energy to be its agent to
engage in power sales, purchases and trades, all for the account of the client
company. We receive directly the proceeds of any sale of our power made by it on
our behalf. Each client company will reimburse Ameren Energy for its costs
incurred in providing service. This agreement will remain in effect for each
client until that client terminates Ameren Energy as agent under the agreement.
General Services Agreement and Fuel Services Agreement
We receive various services from our affiliates under two service
agreements. First, Ameren Services and Resources entered into a general
services agreement in September 1999. Pursuant to this agreement, Ameren
Services agreed to provide to Resources and to its subsidiaries, including us,
various advisory, professional, technical and administrative services. The
services to be provided under this agreement include, among others, accounting
services, advertising and marketing efforts, corporate planning, support
services, development services, executive management functions, human resources
administration, industrial relations services and information services. In
addition, in November 2000, Fuels Co. and Resources entered into a fuel services
agreement. Pursuant to this agreement, Fuels Co. agreed to provide to Resources
and to its subsidiaries, including us, various advisory, professional, technical
and administrative services. The services to be provided under this agreement
include, among others, fuel procurement and management services, emissions
management services and ash management services.
These agreements will continue in effect for the period during which
Resources continues to request services under the terms of the agreements. All
charges for services rendered under these agreements are based on "cost." All
costs which can be directly attributed to a particular service are assigned to
the user of that service and common costs are allocated on a fair and equitable
basis. The cost allocation methods and other aspects of the service arrangements
are subject to review and approval by the SEC under PUHCA.
Parallel Operating Agreements
We entered into several parallel operating agreements with Ameren Services
as agent for AmerenUE and AmerenCIPS in May 2000. Pursuant to these agreements,
our utility affiliates permit us to transmit power and energy generated from our
generating plants on the utility's electric system. Under the parallel operating
agreements, we are required to properly operate and maintain metering equipment,
protective and control devices, generation equipment and communication devices.
Additionally, we are required to operate our generating plants in accordance
with various performance requirements, including harmonic, speed governor,
voltage regulator and voltage control requirements.
We executed parallel operating agreements with Ameren Services covering
parallel operation in Jackson County, Crawford County, Montgomery County, Morgan
County, Jasper County, Gibson City, Pinckneyville, Grand Tower and Kinmundy,
each of which is located in the State of Illinois. The parallel operating
agreements remain in effect until terminated by the parties. These agreements
cover all of our coal plants, our operating
49
combustion turbines at Pinckneyville and Gibson City and our committed units,
and we expect to enter into similar parallel operating agreements with
transmission providers for our future sites.
Committed Unit Contribution Agreement
We have entered into a committed unit contribution agreement, which we
refer to as the combustion turbine agreement, with Resources (on behalf of
itself and Development Co.) as the developers, pursuant to which, under
specified conditions,
. we will advance funds to the developers in respect of the purchase
price of committed units prior to the date that construction of each
committed unit is completed; and
. upon completion, the developers will transfer ownership of each
committed unit to us ready for commercial operation.
With respect to each committed unit, we may advance an amount not greater
than 105% of the sum of
. the amount of unreimbursed expenditures previously made by the
developers pursuant to the equipment contracts related to that
committed unit;
. the amount of scheduled payments due or to become due by the
developers pursuant to those equipment contracts during the 60 day
period following the date of the advance; and
. the amount of unreimbursed expenditures previously made by the
developers related to the committed unit for land, permits,
engineering costs and other costs incurred in connection with the
development and construction of that committed unit.
Upon the earlier of
. sixty days following the date that the committed unit satisfies the
conditions for transfer to us; or
. the date which is twelve months after the scheduled completion date of
that committed unit in respect of which we have advanced funds to the
developers,
the developers are required to either repay to us all funds that we have
advanced for that committed unit, or transfer ownership of those committed unit
to us, together with an assignment of all related equipment contracts and
warranties.
In order to transfer ownership of a committed unit to us, construction of
the committed unit must be complete in accordance with the provisions of the
related equipment contracts and the committed unit must be ready to commence
commercial operation in all respects. In addition, the developers must certify
to us that the committed unit has satisfied all performance tests, including,
but not limited to any guaranteed performance criteria set forth in the related
equipment contracts.
In the event that the developers are not capable of certifying the
requirements set forth in the immediately preceding paragraph, the developers
may transfer ownership of that committed unit to us, if they certify to us that
the committed unit has satisfied all minimum performance criteria set forth in
the related equipment contracts and rebate to us, as a reduction in the purchase
price of that committed unit, any amounts paid to the developers by the
counterparties to the related equipment contracts which represent performance
liquidated damages under those equipment contracts.
If, on the date that the developers propose to transfer a committed unit to
us, the committed unit's performance test results indicate performance levels
below 80% of guaranteed performance levels, we may reject
50
the proposed transfer and the developers are required to repay to us all funds
that we have advanced for that committed unit.
As of the date of issuance of the old notes, the combustion turbine
agreement related only to the committed units described in this prospectus.
Under the combustion turbine agreement, we and the developers may amend the
combustion turbine agreement to incorporate additional combustion turbine units.
Upon amendment, the additional combustion turbine unit will become a "committed
unit" under the combustion turbine agreement.
Our Employees
We employ approximately 750 people primarily at our coal plants. Seventy-
five percent of our employees are represented by the International Brotherhood
of Electrical Workers Local 702 and the International Union of Operating
Engineers Local 148. The current collective bargaining agreements with virtually
all of these locals extend until June 30, 2002.
We believe that we have a good relationship with our employees.
Legal Proceedings
We are not currently involved in any legal proceedings the outcome of which
would have a material adverse effect on our financial condition, results of
operations or cash flows.
Regulation
Federal Utility Regulation
Federal Power Act
Under the Federal Power Act, the Federal Energy Regulatory Commission, or
FERC, has exclusive rate-making jurisdiction over wholesale sales of energy and
transmission in interstate commerce. FERC regulates the owners of facilities
used for the wholesale sale of energy and transmission in interstate commerce as
"public utilities" under the Federal Power Act. We are a "public utility" under
the Federal Power Act.
All public utilities subject to FERC jurisdiction are required to obtain
FERC's acceptance of their rate schedules in connection with the wholesale sale
of energy. FERC has approved our Genco-Marketing Co. agreement and related rate
schedules whereby we sell capacity and energy to Marketing Co. FERC has also
approved the Marketing Co.-CIPS agreement whereby Marketing Co. sells capacity
and energy to AmerenCIPS and has approved Marketing Co. making sales of energy
to unaffiliated persons at market-based rates. FERC has also approved the
arrangement and rate schedules whereby Ameren Energy acts as our agent to make
sales of energy on our behalf to unaffiliated persons at market-based prices.
We are subject to a FERC-approved "code of conduct" which regulates our
arrangements and transactions with our affiliates. Our request for waivers from
FERC to avoid being subject to regulation regarding accounting, record-keeping
and reporting requirements otherwise imposed on utilities subject to FERC
jurisdiction was rejected in April 2001.
We have authority from FERC at any time prior to June 23, 2002 to issue up
to $1 billion of long-term debt and to issue short-term debt in an amount not to
exceed $300 million.
Public Utility Holding Company Act
Our parent, Ameren Corporation, is a holding company registered under the
PUHCA. Under PUHCA, any entity that owns or controls 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
51
exemption is obtained or the SEC determines that the entity is not a holding
company within the meaning of PUHCA. A holding company not entitled to an
exemption must register. Registered holding companies are required to limit
their utility operations generally to a single integrated public utility system
and only those other businesses as are functionally related to the operations of
the utility system. Except as noted below, subsidiaries of a registered holding
company are subject to regulation of activities such as issuance of securities,
affiliate transactions and financial reporting requirements.
Under the Energy Policy Act of 1992, a company engaged exclusively in the
business of owning and/or operating facilities used for the generation of
electric energy exclusively for sale at wholesale may be certified as an "exempt
wholesale generator." An exempt wholesale generator is not a "public utility
company" as defined in PUHCA. We received certification from FERC as an exempt
wholesale generator in 2000. We received the necessary approval from the ICC and
the Missouri Public Service Commission (MPSC) finding that the transfer of the
coal plants from AmerenCIPS to us would benefit customers, was in the public
interest and did not violate applicable state law. Our arrangements with
Marketing Co., AmerenCIPS and Ameren Energy are in compliance with the
provisions under PUHCA designed to prevent affiliate abuse applicable to exempt
wholesale generators and affiliated public utility companies.
As an exempt wholesale generator, we are exempt from most of the provisions
of PUHCA that otherwise would apply to us as a subsidiary of a registered
holding company. Issuance of securities by us is not subject to approval by the
SEC under PUHCA. The SEC has no jurisdiction over the sale of electricity by us
to affiliates or non-affiliates. The SEC may impose limitations on Ameren
Corporation in connection with its financing for the purpose of investing in
exempt wholesale generators and foreign utility companies if Ameren
Corporation's aggregate investment in those activities exceeds 50% of its
consolidated retained earnings. At December 31, 2000, Ameren Corporation's
aggregate investment in those entities was 13% of its consolidated retained
earnings.
State Utility Regulation
The ICC regulates electric public utility companies under the Illinois
Public Utilities Act (IPUA). We are not a public utility under the IPUA and are
not subject to regulation by the ICC as to rates, issuance of securities or
other matters.
We are not subject to the jurisdiction of the MPSC.
In December 1997, the Governor of Illinois signed the Illinois Electric
Service Customer Choice and Rate Relief Law of 1997 providing for electric
utility restructuring in Illinois. This legislation introduces competition into
the supply of electric energy at retail in Illinois.
Major provisions of this legislation include the phasing-in through 2002 of
retail direct access, which allows customers to choose their electric generation
suppliers. The phase-in of retail direct access began on October 1, 1999, with
large commercial and industrial customers principally comprising the initial
group that is entitled to choose suppliers. Retail direct access was offered to
the remaining commercial and industrial customers on December 31, 2000 and will
be offered to residential customers by May 1, 2002.
In many states, including Illinois, companies who sell electricity directly
to retail customers under deregulation legislation must be registered or
licensed. Marketing Co. has obtained "alternative retail electricity supplier"
status in Illinois and is seeking comparable status in other states where retail
competition is developing.
Regional Transmission Organizations and Independent System Operators
All owners of transmission facilities subject to FERC jurisdiction must
make their transmission system available for use by all generators of
electricity in an open and non-discriminatory manner. Marketing Co. and Ameren
Energy arrange to transmit the power we generate and that Marketing Co. and
Ameren Energy sell to customers by reserving transmission on the system of
Ameren and other transmission owners through Open Access Transmission Tariffs.
FERC is fostering better transmission access and more liquid markets for
transmission
52
capacity by encouraging the formation of Independent System Operators (ISOs) and
Regional Transmission Organizations (RTOs). Under FERC Order 2000, an RTO is an
entity that satisfies minimum characteristics (independence, scope and regional
configuration, operational authority and short-term reliability) and minimum
functions (tariff administration and design, congestion management, parallel
path flow, ancillary services, information access, market monitoring, planning
and expansion and interregional coordination). Expansion of ISOs and RTOs should
help keep transmission costs low and improve transmission capacity thus making
it easier for Marketing Co. and Ameren Energy to sell the electricity we
generate over a broader market.
In November 2000, Ameren announced that it is withdrawing from the Midwest
ISO to become a member of the Alliance Regional Transmission Organization
(Alliance RTO), pending necessary regulatory approvals. In January 2001, FERC
conditionally approved the formation of the Alliance RTO, including its rate
structure. In February 2001, in a proceeding before FERC, the Alliance RTO and
the Midwest ISO reached an agreement that would enable Ameren to withdraw from
the Midwest ISO and join the Alliance RTO. This settlement agreement remains
subject to FERC approval. Ameren's withdrawal from the Midwest ISO also remains
subject to MPSC approval. In addition, Ameren's transfer of control and
operation of its transmission assets to the Alliance RTO is subject to MPSC and
ICC approvals.
Environmental Regulation
We must comply with federal, state and local environmental regulations
relating to the safety and health of personnel, the public and the environment,
including the identification, generation, storage, handling, transportation,
disposal, recordkeeping, labeling, reporting of and emergency response in
connection with hazardous and toxic materials, safety and health standards, and
environmental protection requirements, including standards and limitations
relating to the discharge of air and water pollutants. Failure to comply with
those 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 us into compliance. Construction and operating permits under
Illinois' air and water pollution control regulations have been obtained or are
pending with respect to our operating combustion turbine units and committed
units. We have no reason to believe that we will be unable to obtain pending
permits in a timely manner.
Many of the coal plants have full time environmental coordinators.
Additional environmental support is provided by Ameren Services for the coal
plants and the combustion turbine generating facilities.
The operator of the Joppa station, through its parent corporation, is
responsible for environmental compliance for the Joppa station. The Joppa
station is not included within our SO\\2\\ and NO\\X\\ emission allowance
compliance programs.
Air Emission Compliance
We currently are in material compliance with all applicable state and
federal air regulations through a combination of unit-specific and system-wide
compliance strategies. All necessary approvals and reporting procedures have
been implemented with the Illinois Environmental Protection Agency (IEPA) and
the USEPA. We employ an emissions averaging and trading program to comply with
some sulfur dioxide and nitrogen oxides regulations.
Sulfur Dioxide (SO\\2\\)
SO\\2\\ emissions are regulated under Title IV of the Federal Clean Air Act
Amendments of 1990 (CAAA), by USEPA New Source Performance Standards (NSPS) and
by the IEPA regulations and operating permit requirements. Meredosia unit
4/boiler 6 and Newton units 1 and 2 are subject to Subpart D of the NSPS and
have 0.8 pounds of SO\\2\\-per-million British thermal units (BTU) (lb
SO\\2\\/mmBTU) and 1.2 lb SO\\2\\/mmBTU emission standards, respectively.
Coffeen, Grand Tower, Hutsonville and the remaining units at Meredosia are
subject to state-only plant lb SO\\2\\/hr emission limitations ranging from
8,536 lb/hr to 55,555 lb/hr.
53
Title IV establishes an allowance trading program with two phases
introduced over five years. Phase II of the Title IV SO\\2\\ program went into
effect January 1, 2000 and includes all of our coal plants, operating combustion
turbine units and committed units.
With the implementation of Phase II, our units will need to obtain SO\\2\\
allowances to meet these new requirements. There are presently no flue gas
desulfurization systems at our stations which could reduce SO\\2\\ emissions. We
burn lower-sulfur Illinois coal at the Coffeen station and low-sulfur Powder
River Basin coal at the Newton station to help lower annual emissions of
SO\\2\\. In addition, the repowering of the Grand Tower station will provide
additional reductions in SO\\2\\ emissions.
After giving effect to the above compliance measures, we estimate that
there will be an annual shortfall between the number of allowances allocated to
each of our units and expected annual emissions. The current strategy for our
plants is to purchase allowances at market value or to transfer allowances at
cost from the bank of surplus allowances owned by our affiliate, AmerenUE. The
AmerenUE SO\\2\\ allowance bank was approximately 770,000 allowances at the end
of 2000. In January 2001, we exchanged 162,840 SO\\2\\ allowances with vintages
of 2006 and later with AmerenUE for 120,000 SO\\2\\ allowances with vintages of
2002 and earlier. The market value of the allowances exchanged was approximately
equal. We completed this exchange because we experienced a shortfall of SO\\2\\
allowances in 2000 and we are projecting a shortfall in SO\\2\\ allowances in
2001 and 2002 under current generation plans. This transaction was recorded at
the historical cost of the allowances. We may alter our generation plan or
increase our use of low-sulfur coal to improve our position in SO\\2\\
allowances. The estimated cost of purchasing allowances at market value (as
developed by the independent market consultant) is included in our financial
projections set forth in the Independent Technical Review included as Annex A to
this prospectus.
Nitrogen Oxides (NO\\X\\)
NO\\X\\ emissions are regulated under Title IV of the CAAA, by NSPS and by
the IEPA operating permit requirements. Meredosia unit 4/boiler 6 and Newton
units 1 and 2 are subject to Subpart D of the NSPS and have 0.3 lb NO\\X\\/mmBTU
and 0.7 lb NO\\X\\/mmBTU emission standards respectively. All coal-fired units
at Coffeen, Grand Tower, Hutsonville, Meredosia and Newton are subject to the
CAAA Title IV, Phase II NO\\X\\ limitations beginning on January 1, 2000 and
ranging from 0.45 to 0.86 lb NO\\X\\/mmBTU.
In order to comply with the annual NO\\X\\ limitations under Phase II of
the Title IV NO\\X\\ program, a unit must either meet the individual limit for
the boiler type or achieve equivalent compliance by means of an averaging plan.
In June 2000, we submitted an averaging plan to the IEPA. Ameren has chosen to
utilize a system-wide averaging plan for all of our generating facilities, as
the compliance strategy for Phase II NO\\X\\ requirements. We have received a
draft permit from the IEPA approving our averaging plan. Emission data through
August 2000 indicates that our units are in compliance with the proposed
averaging plan.
Illinois has adopted NO\\X\\ control regulations that affect our stations.
In December 2000, the Illinois Pollution Control Board (IPCB) enacted
regulations designed to comply with USEPA's "SIP Call" rule. The regulations
contain a cap on NO\\X\\ emissions of 0.15 lb. NO\\X\\/mmBTU during the ozone
season and are effective May 31, 2004. The ozone season is defined as May 1
through September 30.
Under the IEPA proposal, compliance can be achieved through an emission
allowance trading program. Each unit would be allocated emission allowances
annually for the ozone season. In order to comply with the proposed rules, we
will need to rely on strategies beyond allowance trading. Ameren plans to employ
several NO\\X\\ emission reduction technologies including selective catalytic
reduction, low NO\\X\\ burner and overfire air retrofit, repowering and
combustion optimization. The estimated capital and operating cost of these
control measures, with the exception of such control measures for the pending
additions, is included in the financial projections included in the Independent
Technical Review. We believe we can meet the NO\\X\\ requirements with these
strategies.
In 1997, some northeastern states filed petitions with the USEPA under
Section 126 of the Clean Air Act requesting that USEPA issue a determination
that major sources of NO\\X\\ emissions in other states including Illinois
contribute significantly to "non-attainment" in areas further to the east and
north. These petitions would require NO\\X\\ emission levels of 0.15 lb.
NO\\X\\/mmBTU. Illinois' implementation of the NO\\X\\ SIP Call already imposes
a 0.15
54
standard on our generating units and we do not anticipate additional controls
resulting from the Section 126 petition process.
New Source Review
In the fall of 1999, USEPA initiated enforcement actions against 32 coal-
fired generating units for alleged new source review (NSR) violations. USEPA
claims that the units failed to install pollution control technology following
various major unit modifications. We have not been named in these enforcement
actions and, to date, we have not received requests for information concerning
potential NSR violations at our generating facilities.
Particulates and Opacity
Our units are currently in material compliance with existing particulate
emission limits. The USEPA has proposed new fine particulate matter ambient air
quality standards that may establish additional areas of nonattainment. In May
1999, the U.S. Court of Appeals for the District of Columbia remanded the
regulations back to the USEPA for review. The USEPA appealed the decision to the
U.S. Supreme Court. On February 27, 2001, the U.S. Supreme Court reversed and
remanded the case to the U.S. Court of Appeals for the District of Columbia for
further evaluation and opinion. The U.S. Supreme Court ruled that Congress, in
enacting Clean Air Act provisions that authorized the USEPA to determine air
quality standards, did not unconstitutionally delegate legislative power to the
agency. The U.S. Supreme Court also rejected industry arguments that the USEPA
should have considered implementation costs in setting air quality standards.
The ruling reaffirms the USEPA's authority to establish uniform air quality
standards at a level that is sufficient to protect public health. However, the
manner in which the USEPA proposed to implement the proposed air quality
standard for ozone was ruled unlawful and the U.S. Supreme Court ordered the
remand of the USEPA's implementation policy to the agency for further
consideration. When the proposed ambient standards are ultimately enacted, lower
particulate matter emission limits will be imposed, as well as lower SO\\2\\ and
NO\\X\\ limits in the future.
For all of our coal plants, operating permit conditions allow operation
during periods of opacity exceedances that are due to startup, shutdown,
malfunction and breakdown. Excess opacity emissions have occurred at each of our
coal plants, as is common at many coal-fired generating units. We deploy
engineering practices, such as load reductions, designed to minimize the
magnitude and duration of opacity exceedances.
Other Air Pollutant Considerations
The USEPA is identifying other potentially hazardous emissions, such as
mercury, which may pose a potential health and environmental threat. Regulation
of carbon dioxide and other greenhouse gases associated with climate change also
is being studied by the USEPA. It is currently too early to tell what the impact
of future USEPA regulation of these substances might be or whether they will
affect our generating facilities.
The IPCB has issued a nonbinding informational order concerning
environmental regulation of natural gas-fired, peak-load electrical operating
facilities, or peaker plants, such as most of our combustion turbine generating
units. In its informational order, the IPCB recommends that the State of
Illinois tighten current environmental regulations concerning peaker plants. In
response to the informational order, IEPA may propose more stringent regulations
for peaker plants.
Water and Waste Water Compliance
Our stations are permitted under the National Pollutant Discharge
Elimination System (NPDES) which is administered by the IEPA. Wastewater
treatment facilities have been provided to ensure compliance with permitted
discharge limits. NPDES sampling data indicate general compliance with permit
requirements. There are no outstanding water pollution control violations,
enforcement issues or consent orders for our coal plants regarding water
pollution with the exceptions noted below.
55
Previously, variances were issued to the Newton and Coffeen stations
regarding discharge thermal temperature limits in cooling lakes adjacent to the
facilities. In January 2000, violation notices were issued to the Newton and
Coffeen stations for thermal discharges that caused a fish kill during the
extreme high temperature weather conditions experienced during drought
conditions in July 1999. As a result of the violation notices, the variances
were revoked and both stations were ordered to immediately comply with the
previous thermal limits set out by the IPCB. We completed construction of
engineered surface impoundments at the Newton and Coffeen stations during the
summer of 2000. These impoundments should reduce thermal loads to the lakes that
serve both stations and further reduce the likelihood of a fish kill. This
effort will enhance our ability to meet electric demands during critical summer
periods while better ensuring the protection of environmental resources.
Our Newton, Hutsonville, Grand Tower and Meredosia stations all have active
unlined ash impoundment systems. We close ash ponds when storage capacity
becomes exhausted. Under Illinois law, the closure of ash ponds must comply with
landfill and various groundwater regulations. In accordance with the terms of a
settlement agreement with the Illinois Attorney General and the IEPA, we have
constructed a new lined fly ash basin at the Hutsonville station and we intend
to close the existing unlined basin. These actions are designed to address
groundwater contamination associated with the ash ponds. In general, fly ash
basins constructed in the future will have to be lined at a greater cost.
Solid and Hazardous Waste Compliance
Coal-fired generating facilities create fly ash and bottom ash as by-
products of the coal combustion process. Accordingly, the primary large volume
waste for our coal plants is fly ash and, to a lesser extent, bottom ash.
Depending upon the station, fly ash is typically disposed of at an off-site
commercial landfill, or on-site at a permitted landfill or treated through a
surface impoundment system. Bottom ash is either disposed of on-site in a
surface impoundment system or is used by third parties for road cinders or
building or roofing materials.
Newton Landfill. The Newton Phase I landfill operated from 1978 until
its final closure in 1998. Scrubber sludge, fly ash and bottom ash from our coal
plants were deposited into the Phase I landfill. The Newton station currently
operates a Phase II landfill permitted for chemical and industrial wastes. Low
volume plant wastes, fly ash and bottom ash from the Newton station and the
other coal plants are deposited into the Newton Phase II landfill. The
landfill's design includes all modern components of a solid waste disposal
facility including leachate collection, comprehensive groundwater monitoring and
leak detection, liners and cap materials, and load checking and gate control
requirements. The Newton Phase II landfill is located directly adjacent and
south of the Newton Phase I landfill. A shallow groundwater plume (approximately
12 feet below the ground surface) of ash leachate exists south of the Phase I
landfill and will be intercepted during the construction of future Phase II
landfill areas or cells. The Phase II landfill has no outstanding non-compliance
issues that are anticipated to impact its long term availability and operation.
Coffeen Landfill. The Coffeen station currently back hauls fly ash to
a former coal mine for disposal or sends those wastes to permitted commercial
landfills or for use as product material in cement kilns. Bottom ash is
deposited in a pond. Alternatively, the Coffeen station is considering
landfilling its combustion waste onsite and has obtained a permit to construct
and operate a landfill for chemical and industrial waste streams. Construction
of the landfill is not anticipated at this time. The Coffeen station has
received an underground injection control permit for the disposal of ash in a
former mine works under the station.
Meredosia, Hutsonville and Grand Tower. Our remaining coal plants do
not operate coal combustion landfill facilities. Fly ash and bottom ash is
either sent to permitted commercial landfills or sluiced through a surface
impoundment system. Ash from surface impoundments is periodically removed and
shipped to cement kilns, landfilled or used for other beneficial purposes as
authorized under Illinois law.
Although proposals have been made from time to time to change the legal
classification of ash from coal-fired electric generating facilities under
federal environmental regulations, ash is not currently classified as a
hazardous waste. The USEPA recently announced its intent to develop national
standards to address the disposal of coal combustion wastes in landfills,
surface impoundments and mines. If ash is reclassified as a hazardous waste or
very stringent national ash disposal standards are adopted, the operating costs
of our coal plants would increase.
56
The potential exists for past or future discreet instances of soil and
groundwater contamination at each of our coal plants due to their vintage and
the nature of their operation. We expect to rely on a contractual indemnity from
AmerenCIPS in the event we incur remediation costs at the sites of our coal
plants on account of pre-existing environmental contamination.
57
SUMMARY OF INDEPENDENT TECHNICAL REVIEW
Stone & Webster Consultants, Inc. has prepared the Independent Technical
Review concerning specific technical, environmental and economic aspects of our
electric generating facilities. We have attached the Independent Technical
Review as Annex A to this prospectus. You should read this summary in
conjunction with the full text of the Independent Technical Review. The
Independent Technical Review includes, among other things, a conceptual design
review of our electric generating facilities, a review of the significant
contracts and a review of financial projections, including annual revenues,
expenses and debt service coverage for our coal plants, operating combustion
turbine units and committed units. We retained Stone & Webster Consultants,
Inc. to prepare the Independent Technical Review because it is a leading
consulting engineering firm that devotes a substantial portion of its resources
to providing services related to the technical, environmental and economic
aspects of power projects. Neither we, nor any of our affiliates, is affiliated
with Stone & Webster Consultants, Inc. We advise you that the independent
technical consultant's report is dated October 25, 2000, and information
contained in that report may only be accurate as of that date. We have not
requested, nor do not intend to request, that Stone & Webster Consultants, Inc.
update any information in the Independent Technical Review, including but not
limited to any projected operating and financial information.
For purposes of reviewing the projected operating results, Stone & Webster
Consultants, Inc. relied on specific assumptions regarding material
contingencies and other matters that are not within the control of our company,
Stone & Webster Consultants, Inc. or any other person. Each of these assumptions
is described in the Independent Technical Review. These assumptions are
inherently subject to significant uncertainties, and actual results will differ,
perhaps materially, from those projected. See "Risk Factors." The projected
operating and financial results were not prepared with a view toward compliance
with published guidelines of the SEC, the guidelines established by the American
Institute of Certified Public Accountants for preparation and presentation of
financial projections or U.S. generally accepted accounting principles.
Subject to the information contained and the assumptions and qualifications
made, in the Independent Technical Review, Stone & Webster Consultants, Inc.
expressed the opinions that:
Coal Plants
. The Newton, Coffeen, Meredosia and Hutsonville stations were found to
be well maintained and generally in good condition as compared to
similar facilities of the same age. With the implementation of
enhanced condition monitoring programs and the forecasted capital
improvements, these electric generating facilities should continue to
provide reliable power generation through the term of the financial
model.
. Stone & Webster Consultants, Inc. reviewed the technical inputs to the
independent market consultant's dispatch simulation model. The key
input data, such as claimed capacity, scheduled and forced outage
rates and heat rates were reasonable and consistent with recent
historical experience.
. The generating assets are technically capable of performing at the
capacity factors projected by the independent market consultant.
. The company's forecasted O&M expenses are consistent with Ameren's
historical expenditures and with other similar projects with which
Stone & Webster Consultants, Inc. is familiar. The O&M expenses appear
reasonable and adequate to meet the company's maintenance and
performance objectives.
. The overhaul schedules developed by Ameren are prudent and consistent
with current operations. The overhaul and capital expenses forecasted
in the financial model are considered adequate to support the
continued operation of the generating assets through 2020, assuming
implementation and continuation of condition assessment programs.
58
. The generating assets are in compliance with current permit and
consent order requirements. Ameren's approach to the solutions to the
environmental issues identified is reasonable based on Stone & Webster
Consultants, Inc.'s experience.
. The company plans to comply with current NO\\X\\ and SO\\2\\ emissions
limitations through the purchase of emissions credits and through
capital expenditures, e.g., SCR systems. These plans appear to be
reasonable and adequate, based on the information available at the
time of Stone & Webster Consultants, Inc.'s review.
. A Phase I environmental site assessment was conducted as part of this
review, which indicated potential soil and groundwater contamination
at each of the coal plants. Separately, Stone & Webster Consultants,
Inc. notes that AmerenCIPS has retained responsibility and indemnified
us with regard to all environmental damages or violation of any
environmental requirements attributable to or resulting from any
action prior to the closing date of the asset transfer.
. Stone & Webster Consultants, Inc. reviewed our major agreements and
contracts and is of the opinion that, in general, the technical
requirements are comprehensive, reasonable and achievable as well as
consistent among and between the various documents.
Operating Combustion Turbine Units
. The key input data to the independent market consultant's dispatch
model, such as capacity, availability and heat rates, were reasonable
and consistent with industry norms.
. Performance with respect to projected capacity factors is considered
achievable.
. The combustion turbine technologies (W501D5A, GE LM6000) are
commercially proven and widely used in the market.
. The Westinghouse 501FD (Grand Tower combined cycle), a refinement on
the high temperature W501F technology, incorporates advancements in
low NO\\X\\ combustion technology, compressor and blade designs, and
cooling technology. These are typical of normal design improvements by
manufacturers. The 501F fleet, introduced in 1993, has a strong
operational history and several 501FD units will have been in
commercial operation for nearly a year by the date which the company's
units are scheduled for start-up. Furthermore, the two-year warranty
under the combustion turbine supply contract is considered
advantageous.
. If operated and maintained in accordance with the O&M agreement and
established operating plans and budgets, which are considered
adequate, the useful lives of the units are expected to exceed the
term of the financing.
. A majority of the required permits for the operating combustion
turbine units have been acquired and the permit acquisition plan for
those permits not yet required is reasonable.
. The Phase 1 environmental site assessments revealed no significant
environmental issues at the Gibson City, Pinckneyville and Kinmundy
sites. Grand Tower, as an existing station, is covered by the
indemnification referenced above.
. Stone & Webster Consultants, Inc. reviewed our major agreements and
contracts and is of the opinion that, in general, the technical
requirements are comprehensive, reasonable, and achievable as well as
consistent among and between the various documents.
59
Committed Units
. The scopes of work, specifications and implementation plans in the
available equipment supply contracts, construction contracts, and
design manuals were reasonable and complete. Construction schedules
are considered aggressive but achievable. Projected costs appear to be
reasonably consistent with comparable projects.
Financial Projections
. The availability, capacity and heat rate inputs used by the
independent market consultant to develop its projections of market
prices and energy generation are consistent with the values Stone &
Webster Consultants, Inc. has reviewed and found reasonable.
. The projected heat rate and capacity assumptions have been developed
based on historical data as modified to account for improvements that
have been made or are planned to be made to these facilities. With
continued capital investment, it is reasonable to expect that the heat
rates and capacities can be maintained over the period shown in the
financial model.
. The company's maintenance and capital budgets, reflected in the
financial model, appear reasonable and adequate to meet the
performance objectives safely and reliably in the ordinary course of
business.
. Stone & Webster Consultants, Inc. reviewed the technical and
commercial assumptions and the calculation methodology of the
financial model. The technical assumptions assumed in the financial
model are reasonable and consistent with the contracts reviewed. The
financial model fairly presents, in the opinion of Stone & Webster
Consultants, Inc., projected revenues and expenses under the base case
assumptions.
. The projected revenues from the sale of capacity and energy are more
than adequate to pay the annual operating and maintenance expenses
(including provisions for major maintenance), other operating
expenses, and debt service. Under the base case assumptions, the
average debt service coverage ratio is calculated to be 5.4x from 2000
through 2010. The minimum debt service coverage ratio is 4.4x and
occurs in 2001 and 2003.
. Three sensitivity cases were prepared to test the impact of different
market forces on the energy and capacity prices forecast by the
independent market consultant and the associated impact on the debt
service coverage ratio. The market energy and capacity prices were
forecast assuming (i) the overbuilding of generating facilities in the
region, (ii) higher fuel prices and (iii) lower fuel prices. The
average debt service coverage ratio was most sensitive to the low fuel
price sensitivity case. The average debt service coverage ratio in
this case fell to 4.9x with a minimum of 4.4x in 2005. The average
debt service coverage ratio is 5.3x in the overbuild sensitivity case
and is 6.2x in the high fuel price sensitivity case, with minimum debt
service coverage ratios of 3.2x in 2003 and 4.0x in 2001,
respectively.
60
SUMMARY OF INDEPENDENT MARKET CONSULTANT'S REPORT
Resource Data International, Inc., as independent market consultant, has
prepared a report that analyzes the Midwest United States electricity market and
the economic competitiveness of our electric generating facilities within that
market. The report provides an assessment of the long-term market
opportunities, including capacity and energy prices expected to be received by
generators, in the region for the years 2000 through 2020. We retained Resource
Data International, Inc. to prepare the report because of its expertise in the
analysis of power markets, including future market demand, future market prices
for electric energy and capacity and related matters, for electric generating
facilities. Neither we, nor any of our affiliates, is affiliated with Resource
Data International, Inc. A copy of the report is included as Annex B to this
prospectus and should be read in its entirety. We advise you that the
independent market consultant's report is dated June 6, 2000, and information
contained in that report may only be accurate as of that date. We have not
requested, nor do not intend to request, that Resource Data International, Inc.
update the information in its report.
Below is a summary of the conclusions expressed by Resource Data
International, Inc. in its report. This is merely a summary and is subject to
the information contained, and the assumptions made, in the report. The report
should be read in its entirety in order for the reader to completely understand
the basis of the conclusions and the assumptions upon which they are based. Some
terms used in the summary below are defined in the report. On the basis of its
studies, analyses, and investigations of our electric generating facilities and
the assumptions as set forth in the report, Resource Data International, Inc. is
of the opinion that:
. The market for electricity in the Midwest is characterized by:
(1) Sustained energy and peak demand growth expected to continue
at an annual average rate of 1.4% per year over the next
twenty years, compared to a weather normalized growth rate
of 2.8% over the past five years;
(2) A well-developed electrical transmission system capable of
transferring high volumes of electricity throughout the
Midwest;
(3) Ready access to competitively priced gas and coal supplies
from a diversified range of sources;
(4) A significant amount of base-load generation resources, with
more than 80% of the capacity in the region currently
consisting of coal and nuclear base-load facilities;
(5) A shortage of generating capacity that has recently resulted
in electricity price spikes that are above the long-run
marginal cost of constructing new generating facilities;
(6) Up to 5,800 megawatts of new capacity, mainly peaking,
coming on-line during the next two summers (2000 and 2001);
and
(7) A need for as much as 24,000 megawatts of new generation
capacity between 2000 and 2020.
. Resource Data International, Inc.'s findings regarding our assets are
as follows:
(1) Ameren is the largest generator in MAIN, controlling 24% of
MAIN's overall capacity. The second largest generator,
Mission Energy, controls approximately 20% of MAIN's
capacity.
(2) With the addition of 400 megawatts of peaking capacity in
2000 and 235 megawatts of peaking capacity in 2001, the
company will be a diversified generation enterprise with
competitive base-load, intermediate and peaking generation.
The company has a combination of coal and natural gas units
that span the regional dispatch curve.
61
(3) Through 2002, Resource Data International, Inc. forecasts
that more than 86% of the company's revenues will be derived
from its fixed price contract with Marketing Co. and other
smaller long-term wholesale contracts. In 2004, Resource
Data International, Inc. forecasts that 67% of the company's
revenues will be derived from its fixed price contracts.
Although the company's strategy is to extend the fixed price
contracts or enter into replacement contracts for the bulk
of its output, Resource Data International, Inc.'s analysis
assumes that the company will operate as a competitive
generation company after 2004 and obtain the wholesale price
of power. In the overbuild scenario in which Resource Data
International, Inc. added all new proposed capacity to the
grid, the market reaches an equilibrium in 2004, which is
one year before the company will begin operating primarily
as a competitive generation company.
(4) Due to the existence of substantial amounts of base-load
capacity and a shortage of peaking capacity in MAIN,
Resource Data International, Inc. forecasts that it will be
more profitable to build combustion turbine facilities than
combined cycle facilities over most of the forecast horizon.
This forecast is consistent with the company's plan to add
primarily peaking capacity to its portfolio.
62
CONVERSION TO GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Independent Technical Review contains certain projections for the coal
plants, operating combustion turbine units and the committed units, including
projected cash available for debt service. The projected cash available for debt
service included in the base case projection of the Independent Technical Review
is converted, in the tables below, to operating income and net income, in
accordance with generally accepted accounting principles, which we refer to as
GAAP. To make such conversion, various assumptions were made. The assumptions
are as follows:
. "Cash available for debt service" in the table was obtained from the
Independent Technical Review and is not reduced by capital expenditures.
. "Depreciation and amortization" represents projected depreciation expense
for the following generating stations: Newton, Coffeen, Meredosia,
Hutsonville, Grand Tower, Gibson City, Pinckneyville (Units 1-4), Joppa and
Kinmundy.
. "Interest expense on senior notes" represents interest expense on the old
notes, issued on November 1, 2000.
. "Interest expense on 2001 incremental financing" represents interest
expense on assumed incremental $25 million of permanent financing issued
August 1, 2001 for a ten-year term at 8.25%.
. "Interest expense on refinancing of senior notes, Series A" represents
interest expense on $225 million 7.75% senior notes due 2005 refinanced
upon maturity for a five-year term at 7.35%.
. "Interest expense on refinancing of senior indebtedness" represents
interest expense on $425 million of senior indebtedness due 2010 refinanced
upon maturity for a ten-year term at 8.25%.
. "Interest expense on the AmerenCIPS intercompany note" represents interest
expense on the promissory note issued to AmerenCIPS in exchange for
AmerenCIPS' generating assets reduced on June 30, 2001 by the principal
amount of the tax-exempt pollution control loan obligations assumed to be
transferred to us on that date. The intercompany note was issued on May 1,
2000, bears interest at 7% and has a 10 year amortization schedule with a
balloon payment due at the end of year five. Interest expense during years
2005 through 2010 includes a refinancing assumption in 2005 in which the
principal amount is financed for a five-year term at 7.60% with terms
otherwise similar to the original note.
. "Interest expense on the Ameren Corporation intercompany note" represents
interest expense on the $50 million note issued to Ameren Corporation. The
note was issued on June 30, 2000, bears interest at 7% and has a 10 year
amortization schedule with a balloon payment due at the end of year five.
Interest expense during years 2005 through 2010 includes a refinancing
assumption in 2005 in which the principal amount is financed for a five-
year term at 7.60% with terms otherwise similar to the original note.
. "Interest expense on tax-exempt pollution control loan obligations"
represents interest expense on $104 million of tax-exempt pollution control
loan obligations assumed to be transferred to us from AmerenCIPS on June
30, 2001 and thereafter to bear interest at assumed rates of 6.1% for $51
million and 6.65% for $53 million.
. Income taxes are calculated at an assumed effective tax rate of 38.3%.
63
The information is given in two tables, the first covering 2000 through 2010 and
the second, 2011 through 2020.
(Thousands of Dollars) 2000 2001 2002 2003 2004 2005 2006
------- ------- ------- ------- ------- ------- -------
Cash available for debt service 184,676 181,094 201,270 193,170 204,908 243,571 254,643
Depreciation and amortization 42,013 53,665 61,108 63,523 65,036 66,358 67,725
GAAP operating income 142,663 127,429 140,162 129,647 139,872 177,213 186,918
Interest expense on senior notes 5,690 34,138 34,138 34,138 34,138 31,231 16,700
Interest expense on 2001 incremental - 859 2,063 2,063 2,063 2,063 2,063
financing
Interest expense on refinancing of senior - - - - - 2,756 16,538
notes, Series A
Interest expense on refinancing of senior - - - - - - -
indebtedness
Interest expense on AmerenCIPS 25,743 33,387 27,473 24,931 22,211 20,346 17,601
intercompany note
Interest expense on Ameren Corporation 1,750 3,331 3,066 2,782 2,479 2,271 1,964
intercompany note
Interest expense on tax-exempt pollution - 3,304 6,608 6,608 6,608 6,608 6,608
control loan obligations
GAAP income before income taxes 109,480 52,410 66,815 59,126 72,374 111,938 125,445
Income taxes 41,931 20,073 25,590 22,645 27,719 42,872 48,045
GAAP net income 67,549 32,337 41,225 36,481 44,655 69,066 77,399
(Thousands of Dollars) 2007 2008 2009 2010
------- ------- ------- -------
Cash available for debt service 266,804 286,044 299,493 305,135
Depreciation and amortization 68,780 69,850 71,805 70,966
GAAP operating income 198,024 216,194 227,688 234,169
Interest expense on senior notes 16,700 16,700 16,700 13,917
Interest expense on 2001 incremental 2,063 2,063 2,063 2,063
financing
Interest expense on refinancing of senior 16,538 16,538 16,538 13,781
notes, Series A
Interest expense on refinancing of senior - - - 5,844
indebtedness
Interest expense on AmerenCIPS 14,012 10,151 5,996 1,526
intercompany note
Interest expense on Ameren Corporation 1,564 1,133 669 170
intercompany note
Interest expense on tax-exempt pollution 6,608 6,608 6,608 6,608
control loan obligations
GAAP income before income taxes 140,540 163,002 179,114 190,260
Income taxes 53,827 62,430 68,601 72,870
GAAP net income 86,713 100,572 110,513 117,390
2011 2012 2013 2014 2015 2016 2017
------- ------- ------- ------- ------- ------- -------
Cash available for debt service 335,205 356,753 368,838 394,239 411,922 418,684 433,711
Depreciation and amortization 68,201 70,394 71,839 71,504 72,569 74,074 67,531
GAAP operating income 267,004 286,359 296,999 322,735 339,353 344,610 366,180
Interest expense on 2001 incremental 1,203 - - - - - -
financing
Interest expense on refinancing of 35,063 35,063 35,063 35,063 35,063 35,063 35,063
senior indebtedness
Interest expense on tax-exempt pollution 6,608 6,608 6,608 4,011 3,491 3,491 3,491
control loan obligations
GAAP income before income taxes 224,130 244,688 255,328 283,662 300,799 306,056 327,626
Income taxes 85,842 93,716 97,791 108,642 115,206 117,220 125,481
GAAP net income 138,288 150,973 157,537 175,019 185,593 188,837 202,145
2018 2019 2020
------- ------- -------
Cash available for debt service 451,741 463,564 474,092
Depreciation and amortization 66,574 66,989 62,550
GAAP operating income 385,167 396,575 411,542
Interest expense on 2001 incremental - - -
financing
Interest expense on refinancing of 35,063 35,063 29,219
senior indebtedness
Interest expense on tax-exempt pollution 3,491 3,491 3,491
control loan obligations
GAAP income before income taxes 346,613 358,021 378,832
Income taxes 132,753 137,122 145,093
GAAP net income 213,860 220,899 233,739
64
OUR MANAGEMENT
Except as otherwise indicated below, each of our officers and directors
have served in their positions since our company was formed. The following are
our officers and directors:
Paul A. Agathen Director
Donald E. Brandt................... Director
Daniel F. Cole..................... Director
Gary L. Rainwater.................. President and Director
R. Alan Kelley..................... Senior Vice President--Operations
Warner L. Baxter................... Vice President and Controller
Michael J. Montana................. Vice President--Supply Services
Robert L. Powers................... Vice President--Technical Services
J.L. Simpson....................... Vice President--Power Operations
Steven R. Sullivan................. Vice President, General Counsel and Secretary
Jerre E. Birdsong.................. Treasurer
Paul A. Agathen, Director. Mr. Agathen is also a Senior Vice President of
Ameren Services. Mr. Agathen was employed by AmerenUE in 1975 as an attorney. He
was named General Attorney of AmerenUE in 1982, Vice President, Environmental
and Safety in 1994 and Senior Vice President in 1996. He was elected to his
present position at Ameren Services on December 31, 1997. Other directorships:
AmerenUE since 1998; AmerenCIPS since 1997. Age: 54.
Donald E. Brandt, Director. Mr. Brandt is also Senior Vice President--
Finance of Ameren Corporation and Senior Vice President--Finance and Corporate
Services of AmerenUE and Ameren Services. Mr. Brandt worked for Price Waterhouse
(now PricewaterhouseCoopers LLP) from 1975 until his appointment as Controller
of AmerenUE in 1983. He was elected to his present positions at Ameren
Corporation and Ameren Services on December 31, 1997. Other directorships:
AmerenUE since 1998; AmerenCIPS since 1997; Huntco Inc.; Mercantile Mutual
Funds, Inc. Age: 46.
Daniel F. Cole, Director. Mr. Cole is also a Senior Vice President of
AmerenUE and Ameren Services. AmerenUE employed Mr. Cole in 1976 as an engineer.
He was named AmerenUE's Manager--Resource Planning in 1996 and General Manager--
Corporate Planning in 1997. In 1998, Mr. Cole was elected as Vice President of
Corporate Planning of Ameren Services. Mr. Cole was elected to his present
positions at AmerenUE and Ameren Services in 1999. Age: 47.
Gary L. Rainwater, President and Director. In addition, Mr. Rainwater was
elected Executive Vice President of AmerenCIPS in January 1997 and was named
President and Chief Executive Officer of AmerenCIPS in December 1997. Before
joining AmerenCIPS he worked for AmerenUE for 17 years, beginning his career in
1979 as an engineer. He was named General Manager--Corporate Planning in 1988
and Vice President in 1993. Other directorships: AmerenUE since 1998; AmerenCIPS
since 1997. Age: 54.
R. Alan Kelley, Senior Vice President--Operations. Mr. Kelley had also
been the President of Electric Energy, Inc. (a power generation affiliate, 60%
effectively owned by Ameren Corporation) since 1987 and was elected Chairman of
the Board of Electric Energy, Inc. in 2000. He had also been Vice President--
Energy Supply of AmerenUE from 1988 to 1997 and a Vice President of Ameren
Services from 1997 to 2000. Age: 48.
Warner L. Baxter, Vice President and Controller. Mr. Baxter was elected as
an officer of our company in July 2000. Mr. Baxter is also Vice President and
Controller of Ameren Corporation, AmerenUE, AmerenCIPS, and Ameren Services.
Mr. Baxter worked for Price Waterhouse (now PricewaterhouseCoopers LLP) from
1983 until his appointment as Assistant Controller of AmerenUE in 1995. He was
promoted to Controller in 1996 and was elected Vice President and Controller of
Ameren Corporation, AmerenUE, and Ameren Services in 1998. He was elected Vice
President and Controller of AmerenCIPS in 1999. Other directorships: AmerenUE
since 1999; AmerenCIPS since 1999. Age: 39.
65
Michael J. Montana, Vice President--Supply Services. Mr. Montana was
elected as an officer of our company in November 2000. Mr. Montana is also Vice
President--Supply Services of AmerenUE, AmerenCIPS and Ameren Services. He
joined AmerenUE as an engineer in 1971 and had also served as Purchasing
Department Buyer from 1973 to 1976, executive assistant from 1976 to 1984,
manager of Industrial Relations from 1984 to 1988 and Vice President of
Industrial Relations from 1988 to 1995 of AmerenUE. He was elected Vice
President of Ameren Services in 1997 and Vice President of AmerenCIPS in 1998.
Age: 54.
Robert L. Powers, Vice President--Technical Services. Mr. Powers was
elected as an officer of our company in July 2000. Mr. Powers was also elected
Vice President of Electric Energy, Inc. in February 1990 and was elected
President of that company in May 2000. Before joining Electric Energy, Inc., Mr.
Powers was Site Manager for Quality Assurance at AmerenUE's Callaway Nuclear
plant from 1976 to 1985 and Manager of Quality Improvement Process from 1985 to
1989. Mr. Powers began his power plant experience with Bechtel Power Corporation
as a mechanical field engineer at AmerenUE's Labadie plant in 1970. Age: 52.
J.L. Simpson, Vice President--Power Operations. Mr. Simpson had also been
a Vice President of AmerenCIPS until 2000. Mr. Simpson joined AmerenCIPS in
1978 as an engineer at the Newton Station. He held staff positions in
AmerenCIPS' Power Production and Environmental Affairs departments before being
named Assistant Superintendent at the Grand Tower station in 1986. Mr. Simpson
was named Plant Manager at the Grand Tower station in 1991 and Plant Manager at
the Meredosia station in 1994. Age: 45.
Steven R. Sullivan, Vice President, General Counsel and Secretary. Mr.
Sullivan has also been Vice President, General Counsel and Secretary of Ameren
Corporation, AmerenUE, AmerenCIPS, Ameren Services and Ameren Energy since 1998.
Mr. Sullivan was previously employed by Anheuser Busch Companies, Inc. as an
attorney from 1995 to 1998. Age: 41.
Jerre E. Birdsong, Treasurer. Mr. Birdsong has also been Treasurer of
AmerenUE since 1993, Ameren Corporation since 1996, AmerenCIPS and Ameren
Services since 1997, and Ameren Energy since 1998. Age: 46.
Committees of the Board of Directors
Our board of directors does not have standing committees. The board
committees (including the Human Resources Committee) of our parent company,
Ameren Corporation, perform committee functions for our board.
Compensation Committee Interlocks and Insider Participants
We do not have a compensation committee and there is no other committee of
our board of directors that performs similar functions. The Human Resources
Committee of Ameren Corporation considered compensation matters with respect to
our executive officers. Some of our executive officers serve on the boards of
directors of other Ameren companies whose executive officers serve on our board
of directors.
Director Compensation
The members of our board of directors are executive officers of Ameren
Corporation or its subsidiaries, and they do not receive any compensation for
their services as our directors.
Executive Compensation
Our management is provided a competitive total compensation package which
includes benefits comparable to that provided to other Ameren management
employees. As noted in the information above, several of our management
personnel also have duties with other Ameren entities and may spend the majority
of their time at those duties. In general, all of our management employees are
paid through our affiliate Ameren Services. We pay all the direct costs of our
employee compensation and our proportionate share of direct and indirect
compensation expense for those employees who spend a portion of their time
working for other Ameren entities. Allocation methodologies for compensation are
subject to review by the SEC under PUHCA.
66
Compensation Tables
The following tables contain compensation information, for the periods
indicated, for (a) our president and chief executive officer and (b) the four
other most highly compensated executive officers of our company who were serving
as executive officers at the end of 2000.
Summary Compensation Table
Long-Term
Compensation
Annual ------------
Compensation Securities
Name and ------------ Underlying All Other
Principal Position(1) Year(2) Salary($) Bonus($) Options(#) Compensation($)(3)
--------------------- ------- --------- -------- ---------- ------------------
G.L. Rainwater............ 2000 400,000 115,200 32,600 9,450
President
W.L. Baxter............... 2000 220,000 47,000 14,100 4,634
Vice President and
Controller
S.R. Sullivan............. 2000 220,000 44,600 14,100 4,888
Vice President, General
Counsel and Secretary
R.A. Kelley............... 2000 195,000 54,000 14,100 8,075
Senior Vice President -
Operations
J.E. Birdsong............. 2000 185,000 39,500 14,100 9,683
Treasurer
_________________________________
(1) Includes compensation received as an officer of Ameren Corporation and its
subsidiaries during 2000.
(2) Our company began doing business in May 2000.
(3) Amounts include (a) matching contributions to the 401(k) plan and (b)
above-market earnings on deferred compensation, as follows:
(a) (b)
--- ---
G.L. Rainwater $5,100 $4,350
W.L. Baxter 2,599 2,035
S.R. Sullivan 3,133 1,755
R.A. Kelley 5,932 2,143
J.E. Birdsong 7,492 2,191
67
Option Grants in 2000
Number of % of Total
Shares Options
Underlying Granted to Exercise Grant Date
Options Employees Price Expiration Present Value
Name Granted(1) in 2000 ($/Sh) Date ($)(2)
---- ---------- ------- ----- ----- ------
G.L. Rainwater............. 32,600 3.41 31.00 2/11/10 135,290
W.L. Baxter................ 14,100 1.47 31.00 2/11/10 58,515
S.R. Sullivan.............. 14,100 1.47 31.00 2/11/10 58,515
R.A. Kelley................ 14,100 1.47 31.00 2/11/10 58,515
J.E. Birdsong.............. 14,100 1.47 31.00 2/11/10 58,515
_____________________________
(1) Options relate to Ameren Corporation common stock and vest 25% annually
beginning February 11, 2002. The options are not transferable.
(2) The figures in the column entitled "Grant Date Present Value" were
determined using the binomial option pricing model, a derivative of the
Black-Scholes option pricing model. Assumptions used for the model are as
follows: an option term of ten years, stock volatility of 17.39%, a
dividend yield of 6.61%, risk-free interest rate of 6.81% and a vesting
restrictions discount rate of 3% per year over the five-year vesting
period. The calculation of figures in the column entitled "Grant Date
Present Value" is presented in accordance with SEC proxy requirements, and
we have no way to determine whether the pricing model can properly or
accurately determine the value of an option. There is no assurance that the
value, if any, that may be realized will be at or near the value estimated
by the model. No value will be realized by the optionee unless the stock
price increases from the exercise price, in which case shareholders would
benefit commensurately.
68
Aggregated Option Exercises in 2000
and Year-End Values
Value of
Shares Value Unexercised In-the-Money
Acquired on Realized Options at Year End(#) Options at Year End($)(1)
---------------------- -------------------------
Name Exercise(#) $ Exercisable Unexercisable Exercisable Unexercisable
---- ----------- ------ ----------- ------------- ----------- -------------
G.L. Rainwater............ -- -- 6,450 79,850 45,553 906,128
W.L. Baxter............... -- -- 6,800 34,400 45,269 386,294
S.R. Sullivan............. -- -- 1,325 28,775 8,613 345,400
R.A. Kelley............... -- -- 8,100 34,400 58,538 386,294
J.E. Birdsong............. 1,875 6,152 5,175 34,400 41,367 386,294
__________
(1) These columns represent the excess of the closing price of Ameren
Corporation's common stock of $46.3125 per share, as of December 29, 2000,
above the exercise price of the options. The amounts under the column
entitled "Exercisable" report the "value" of options that are vested and
therefore could be exercised. The column entitled "Unexercisable" reports
the "value" of options that are not vested and therefore could not be
exercised as of December 31, 2000.
Ameren Retirement Plan
Most salaried employees of Ameren earn benefits under the Ameren Retirement
Plan immediately upon employment. Benefits generally become vested after five
years of service. On an annual basis a bookkeeping account in a participant's
name is credited with an amount equal to a percentage of the participant's
pensionable earnings for the year. Pensionable earnings equals base pay,
overtime and annual bonuses, which are equivalent to amounts shown as "Annual
Compensation" in the Summary Compensation Table. The applicable percentage is
based on the participant's age as of December 31 of that year. If the
participant was an employee prior to July 1, 1998, an additional transition
credit percentage is credited to the participant's account through 2007 (or an
earlier date if the participant had less than 10 years of service on December
31, 1998).
Regular Credit for Transition Credit
Participant's Age on Pensionable Pensionable Total
December 31 Earnings/*/ Earnings Credits
----------- ----------- -------- -------
Less than 30 3% 1% 4%
30 to 34 4% 1% 5%
35 to 39 4% 2% 6%
40 to 44 5% 3% 8%
45 to 49 6% 4.5% 10.5%
50 to 54 7% 4% 11%
55 and over 8% 3% 11%
* An additional regular credit of 3% is received for pensionable earnings
above the Social Security wage base.
69
These accounts also receive interest credits based on the average yield for
one-year U.S. Treasury Bills for the previous October, plus 1%. In addition,
some annuity benefits earned by participants under prior plans as of December
31, 1997 were converted to additional credit balances under the retirement plan
as of January 1, 1998. When a participant terminates employment, the amount
credited to the participant's account is converted to an annuity or paid to the
participant in a lump sum. The participant can also choose to defer
distribution, in which case the account balance is credited with interest at the
applicable rate until the future date of distribution. Benefits are not subject
to any deduction for Social Security or other offset amounts.
In some cases pension benefits under the retirement plan are reduced to
comply with maximum limitations imposed by the Internal Revenue Code. A
supplemental retirement plan is maintained by Ameren to provide for a
supplemental benefit equal to the difference between the benefit that would have
been paid if Internal Revenue Code limitations were not in effect and the
reduced benefit payable as a result of those Internal Revenue Code limitations.
The plan is unfunded and is not a qualified plan under the Internal Revenue
Code.
The following table shows the estimated annual retirement benefits,
including supplemental benefits, which would be payable to each executive
officer listed if he were to retire at age 65 at his 2000 base salary and annual
bonus, and payments were made in the form of a single life annuity.
Name Year of 65/th/ Birthday Estimated Annual Benefit
---- ----------------------- ------------------------
G.L. Rainwater.................... 2011 $192,000
W.L. Baxter....................... 2026 160,000
S.R. Sullivan..................... 2025 168,000
R.A. Kelley....................... 2017 147,000
J.E. Birdsong..................... 2019 137,000
Change of Control Severance Plan
Under the Ameren Corporation Change of Control Severance Plan, designated
officers of Ameren, including current officers of our company named in the
Summary Compensation Table, are entitled to receive severance benefits if their
employment is terminated under specified circumstances within three years after
a "change of control." A "change of control" occurs, in general, if:
. any individual, entity or group acquires 20% or more of the
outstanding common stock of Ameren Corporation or of the combined
voting power of the outstanding voting securities of Ameren
Corporation;
. individuals who, as of the effective date of the severance plan,
constitute the board of directors of Ameren Corporation, or who have
been approved by a majority of the board, cease for any reason to
constitute a majority of the board; or
. Ameren Corporation enters into specified business combinations, unless
some requirements are met regarding continuing ownership of the
outstanding common stock and voting securities of Ameren Corporation
and the membership of its board of directors.
Severance benefits are based upon a severance period of two or three years,
depending on the officer's position. An officer entitled to severance will
receive the following:
. salary and unpaid vacation pay through the date of termination;
. a pro rata bonus for the year of termination, and base salary and
bonus for the severance period;
70
. continued employee welfare benefits for the severance period;
. a cash payment equal to the actuarial value of the additional benefits
the officer would have received under Ameren's qualified and
supplemental retirement plans if employed for the severance period;
. up to $30,000 for the cost of outplacement services; and
. reimbursement for any excise tax imposed on those benefits as excess
payments under the Internal Revenue Code.
Principal Stockholders
Development Co. owns 1,000 shares of our common stock, which constitute all
of our outstanding capital stock. Resources owns all of the outstanding shares
of capital stock of Development Co. and Ameren Corporation owns all of the
outstanding shares of capital stock of Resources. The ownership interests of
our directors and executive officers in Ameren Corporation common stock are set
forth below.
Securities of Ameren Corporation
Amount and Nature of
Beneficial Ownership(1)(2)
Name of Holder as of February 1, 2001
-------------- ----------------------
Paul A. Agathen 32,980
Donald E. Brandt 33,222
Daniel F. Cole 7,692
Gary L. Rainwater 19,457
R. Alan Kelly 14,800
Warner L. Baxter 11,124
Steven R. Sullivan 4,286
Jerre E. Birdsong 11,160
All directors and executive officers as a group 147,445
(1) Includes shares held jointly. Also includes shares issuable
within 60 days upon the exercise of stock options as follows:
Mr. Agathen, 28,175; Mr. Brandt, 31,675; Mr. Cole, 5,146; Mr.
Rainwater, 13,425; Mr. Kelley, 12,250; Mr. Baxter, 10,950; Mr.
Sullivan, 4,000; and Mr. Birdsong, 9,325. Reported shares
include those for which a director or executive officer has
voting or investment power because of joint or fiduciary
ownership of the shares or a relationship with the record
owner, most commonly a spouse, even if that director or
executive officer does not claim beneficial ownership.
(2) Shares beneficially owned by all directors and executive
officers in the aggregate do not exceed one percent of any
class of equity securities outstanding.
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AFFILIATE RELATIONSHIPS AND TRANSACTIONS
We have important relationships with and have entered into a number of
agreements with related parties.
Power Supply
Our power is sold through our affiliates Marketing Co. and Ameren Energy.
All future marketing efforts relating to our capacity will be conducted by those
companies. Under the amended joint dispatch agreement, we are required to
coordinate our scheduling and dispatch efforts with AmerenUE.
Intercompany Loans and Payments
We purchased our coal plants from our affiliate AmerenCIPS in exchange for
our issuance of a subordinated promissory note in the amount of $552 million.
This note is subordinated to our obligations on our senior debt, including the
old notes and the new notes we are offering in exchange for the old notes.
We have entered into an agreement with Resources under which, in the event
that upon maturity, the AmerenCIPS subordinated note has not been paid in full
or refinanced with other subordinated intercompany indebtedness with
substantially similar terms of subordination, then Resources will assume our
obligations under the AmerenCIPS subordinated note (subject to any required
regulatory approval), with no further liability to us, or contribute sufficient
funds to us as equity or subordinated debt to enable us to pay in full the
remaining balance of the AmerenCIPS subordinated note.
During 2001, we expect to assume, subject to regulatory approval, the
obligations of AmerenCIPS with respect to $104 million of outstanding tax-exempt
pollution control loan obligations in exchange for a reduction in a similar
amount due on the AmerenCIPS subordinated note.
We borrowed $50 million from Ameren Corporation for working capital
purposes and issued to Ameren Corporation a subordinated promissory note in the
same amount. This note is subordinated to our obligations on our senior debt,
including the old notes and the new notes we are offering in exchange for the
old notes, as well as the subordinated note we issued to AmerenCIPS.
We have incurred intercompany borrowings to meet our capital and operating
needs and expect to continue to do so.
We have entered into an agreement with Resources and Development Co. in
which, under specified conditions, we will prefund a portion of the acquisition
cost of the committed units.
AmerenCIPS has agreed in connection with the transfer of the coal plants to
us to indemnify us for environmental claims relating to those units for events
or occurrences arising prior to May 1, 2000.
Intercompany Services
Our executive management and many administrative services are provided by
Ameren Services. We pay Ameren Services the cost of providing these services
including an allocation of common costs for services shared with other
affiliates of Ameren Corporation. Ameren Services bills us for the cost of the
services provided subject to allocation methods approved by the SEC under PUHCA.
We are currently relying on our affiliates Resources and Development Co. to
engage in the development and construction of our new generation capacity.
We are relying on our affiliate, Fuels Co., to manage our coal, natural gas
and fuel oil purchases.
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Tax Matters
We and the other Ameren companies have entered into a tax allocation
agreement that has established a method by which the federal and state income
tax liabilities and benefits of the Ameren companies, which file consolidated
federal income tax returns, are allocated in a fair and equitable manner and in
compliance with applicable regulations. In general, we are required to pay
income taxes in an amount not less than what we would pay if our income tax were
calculated on a separate return basis.
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DESCRIPTION OF THE NEW NOTES
General
The new notes will be issued under an indenture dated as of November 1,
2000 between us and The Bank of New York, as trustee, and a series supplemental
indenture. The aggregate principal amount of bonds, debentures, promissory notes
or other evidences of indebtedness that may be issued under the indenture is
unlimited. Subject to the terms of the indenture, we may issue additional notes
under the indenture in the future at our discretion. Issuances of individual
series of notes, including this exchange offering, will be governed by the
indenture and the corresponding series supplemental indenture. The following
summaries of provisions of the new notes and the indenture do not purport to be
complete and are subject, and qualified in their entirety by reference, to all
of the provisions of the new notes and the indenture, including the definitions
of various terms therein. The definitions of capitalized terms used in the
following summary are set forth below under "Definitions."
The new notes will not be guaranteed by, or otherwise be obligations of,
Ameren Corporation or any of its direct or indirect subsidiaries other than our
company.
Principal, Maturity and Interest
The old notes were issued in two series, Series A Notes ($225 million) and
Series B Notes ($200 million). We will offer the new notes in two series, which
will be identical in all material respects to the old notes, except that the
registration rights and related liquidated damages provisions and transfer
restrictions applicable to the old notes are not applicable to the new notes.
The new notes will consist of the 7.75% Senior Notes, Series C due 2005 ($225
million), or the Series C Notes, which will mature on November 1, 2005, and the
8.35% Senior Notes, Series D due 2010 ($200 million), or the Series D Notes,
which will mature on November 1, 2010. To the extent any old notes are not
exchanged for new notes, those old notes will remain outstanding under the
indenture and will rank pari passu with the new notes and any other securities
issued under the indenture.
Interest will be payable on the new notes semi-annually each May 1 and
November 1. Interest on the new notes will accrue from the last date through
which interest was paid on the old notes (expected to be May 1, 2001) or, if no
interest has been paid, from the date of issuance of the old notes. Interest
will first be paid on the new notes on the first May 1 or November 1 following
the date the exchange offer is completed (expected to be November 1, 2001) until
the principal is paid or made available for payment. No interest will be paid
in connection with the exchange. Interest will be computed on the basis of a
360-day year comprised of twelve 30-day months.
Payment of principal of the new notes will be made against surrender of
those notes at the office or agency of our company in St. Louis, Missouri.
Payment of interest on the new notes will be made to the person in whose name
the new notes are registered at the close of business on the April 15 or October
15 immediately preceding the relevant interest payment date. For so long as the
new notes are issued in book-entry form, payments of principal and interest
shall be made in immediately available funds by wire transfer to DTC or its
nominee. If the new notes are issued in certificated form to a Holder (as
defined below) other than DTC, payments of principal and interest shall be made
by check mailed to that Holder at its registered address or, upon written
application by a Holder of $1,000,000 or more in aggregate principal amount of
Series C Notes or Series D Notes to the trustee in accordance with the terms of
the indenture, by wire transfer of immediately available funds to an account
maintained by that Holder with a bank or other financial institution. Default
interest will be paid in the same manner to Holders as of a special record date
established in accordance with the indenture.
All amounts paid by us for the payment of principal, premium (if any) or
interest on any new notes that remain unclaimed at the end of two years after
payment has become due and payable will be repaid to us and the Holders of those
new notes will thereafter look only to us for payment thereof.
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Optional Redemption with Make-Whole Premium
At any time and at our option, we may redeem the new notes, in whole or in
part (if in part, by lot or by another method as the trustee shall deem fair or
appropriate) at the redemption price of 100% of principal amount of those new
notes, plus accrued interest on the principal amount of those new notes, if any,
to the redemption date, plus the Make-Whole Premium.
Notice of redemption to the Holders of new notes to be redeemed will be
given by us by mailing notice of redemption by first class mail at least 30 days
and not more than 60 days prior to the date fixed for redemption to the Holders
of new notes at their last addresses as they shall appear in the securities
register. Failure to give notice by mail, or any defect in the notice to the
Holder of any new note designated for redemption as a whole or in part will not
affect the validity of the proceedings for the redemption of any other new note.
The notice of redemption to each Holder will specify that the new notes are
being redeemed pursuant to the indenture, the date fixed for redemption, the
place or places of payment, the CUSIP and ISIN numbers (as applicable), that
payment will be made upon presentation and surrender of the new notes, that
interest accrued to the date fixed for redemption will be paid as specified in
the indenture and that, on and after said date interest thereon or on the
portions thereof to be redeemed will cease to accrue.
Reporting Obligations; Information to Holders
We will furnish to the trustee:
(i) unless we are then filing comparable reports pursuant to the
reporting requirements of the Exchange Act, as soon as practicable and in any
event within 45 days after the end of the first, second and third quarterly
accounting periods of each fiscal year (commencing with the quarter ending
September 30, 2000), our unaudited consolidated balance sheet as of the last day
of that quarterly period and the related consolidated statements of income and
cash flows during that quarterly period prepared in accordance with GAAP and (in
the case of second and third quarterly periods) for the portion of the fiscal
year ending with the last day of that quarterly period, setting forth in each
case in comparative form corresponding unaudited figures from the preceding
fiscal year (except in the case where the preceding fiscal year includes periods
prior to our formation) and accompanied by (A) a written statement of our
authorized representative to the effect that those financial statements fairly
represent our financial condition and results of operations at and as of their
respective dates, (B) a section substantially similar to the "Management's
Discussion and Analysis," or MD&A, section of an SEC Form 10-Q (without any
comparison to periods prior to our formation), and (C) a calculation of the
Senior Debt Service Coverage Ratio for the prior four quarterly periods (or the
number of complete quarterly periods since July 1, 2000);
(ii) unless we are then filing comparable reports pursuant to the
reporting requirements of the Exchange Act, as soon as practicable and in any
event within 90 days after the end of each fiscal year (commencing with the
fiscal year ending December 31, 2000), our consolidated balance sheet as of the
end of that year and the related consolidated statements of income, cash flow,
and retained earnings during that year setting forth in each case in comparative
form corresponding figures from the preceding fiscal year (except in the case
where the preceding fiscal year includes periods prior to our formation),
accompanied by (A) an audit report thereon of a firm of independent public
accountants of recognized national standing, (B) a section substantially similar
to the MD&A section of an SEC Form 10-K (without any comparison to periods prior
to our formation), and (C) a calculation of the Senior Debt Service Coverage
Ratio for the prior four quarterly periods (or the number of complete quarterly
periods since July 1, 2000);
(iii) at the time of the delivery of the report provided for in clause
(ii) above (or at the time of the filing of the comparable report pursuant to
the Exchange Act), an officer's certificate to the effect that, to the best of
the officer's knowledge, no default or event of default under the notes of any
series or the indenture has occurred and is continuing or, if any default or
event of default thereunder has occurred and is continuing, specifying the
nature and extent thereof and what action we are taking or propose to take in
response thereto; and
(iv) promptly after we obtain actual knowledge of the occurrence thereof,
written notice of the occurrence of any event or condition which constitutes an
event of default, and an officer's certificate of our
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company specifically stating that the event of default has occurred and setting
forth the details thereof and the action which we are taking or propose to take
with respect thereto.
The calculation required by (i)(C) and (ii)(C) shall be furnished to the
trustee within the time period provided therefor unless we are including that
information in reports filed pursuant to the reporting requirements of the
Exchange Act.
All information provided to the trustee as indicated above also will be
provided by the trustee upon written request to the trustee (which may be a
single continuing request), to (x) Holders, (y) holders of beneficial interests
in the new notes or (z) prospective purchasers of the new notes or beneficial
interests in the new notes. We will furnish to the trustee, upon its request,
sufficient copies of all of this information to accommodate the requests of
holders and prospective holders of beneficial interests in the new notes.
Upon the request of any Holder, any holder of a beneficial interest in the
new notes, or the trustee (on behalf of a Holder or a holder of a beneficial
interest in the new notes), we will furnish the information specified in
paragraph (d)(4) of Rule 144A to Holders (and to holders of beneficial interests
in the new notes), prospective purchasers of the new notes (and of beneficial
interests in the new notes) who are qualified institutional buyers or
institutional accredited investors or to the trustee for delivery to the Holder
or prospective purchasers of the new notes or beneficial interests therein, as
the case may be, unless, at the time of the request, we are subject to the
reporting requirements of Section 13 or 15(d) of the Exchange Act.
If we cease to maintain our status as a reporting company under the
Exchange Act, whether or not the SEC rules and regulations require us to
maintain that status (unless the SEC will not accept the filing of the
applicable reports), the registration rights agreement that we entered into
requires us to pay the Holders of outstanding new notes additional interest at a
rate of 0.5% per annum until that default has been cured, at which time any
increase in the interest rate described in this paragraph will cease to be
effective.
Covenants
Mergers and Consolidations
We will not consolidate with or merge with or into any other person, or
sell, convey, transfer or lease our properties and assets substantially as an
entirety to any person, and we will not permit any person to consolidate with or
merge with or into us, unless: (i) immediately prior to and immediately
following the consolidation, merger, sale or lease, no Event of Default under
the indenture shall have occurred and be continuing, and (ii) we are the
surviving or continuing corporation, or the surviving or continuing corporation
or corporation that acquires by sale, conveyance, transfer or lease is
incorporated in the United States and expressly assumes the payment and
performance of all of our obligations under the indenture and the new notes.
Limitation on Asset Sales
Except for the sale of our properties and assets substantially as an
entirety as described in "--Mergers and Consolidations" above, and other than
assets required to be sold to conform with governmental regulations, we will
not, and will not permit any of our Subsidiaries to, consummate any Asset Sale,
if the aggregate net book value of all Asset Sales consummated since the date of
issuance of the old notes would exceed 25% of our Consolidated Tangible Assets
as of the beginning of our most recently ended full fiscal quarter; provided,
however, that any Asset Sale will be disregarded for purposes of the 25%
limitation specified above if the proceeds of that sale (i) are, within 12
months of the Asset Sale, invested or reinvested by us or any Subsidiary in a
Permitted Business, (ii) are used by us or a Subsidiary to repay Indebtedness of
our company or that Subsidiary, or (iii) are retained by us or our Subsidiaries.
Additionally, if after giving effect to any Asset Sale that otherwise would
cause the 25% limitation to be exceeded, each Rating Agency then rating the
notes confirms the then current rating of the new notes, the portion of the
Asset Sale in excess of the 25% limitation will also be disregarded for purposes
of the foregoing limitations.
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Limitation on Liens
We shall not, and shall not permit any of our Subsidiaries to, issue,
assume, guarantee or permit to exist any Indebtedness secured by any lien on any
property of our company or our Subsidiaries, whether owned on the date that the
old notes were issued or acquired after that date, without effectively securing
the outstanding new notes (together with, if we shall so determine, any other
Indebtedness of or guaranteed by our company ranking equally with the new notes)
equally and ratably with that Indebtedness (but only so long as that
Indebtedness is so secured); provided, however, that the foregoing restriction
shall not apply to the following liens: (i) pledges or deposits in the ordinary
course of business in connection with bids, tenders, contracts or statutory
obligations or to secure surety or performance bonds, (ii) liens imposed by law,
such as carriers', warehousemen's and mechanics' liens, arising in the ordinary
course of business, (iii) liens for property taxes being contested in good
faith, (iv) minor encumbrances, easements or reservations which do not in the
aggregate materially adversely affect the value of the properties or impair
their use, (v) liens on any property existing at the time of acquisition of that
property (which liens may also extend to subsequent repairs, alterations and
improvements to that property), (vi) liens to secure purchase money Indebtedness
not in excess of the cost or value of the property acquired, (vii) liens, if
any, in existence on the date that the old notes were issued, (viii) other liens
to secure Indebtedness so long as the amount of outstanding Indebtedness secured
by liens pursuant to this provision does not exceed 10% of our Consolidated
Tangible Assets, and (ix) liens granted in connection with extending, renewing,
replacing or refinancing any of the Indebtedness (so long as there is no
increase in the principal amount of the Indebtedness), described in the
foregoing clauses (v) through (viii) above.
In the event that we shall propose to pledge, mortgage or hypothecate any
property, other than as permitted by clauses (i) through (ix) of the previous
paragraph, we shall (prior to pledging, mortgaging or hypothecating that
property) give written notice of our proposal to do so to the trustee, who shall
give notice to the Holders, and we shall, prior to or simultaneously with that
pledge, mortgage or hypothecation, effectively secure all the new notes equally
and ratably with that Indebtedness.
Limitations on Subsidiary Indebtedness
We shall not permit any Subsidiary which may acquire any Initial Generating
Assets to create or incur or suffer to exist any Indebtedness for borrowed
money.
Transitional Covenants
Restricted Payments
We shall not make any Restricted Payment unless on a Pro Forma Basis at the
time the Restricted Payment is to be made, (a) the Senior Debt Service Coverage
Ratio shall equal at least 1.75 to 1.0 for the most recently ended four full
fiscal quarters, or the shorter period commencing on July 1, 2000 and ending on
the last day of the most recent fiscal quarter for which financial statements
have been delivered to the trustee and (b) based on projections prepared by us
on a reasonable basis, the projected Senior Debt Service Coverage Ratio for each
of the succeeding four six-month periods (commencing with the month in which the
Restricted Payment is to be made) or, with respect to any date within the 24-
month period prior to the final maturity date for the new notes, the number of
complete six-month periods, if any, until the final maturity date for the new
notes, in each case measured as individual six-month periods, is projected to be
greater than or equal to 1.75 to 1; provided, however, that for any period in
respect of which the projected Senior Debt Service Coverage Ratio is calculated
pursuant to this clause (b) for which two-thirds or more of revenues are derived
directly or indirectly from contracts with AmerenCIPS, AmerenUE or non-
affiliated third parties and which have a then remaining term of two years or
more, that ratio shall be greater than or equal to 1.50 to 1.0.
Debt Incurrence Test
We shall not incur any Indebtedness for borrowed money other than Permitted
Indebtedness unless on a Pro Forma Basis for the debt incurrence and any related
transactions either (i)(a) the Senior Debt Service Coverage
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Ratio shall equal at least 2.5 to 1.0 for the most recently ended four full
fiscal quarters, or the shorter period commencing on July 1, 2000 and ending on
the last day of the most recent fiscal quarter for which financial statements
have been delivered to the trustee and (b) our Senior Debt to Capital Ratio
shall not exceed 0.6 to 1.0 or (ii) each Rating Agency then rating the new notes
provides a Ratings Reaffirmation of the then existing rating of those new notes
after giving effect to that additional Indebtedness.
Termination of Transitional Covenants
At any time following the date on which financial statements for five full
years of our operations are available, we may cease to comply with the covenants
above regarding Restricted Payments and the Debt Incurrence Test if each of
Moody's, S&P and Fitch, to the extent those rating agencies are then rating the
outstanding new notes of each series, provides a Ratings Reaffirmation of at
least the original rating of the old notes which were exchanged for those new
notes after giving effect to that fact, in which case from and after the date of
the reaffirmation those covenants shall be deemed to be of no further force and
effect.
Definitions
"Asset Sale" means any sale, lease (except for the lease of the Joppa 7B
generating stations so long as our company or a Subsidiary remains the lessor),
sale-leaseback, transfer, conveyance or other disposition of any assets
including by way of the issue by us or any of our Subsidiaries of equity
interests in those Subsidiaries, except (a) in the ordinary course of business
to the extent that that property is (i) worn out or is no longer useful or
necessary in connection with the operation of our business or sale inventory or
(ii) being transferred to a wholly-owned Subsidiary of our company or (b) if,
prior to that conveyance or disposition, each Rating Agency provides a Ratings
Reaffirmation of the then existing rating of the new notes after giving effect
to that Asset Sale.
"Available Cash" means, for a given period, all funds of our company
remaining after payment of all operating and maintenance expenditures, Senior
Debt Service, capital expenditures, taxes and reasonable reserves for working
capital and other corporate purposes determined by us in our discretion, in each
case, for that period.
"Cash Flow Available for Senior Debt" for any period means, without
duplication, (i) EBITDA of our company and our consolidated Subsidiaries for
that period, minus (ii) EBITDA for that period of the consolidated Subsidiaries,
if any, of our company that are financed with Indebtedness that does not
constitute Indebtedness of our company, plus (iii) distributions received by our
company from Subsidiaries described in the foregoing clause (ii) during that
period, minus (iv) distributions described in the foregoing clause (iii) that
are attributable to extraordinary gains or other non-recurring items included in
EBITDA, minus (v) any income reported by our company for that period for persons
that are not consolidated Subsidiaries of our company that are financed with
Indebtedness that does not constitute Indebtedness of our company, plus (vi)
distributions received by our company from persons described in the foregoing
clause (v) during that period, minus (vii) distributions described in the
foregoing clause (vi) that are attributable to extraordinary gains or other non-
recurring items included in EBITDA.
"Committed Unit Contribution Agreement" means the Committed Unit
Contribution Agreement, between us and Resources (on behalf of itself and
Development Co.), in respect of the committed units.
"Consolidated Tangible Assets" means, (at any date of determination) the
total assets of our company and our Subsidiaries determined in accordance with
GAAP, excluding, however, from the determination of total assets (a) goodwill,
organizational expenses, research and product development expenses, trademarks,
trade names, copyrights, patents, patent applications, licenses and rights in
any thereof, and other similar intangibles, (b) all deferred charges or
unamortized debt discount and expenses, (c) all reserves carried and not
deducted from assets, (d) securities which are not readily marketable, (e) cash
held in sinking or other analogous funds established for the purpose of
redemption, retirement or prepayment of capital stock or other equity interests
or debt, (f) any write-up in the book value of any assets resulting from a
revaluation thereof subsequent to June 30, 2000, and (g) any items not included
in clauses (a) through (f) above which are treated as intangibles in conformity
with GAAP, plus the aggregate net book value of all asset sales or dispositions
made by our company and any of our Subsidiaries since the original issue date of
the old notes to the extent that the proceeds thereof or other consideration
received therefor are not invested or reinvested in a Permitted Business, or are
not retained by us or our Subsidiaries.
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"EBITDA" means, with respect to any person for any period, the (i) income
(or loss) before interest and taxes of that person, plus (ii) to the extent
deducted in determining the income (or loss), depreciation, amortization and
other similar non-cash charges and reserves, minus (iii) to the extent
recognized in determining the income (or loss), extraordinary gains (or losses),
restructuring charges or other non-recurring items, plus (iv) to the extent
deducted in determining the income (or loss), lease obligations of the type
referred to in clause (v) of the definition of Indebtedness.
"GAAP" means U.S. generally accepted accounting principles.
"Holder" means a registered holder of a new note.
"Indebtedness" of any person means (i) all indebtedness of that person for
borrowed money, (ii) all obligations of that person evidenced by bonds,
debentures, notes or other similar instruments, (iii) all obligations of that
person to pay the deferred purchase price of property or services, (iv) all
indebtedness created or arising under any conditional sale or other title
retention agreement with respect to property acquired by that 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 the property), (v)
all capital lease obligations of that person (excluding leases of property in
the ordinary course of business), (vi) all obligations, contingent or otherwise,
of that person under acceptance, letter of credit or similar facilities other
than commercial leases, (vii) all unconditional obligations of that person to
purchase, redeem, retire, defease or otherwise acquire for value any capital
stock or other equity interests of that person or any warrants, rights, or
options to acquire the capital stock or other equity interests, (viii) all
Indebtedness of any other person of the type referred to in clauses (i) through
(vii) guaranteed by that person or for which that person shall otherwise
(including pursuant to any keepwell, makewell or similar arrangement) become
directly or indirectly liable, and (ix) all Indebtedness of the type referred to
in clauses (i) through (vii) above secured by (or for which the holder of the
Indebtedness has an existing right, contingent or otherwise, to be secured by)
any lien or security interest on property.
"Initial Generating Assets" means the coal plants, operating combustion
turbine units and committed units.
"Make-Whole Premium" means, with respect to the new notes of Series C and
Series D, a computation as of a date not more than five days prior to the
redemption date of the following:
(i) the average life of the remaining scheduled payments of principal in
respect of outstanding new notes of that series (the "Remaining Average Life")
as of the redemption date;
(ii) the yield to maturity for the United States treasury security having
an average life equal to the Remaining Average Life of that series and trading
in the secondary market at the price closest to the principal amount thereof
(the "Primary Issue") (subject to extrapolation if no United States treasury
security has an average life equal to the Remaining Average Life of that
series); and
(iii) the discounted present value of the then-remaining scheduled
payments of principal and interest (but excluding that portion of any scheduled
payment of interest that is actually due and paid on the redemption date) in
respect of outstanding new notes of that series as of the redemption date using
a discount factor equal to the sum of (x) the yield to maturity for the Primary
Issue, plus (y) 25 basis points.
The amount of Make-Whole Premium in respect of new notes of the series to
be redeemed shall be an amount equal to (x) the discounted present value of the
new notes to be redeemed determined in accordance with clause (iii) above, minus
(y) the unpaid principal amount of the new notes; provided, however, that the
Make-Whole Premium shall not be less than zero.
"Non-utility Money Pool Borrowings" means borrowings by us under the Ameren
Corporation non-utility money pool agreement.
"Parent" means with respect to any person, any other person who directly or
indirectly owns greater than 50% of the voting equity interests of that person.
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"Permitted Business" means a business that is the same as or similar to our
business as of the date that the old notes were issued under the indenture, or
any business reasonably related thereto, including advances made by us pursuant
to a valid Committed Unit Contribution Agreement.
"Permitted Indebtedness" means (i) the Subordinated Intercompany Notes,
(ii) Non-utility Money Pool Borrowings, (iii) Subordinated Parent Borrowings and
(iv) tax-exempt pollution control loan obligations not to exceed $104 million in
aggregate principal amount.
"Pro Forma Basis" means, for the purpose of "Transitional Covenants--Debt
Incurrence Test" above and the making of a Restricted Payment described in
clause (iii) of the definition of "Restricted Payments" below, that the
calculation shall give effect to the incurrence of the Indebtedness, the making
of the Restricted Payment, various acquisitions or dispositions of assets in the
relevant period and, in each case, the application of proceeds thereof.
"Rating Agencies" means Standard & Poor's Ratings Services and Moody's
Investors Services, Inc.
"Ratings Reaffirmation" means a reaffirmation by a rating agency of its
original or then current credit ratings (as applicable) of any of the notes
outstanding, giving effect to the transaction giving rise to the request for
reaffirmation.
"Restricted Payments" means, collectively, (i) distributions including
payments of dividends or redemptions or repurchases of ownership interests in
our company; (ii) payments of principal, interest or premium, if any, on, or
repurchases of, any Subordinated Parent Borrowings or other subordinated
Indebtedness we issue (including to an affiliate) and (iii) investments made by
us or any Subsidiary in any partnership, joint venture or other entity which is
not a Subsidiary. Restricted Payments do not include (A) payments in respect of
the Subordinated CIPS Note, (B) investments in the Ameren Corporation non-
utility money pool, (C) repayments of Non-utility Money Pool Borrowings, and (D)
advances made by us pursuant to the terms of a valid Committed Unit Contribution
Agreement. Restricted Payments also do not include redemptions or repurchases of
our ownership interests or other subordinated Indebtedness with the proceeds
from the substantially concurrent issuance by us of other ownership interests or
subordinated Indebtedness. Each payment of principal on the Subordinated CIPS
Note other than at final maturity is payable solely to the extent of Available
Cash.
"Senior Debt Service" means, with respect to any person for any period, the
sum, without duplication, of (i) the aggregate amount of interest expense with
respect to Indebtedness of that person for the period including (A) the net
costs under interest rate hedge agreements, (B) all capitalized interest, (C)
the interest portion of any deferred payment obligation and (D) payments in the
nature of interest under lease obligations of that person scheduled to be paid
by that person during the period (in each case, exclusive of Indebtedness which
is by its terms subordinated in right of payment to any other Indebtedness of
our company, including, but not limited to, the Subordinated Intercompany Notes
and Subordinated Parent Borrowings), and (ii) the aggregate amount of all
mandatory scheduled payments (whether designated as payments or prepayments) and
sinking fund payments with respect to principal of any Indebtedness of that
person, including payments in the nature of principal under lease obligations,
in each case scheduled to be paid by that person during the period (in each
case, exclusive of Indebtedness which is by its terms subordinated in right of
payment to any other Indebtedness of our company, including, but not limited to,
the Subordinated Intercompany Notes and Subordinated Parent Borrowings).
"Senior Debt Service Coverage Ratio" for any period means, the ratio of (i)
Cash Flow Available for Senior Debt for that period to (ii) Senior Debt Service
for that period.
"Senior Debt to Capital Ratio" means, with respect to any person, the ratio
as of the most recent fiscal quarter for which financial statements have been
delivered to the trustee of (i) the aggregate principal amount of Senior
Indebtedness of that person then outstanding to (ii) Total Capitalization.
"Senior Indebtedness" means, with respect to any person, all Indebtedness
of that person, exclusive of Indebtedness which is by its terms subordinated in
right of payment to any of our other Indebtedness, including, but not limited
to, the Subordinated Intercompany Notes and Subordinated Parent Borrowings.
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"Subordinated Ameren Note" means the subordinated note issued by us to
Ameren Corporation on June 30, 2000 in the amount of $50 million, and, provided
that there is no increase in the principal amount thereof, any refinancing or
extension thereof.
"Subordinated CIPS Note" means the subordinated note issued by us to
AmerenCIPS in the amount of $552 million in connection with our acquisition of
the coal plants and, provided that there is no increase in the principal amount
thereof, any refinancing or extension thereof.
"Subordinated Intercompany Notes" means collectively (i) the Subordinated
Ameren Note and (ii) the Subordinated CIPS Note.
"Subordinated Parent Borrowings" means the Subordinated Ameren Note and any
other borrowings by us from a Parent, provided that the borrowings are
subordinated on terms substantially similar to the terms of subordination set
forth in the indenture.
"Subsidiary" means any corporation or other entity of which sufficient
voting stock or other ownership or economic interests having ordinary voting
power to elect a majority of the board of directors (or equivalent body) are at
the time directly or indirectly held by us.
"Total Capitalization" means, with respect to any person, the sum, without
duplication, of (i) total common stock equity or analogous ownership interests
of that person, (ii) preferred stock and preferred securities of that person,
(iii) additional paid in capital or analogous interests of that person, (iv)
retained earnings of that person and (v) the aggregate principal amount of
Indebtedness (including all intercompany notes) of that person then outstanding.
Events of Default
The following constitute Events of Default under the indenture:
(a) our default in the payment of all or any part of the principal of, or
premium, if any, on, any of the notes issued under the indenture as
and when the same shall become due and payable either at maturity,
upon any redemption, by declaration of acceleration or otherwise; or
(b) our default in the payment of any installment of interest upon any of
the notes issued under the indenture as and when the same shall become
due and payable, and continuance of that default for a period of five
days; or
(c) an event of default, as defined in any of our instruments under which
there may be issued, or by which there may be secured or evidenced,
any Indebtedness of our company that has resulted in the acceleration
of that Indebtedness, or any default occurring in payment of that
Indebtedness at final maturity (and after the expiration of any
applicable grace periods), other than that Indebtedness the principal
of, and interest on which, does not individually, or in the aggregate,
exceed $25,000,000; or
(d) our failure to perform or observe any covenant or agreement (while the
covenant or agreement is effective) with respect to Limitations on
Liens, Limitations on Subsidiary Indebtedness, Restricted Payments,
Debt Incurrence Test, Mergers and Consolidations or Limitation on
Asset Sales and the failure shall continue uncured for more than
thirty (30) days after we have actual knowledge of the failure; or
(e) our failure to perform or observe any of our covenants or agreements
contained in any other provision of the indenture and the failure
shall continue uncured for more than thirty (30) days after we have
actual knowledge of the failure; provided, that if we commence efforts
to cure the default within the thirty (30)-day period and are
diligently attempting to cure the default, we may continue to effect
the cure of the default (and the default shall not be deemed an "Event
of Default" under the indenture) for
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an additional sixty (60) days so long as we certify to the trustee
that no other Event of Default has occurred and is continuing and we
are diligently pursuing the cure; or
(f) one or more final judgments, decrees or orders of any court, tribunal,
arbitrator, administrative or other governmental body or similar
entity for the payment of money shall be rendered against us or any of
our properties in an aggregate amount in excess of $25,000,000
(excluding the amount thereof covered by insurance) and the judgment,
decree or order shall remain unvacated, undischarged and unstayed for
more than 60 consecutive days, except while being contested in good
faith by appropriate proceedings; or
(g) specified events of bankruptcy, insolvency or reorganization involving
our company or a Subsidiary; or
(h) one or more payments aggregating $25 million or more due to us under
the terms of the Genco-Marketing Co. agreement (or any successor long-
term agreement between us and Marketing Co. (or any successor which is
a subsidiary of Ameren Corporation) for the sale of more than 50% of
the capacity and energy of the Initial Generating Assets) are not made
within 60 days of the date they are due; or
(i) the Marketing Co.-CIPS agreement in effect on the date we issued the
old notes is terminated for any reason prior to its scheduled
termination date, unless (A) within 60 days of the termination (or the
longer period as may be needed to secure required regulatory approvals
so long as we are diligently pursuing those approvals), the Marketing
Co.-CIPS agreement is replaced with a power purchase agreement having
a term at least equal to the then remaining term of the Marketing Co.-
CIPS agreement between Marketing Co. and a counterparty with ratings
issued by the Rating Agencies at least equal to the lower of (i) the
ratings then assigned to AmerenCIPS' (or its successor's) senior
unsecured debt, or (ii) the ratings then assigned to the new notes,
and having similar economic terms to Marketing Co., or (B) we provide
to the trustee a Ratings Reaffirmation of the Rating Agencies' then
existing ratings of the outstanding notes; provided, however, no Event
of Default shall be deemed to occur if we enter into a replacement
power purchase agreement directly with AmerenCIPS (or a successor) for
a term at least equal to the remaining term of the Marketing Co.-CIPS
agreement and having similar economic terms to us, in which case the
Event of Default described in this clause (i) shall apply on
corresponding terms to that replacement power purchase agreement; or
(j) at any time that the Marketing Co.-CIPS agreement in effect on the
date we issued the old notes is in effect, the Genco-Marketing Co.
agreement in effect as of that date is terminated for any reason,
unless (A) within 60 days of the termination (or the longer period as
may be needed to secure required regulatory approvals so long as we
are diligently pursuing those approvals), we replace the Genco-
Marketing Co. agreement with a power purchase agreement with Marketing
Co., a successor to Marketing Co. that is a subsidiary of Ameren
Corporation or a non-affiliated power marketing company, for a term at
least equal to the remaining term of the Genco-Marketing Co. agreement
provided that (i) the replacement power purchase agreement has
economic terms to us similar to the Genco-Marketing Co. agreement, and
(ii) any non-affiliated counterparty under that agreement has ratings
assigned to it that meet the requirements of clause (i)(A) above, or
(B) we provide to the trustee a Ratings Reaffirmation of the Rating
Agencies' then existing ratings of the outstanding new notes.
If an Event of Default (other than an Event of Default based on an event of
our bankruptcy, insolvency or reorganization) shall occur and be continuing,
either the trustee or the holders of not less than 25% in aggregate principal
amount of the notes outstanding under the indenture may, by written notice to us
(and to the trustee if given by holders), declare the principal of and accrued
interest on all notes outstanding under the indenture to be immediately due and
payable, but upon some conditions that declaration may be annulled and past
defaults (except, unless theretofore cured, a default in payment of principal,
premium or interest) may be waived by the holders of a majority in aggregate
principal amount of notes then outstanding under the indenture. If an Event of
Default due to our bankruptcy, insolvency or reorganization occurs, all unpaid
principal, premium, if any, and interest in respect of the notes issued under
the indenture will automatically become due and payable without any declaration
or other act on the part of the trustee or any holder. The occurrence of an
event described in paragraph (g) of this section with
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respect to a Subsidiary shall not constitute an Event of Default if (x) the
creditors of that Subsidiary have no recourse to our company or (y) that
Subsidiary is not a "significant subsidiary" as defined in Regulation S-X under
the Securities Act.
The holders of a majority in principal amount of the notes then outstanding
under the indenture shall have the right to direct the time, method and place of
conducting any proceeding for any remedy available to the trustee under the
indenture, subject to the limitations specified in the indenture, provided that
the holders shall have offered to the trustee reasonable indemnity against
expenses and liabilities.
Modification of the Indenture and Supplemental Indentures
With the consent of the holders of not less than a majority in aggregate
principal amount of the notes of all series at the time outstanding considered
as one class, we and the trustee may modify the indenture or any indentures
supplemental thereto or the rights of the Holders of the new notes; provided,
that if there are notes of more than one series outstanding and if a proposed
supplemental indenture directly affects the rights of the holders of one or
more, but less than all, of that series, then the consent only of the holders of
not less than a majority in aggregate principal amount of the outstanding notes
of all series so directly affected, considered as one class, will be required;
provided, further, that no supplemental indenture shall
. change the stated maturity of the principal of, or any installment of
principal of or interest on, any note, or reduce the principal amount
thereof, or reduce the rate or extend the time of payment of interest
thereon, or reduce any amount payable on redemption thereof or impair or
affect the right of any holder to institute suit for the payment
thereof, in each case without the consent of the holder of each note so
affected; or
. without the consent of the holders of all notes then outstanding, reduce
the percentage of notes, the consent of the holders of which is required
for the modification, or the percentage of notes, the consent of the
holders of which is required for any waiver provided for in the
indenture.
We and the trustee without the consent of any holder may amend the
indenture and the new notes for the purpose of curing any ambiguity, or of
curing, correcting or supplementing any defective provision thereof, or in any
manner which we and the trustee may determine is not inconsistent with the
indenture and the new notes and will not adversely affect the interests of any
holder.
Reduction of Subordinated CIPS Note
Under the indenture, we may prepay or otherwise reduce in principal amount,
in whole or in part, the Subordinated CIPS Note under one or more of the
following conditions:
. upon the assumption of the obligations and liabilities of AmerenCIPS
under up to $182 million of tax-exempt pollution control loan
obligations, in which case the Subordinated CIPS Note shall be reduced
by the outstanding principal amount of those pollution control loan
obligations assumed by us;
. upon exchange (and use of proceeds from that exchange) for debt or
equity securities with terms at least as subordinate as the Subordinated
CIPS Note; or
. with the prior written consent of the holders of not less than a
majority in aggregate principal amount of the notes outstanding under
the indenture and the approvals required under the terms of any other
Senior Indebtedness.
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Defeasance and Covenant Defeasance
Defeasance
The indenture provides that we will be deemed to have paid and will be
discharged from any and all obligations in respect of the new notes, on the
123rd day after the deposit referred to below has been made, and the provisions
of the indenture will cease to be applicable with respect to the new notes
(except for, among other matters, obligations to register the transfer of or
exchange of the new notes, to replace apparently mutilated, defaced, destroyed,
lost or stolen notes, to maintain paying agencies and to hold funds for payment
in trust) if
. we have deposited with the trustee, in trust, money and/or U.S.
Government Obligations (as defined in the indenture) that, through the
payment of interest and principal in respect thereof in accordance with
their terms will provide money in an amount sufficient to pay the
principal of, premium, if any, and accrued interest on the new notes, at
the time those payments are due in accordance with the terms of the
indenture,
. we have delivered to the trustee (i) an opinion of counsel to the effect
that Holders will not recognize income, gain or loss for federal income
tax purposes as a result of our exercise of our option under the
defeasance provisions of the indenture and will be subject to federal
income tax on the same amount and in the same manner and at the same
times as would have been the case if that deposit, defeasance and
discharge had not occurred, which opinion of counsel must be based upon
a ruling of the Internal Revenue Service to the same effect or a change
in applicable federal income tax law or related treasury regulations
after the date of the indenture and (ii) an opinion of counsel to the
effect that the defeasance trust does not constitute an "investment
company" within the meaning of the Investment Company Act of 1940, as
amended, and after the passage of 123 days following the deposit, the
trust fund will not be subject to the effect of Section 547 of the U.S.
Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law;
. immediately after giving effect to that deposit, on a Pro Forma basis no
Event of Default, or event that after the giving of notice or lapse of
time or both would become an Event of Default, shall have occurred and
be continuing on the date of the deposit or during the period ending on
the 123rd day after the date of the deposit, and the deposit shall not
result in a breach or violation of, or constitute a default under, any
other agreement or instrument to which we are a party or by which we are
bound; and
. if at that time the new notes are listed on a national securities
exchange, we have delivered to the trustee an opinion of counsel to the
effect that the new notes will not be delisted as a result of the
deposit, defeasance and discharge.
Defeasance of Various Covenants and Various Events of Default
The indenture further provides that the provisions of the indenture will
cease to be applicable with respect to
. the covenants described under "Covenants--Mergers and Consolidations,"
"--Limitation on Asset Sales," "--Limitation on Liens" and "--
Limitations on Subsidiary Indebtedness" and "Transitional Covenants--
Restricted Payments" and "--Debt Incurrence Test;" and
. clause (e) under "Events of Default" with respect to the covenants
listed above and clauses (c) and (f) under "Events of Default" upon the
deposit with the trustee, in trust, of money and/or U.S. Government
Obligations that through the payment of interest and principal in
respect thereof in accordance with their terms will provide money in an
amount sufficient to pay the principal of, premium, if any, and accrued
interest on the new notes, the satisfaction of the conditions described
in clauses (B)(ii), (C) and (D) under "--Defeasance" above and the
delivery by us to the trustee of an opinion of counsel to the
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effect that, among other things, the Holders of the new notes will not
recognize income, gain or loss for federal income tax purposes as a
result of the deposit and defeasance of the specified covenants and
Events of Default and will be subject to federal income tax on the same
amount and in the same manner and at the same times as would have been
the case if the deposit and defeasance had not occurred.
Defeasance and Other Events of Default
If we exercise our option to omit compliance with the covenants and
provisions of the indenture with respect to the new notes as described in the
immediately preceding paragraph and the new notes are declared due and payable
because of the occurrence of an Event of Default that remains applicable, the
amount of money and/or U.S. Government Obligations on deposit with the trustee
will be sufficient to pay amounts due on the new notes, at the time of their
stated maturity, but may not be sufficient to pay amounts due on the new notes
at the time of acceleration resulting from that Event of Default. We shall
remain liable for those payments.
Book-Entry; Delivery and Form
The old notes were issued in the form of four global notes held in book-
entry form, two representing each series of the old notes issued under Rule 144A
and two representing each series of the old notes issued under Regulation S.
DTC will act as the initial securities depositary for the new notes. The new
notes will be issued only as fully registered securities registered in the name
of DTC's nominee. One or more fully registered global note certificates will be
issued, representing in the aggregate the total principal amount of new notes,
and will be deposited with DTC. Except in the limited circumstances described
under "--Certificated Notes" below, beneficial interests in the global notes
will only be recorded by book-entry and owners of beneficial interests in the
global notes will not be entitled to receive physical delivery of certificates
representing the new notes.
The new notes will be issued only in definitive, fully registered form,
without coupons, in denominations of $100,000 and integral multiples of $1,000
in excess thereof. No service charge will be made for any registration of
transfer or exchange of the new notes, but the trustee may require payment of a
sum sufficient to cover any tax or other governmental charge payable in
connection with that transfer or exchange.
Upon the issuance of the global notes representing the new notes, DTC or
its nominee will credit, on its internal system, the respective principal
amounts of the individual beneficial interests represented by those global notes
to the accounts of persons who have accounts with DTC. Ownership of beneficial
interests in a global note will be limited to persons who have accounts with DTC
("participants") or persons who hold interests through participants. Ownership
of beneficial interests in the global notes will be shown on, and the transfer
of that ownership will be effected only through, records maintained by DTC or
its nominee (with respect to interests of participants) and the records of agent
members (with respect to interests of persons other than participants).
Beneficial owners will not receive written confirmation from DTC of their
purchases, but beneficial owners are expected to receive written confirmations
providing details of the transactions, as well as periodic statements of their
holdings, from the direct or indirect participants through which the beneficial
owners purchased new notes.
DTC has no knowledge of the actual beneficial owners of the new notes.
DTC's records reflects only the identity of the direct participants to whose
accounts the new notes are credited, which may or may not be the beneficial
owners. The participants will remain responsible for keeping account of their
holdings on behalf of the customers.
Conveyance of notices and other communications by DTC to direct
participants, by direct participants to indirect participants and by direct
participants and indirect participants to beneficial owners will be governed by
arrangements among them, subject to any statutory or regulatory requirements as
may be in effect from time to time.
So long as DTC or its nominee is the Holder of a global note, DTC or its
nominee, as the case may be, will be considered the Holder of the new notes
represented by that global note for all purposes under the indenture and the new
notes. No beneficial owner of an interest in a global note will be able to
transfer that interest except in accordance with DTC's applicable procedures (in
addition to those under the indenture referred to in this prospectus)
85
unless we shall issue certificates for the new notes in definitive registered
form as described under "--Certificated Notes" below.
Payments of the principal of, and interest and premium, if any, on, the
global notes will be made to DTC or its nominees, as the Holders of the global
notes. Neither we nor the trustee will have any responsibility or liability for
any aspect of the records relating to or payments made on account of beneficial
ownership interests in the global notes or for maintaining, supervising or
reviewing any records relating to beneficial ownership interests.
We expect that DTC or its nominee, upon receipt of any payment of principal
of, and interest or premium, if any, on, a global note held by it or its
nominee, will immediately credit participants' accounts with payments in amounts
proportionate to their respective beneficial interests in the principal amount
of that global note as shown on the records of DTC or its nominee. DTC's
practice is to credit direct participants' accounts on the relevant payment
dated in accordance with their respective holdings shown on DTC's records unless
DTC has reason to believe that it will not receive payments on that payment
date. Payments by participants to beneficial owners will be governed by
standing instructions and customary practices, as is the case with securities
held for the account of customers registered in "street name," and will be the
responsibility of the participant and not of DTC or us, subject to any statutory
or regulatory requirements as may be in effect from time to time. Payment to
DTC is our responsibility, disbursements of those payments to direct
participants is the responsibility of DTC and disbursements of those payments to
the beneficial owners is the responsibility of direct and indirect participants.
We will send redemption notices to DTC. If less than all of the new notes
are being redeemed, DTC will reduce the amount of the interest of each direct
participant in the new notes in accordance with its procedures.
Although voting with respect to the new notes is limited, in those cases
where a vote is required, neither DTC nor its nominee will itself consent or
vote with respect to the new notes. Under its usual procedures, DTC would mail
an omnibus proxy to us as soon as possible after the record date. The omnibus
proxy assigns the consenting or voting rights of DTC's nominee to those direct
participants to whose accounts the new notes are credited on the record date
(identified in a listing attached to the omnibus proxy).
Transfers between participants in DTC will be effected in the ordinary way
in accordance with DTC rules and will be settled in same-day funds. The laws of
some jurisdictions require that some persons take physical delivery of
securities in definitive form. Consequently, the ability to transfer beneficial
interests in a global note to those persons may be limited. Because DTC can only
act on behalf of participants, who in turn act on behalf of indirect
participants and some banks, the ability of a person having a beneficial
interest in a global note to pledge that interest to persons or entities that do
not participate in the DTC system, or otherwise take actions in respect of that
interest, may be affected by the lack of a physical certificate representing
that interest.
DTC has advised us that it will take any action permitted to be taken by a
Holder of new notes (including the presentation of new notes for exchange as
described below) only at the direction of one or more participants to whose
account with DTC interests in the global note are credited, and only in respect
of that portion of the aggregate principal amount of the new notes as to which
the participant or participants has or have given that direction.
DTC has advised us as follows: DTC is a limited purpose trust company
organized under the laws of the State of New York; a member of the Federal
Reserve System; a "clearing corporation" within the meaning of the New York
Uniform Commercial Code; and a "clearing agency" registered pursuant to the
provisions of Section 17A of the Exchange Act. DTC 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 may include other
organizations. Indirect access to the DTC system is available to others such as
banks, brokers, dealers and trust companies that clear through or maintain a
custodial relationship with a DTC participant, either directly or indirectly.
Although DTC has agreed to the foregoing procedures in order to facilitate
transfers of interest in the global notes among participants of DTC they are
under no obligation to perform or continue to perform these procedures, and
these procedures may be discontinued at any time. Neither we nor the trustee
will have any responsibility for the
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performance by DTC or its participants or indirect participants or its
obligations under the rules and procedures governing its operations.
Certificated Notes
If:
. DTC or any successor depository notifies us that it is unwilling or
unable to continue as a depository for a global note or ceases to be a
"clearing agency" registered under the Exchange Act and a successor
depository is not appointed by us within 90 days of that notice, or
. an Event of Default under the new notes has occurred and is continuing
and payment of principal and interest has been accelerated,
we shall issue certificates for the new notes in definitive registered form in
exchange for the global notes. The Holder of a certificated definitive
registered new note may transfer that new note by surrendering it at the office
or agency maintained by us for that purpose in St. Louis, Missouri, which
initially will be the office of the trustee.
The information in this section concerning DTC and DTC's book-entry system
has been obtained from sources that we believe to be reliable, but we take no
responsibility for the accuracy of that information. We have no responsibility
for the performance by DTC or its participants of their respective obligations
as described in this prospectus or under the rules and procedures governing
their respective operations.
The Trustee
The Bank of New York is the trustee under the indenture.
Governing Law
The indenture, the supplemental indentures and the notes will be governed
by, and construed in accordance with, the laws of the State of New York.
87
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following is a summary of the material United States federal tax
consequences of the exchange of the old notes for the new notes and, in the case
of non-U.S. holders, of the ownership and disposition of the new notes. This
summary is based on the Internal Revenue Code of 1986, existing and proposed
Treasury regulations promulgated thereunder and administrative and judicial
interpretations thereof, all in effect as of the date of this prospectus and all
of which are subject to change, possibly with retroactive effect. The summary
assumes that you hold the old notes, and will hold the new notes, as capital
assets within the meaning of Section 1221 of the Internal Revenue Code. It does
not address any state, local or foreign tax consequences of the exchange of the
old notes for the new notes or of the ownership and disposition of new notes by
non-U.S. holders. It also does not discuss all of the tax consequences that may
be relevant to you in the light of your particular circumstances or if you are a
specified type of holder, including:
. a bank;
. an insurance company;
. a tax-exempt organization;
. a dealer in securities or foreign currencies;
. a holder who or that will hold a new note as part of a hedging
transaction, "straddle," conversion transaction or other integrated
transaction for United States federal income tax purposes;
. a holder whose functional currency is not the United States dollar; or
. a holder who or that did not purchase the old notes for cash at their
original issue date at their original offering price.
You should consult with your own tax advisor about the application of the
United States federal income and estate tax laws to your particular situation as
well as any consequences of the exchange of old notes for new notes and of the
ownership and disposition of new notes under the tax laws of any state, local or
foreign jurisdiction.
United States Federal Income Tax Consequences of the Exchange
Your acceptance of the exchange offer and the related exchange of your old
notes for new notes will not be a taxable event for United States federal income
tax purposes. Your new notes will be treated as a continuation of the old
notes. You will have the same tax basis and holding period in the new notes as
you had in the old notes immediately before the exchange.
United States Federal Tax Consequences to Non-U.S. Holders
If you are a non-U.S. holder, the following discussion describes the United
States federal income and estate tax consequences of the ownership and
disposition of the new notes that may be applicable to you. You are a non-U.S.
holder if you are a beneficial owner of a new note who or that, for United
States federal income tax purposes, is
. an individual other than a citizen or resident alien of the United
States;
. a corporation or partnership that is not created or organized in or
under the laws of the United States or any of its political subdivisions
and, in the case of a partnership, is not treated as a United States
person under Treasury regulations;
88
. an estate other than an estate the income of which is subject to United
States federal income taxation regardless of its source; or
. a trust if no court within the United States is able to exercise primary
supervision over the trust's administration or one or more United States
persons do not have the authority to control all of the trust's
substantial decisions.
Ownership
Subject to the discussion below concerning backup withholding, you will not
be subject to withholding of United States federal income tax on payments of
principal, interest and premium, if any, on the new notes, provided that, in the
case of interest, you satisfy the following conditions:
. you do not own, actually or constructively, 10% or more of the total
combined voting power of all classes of our stock entitled to vote;
. you are not a controlled foreign corporation that is related, directly,
indirectly or constructively, to us through stock ownership; and
. you satisfy the certification requirements, described generally below,
set forth in Section 871(h) or Section 881(c) of the Internal Revenue
Code and the regulations under the Internal Revenue Code.
If you cannot meet these conditions, you generally will be subject to U.S.
withholding tax at the rate of 30% on interest payments, unless you are eligible
for a reduced withholding tax rate under an applicable U.S. income tax treaty.
You will fulfill the certification requirement referred to above if you
certify on Internal Revenue Service Form W-8BEN (or successor form), under
penalties of perjury, that you are not a United States person and provide your
name and address, and file the Form W-8BEN with us or our paying agent. If a
new note is held on your behalf by a securities clearing organization, bank or
other financial institution holding customers' securities in the ordinary course
of its trade or business, the certification requirement will be fulfilled if the
financial institution files with us or our paying agent a statement, signed
under penalties of perjury, that it has received the Form W-8BEN from you (or
from another intermediary financial institution acting on your behalf) and
furnishes us or our paying agent with a copy thereof. If you are a foreign
partnership, unless you have entered into a withholding agreement with the
Internal Revenue Service, you will be required, in addition to providing an
intermediary Form W-8BEN, to attach an appropriate certification by each
partner. A look-through rule will apply in the case of tiered partnerships.
Foreign partnerships and their partners should consult their own tax advisors
regarding possible additional certification and reporting requirements.
If you are engaged in the conduct of a trade or business in the United
States, and if interest on a new note is effectively connected with the conduct
of that trade or business, you will be subject to regular United States federal
income tax on that interest on a net income basis in the same manner as if you
were a United States person. You will be exempt from the withholding tax
discussed above if you provide to us or our paying agent a properly executed
Internal Revenue Service Form W-8ECI (or successor form). In addition, if you
are a foreign corporation, you may be subject to a branch profits tax at the
rate of 30%, or a lesser rate as may be specified by an applicable U.S. income
tax treaty, on your effectively connected earnings and profits for the taxable
year, subject to various adjustments. For purposes of the branch profits tax,
interest on a new note will be included in your effectively connected earnings
and profits if the interest is effectively connected with the conduct of a trade
or business in the United States.
89
Sale, Exchange, Redemption or Other Disposition
Subject to the discussion below concerning backup withholding, you will not
be subject to United States federal income tax, or to any withholding thereof,
on any gain realized on the sale, exchange, redemption or other disposition of a
new note, unless:
. you are an individual who is present in the United States for 183 days
or more in the taxable year of the disposition and various other
conditions are met; or
. the gain is effectively connected with the conduct by you of a trade or
business in the United States.
If you are engaged in the conduct of a trade or business in the United
States, and if any gain realized on the sale, exchange, redemption or other
disposition of a new note is effectively connected with the conduct of that
trade or business, you will be subject to regular United States federal income
tax on the gain on a net income basis in the same manner as if you were a United
States person. In addition, if you are a foreign corporation, you may be
subject to a branch profits tax at the rate of 30%, or a lesser rate as may be
specified by an applicable U.S. income tax treaty, on your effectively connected
earnings and profits for the taxable year, subject to various adjustments. For
purposes of the branch profits tax, any gain recognized on the sale, exchange,
redemption or other disposition of a new note will be included in your
effectively connected earnings and profits if the gain is effectively connected
with the conduct of a trade or business in the United States.
Estate Tax
If you are an individual non-U.S. holder and if you hold a new note at the
time of your death, the new note will not be includible in your gross estate for
purposes of the United States federal estate tax, provided that, at the time of
your death:
. you do not own, actually or constructively, 10% or more of the total
combined voting power of all classes of our stock entitled to vote; and
. payments of interest with respect to the new note, if received at that
time, would not have been effectively connected with the conduct of your
trade or business in the United States.
Backup Withholding and Information Reporting
Under current United States federal income tax law, you will not be subject
to backup withholding tax at the rate of 31% or to information reporting on
payments of interest if the certifications required by Section 871(h) or Section
881(c) of the Internal Revenue Code and described generally above are received,
provided that neither we nor our paying agent has actual knowledge that you are
a United States person.
Under current Treasury regulations, payments of the proceeds of the sale,
exchange, redemption or other disposition of a new note made to or through a
foreign office of a broker generally will not be subject to backup withholding
or information reporting. However, information reporting will be required if a
broker is either:
. a United States person;
. a controlled foreign corporation for United States federal income tax
purposes;
. a foreign person 50% or more of whose gross income is effectively
connected with the conduct of a United States trade or business for a
specified three-year period; or
. in the case of payments made after December 31, 2000, a foreign
partnership with specified connections to the United States;
90
unless the broker has in its records documentary evidence that you, as payee,
are not a United States person or that otherwise establishes an exemption.
Backup withholding may apply to any payment that a broker is required to report
if the broker has actual knowledge that you, as payee, are a United States
person. Payments to or through the United States office of a broker will be
subject to backup withholding and information reporting unless you certify,
under penalties of perjury, that you are not a United States person or otherwise
establish an exemption.
Any amounts withheld from a payment under the backup withholding rules will
be allowed as a credit against your United States federal income tax liability
and may entitle you to a refund, provided that the required information is
furnished to the Internal Revenue Service. You should consult your own tax
advisor regarding the application of the information reporting and backup
withholding requirements to your particular situation, the availability of an
exemption therefrom, and the procedure for obtaining an exemption, if available.
91
PLAN OF DISTRIBUTION
Except as described below, a broker-dealer may not participate in the
exchange offer in connection with a distribution of the new notes. Each broker-
dealer that receives new notes for its own account pursuant to the exchange
offer must acknowledge that it will deliver a prospectus in connection with any
resale of those new notes. Based on SEC staff interpretations issued to third
parties, a broker-dealer may use this prospectus, as it may be amended or
supplemented from time to time, in connection with resales of new notes received
in exchange for old notes where those old notes were acquired as a result of
market-making or other trading activities. We have agreed that, for a period of
270 days after the consummation of the exchange offer, we will make this
prospectus, as amended or supplemented, available to any broker-dealer for use
in connection with those resales. In addition, until August 27, 2001, all
dealers effecting transactions in the new notes may be required to deliver a
prospectus.
The information described above concerning SEC staff interpretations is not
intended to constitute legal advice, and broker-dealers should consult their own
legal advisors with respect to these matters.
We will not receive any proceeds from any sale of new notes by broker-
dealers. Broker-dealers may sell from time to time new notes they receive for
their own account pursuant to the exchange offer through:
. one or more transactions in the over-the-counter market;
. in negotiated transactions;
. through the writing of options on the new notes; or
. a combination of those methods of resale.
Those broker-dealers may sell at:
. market prices prevailing at the time of resale;
. prices related to those prevailing market prices; or
. negotiated prices.
Any broker-dealer may resell directly to purchasers or to or through
brokers or dealers who may receive compensation in the form of commissions or
concessions from the broker-dealer or the purchasers of the new notes. Any
broker-dealer that resells new notes that it received for its own account
pursuant to the exchange offer and any broker-dealer that participates in a
distribution of the new notes may be deemed to be an "underwriter" within the
meaning of the Securities Act. Any profit on any underwriter's resale of new
notes and any commission or concessions received by any underwriters may be
deemed to be underwriting compensation under the Securities Act. The letter of
transmittal states that a broker-dealer will not be deemed to admit that it is
an "underwriter" within the meaning of the Securities Act by acknowledging that
it will deliver and by delivering a prospectus.
We have agreed, for a period of 270 days after the expiration date to
promptly send additional copies of this prospectus and any amendment or
supplement to this prospectus to any broker-dealer that requests those documents
in the letter of transmittal. We have also agreed to pay expenses incident to
the exchange offer other than commissions or concessions of any broker or dealer
and transfer taxes, if any, and will indemnify the holders of the new notes
(including any broker-dealers) against various liabilities, including
liabilities under the Securities Act. This indemnification obligation does not
extend to statements or omissions in the registration statement or prospectus
made in reliance upon and in conformity with written information pertaining to
the holder that is furnished to us by or on behalf of the holder.
92
LEGAL MATTERS
Various legal matters relating to the new notes offered hereby will be
passed upon for us by Jones, Day, Reavis & Pogue, Chicago, Illinois.
EXPERTS
The financial statements as of December 31, 2000 and for the period May 1,
2000 through December 31, 2000 included in this prospectus have been so included
in reliance on the report of PricewaterhouseCoopers LLP, independent
accountants, given on the authority of said firm as experts in auditing and
accounting.
The Independent Technical Review included as Annex A to this prospectus has
been prepared by Stone & Webster Consultants, Inc. (formerly S&W Consultants,
Inc.) and is included in this prospectus in reliance upon the authority of Stone
& Webster Consultants, Inc. and its affiliates as experts in the review of the
design and operation of electric generating facilities. The independent market
consultant's report included as Annex B to this prospectus has been prepared by
Resource Data International, Inc. and is included in this prospectus in reliance
upon the authority of that firm as experts in the analysis of power markets,
including future market demand, future market prices for electric energy and
capacity and related matters, for electric generating facilities.
WHERE YOU CAN FIND MORE INFORMATION
We are not currently subject to the periodic reporting and other
information requirements of the Exchange Act. Upon the completion of the
exchange offer we will become subject to those periodic reporting requirements.
Our parent company, Ameren Corporation, is subject to the informational
requirements of the Exchange Act and, in accordance with that act, files
reports, proxy statements and other information with the SEC. These reports,
proxy statements and other information may be inspected and copied at the
offices of the SEC at the following addresses:
Judiciary Plaza Citicorp Center 7 World Trade Center
450 Fifth Street, N.W. 500 West Madison Street Suite 1300
Washington, D.C. 20549 Chicago, Illinois 60661 New York, New York 10048
You may obtain information regarding the operation of the SEC's public
reference rooms by calling the SEC at 1-800-SEC-0330. The SEC also maintains a
website that contains reports and other information regarding registrants such
as Ameren Corporation that file electronically with the SEC. The address of that
site is (http:\\www.sec.gov). The new notes offered for exchange under this
prospectus will not be guaranteed by, or otherwise be obligations of, Ameren
Corporation or any of its direct or indirect subsidiaries other than our
company.
We have filed with the SEC a registration statement on Form S-4 under the
Securities Act, and the rules and regulations promulgated under the Securities
Act, with respect to the new notes offered for exchange under this prospectus.
This prospectus, which constitutes part of that registration statement, does not
contain all of the information set forth in the registration statement and the
attached exhibits and schedules. The statements contained in this prospectus as
to the contents of any contract, agreement or other document that is filed as an
exhibit to the registration statement are not necessarily complete. Accordingly,
each of those statements is qualified in all respects by reference to the full
text of the contract, agreement or document filed as an exhibit to the
registration statement or otherwise filed with the SEC.
We are incorporated in the State of Illinois. Our principal executive
offices are located at 1901 Chouteau Avenue, St. Louis, Missouri 63103. Our
telephone number is (314) 554-3922. You can find limited information regarding
our company on Ameren's website at (http://www.ameren.com). That website is not
incorporated by reference in this prospectus.
____________________
93
INDEX TO FINANCIAL STATEMENTS
Report of Independent Accountants....................................................................................... F-2
Financial Statements: Balance Sheet December 31, 2000.................................................................. F-3
Statement of Income for the Period From May 1, 2000 Through December 31, 2000........................................... F-4
Statement of Cash Flows for the Period From May 1, 2000 Through December 31, 2000....................................... F-5
Statement of Shareholder's Equity for the Period From May 1, 2000 Through December 31, 2000............................. F-6
Notes to the Financial Statements....................................................................................... F-7
F-1
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholder
of AmerenEnergy Generating Company
In our opinion, the accompanying balance sheet and related statements of income,
of cash flows and of shareholder's equity present fairly, in all material
respects, the financial position of AmerenEnergy Generating Company, a wholly-
owned subsidiary of Ameren Corporation, at December 31, 2000 and the results of
its operations and its cash flows for the period May 1, 2000 through December
31, 2000, in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
the Company's management; our responsibility is to express an opinion on these
financial statements based on our audit. We conducted our audit of these
statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 5, 2001
F-2
AMEREN ENERGY GENERATING COMPANY
- --------------------------------
BALANCE SHEET
- -------------
(Thousands of Dollars)
ASSETS December 31, 2000
------ -----------------
Current:
Cash and cash equivalents $ 596
Accounts receivable - intercompany 57,887
Accounts receivable 10,694
Other receivables - intercompany 125,850
Materials and supplies, at average cost
Fossil fuel 24,791
Other 19,120
Other current assets 1,489
------------------
Total current assets 240,427
------------------
Property and plant at cost, net 951,017
Advances for committed units - intercompany 125,000
Deferred income taxes, net 69,918
------------------
Other assets 7,300
------------------
TOTAL ASSETS $1,393,662
=================
LIABILITIES AND SHAREHOLDER'S EQUITY
------------------------------------
Current:
Current portion of subordinated notes payable intercompany $ 43,544
Accounts and wages payable 30,942
Accounts and wages payable - intercompany 23,028
Current portion of income tax payable - intercompany 15,874
Taxes accrued 26,277
Interest accrued 5,690
Interest payable - intercompany 3,801
Other 4,587
------------------
Total current liabilities 153,743
------------------
Other deferred credits 609
Accumulated deferred investment tax credits 18,233
Income tax payable - intercompany 195,509
Long-term debt, net 423,676
Subordinated notes payable - intercompany 558,082
Commitments and contingencies (Note 9)
Shareholder's equity:
Common stock, $1 par value, authorized 10,000 shares -
outstanding 2,000 shares 2
Retained earnings 43,808
------------------
Total shareholder's equity 43,810
------------------
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY $ 1,393,662
==================
-------------------------------------------------------------------------------------
See notes to financial statements which are an integral part of these
statements.
F-3
AMEREN ENERGY GENERATING COMPANY
- --------------------------------
STATEMENT OF INCOME
- -------------------
(Thousands of Dollars)
For the period May 1, 2000 through December 31, 2000
OPERATING REVENUES:
Electric - intercompany $ 372,179
Electric 105,104
Other - intercompany 2,418
------------------
Total operating revenues 479,701
------------------
OPERATING EXPENSES:
Operations :
Fuel and purchased power 235,320
Other (includes $18,447 - intercompany) 53,956
------------------
289,276
Maintenance 45,725
Depreciation and amortization 28,277
Other taxes 13,155
------------------
Total operating expenses 376,433
------------------
Operating income 103,268
Interest expense - intercompany 29,537
Interest expense 5,344
Other income (includes $1,203 - intercompany) (2,634)
------------------
Income before income taxes 71,021
Income taxes 27,213
------------------
NET INCOME $ 43,808
==================
See notes to financial statements which are an integral part of these
statements.
F-4
AMEREN ENERGY GENERATING COMPANY
- --------------------------------
STATEMENT OF CASH FLOWS
- -----------------------
(Thousands of Dollars)
For the period May 1, 2000 through December 31, 2000
Cash Flows From Operating Activities:
Net income $ 43,808
Adjustments to reconcile net income to net cash
Used In operating activities:
Depreciation and amortization 28,277
Deferred income taxes 5,981
Deferred investment tax credits (1,495)
Changes in assets and liabilities:
Receivables, net (68,581)
Materials and supplies 9,895
Accounts and wages payable 47,429
Taxes accrued 26,277
Income tax payable - intercompany (8,212)
Interest accrued and payable 9,491
Other, net 4,408
---------
Net Cash Provided By Operating Activities 97,278
---------
Cash Flows From Investing Activities:
Construction expenditures (345,241)
Advances for committed units - intercompany (125,000)
Other receivables - intercompany (99,850)
---------
Net Cash Used In Investing Activities (570,091)
----------
Cash Flows From Financing Activities:
Issuances -
Notes payable - intercompany 50,000
Long-term debt 423,643
Debt issuance costs (6,621)
----------
Net Cash Provided By Financing Activities 467,022
----------
Net Change In Cash And Cash Equivalents (5,791)
----------
Cash And Cash Equivalents At Beginning Of Period 6,387
----------
Cash And Cash Equivalents At End Of Period $ 596
----------
Cash paid during the period:
---------------------------------------------------------------------------------
Interest $ 26,073
Income taxes $ 13,524
The following significant non-cash transaction occurred during the period: the
transfer of AmerenCIPS' generating assets to AmerenEnergy Generating Company in
exchange for a subordinated promissory note and AmerenEnergy Generating Company
common stock. See Notes 2, 5 and 7 for further discussion of this transaction.
See notes to financial statements which are an integral part of these
statements.
F-5
AMEREN ENERGY GENERATING COMPANY
- --------------------------------
STATEMENT OF SHAREHOLDER'S EQUITY
- ---------------------------------
(Thousands of Dollars)
For the period May 1, 2000 through December 31, 2000
Common Stock Total
------------------------------------
Retained Shareholder's
Shares Par Value Earnings Equity
----------- -------------- ------------- ----------------
Balance May 1, 2000 2,000 $ 2 $ - $ 2
Net Income 43,808 43,808
----------- -------------- ------------- ----------------
Balance December 31, 2000 2,000 $ 2 $ 43,808 $ 43,810
----------- -------------- ------------- ----------------
See notes to financial statements which are an integral part of these
statements.
F-6
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31, 2000
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Ameren Corporation is a registered holding company under the Public Utility
Holding Company Act of 1935 (PUHCA) that was formed in December 1997 upon the
merger of CIPSCO Incorporated, the former parent company of Central Illinois
Public Service Company (AmerenCIPS), and Union Electric Company (AmerenUE). In
response to the Illinois Electric Service Customer Choice and Rate Relief Law of
1997, on May 1, 2000, following the receipt of all required State and Federal
regulatory approvals, AmerenCIPS transferred its electric generating assets and
related liabilities, at historical net book value, to a newly created non-
regulated company, AmerenEnergy Generating Company (Genco or the company), a
subsidiary of Ameren Corporation's wholly-owned subsidiary, AmerenEnergy
Resources Company (Resources), in exchange for a subordinated promissory note
from the company and 1,000 shares of the company's common stock.
Resources is a holding company for Ameren Corporation's non-regulated
electric generation business whose principal subsidiaries include the company,
AmerenEnergy Development Company (Development Co.), AmerenEnergy Fuels and
Services Company (Fuels Co.) and AmerenEnergy Marketing Company (Marketing
Co.). Fuels Co. acts as the company's agent and manages the company's coal,
natural gas and fuel oil procurement and supply. Development Co. develops and
constructs generation assets for the company, and the company purchases
generation assets from Development Co. when the assets are available for
commercial operation. Marketing Co. focuses on marketing energy, capacity and
other energy products for terms in excess of one year. In addition,
AmerenEnergy, Inc. (Ameren Energy), Ameren Corporation's energy trading and
marketing subsidiary, acts as agent for the company and enters into contracts
for the sale and purchase of energy on behalf of the company for terms less than
a year. The company qualifies as an exempt wholesale generator under PUHCA and
owns and operates Resource's non-regulated electric generation business. The
company's fiscal year-end is December 31.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires management to make certain estimates and
assumptions. Such estimates and assumptions affect reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the date
of the financial statements and the reported amounts of revenues and expenses
during the reported period. Actual results could differ from those estimates.
Property and Plant
The cost of additions to, and betterments of, units of property and plant
is capitalized. Cost includes labor, material, applicable taxes and overheads.
Maintenance expenditures and the renewal of items not considered units of
property are charged to income as incurred. When units of depreciable property
are retired, the original cost and removal cost, less salvage value, are charged
to accumulated depreciation.
Depreciation
Depreciation is provided over the estimated lives of the various classes of
depreciable property by applying composite rates on a straight-line basis. The
provision for depreciation for the period May 1, 2000 through December 31, 2000
was approximately 2.7% of the average depreciable costs on an annualized basis.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments
purchased with an original maturity of three months or less.
F-7
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
Materials and Supplies
Materials and supplies are stated at average cost.
Income Taxes
The company is included in the consolidated federal income tax return filed
by Ameren Corporation. As a subsidiary of Ameren Corporation, the company could
be considered jointly and severably liable for assessments of additional tax on
the consolidated group. Income taxes are allocated to the individual companies
based on their respective taxable income or loss. The company's provision for
income taxes has been presented based on federal and state taxes the company
would have presented on a separate company basis. Deferred tax assets and
liabilities are recognized for the tax consequences of transactions that have
been treated differently for financial reporting and tax return purposes, using
statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.
Unamortized Debt Discount and Expense
Discount and expense associated with long-term debt are amortized over the
life of the related issue.
Interest Capitalized
Interest is capitalized in accordance with SFAS No. 34, "Capitalization of
Interest Cost." For the period May 1, 2000 through December 31, 2000, interest
expense capitalized was $0.8 million.
Advances for Committed Units
Advances for committed units represent amounts loaned to Development Co.
under a committed unit contribution agreement. See Note 2 for further
discussion of this agreement.
Revenue
The company records electric revenues for service rendered, at the end of
each accounting period. See Note 3 for further discussion of electric power
supply agreements.
Evaluation of Assets for Impairment
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of" prescribes general standards for the
recognition and measurement of impairment losses. The company determines if
long-lived assets are impaired by comparing their undiscounted expected future
cash flows to their carrying amount. An impairment loss is recognized if the
undiscounted expected future cash flows are less than the carrying amount of the
asset. As of December 31, 2000, no impairment was identified.
Energy Contracts
The Emerging Issues Task Force of the Financial Accounting Standards Board
(EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities" became effective on January 1, 1999. EITF 98-10 provides guidance
on the accounting for energy contracts entered into for the purchase or sale of
electricity, natural gas, capacity and transportation. The EITF reached a
consensus in EITF 98-10 that sales and purchase activities being performed need
to be classified as either trading or nontrading. Furthermore, transactions
that are determined to be trading activities would be recognized on the balance
sheet measured at fair value, with gains and losses included in earnings.
Ameren Energy enters into contracts for the sale and purchase of energy on
behalf of the company. The company is ultimately responsible for the
performance of these contracts. As of
F-8
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
December 31, 2000, virtually all of Ameren Energy's transactions were considered
nontrading activities and were accounted for using the accrual or settlement
method, which represents industry practice.
Derivatives
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS
133 defines and establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities and requires recognition of all
derivatives as either assets or liabilities on the balance sheet measured at
fair value. The intended use of the derivatives and their designation as either
a fair value hedge, a cash flow hedge, or a foreign currency hedge will
determine when the gains or losses on the derivatives are to be reported in
earnings and when they are to be reported as a component of other comprehensive
income in stockholders' equity. In June 1999, the FASB issued SFAS 137,
"Accounting for Derivative Instruments and Hedging Activities--Deferral of the
Effective Date of FASB Statement No. 133," which delayed the effective date of
SFAS 133 to all fiscal quarters of all fiscal years, beginning after June 15,
2000. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - an amendment of FASB
Statement No. 133," which amended certain accounting and reporting standards of
SFAS 133. The Company is adopting SFAS 133 in the first quarter of 2001. The
impact of this standard to the company resulted in a cumulative charge as of
January 1, 2001 of $2 million after income taxes to the income statement and a
cumulative adjustment of $3 million to other comprehensive income which
decreased stockholders' equity. However, the Derivatives Implementation Group
(DIG), a committee of the FASB responsible for providing guidance on the
implementation of SFAS 133, has not reached a conclusion regarding the
appropriate accounting treatment of certain types of energy contracts under SFAS
133. The company is unable to predict when this issue will ultimately be
resolved and the impact the resolution will have on the company's future
financial position, results of operations or liquidity. Implementation of SFAS
133 will likely increase the volatility of the company's earnings in future
periods.
NOTE 2 - Intercompany Transactions
The company has transactions in the normal course of business with Ameren
Corporation and other Ameren companies. These transactions primarily consist of
power purchases and sales, services received or rendered, borrowings and
lendings. The transactions with Ameren Corporation and other Ameren companies
are reported as intercompany transactions.
On May 1, 2000, AmerenCIPS transferred its electric generating assets and
related liabilities, at net book value, to the company, in exchange for a
subordinated promissory note from the company in the principal amount of $552
million and 1,000 shares of the company's common stock. The transferred assets
represent generating capacity of approximately 2,860 megawatts. Approximately
45% of AmerenCIPS' employees were transferred to the company as part of the
transaction. The significant components of net assets transferred are as
follows:
(Thousands of dollars)
Cash $ 6,387
Other receivable - intercompany 26,000
Material and supplies 53,806
Other current assets 5,522
Property and plant, net 635,031
---------
Total assets transferred $ 726,746
---------
Accounts payable $ 6,541
Other current liabilities 3,351
Other deferred credits 1,804
Deferred investment tax credits 19,728
Deferred tax liabilities, net 143,696
---------
Total liabilities transferred 175,120
---------
Net assets transferred $ 551,626
---------
F-9
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
On June 30, 2000 the company, through the issuance of a subordinated
promissory note, borrowed $50 million from Ameren Corporation to meet working
capital needs. The two subordinated promissory notes each have a term of five
years and bear interest at 7% based on a 10-year amortization.
In June and July of 2000, the company acquired combustion turbine
generating units at Pinckneyville and Gibson City, Illinois from Development Co.
at Development Co.'s historical net book value. The total installed cost of
these combustion turbine generating units is approximately $200 million. In
September 2000, the company also acquired three combustion turbine generating
units at the Joppa, Illinois site from an affiliate at the affiliate's
historical net book value. The total installed cost of these combustion turbine
generating units is approximately $73 million. The company has entered into an
operating lease agreement with Development Co. for these units at the Joppa site
wherein the three combustion turbine generating units have been leased to
Development Co. for a minimum term of fifteen years. The company receives
rental payments under the lease in fixed monthly amounts that vary over the term
of the lease and range in amount from $0.8 - $1.0 million. Development Co. is
entitled to all of the output produced from the three combustion turbine
generating units and will be responsible for all operating expenses.
Development Co. intends to enter into an agreement with Midwest Electric Power,
Inc., an affiliate, under which Midwest Electric Power, Inc. will provide
operations and maintenance services. On November 1, 2000, Development Co. and
Marketing Co. entered into an electric power supply agreement, referred to as
the Development Co.-Marketing Co. agreement. The Development Co.-Marketing Co.
agreement entitles Marketing Co. to all of the output from the Joppa site. The
Development Co.-Marketing Co. agreement contains a monthly capacity charge that
approximates the lease payment obligation Development Co. incurs from the
company and an energy charge equal to the variable costs of operating the
combustion turbine generating units.
On November 1, 2000, the company and Development Co., in conjunction with
the financing described in Note 6, entered into a committed unit contribution
agreement, whereby the company agreed to advance $125 million in cash to
Development Co. in exchange for the delivery of combustion turbine generating
units at Kinmundy and Grand Tower, Illinois, which are expected to be
commercially available in mid-2001. Under this agreement, the purchase price of
the combustion turbine generating units to be delivered to the company in 2001
will be reduced by the amount advanced to Development Co. At December 31, 2000
the amount advanced to Development Co. under the committed unit contribution
agreement is recorded as advances for committed units - intercompany.
Prior to AmerenCIPS' transfer of its generating assets to the company on
May 1, 2000, AmerenCIPS and AmerenUE jointly dispatched their generation
pursuant to a joint dispatch agreement. In connection with the asset transfer,
AmerenCIPS assigned its electric generation rights and obligations under this
agreement to the company and the agreement was amended to reflect the fact that
the company now owns and operates the generation assets previously owned by
AmerenCIPS. As a result, the company jointly dispatches generation with
AmerenUE under a new amended joint dispatch agreement. Under the agreement, the
company and AmerenUE are entitled to serve load requirements from their own
least-cost generation first, and then will allow the other company access to any
available excess generation. All of the company's sales to Marketing Co. are
considered load requirements. Sales made by the company to other customers
through Ameren Energy as the company's agent are not considered load
requirements. For the period May 1, 2000 through December 31, 2000, $105
million of the company's electric revenues were derived through the sale of the
company's available generation to other customers and $31 million of the
company's electric revenues were derived through sales of available generation
to AmerenUE through the amended joint dispatch agreement.
The company's financial statements include charges for services that Ameren
Services Company (Ameren Services), a wholly owned subsidiary of Ameren
Corporation, provides to the company. Ameren Services provides the company with
certain support functions such as accounting, finance, corporate planning, audit
and compliance service, investor relations, legal, corporate development,
regulatory, risk management, and tax services. In addition to support
functions, Ameren Services provides the company with specialized support
functions, including information technology, human resources, environmental
resources, purchasing and materials management, and public affairs.
F-10
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
Charges are based upon the actual costs incurred by Ameren Services.
Charges are billed monthly to the company and are included in other operating
expenses in the accompanying Statement of Income. These charges were allocated
to the company based on utilization or other methods which management believes
to be reasonable. For the period May 1, 2000 through December 31, 2000,
charges to the company were $18 million.
See Notes 3, 5, 7 and 9 for other intercompany agreements and transactions.
NOTE 3 - Electric Power Supply Agreement
On May 1, 2000 (and amended August 14, 2000), an electric power supply
agreement was entered into between the company and Marketing Co., referred to as
the Genco-Marketing Co. agreement. Also on May 1, 2000, Marketing Co. entered
into an electric power supply agreement with AmerenCIPS, referred to as the
Marketing Co.-CIPS agreement, to supply sufficient power to meet AmerenCIPS'
native load requirements. A portion of the capacity and energy supplied by the
company to Marketing Co. will be resold to AmerenCIPS for resale to AmerenCIPS'
native load customers at rates specified by the Illinois Commerce Commission
(which approximate the historical regulatory rates for generation) or to retail
customers allowed choice of an electric supplier under state law at market based
prices. Power will continue to be jointly dispatched between AmerenUE and the
company. The Marketing Co.-CIPS agreement expires December 31, 2004 and the
Genco-Marketing Co. agreement may be terminated upon at least one year's notice
given by either party, but in no event can it be terminated prior to December
31, 2004. For the period May 1, 2000 through December 31, 2000, $341 million of
the company's electric revenue was derived under the Genco-Marketing Co.
agreement. No other customer represents greater than 10% of the company's
revenues.
NOTE 4 - Concentration of Risk
Market Risk
Fuels Co. and Ameren Energy, on behalf of the company, engage in price risk
management activities related to electricity and fuel. In addition to buying
and selling these commodities, the company uses derivative financial instruments
to manage market risks and reduce exposure resulting from fluctuations in the
prices of electricity and fuel. Hedging instruments include futures, forward
contracts and options. The use of these types of contracts allows the company
to manage and hedge its contractual commitments and reduce exposure related to
the volatility of commodity market prices.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties
fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded
futures contracts are supported by the financial resources and credit quality of
the clearing members of NYMEX and have nominal credit risk. On all other
transactions, the company is exposed to credit risk in the event of
nonperformance by the counterparties in the transaction.
The company's financial instruments subject to credit risk consist
primarily of accounts receivable and forward contracts. The company's revenues
are primarily derived from the sales of electricity to Marketing Co. as
described in Note 3. Approximately 89% of the company's accounts receivable are
related party receivables from Marketing Co. No other customer represents
greater than 10% of the company's accounts receivable. For each counterparty in
forward contracts, the company analyzes the counterparty's financial condition
prior to entering into an agreement, establishes credit limits and monitors the
appropriateness of these limits on an ongoing basis through a credit risk
management program.
NOTE 5 - Intercompany Financing
The company has the ability to borrow up to $463 million from Ameren
Corporation through a non-utility money pool agreement. However, the total
amount available to the company at any given time is reduced by the amount of
borrowings from the non-utility money pool by other Ameren non-regulated
companies but increased to the extent other Ameren non-regulated companies have
surplus funds and the availability of other external borrowing sources. The
non-utility money pool was established to coordinate and provide for certain
short-term
F-11
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
cash and working capital requirements and is administered by Ameren Services.
Interest is calculated at varying rates of interest depending on the composition
of internal and external funds in the non-utility money pool. For the period May
1, 2000 through December 31, 2000 the average interest rate for the non-utility
money pool was 6.52%. At December 31, 2000, the company had loaned $100 million
to the non-utility money pool, which is included in other receivables--
intercompany, and at least $296 million was available through the non-utility
money pool subject to reduction for borrowings by other Ameren non-regulated
companies.
The note to AmerenCIPS is a subordinated intercompany note. The company
and AmerenCIPS have agreed that debt service during the term of the AmerenCIPS
subordinated note will be payable solely from ''available cash,'' defined as
cash available after payment of all operating and maintenance expenses, debt
service, capital expenditures, taxes and reasonable reserves for working capital
and other corporate purposes as determined by the company in its discretion. Any
installment payment amount which is not paid when due because of the available
cash limitation will be payable when available cash becomes sufficient to permit
the payment, or else carried forward until maturity. The company may not prepay
the AmerenCIPS subordinated note in whole or in part prior to the stated
maturity, May 1, 2005, without the prior written consent of the holders of a
majority of the outstanding notes issued under the indenture and such approvals
as are required under the terms of any other senior indebtedness. However, the
outstanding principal amount of the AmerenCIPS subordinated note will be reduced
by the amount of tax-exempt pollution control loan obligations the company
assumes from AmerenCIPS. In addition, with the consent of AmerenCIPS, the
company may also prepay the AmerenCIPS subordinated note in whole or in part
with proceeds derived from other debt or equity securities it may issue which
rank subordinate and junior to senior indebtedness on terms comparable to those
of the AmerenCIPS subordinated note. The AmerenCIPS subordinated note may not be
transferred by AmerenCIPS except to another wholly-owned subsidiary of Ameren.
Resources has agreed with the company that, in the event that upon maturity the
AmerenCIPS subordinated note has not been paid in full or refinanced with other
subordinated intercompany indebtedness with terms at least as subordinate, then
Resources will assume the company's obligations under the AmerenCIPS
subordinated note (subject to regulatory approval), with no further liability to
the company, or contribute sufficient funds to the company as equity or
subordinated debt to enable the company to pay in full the remaining balance of
the AmerenCIPS subordinated note.
On June 30, 2000 the company issued a second subordinated intercompany note
in the amount of $50 million to Ameren Corporation. This note is subordinated
to all senior debt as well as to the subordinated note held by AmerenCIPS. The
two subordinated intercompany notes each have a term of five years and bear
interest at 7% based on a 10-year amortization.
The aggregate maturities of the subordinated notes payable are as follows:
Year Ended December 31,
2001 $ 43,544
2002 46,592
2003 49,854
2004 53,344
2005 408,292
--------
$601,626
--------
NOTE 6 - Long-term Debt
On November 1, 2000, the company issued 7.75% Senior Notes, Series A due
2005 (Series A Notes) and 8.35% Senior Notes, Series B due 2010 (Series B Notes)
(collectively, the Senior Notes). Series A Notes totaled $225 million.
Interest accrues on the Series A Notes at a rate of 7.75% per year and is
payable semiannually in arrears on May 1 and November 1 of each year commencing
on May 1, 2001. Principal of the Series A Notes will be payable on November 1,
2005. Series B Notes totaled $200 million. Interest accrues on the Series B
Notes at a rate of 8.35% per year and is payable semiannually in arrears on May
1 and November 1 of each year commencing on May 1, 2001. Principal of the
Series B Notes will be payable on November 1, 2010. The proceeds from the
Senior Notes were $423.6 million before transaction costs. Debt covenants limit
the company's ability to, among
F-12
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
other things, sell assets, create liens and engage in mergers, consolidations or
similar transactions. At December 31, 2000, the company was in compliance with
all applicable debt covenants.
December 31,
(Thousands of dollars) 2000
--------------------------------------- ------------
7.75% Senior Notes, Series A due 2005 $225,000
8.35% Senior Notes, Series B due 2010 200,000
------------
425,000
------------
Unamortized discount on debt (1,324)
============
Total Long-Term Debt $423,676
============
NOTE 7 - Income Taxes
Total income tax expense for the period May 1 through December 31, 2000
resulted in an effective tax rate of 38.3% on earnings before income taxes.
Principal reasons such rates differ from the statutory federal rate:
--------------------------------------------------------------------
Period May 1, 2000
through December 31,
2000
--------------------------------------------------------------------
Statutory federal income 35.0%
tax rate
Increases (decreases) from:
Depreciation differences (0.2)
Amortization of investment tax credit (1.7)
State income tax 5.2
Other -
--------------------------------------------------------------------
Effective income tax rate 38.3%
--------------------------------------------------------------------
Income tax expense components:
--------------------------------------------------------------------
(Thousands of dollars) Period May 1, 2000
through December 31,
2000
---------------------------------------------------------------------
Current tax expense
U.S. Federal $18,552
State and local 4,175
---------------------------------------------------------------------
Total current income taxes $22,727
---------------------------------------------------------------------
Deferred tax expense 5,981
Amortization of investment tax credit (1,495)
---------------------------------------------------------------------
Total tax expense $27,213
---------------------------------------------------------------------
In accordance with Statement of Financial Accounting Standards No. 109
(SFAS 109), as a result of the step-up in basis for tax purposes of the
transferred assets from AmerenCIPS to the company an additional tax basis for
the company and a deferred intercompany tax gain for AmerenCIPS of approximately
$552 million was recorded, resulting in a deferred tax asset for the company of
approximately $219 million and an equivalent income tax payable - intercompany
balance. This transaction was recorded as a non-cash transaction. The deferred
tax
F-13
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
asset and intercompany tax payable are being amortized and paid, respectively,
over twenty years, the approximate remaining life of the transferred assets.
Other deferred income taxes reflect the net tax effects of temporary
differences between the carrying amount of assets and liabilities for financial
reporting purposes and amounts used for income tax purposes. Significant
components of the company's deferred tax assets and liabilities are as follows:
(Thousands of dollars) December 31, 2000
-----------------
Deferred tax assets:
Tax basis step-up $211,383
Tax basis of coal contract 8,967
Investment tax credits 7,609
Other 468
--------
228,427
Deferred tax liabilities:
Property timing differences 157,983
Other 526
--------
158,509
Net deferred tax asset $ 69,918
--------
NOTE 8 - Retirement Benefits
The Ameren retirement plan covers qualified employees of Ameren and its
subsidiaries, including the company. Benefits are based on the employees' years
of service and compensation. The Ameren plan is funded in compliance with
income tax regulations and federal funding requirements. The company, along with
other subsidiaries of Ameren, is a participant in the Ameren plan and is
responsible for its proportional share of the plan costs. The company's share
of plan costs for the period May 1, 2000 through December 31, 2000 was $0.5
million, of which approximately 1% was charged to construction accounts.
In addition to providing retirement benefits, the company through Ameren
provides certain health care and life insurance benefits for retired employees.
Ameren's postretirement benefit plans cover all employees of the company. The
company's share of the postretirement costs for the period May 1, 2000 through
December 31, 2000 was approximately $1.8 million.
NOTE 9 - Commitments and Contingencies
The company has commitments for the purchase of coal under long-term
contracts. Coal contract commitments, including transportation costs, for the
period 2001 through 2005 are estimated to total $554 million. Total coal
purchases, including transportation costs, for the period May 1, 2000 through
December 31, 2000 was $95 million. Because of uncertainties of supply due to
potential work stoppages, delays in coal deliveries, equipment breakdowns and
other factors, the company has a policy of maintaining coal inventory consistent
with its expected burn practices. Recently, the company has experienced some
delays in its coal deliveries due to certain transportation and operating
constraints in the system. The company is working closely with the
transportation companies and monitoring its operating practices in order to
maintain adequate levels of coal inventory for future operating purposes. The
company also has existing contracts with pipeline and natural gas suppliers to
provide transportation and storage of natural gas for electric generation. Gas-
related contract cost commitments for the period 2001 through 2005 are estimated
to total $13 million. Total delivered natural gas costs were approximately $7
million for the period May 1, 2000 through December 31, 2000.
The company intends to purchase combustion turbine generating units at
Kinmundy and Grand Tower, Illinois, Columbia, Missouri and at the existing
Pinckneyville station for approximately $452 million in 2001, once they are
available for commercial operation. These simple cycle and combined cycle
combustion turbine generating units will provide incremental capacity of 820
megawatts.
F-14
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
The company also intends to purchase additional combustion turbine
generating units at undetermined sites. These combustion turbine generating
units are expected to cost up to $736 million and provide additional capacity of
up to 1,490 megawatts and are expected to be available for commercial operation
between mid-2002 and mid-2005. The following is a summary of the company's
planned additions of combustion turbine generating units.
Year Megawatts Estimated Cost (in millions)
---- --------- ----------------------------
2001 820 $452
2002 515 $250
2003 325 $206
2004 325 $140
2005 325 $140
These future plans are subject to change, including increasing or
decreasing planned or installed future generating capacity, based on market
conditions, regulatory approvals for additions, the company's results of
operations and financial condition, availability of financing and other factors
determined by management.
For the period May 1, 2000 through December 31, 2000, nine combustion
turbine generating units were placed in commercial operation at Pinckneyville,
Gibson City and Joppa, Illinois. These units provide additional capacity of 584
megawatts and cost approximately $273 million, as described in Note 2.
The company anticipates securing additional permanent financing during
2001-2004 to fund the purchase of completed combustion turbine generating
facilities. At this time, the company is unable to determine the amount of the
additional permanent financing, as well as the additional financing's impact on
the company's financial position, results of operation or liquidity.
Capital expenditures at the company's existing coal-fired plants are
expected to approximate $160 million in total for the period 2001 through 2005,
excluding any capital expenditures required to comply with nitrogen oxide
(NO\X\) emissions standards discussed below.
Title IV of the Clean Air Act Amendments of 1990 required the company to
significantly reduce total annual sulfur dioxide (SO\\2\\) and NO\\X\\ emissions
by the year 2000. By switching to low-sulfur coal, acquiring SO\\2\\ allowances
from AmerenUE and installing advanced NO\\X\\ reduction combustion technology,
the company is meeting these requirements.
In January 2001, the company exchanged 162,840 SO\\2\\ allowances with
vintages of 2006 and later with AmerenUE for 120,000 SO\\2\\ allowances with
vintages of 2002 and earlier. The market value of the allowances exchanged was
approximately equal. The company completed this exchange because the company
experienced a shortfall of SO\\2\\ allowances in 2000 and is projecting a
shortfall in SO\\2\\ allowances in 2001 and 2002 under current generation plans.
The company may alter its generation plan or increase its use of low-sulfur coal
to improve its position in SO\\2\\ allowances. This transaction was recorded at
the historical cost of the allowances.
In July 1997, the United States Environmental Protection Agency (USEPA)
issued regulations revising the National Ambient Air Quality Standards for ozone
and particulate matter. In May 1999, the U.S. Court of Appeals for the District
of Columbia remanded the regulations back to the USEPA for review. The USEPA
appealed the decision to the U.S. Supreme Court. On February 27, 2001, the U.S.
Supreme Court reversed and remanded the case to the U.S. Court of Appeals for
the District of Columbia for further evaluation and opinion. The U.S. Supreme
Court ruled that Congress, in enacting Clean Air Act provisions that authorized
the USEPA to determine air quality standards, did not unconstitutionally
delegate legislative power to the agency. The U.S. Supreme Court also rejected
industry arguments that the USEPA should have considered implementation costs in
setting air quality standards. The ruling reaffirms the USEPA's authority to
establish uniform air quality standards at a level that is sufficient to protect
public health. However, the manner in which the USEPA proposed to implement the
proposed air quality standard for ozone was ruled unlawful and the U.S. Supreme
Court ordered the remand of the USEPA's implementation policy to the agency for
further consideration. When the proposed ambient standards are ultimately
enacted, such standards will require significant additional reductions in
SO\\2\\ and NO\\X\\ emissions from the company's
F-15
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
power plants. At this time, the company is unable to predict the ultimate impact
of these revised air quality standards on its future financial condition,
results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the
USEPA issued the implementation of regulations in September 1998 to reduce
NO\\X\\ emissions from coal-fired boilers and other sources in 22 states,
including Illinois (where all of the company's coal-fired power plant boilers
are located). The regulations were challenged in a U.S. District Court. In March
2000, the court upheld the regulations pertaining to Illinois and further
delayed the compliance date until 2004. The regulations mandate a 75% reduction
in NO\\X\\ emissions from utility boilers in Illinois by the year 2004. The
NO\\X\\ emissions reductions already achieved on several of the company's coal-
fired power plants will help to reduce the costs of compliance with this
regulation. However, the regulations will require the installation of selective
catalytic reduction technology on some of the company's units, as well as other
additional controls.
Currently, the company estimates that its additional capital expenditures
to comply with the final NO\\X\\ regulations could range from $125 million to
$150 million in total over the period from 2001 to 2004. Associated operations
and maintenance expenditures could increase $5 million to $8 million annually,
beginning in 2005. The company will explore alternatives to comply with these
new regulations in order to minimize, to the extent possible, its capital costs
and operating expenses. The company is unable to predict the outcome of the
litigation, the regulation implementation date or the ultimate impact of these
standards on its future financial condition, results of operations or liquidity.
The Illinois Electric Service Customer Choice and Rate Relief Law of 1997
provides for retail direct access, which allows customers to choose their
electric generation supplier, to be phased in over several years. The phase-in
of retail direct access began on October 1, 1999, with large industrial and
commercial customers principally comprising the initial group. The remaining
commercial and industrial customers in Illinois were offered choice on December
31, 2000. Retail direct access will be offered to residential customers on May
1, 2002. The company is unable to predict the ultimate impact that retail
direct access in Illinois will have on its future financial condition, results
of operation or liquidity.
During the course of Ameren Corporation's resource planning, several
alternatives are being considered to satisfy load requirements for AmerenUE,
AmerenCIPS, Marketing Co. and the company for 2001 and beyond. One of these
alternatives was for AmerenUE to transfer its Illinois-based electric and
natural gas businesses and certain of its Illinois-based distribution and
transmission assets and personnel to AmerenCIPS. The assets and related
liabilities were proposed to be transferred from AmerenUE to AmerenCIPS at
historical net book value. In March 2001, Ameren Corporation decided it will no
longer pursue this transfer and will be taking the necessary action to withdraw
pending requests for regulatory approvals. This transfer would have added about
525 megawatts of demand to the AmerenCIPS load that would have been supplied by
the company under the Marketing Co.-CIPS agreement. At this time, management is
unable to predict which course of action it will pursue to satisfy these
requirements and their ultimate impact on the company's financial position,
results of operation or liquidity.
Subject to certain approvals, the company intends to become primarily
liable for approximately $104 million of tax-exempt pollution control loan
obligations to be transferred from AmerenCIPS during 2001. Upon the transfer of
these obligations to the company, the amount of the company's liability to
AmerenCIPS under the $552 million intercompany promissory note would be reduced
by a similar amount. The pollution control loan obligations referred to above
have maturity dates ranging from 2014 to 2028 and bear interest at variable
rates. At December 31, 2000, the interest rate on the pollution control loan
obligations was 4.95%. However, concurrent with the transfer of the variable
rate obligations to the company, the company expects to convert these to fixed
interest rate obligations based on market conditions at that time.
Certain employees of the company and its affiliated companies are
represented by the International Brotherhood of Electrical Workers (IBEW) and
the International Union of Operating Engineers (IUOE). These employees comprise
approximately 75% of the company's workforce. Labor agreements covering
virtually all represented employees of the company expired in 1999 and were
renewed for a term expiring in 2002.
F-16
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-Cont'd
The company is involved in other legal and administrative proceedings
before various courts and agencies with respect to matters arising in the
ordinary course of business. The company believes that the final disposition of
these proceedings will not have a material adverse effect on its financial
position, results of operations or liquidity.
NOTE 10 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value.
Cash and Temporary Investments/Short-Term Borrowings
The carrying amounts approximate fair value because of the short-term
maturity of these instruments.
Long-Term Debt
The fair value is estimated based on the quoted market prices for same or
similar issues or on the current rates offered to the company for debt of
comparable maturities.
Carrying amounts and estimated fair values of the company's financial
instruments at December 31, 2000:
-----------------------------------------------------------------------
(Thousands of Dollars) Carrying Fair
Amount Value
-----------------------------------------------------------------------
Long-term debt (including current portion) $423,676 $440,567
-----------------------------------------------------------------------
NOTE 11 - Other Financial Information
(Thousands of dollars) December 31, 2000
-----------------
Other Materials and Supplies
Spare Parts $ 13,128
General Materials 5,090
Other 902
-----------------
$ 19,120
=================
Property and Plant, net
Electric Plant $ 1,574,724
Other 29
-----------------
Property and plant, at original cost 1,574,753
Less accumulated depreciation (647,872)
-----------------
926,881
Construction work in progress 24,136
-----------------
$ 951,017
=================
F-17
Annex A
INDEPENDENT TECHNICAL REVIEW
AMEREN ENERGY GENERATING COMPANY
ASSETS
[GRAPHICS]
October 25, 2000
Final Report
[LOGO] S&W Consultants
A Shaw Group Company
Annex A
Independent Technical Review
Ameren Genco Assets
-------------------
Independent Technical Review
Ameren Energy Generating Company Assets
CONFIDENTIAL
Final Report
October 25, 2000
[LOGO]S&W Consultants, Inc. A-ii
LEGAL NOTICE
This report was prepared by S&W Consultants, Inc. ("S&W Consultants") and its
affiliated company, Stone & Webster, Inc., both hereafter referred to as S&W
Consultants, expressly for Lehman Brothers Inc. ("Lehman Brothers") for the
Ameren Energy Generating Company ("Genco") Acquisition Project (the "Project").
Neither S&W Consultants, nor Lehman Brothers, 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. Any recipient of this report, by their reliance on, acceptance or
use of this report, releases S&W Consultants and its affiliates from any
liability for any direct, indirect, consequential or special loss or damage
whether arising in contract, tort (including negligence) or otherwise. Nothing
expressed in this report should be construed as a legal opinion as to compliance
with law or regulation. Accordingly, no statement by S&W Consultants should be
construed to contain such an opinion.
[LOGO]S&W Consultants, Inc. A-iii
Independent Technical Review for Financing: Ameren Energy Generating Company
Assets
Table of Contents
1 EXECUTIVE SUMMARY........................................................................................ 1
1.1 Coal-fired Stations................................................................................... 6
1.1.1 Condition Assessment............................................................................. 6
1.1.2 Performance...................................................................................... 8
1.1.3 O&M.............................................................................................. 10
1.2 Gas-fired Stations.................................................................................... 11
1.2.1 Operating CT Units............................................................................... 11
1.2.2 Committed Units.................................................................................. 12
1.2.3 O&M.............................................................................................. 12
1.3 Project Agreements.................................................................................... 13
1.4 Conclusions........................................................................................... 13
1.4.1 Coal-fired Stations.............................................................................. 13
1.4.2 Gas-fired Stations............................................................................... 14
1.4.3 Financial Projections............................................................................ 14
2 INTRODUCTION............................................................................................. 16
2.1 Background............................................................................................ 16
2.2 Scope of Services..................................................................................... 17
3 COAL-FIRED STATIONS...................................................................................... 20
3.1 Condition Assessment.................................................................................. 20
3.1.1 Newton Power Station............................................................................. 20
3.1.2 Coffeen Power Station............................................................................ 28
3.1.3 Meredosia Power Station.......................................................................... 37
3.1.4 Hutsonville Power Station........................................................................ 49
3.1.5 Grand Tower Power Station........................................................................ 56
3.2 Performance........................................................................................... 60
3.2.1 Newton Power Station............................................................................. 61
3.2.2 Coffeen Power Station............................................................................ 62
3.2.3 Meredosia Power Station.......................................................................... 62
3.2.4 Hutsonville Power Station........................................................................ 64
3.2.5 Ancillary Services............................................................................... 65
3.3 Operation & Maintenance............................................................................... 65
3.3.1 Newton Power Station............................................................................. 65
3.3.2 Coffeen Power Station............................................................................ 68
3.3.3 Meredosia Power Station.......................................................................... 70
3.3.4 Hutsonville Power Station........................................................................ 73
3.3.5 Grand Tower Power Station........................................................................ 74
3.4 Environmental......................................................................................... 76
3.4.1 Current and Emerging Air Quality Regulations..................................................... 76
3.4.2 Systemwide Air Emissions Compliance Programs..................................................... 78
3.4.3 Generating Station Environmental Compliance...................................................... 81
4 GAS-FIRED STATIONS....................................................................................... 96
4.1 Design and Construction............................................................................... 96
4.1.1 Operating CT Units............................................................................... 96
4.1.2 Committed Units.................................................................................. 103
4.2 Projected Performance................................................................................. 111
4.2.1 Operating CT Units............................................................................... 111
4.2.2 Committed Units.................................................................................. 112
[LOGO]S&W Consultants, Inc. A-iv
4.3 Projected Operation and Maintenance....................................................................... 114
4.3.1 Gibson City, Pinckneyville and Kinmundy........................................................... 114
4.3.2 Grand Tower....................................................................................... 117
4.4 Environmental.......................................................................................... 117
4.4.1 Operating CT Units................................................................................ 117
4.4.2 Committed Units................................................................................... 119
5 PROJECT AGREEMENTS........................................................................................ 121
5.1 Asset Transfer Agreement............................................................................... 121
5.2 Electric Power Supply Agreements....................................................................... 121
5.2.1 Wholesale / Bilateral Contracts................................................................... 122
5.3 Agency Agreement....................................................................................... 122
5.4 Operation and Maintenance.............................................................................. 122
5.5 Fuel Supply............................................................................................ 122
6 FINANCIAL PROJECTIONS..................................................................................... 124
6.1 Technical Assumptions.................................................................................. 125
6.2 Financing Assumptions.................................................................................. 126
6.3 Revenues............................................................................................... 126
6.4 Expenses............................................................................................... 127
6.4.1 Fuel Cost......................................................................................... 128
6.4.2 O&M Costs......................................................................................... 128
6.4.3 Capital Expenditures.............................................................................. 129
6.5 Base Case Results...................................................................................... 129
6.6 Sensitivity Analysis................................................................................... 130
6.7 Conclusions............................................................................................ 131
APPENDIX A: DOCUMENTS REVIEWED.................................................................................. 140
[LOGO]S&W Consultants, Inc. A-v
Annex A
Independent Technical Review
Ameren Genco Assets
-------------------
1 Executive summary
S&W Consultants was retained by Ameren Corporation ("Ameren", which shall also
refer to one or more of its subsidiaries) on behalf of Lehman Brothers, Initial
Purchaser for a Rule 144A Bond issuance by Genco, to perform a lenders'
independent technical review of the portfolio of generating assets owned or to
be acquired by Genco. The generating assets ("the Assets") include the existing
predominantly coal-fired stations ("Coal-fired Stations") shown in Table 1-1.
The Assets also include natural gas fired combined cycle and combustion turbine
("CT") stations ("Gas-fired Stations") as shown on Table 1-2. These have either
commenced commercial operation ("Operating CT Units") or are under construction
("Committed Units").
Table 1-1. Summary of Asset Characteristics: Coal-fired Stations
===============================================================================================
Station/Unit Type Date Commissioned Fuel Capacity (MW)
- -----------------------------------------------------------------------------------------------
Summer (Net)
- -----------------------------------------------------------------------------------------------
Newton Power Station
- -----------------------------------------------------------------------------------------------
Unit 1 Steam-Electric 1977 Coal 555
- -----------------------------------------------------------------------------------------------
Unit 2 Steam-Electric 1982 Coal 555
- -----------------------------------------------------------------------------------------------
Total 1110
- -----------------------------------------------------------------------------------------------
Coffeen Power Station
- -----------------------------------------------------------------------------------------------
Unit 1 Steam-Electric 1965 Coal 340
- -----------------------------------------------------------------------------------------------
Unit 2 Steam-Electric 1972 Coal 560
- -----------------------------------------------------------------------------------------------
Total 900
- -----------------------------------------------------------------------------------------------
Meredosia Power Station
- -----------------------------------------------------------------------------------------------
Unit 1 Steam-Electric 1948 Coal 62
- -----------------------------------------------------------------------------------------------
Unit 2 Steam-Electric 1949 Coal 62
- -----------------------------------------------------------------------------------------------
Unit 3 Steam-Electric 1960 Coal 215
- -----------------------------------------------------------------------------------------------
Unit 4 Steam-Electric 1975 Oil 168
- -----------------------------------------------------------------------------------------------
Total 507
- -----------------------------------------------------------------------------------------------
Hutsonville Power Station
- -----------------------------------------------------------------------------------------------
Unit 3 Steam-Electric 1953 Coal 76
- -----------------------------------------------------------------------------------------------
Unit 4 Steam-Electric 1954 Coal 77
- -----------------------------------------------------------------------------------------------
Total 153
- -----------------------------------------------------------------------------------------------
Grand Tower Power Station (to be repowered)
- -----------------------------------------------------------------------------------------------
Unit 3 Steam-Electric 1951 Coal 85
- -----------------------------------------------------------------------------------------------
Unit 4 Steam-Electric 1958 Coal 105
- -----------------------------------------------------------------------------------------------
Total 190
===============================================================================================
Totals 2860
===============================================================================================
[LOGO] S&W Consultants, Inc. A-1
Table 1-2. Summary of Asset Characteristics: Gas-fired Stations
===============================================================================================
Station/Unit Type Commercial Fuel Capacity (MW)
Operation Date
- -----------------------------------------------------------------------------------------------
Summer (net)
- -----------------------------------------------------------------------------------------------
Operating CT Units
- -----------------------------------------------------------------------------------------------
Gibson City Power Station
- -----------------------------------------------------------------------------------------------
Unit 1 CT achieved Gas or oil 115
- -----------------------------------------------------------------------------------------------
Unit 2 CT achieved Gas or oil 115
- -----------------------------------------------------------------------------------------------
Total 230
- -----------------------------------------------------------------------------------------------
Pinckneyville Power Station
- -----------------------------------------------------------------------------------------------
Unit 1 CT achieved Natural gas 42
- -----------------------------------------------------------------------------------------------
Unit 2 CT achieved Natural gas 42
- -----------------------------------------------------------------------------------------------
Unit 3 CT achieved Natural gas 42
- -----------------------------------------------------------------------------------------------
Unit 4 CT achieved Natural gas 42
- -----------------------------------------------------------------------------------------------
Total 168
- -----------------------------------------------------------------------------------------------
Joppa Power Station
- -----------------------------------------------------------------------------------------------
Unit 1 CT achieved Natural gas 62
- -----------------------------------------------------------------------------------------------
Unit 2 CT achieved Natural gas 62
- -----------------------------------------------------------------------------------------------
Unit 3 CT achieved Natural gas 62
- -----------------------------------------------------------------------------------------------
Total 186
- -----------------------------------------------------------------------------------------------
Committed Units
- -----------------------------------------------------------------------------------------------
Grand Tower Power Station (repower)
- -----------------------------------------------------------------------------------------------
Unit 1/3 Combined cycle 06/01 Natural gas 239
- -----------------------------------------------------------------------------------------------
Unit 2/4 Combined cycle 07/01 Natural gas 253
- -----------------------------------------------------------------------------------------------
Total 492
- ----------------------------------------------------------------------------------------------
Kinmundy Power Station
- -----------------------------------------------------------------------------------------------
Unit 1 CT 06/01 Gas or oil 115
- -----------------------------------------------------------------------------------------------
Unit 2 CT 06/01 Gas or oil 115
- -----------------------------------------------------------------------------------------------
Total 230
===============================================================================================
Totals 1306
===============================================================================================
The location of each of the Assets is shown on Figure 1-1.
[LOGO] S&W Consultants, Inc. A-2
Figure 1-1. Asset Location
[A map depicting the State of Illinois and the surrounding areas that
illustrates the locations of Genco's assets and indicates whether each such
location has coal-fired, gas-fired or repowered units. This figure shows the
following: Gibson City CTs (gas-fired), Meredosia Station (coal-fired), Coffeen
Station (coal-fired), Hutsonville Station (coal-fired), Newton Station (coal-
fired), Kinmundy CTs (gas-fired), Pinckneyville CTs (gas-fired), Grand Tower
Station (repower) and Joppa CTs (gas-fired).]
[LOGO] S&W Consultants, Inc. A-3
From the perspective of the portfolio as a whole, i.e., Coal-fired Stations and
Gas-fired Stations, Figures 1-1 show (a) total generation, (b) revenues and (c)
capacity broken down by dispatch type, i.e., base load, intermediate or peaking
service. The base load units contribute the majority of the portfolio capacity,
generation and corresponding revenues. Note that the leased station (Joppa) is
not considered as contributing to total generation.
Figure 1-1(a)
----------------------------------------------------
Operating Mode as Percentage of Total Generation
(2002)
[A pie chart showing the composition of total generation by dispatch type. The
chart indicates the following break-down: base load service, 13,439 GWh (87% of
total generation); intermediate service, 1920 GWh (12% of total generation); and
peaking service, 170 GWh (1% of total generation).]
Figure 1-1(b)
----------------------------------------------------
Operating Mode as Percentage of Total Revenues
(2000-2004)
[A pie chart showing the composition of total revenues by dispatch type. The
chart indicates the following break-down: base load service, 73% of total
revenues; intermediate service, 18% of total revenues; peaking service, 7% of
total revenues; and the leased Joppa Station, 2% of total revenues.]
Figure 1-1(c)
----------------------------------------------------
Operating Mode as Percentage of Total Capacity
[A pie chart showing the composition of total capacity by dispatch type. The
chart indicates the following break-down: base load service, 2010 MW (50% of
total capacity); intermediate service, 984 MW (25% of total capacity); peaking
service, 796 MW (20% of total capacity); and the leased Joppa Station, 186 MW
(5% of total capacity).]
[LOGO] S&W Consultants, Inc.
A-4
Figure 1-2 shows the composition, by fuel type, of total capacity and revenues.
Figure 1-2(a) Figure 1-2(b)
---------------------------------------------------- ----------------------------------------------------
Fuel Type as Percentage of Total Capacity Fuel Type Percentage of Revenues
(2002) (2002)
[A pie chart showing the composition of total [A pie chart showing the composition of revenues
capacity by fuel type. The chart indicates the by fuel type. The chart indicates the following
following break-down: coal, 2502 MW (63% of break-down: coal, 79% of revenues; gas, 19% of
total capacity); natural gas, 1306 MW (33% of revenues; and oil, 2% of revenues.]
total capacity); and oil, 168 MW (4% of total
capacity).]
---------------------------------------------------- ----------------------------------------------------
Similarly, Figure 1-3 shows the composition, by technology type, of total
capacity and revenues.
Figure 1-3(a) Figure 1-3(b)
---------------------------------------------------- ----------------------------------------------------
Technology Type as Percentage of Total Capacity Technology Type as Percentage of
(2002) Revenues (2002)
[A pie chart showing the composition of [A pie chart showing the composition of
total capacity by technology type. The revenues by technology type. The chart
chart indicates the following break-down: indicates the following break-down:
steam-electric technology, 2670 MW (67% of steam-electric technology, 80% of revenues;
total capacity); combustion turbine combined cycle technology, 10% of revenues;
technology, 823 MW (21% of total capacity); and combustion turbine technology,
and combined cycle technology, 492 MW (12% of 10% of revenues.]
total capacity).]
--------------------------------------------------- ----------------------------------------------------
This Independent Technical Review (the "Report"), including the observations and
conclusions presented herein, is based on, among other things, our review of the
available technical, performance and cost data (documents listed as Appendix A),
visits to each facility and interviews with Ameren personnel (some of whom are
now Genco personnel). The Report presents our findings and conclusions regarding
the following:
. The condition and expected remaining life of the existing assets;
. The design and construction schedules of the Gas-fired Stations;
. The projected capital costs, operating and maintenance expenses, and
environmental issues relating to the future operation and maintenance of
the facilities;
. The terms (technical) of the Electric Power Supply Agreements, Operation
and Maintenance ("O&M") Agreements and Fuel Supply Agreements; and
[LOGO] S&W Consultants, Inc. A-5
. The pro forma financial model ("Financial Model"), including Genco's
projected cash flows and debt service coverages.
1.1 Coal-fired Stations
The Coal-fired Stations include Newton, Coffeen, Meredosia, Hutsonville and
Grand Tower. S&W Consultants' conclusions regarding condition assessment,
performance, O&M, and environmental compliance of each station are presented in
the following sections. The costs for planned projects and improvements
discussed below are reflected in the Financial Model.
1.1.1 Condition Assessment
The Newton Power Station consists of two essentially identical steam-electric
generating units. Units 1 and 2 are balanced draft, reheat, coal-fired units
each rated at 555 MW net. The units were placed in base load operation in 1977
and 1982. Cooling water to supply the once-through cooling system for the units
is taken from and discharged back to a man-made lake. The units are equipped
with electrostatic precipitators for control of particulate emissions. Unit 1
uses low NO\\x\\ burners for NO\\x\\ control. Unit 2 currently has no special
provisions for NO\\x\\ control, but the station plans to install a low NO\\x\\
burner system in 2001. SO\\2\\ is controlled by firing low sulfur coal,
currently Powder River Basin ("PRB") coal.
The Newton boilers are in good overall condition. The normal base loading of the
units has contributed to prolonging the life of boiler components. Both boilers
will require economizer, secondary superheater and pendant finishing reheater
replacement for which budgetary allocation has been made. The use of PRB coal in
1998 and 1999 resulted in some increased tube erosion and redistribution of heat
absorption but the transition has been reasonably smooth. The capital budget for
boiler improvements reflects expected replacements due to normal aging.
The Newton turbine generators are of a class of General Electric units which
have a well documented class history. As with the boilers, the turbine
maintenance and capital budgets reflect results of recent inspections and
overhauls coupled with industry experience with this class.
Both Newton units are fully capable of reliable base load operation for at least
20 additional years provided that a comprehensive non-destructive testing and
inspection program is followed. The units are currently in very good condition
and appear to be well maintained. The Newton Power Station was found to be very
clean when compared to similar stations of this type and age.
The Coffeen Power Station consists of two steam-electric generating units. Units
1 and 2 are balanced draft, reheat, coal-fired units rated at 340 MW and 560 MW
net, respectively. The units were placed in base load operation in 1965 and
1972. The station appeared to be reasonably well maintained and in good
condition. Cooling water for the main condensers is taken from and discharged to
a man-made lake. Units 1 and 2 are equipped with electrostatic precipitators for
particulate control. Units 1 and 2 have no special provisions for SO\\2\\
control. Unit 1 has no special provisions for NO\\x\\ control. Unit 2 presently
employs cyclone burners with an over-fire air ("OFA") system installed in
December 1999. Selective catalytic reduction systems ("SCRs") are planned for
both units in the 2000-2003 time frame.
Both boilers are in overall good condition and could be operated at least
through the term of the financing provided timely maintenance is performed and
replacements are made. Historical base load operation of the units has
contributed to prolonging the useful life of boiler components. Superheater and
reheater tube replacements will be required in the future. The projected Coffeen
capital budget reflects normal replacements due to aging.
[LOGO] S&W Consultants, Inc. A-6
As with Newton, the Coffeen turbine generators each have a well documented class
history. High pressure ("HP") and intermediate pressure ("IP") inlet stage
erosion has been addressed by periodic replacements with erosion resistant
coatings. Gradual shell distortion will require straightening and eventual
replacement. The rotor bores have been inspected with no potential end of life
defects detected.
Both Coffeen units should be fully capable of reliable base load operation for
20 additional years provided that a comprehensive non-destructive testing and
inspection program is followed and used to schedule major maintenance and
replacements. The units are in good condition and appear to be well maintained.
The Meredosia Power Station consists of four steam-electric generating units.
Units 1 and 2 are essentially identical, balanced draft, nonreheat, coal-fired
units rated at 62 MW net. These units were placed in service in 1948 and 1949.
Unit 3 is a twin furnace design balanced draft, reheat, coal-fired unit rated at
215 MW net. Unit 3 was placed in service in 1960. Unit 4 is a pressurized,
reheat, oil-fired unit rated at 168 MW net. Unit 4 was placed in service in
1975. The station appeared to be well maintained and in good condition,
considering the age of Units 1 and 2 and the historically infrequent operation
of Unit 4.
The major power generation equipment is located indoors with the exception of
the Unit 4 boiler which is located outdoors. Condenser cooling water for Units
1-3 is taken from and discharged back to the Illinois River. Unit 4 utilizes a
mechanical draft cooling tower and closed-loop system for condenser cooling.
Units 1, 2, and 3 are equipped with electrostatic precipitators for control of
particulates; Unit 4 has no precipitator. Units 1, and 2 and have no special
provisions for NO\\x\\ control. Unit 3 had ABB-CE level 1 low NO\\x\\ burners
installed in 1997. The Unit 4 boiler is equipped with over-fire air and gas
recirculation to allow for NO\\x\\ control. None of the units have provisions
for control of SO\\2\\ emissions.
Meredosia Units 1 and 2 are older, less efficient units that have been utilized
as peaking units in recent years, but are projected to provide intermediate
service in the future. The expected capital requirements would be to compensate
for the effects of additional component aging of the boilers through planned
replacements and maintenance for 20 years or as long as they remain economically
competitive. The boilers would be expected to require more intensive
non-destructive testing if they are to remain in service for an extended period
of up to 30 years. Turbine replacement has been budgeted.
The current condition of Meredosia Unit 3 would permit an additional 20 years of
operation. NO\\x\\ levels were brought into compliance with the addition of low
NO\\x\\ burners and overfire air. Superheater and reheater pendants should be
replaced. Extensive tube erosion shield replacement will continue to be
necessary. It is likely that the superheater and reheater outlet headers would
require replacement to achieve 20 years of additional reliable life in
intermediate service. The primary superheater will also require rebuilding. It
is recommended that non-destructive testing be intensified to establish a
condition baseline for future economic operation. In addition to the
aforementioned items, turbine replacement has been budgeted.
Meredosia Unit 4 can continue in operation as a peaking unit for 20 years
provided that a comprehensive non-destructive testing and inspection program is
instituted. Peaking duty imposes more severe stresses and can result in
accelerated component life consumption. The winter unit layup periods must be
done under dry conditions and boilers and other equipment should be protected
with a nitrogen blanket. It is unlikely that the unit would ever be returned to
base load service firing oil, and natural gas is not currently available at the
site. Considering the low projected capacity factor, the next scheduled overhaul
should include a more complete turbine dismantling to establish a baseline
condition of shells, rotor and steam path components.
[LOGO] S&W Consultants, Inc. A-7
The Hutsonville Power Station currently consists of two steam-electric
generating units. Units 3 and 4 are identical balanced draft, reheat, coal-fired
steam-electric generating units rated at 76 and 77 MW net respectively. The
units were placed in service in 1953 and 1954. The station appeared to be well
maintained and in reasonably good condition, particularly considering its age.
Water for the station's once-through cooling system is taken from and discharged
back to the Wabash River. The units are equipped with electrostatic
precipitators for control of particulate emissions. The units have no special
provisions for NO\\x\\ or SO\\2\\ control.
Hutsonville Units 3 and 4, although found to be in apparent good condition for
their age, have operated in recent years at low capacity factors. This operating
mode involves more frequent cycling which tends to increase component stress
levels and consume remaining life at a more rapid rate. Both units are nearly 50
years old and the recent history of non-destructive examination and testing
("NDE/NDT") and metallurgical testing is quite limited. Steam turbine
replacement has been budgeted. With this capital expenditure and others that
could potentially be identified through a resumption of NDE, the Hutsonville
units can be operated reliably in intermediate service as projected for another
20 years. A modern burner management system will also be required and has been
budgeted. It is likely that some additional impacts of the low capacity factor
cyclic operation will be detected in both boilers. It will be necessary to
perform tube, header and piping inspections to identify other component
replacements in order to operate until 2020.
The Grand Tower Power Station currently consists of two steam-electric
generating units. The boilers are to be retired in November 2000 and March 2001.
Unit 3 is a balanced draft, nonreheat, coal-fired unit rated at 85 MW net. Unit
3 was placed in service in 1951. Unit 4 is a balanced draft, reheat, coal-fired
unit rated at 105 MW net. Unit 4 was placed in service in 1958. Cooling water
for the main condensers is taken from and discharged back to the Mississippi
River in a once-through system. Units 3 and 4 are equipped with electrostatic
precipitators for control of particulate emissions. Units 3 and 4 have no
special provisions for NO\\x\\ or SO\\2\\ control.
The station is in the process of being repowered as a gas-fired combined cycle
unit scheduled to go into commercial operation, providing intermediate service,
in 2001. The majority of the existing fuel systems and steam generation
equipment and auxiliaries will be retired in place. The existing Unit 3 and 4
steam turbines will be repowered with two SWPC 501FD CTs. Each CT is rated
approximately 176 MW (gross, 59(Degrees)F). After the repowering, the Unit 3 and
4 steam turbines will be rated at approximately 90 MW and 112 MW net
respectively. Nomenclature for the two combined cycle systems will be Unit 1/3
(239 MW net) and Unit 2/4 (253 MW net). 30 years of reliable operation should be
achievable with appropriate operation and maintenance. The capital expenditures
budget includes future replacement of both steam turbines. The station is
projected to provide intermediate service.
1.1.2 Performance
S&W Consultants reviewed the technical inputs to the Market Consultant's
dispatch simulation model for the Coal-fired Stations. The key input data, such
as claimed capacity, scheduled and forced outage rates and heat rates were
reasonable and consistent with recent historical experience. Historical
performance was also compared to the NERC industry-wide data for similar sized
units with the same fuel type, and a discussion is provided for each station.
The five-year historical averages and the Market Consultant's projected
performance forecasts are summarized in Table 1.1-1 below for the existing
Coal-fired Stations that will remain in service. Projected values are averaged
over 20 years.
[LOGO] S&W Consultants, Inc. A-8
Table 1.1-1. Station Performance Summary
===================================================================================================================================
Newton Coffeen Meredosia Hutsonville
- -----------------------------------------------------------------------------------------------------------------------------------
Historical Forecast Historical Forecast Historical Forecast Historical Forecast
(5-yr avg.) (20-yr avg.) (5-yr avg.) (20-yr avg.) (5-yr avg.) (20-yr avg.) (5-yr avg.) (20-yr avg.)
- -----------------------------------------------------------------------------------------------------------------------------------
Capacity Factor (%)
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 1 62.1% 82.7% 39.1% 63.6% 24.1% 30.6% - -
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 2 56.8% 84.3% 51.0% 67.6% 21.6% 29.8% - -
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 3 - - - - 46.7% 44.1% 40.4% 20.3%
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 4 - - - - 2.5% 0.4% 37.8% 23.0%
- -----------------------------------------------------------------------------------------------------------------------------------
EAF (%)
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 1 82.6% 82.8% 67.8% 76.3% 84.2% 86.4% - -
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 2 82.5% 88.5% 71.6% 78.7% 84.7% 84.2% - -
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 3 - - - - 73.7% 87.2% 82.2% 84.6%
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 4 - - - - 57.8% 57.5% 82.0% 88.5%
- -----------------------------------------------------------------------------------------------------------------------------------
EFOR (%)
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 1 6.2% 9.7% 13.3% 12.7% 22.3% 9.1% - -
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 2 5.2% 9.0& 12.5% 13.0% 11.1% 9.1% - -
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 3 - - - - 8.9% 6.0% 7.9% 7.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 4 - - - - 68.3% 28.3% 8.0% 7.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh)
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 1 10,107 10,107 10,871 10,871 13,209 13,209 - -
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 2 10,306 10,306 10,407 10,407 13,209 13,209 - -
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 3 - - - - 10,461 10,461 11,006 11,006
- -----------------------------------------------------------------------------------------------------------------------------------
Unit 4 - - - - 25,502 25,502 10,921 10,921
===================================================================================================================================
Capacity factor forecasts are also shown in Figure 1-4. The
higher-than-historical capacity factors at Newton, Coffeen, and Meredosia are
attributable mainly to reductions in the delivered price of coal due to recent
fuel contract re-negotiations and as reflected in the Market Consultant's coal
pricing projections relative to natural gas pricing. Newton additionally
benefits from a fuel switch to PRB coal, which has lower associated
environmental compliance costs. These stations were designed for base load
service and should be able to safely and reliably meet these capacity factor
projections, assuming that appropriate operations and maintenance practices are
followed and budgeted capital projects implemented (as reflected in the budget
forecasts).
The projected increases in equivalent availability factor ("EAF") for some units
are due to decreased planned outage durations and potential to decrease forced
outages. Projected heat rates were based on recent historical performance. S&W
Consultants finds these assumptions reasonable.
[LOGO] S&W Consultants, Inc. A-9
Figure 1-4. Projected Capacity Factors (Coal -fired Stations)
================================================================================
[Four separate line graphs illustrating the projected capacity factors for the
four coal-fired stations. The graphs illustrate the following: (1) Newton
capacity factors for Units 1 and 2 for the years 2000 through 2020; (2) Coffeen
capacity factors for Units 1 and 2 for the years 2000 through 2020; (3)
Meredosia capacity factors for Units 1, 2, 3 and 4 for the years 2000 through
2020; and (4) Hutsonville capacity factors of Units 3 and 4 for the years 2000
through 2020.]
Graph 1 - Newton
- -------------------------------------------------------------------------------------------------------------------------
Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- -------------------------------------------------------------------------------------------------------------------------
Newton 1 85% 84% 84% 85% 84% 83% 84% 84% 84% 84% 84%
- -------------------------------------------------------------------------------------------------------------------------
Newton 2 86% 86% 86% 85% 85% 84% 84% 84% 84% 85% 85%
- -------------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------
Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- --- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------------------------------
Newton 1 84% 85% 85% 85% 85% 85% 86% 86% 86% 86%
- ----------------------------------------------------------------------------------------------------------------
Newton 2 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
- ----------------------------------------------------------------------------------------------------------------
Graph 2 - Coffeen
- ------------------------------------------------------------------------------------------------------------------------
Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- --- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ------------------------------------------------------------------------------------------------------------------------
Coffeen 1 61% 65% 60% 52% 52% 55% 57% 58% 59% 61% 62%
- ------------------------------------------------------------------------------------------------------------------------
Coffeen 2 69% 73% 69% 59% 58% 59% 61% 61% 63% 65% 65%
- ------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ---- --- ---- ---- ---- ---- ---- ---- ---- ---- ----
- --------------------------------------------------------------------------------------------------------------
Coffeen 1 71% 73% 73% 73% 73% 74% 74% 74% 74% 75%
- --------------------------------------------------------------------------------------------------------------
Coffeen 2 74% 75% 75% 76% 76% 76% 77% 77% 77% 77%
- --------------------------------------------------------------------------------------------------------------
Graph 3 - Meredosia
- -------------------------------------------------------------------------------------------------------------------------
Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- -------------------------------------------------------------------------------------------------------------------------
Unit 1 17% 19% 14% 14% 16% 19% 20% 22% 25% 27% 24%
- -------------------------------------------------------------------------------------------------------------------------
Unit 2 16% 19% 15% 13% 16% 19% 20% 21% 25% 27% 24%
- -------------------------------------------------------------------------------------------------------------------------
Unit 3 33% 44% 35% 24% 25% 30% 34% 35% 42% 45% 42%
- -------------------------------------------------------------------------------------------------------------------------
Unit 4 0.9% 0.6% 0.4% 0.4% 0.4% 0.2% 0.2% 0.2% 0.2% 0.1% 0.1%
- -------------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------
Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------------------------------
Unit 1 27% 29% 31% 35% 38% 38% 41% 43% 46% 49%
- ----------------------------------------------------------------------------------------------------------------
Unit 2 27% 28% 30% 34% 38% 38% 41% 43% 46% 49%
- ----------------------------------------------------------------------------------------------------------------
Unit 3 48% 48% 50% 54% 59% 60% 63% 66% 68% 70%
- ----------------------------------------------------------------------------------------------------------------
Unit 4 0.1% 0.2% 0.1% 0.1% 0.6% 0.6% 0.7% 0.7% 0.8% 1.0%
- ----------------------------------------------------------------------------------------------------------------
Graph 4 - Hutsonville
- -------------------------------------------------------------------------------------------------------------------------
Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- --- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- -------------------------------------------------------------------------------------------------------------------------
Unit 3 19% 17% 16% 15% 16% 21% 22% 22% 26% 25% 26%
- -------------------------------------------------------------------------------------------------------------------------
Unit 4 23% 22% 19% 16% 18% 22% 23% 24% 28% 29% 29%
- -------------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------
Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------------------------------
Unit 3 31% 31% 33% 37% 41% 42% 44% 46% 49% 51%
- ----------------------------------------------------------------------------------------------------------------
Unit 4 32% 36% 38% 40% 45% 45% 48% 50% 53% 56%
- ----------------------------------------------------------------------------------------------------------------
1.1.3 O&M
S&W Consultants reviewed staffing, O&M, and capital expense information provided
by Genco and Ameren corporate management and station operations personnel. The
O&M expenses forecasted by Geneco and Ameren are consistent with the staffing
operating plan shown in the Financial Model. The staffing is projected to remain
constant over time for most of the Assets. S&W Consultants found the projected
staffing, summarized in Figure 1-5 (including both Coal-and Gas-fired Stations)
to be reasonable, sufficient and comparable to levels at independent power
producer ("IPP") operated facilities. As is typical, the coal-fired units
require relatively more maintenance than the gas-fired units, and have
correspondingly higher labor requirements. Staffing levels at Hutsonville, while
higher than the other stations, are reasonable when considering the smaller
station capacity, age of the station, and level of automation. The O&M expenses
appear reasonable and adequate for the continued safe and reliable operation of
the Assets.
[LOGO] S&W Consultants, Inc. A-10
Figure 1-5.
-----------------------------------------------------------------
Number of Employees per MW Capacity
[A bar graph showing the projected number of employees per MW capacity at the
following stations: Newton (0.19), Coffeen (0.27), Meredosia (0.27), Hutsonville
(0.53), Grand Tower (after repowering) (0.10), Gibson City (0.02), Kinmundy
(0.02) and Pinckneyville (0.05).]
-----------------------------------------------------------------
S&W Consultants reviewed detailed capital and overhaul expense forecasts
provided by Ameren for each of the Assets. These budgeted expenses were reviewed
and found to be adequate to support the continued operation of the Assets at the
level (i.e., capacity factor) projected through 2020. Based on S&W Consultants'
review, there are no known existing conditions that would preclude operation of
the assets through 2020 assuming enhancement of condition assessment programs
(including NDE/NDT), maintenance and capital improvement programs as reflected
in the Financial Model and as appropriate considering the age(s) of the Assets.
1.2 Gas-fired Stations
1.2.1 Operating CT Units
The Gibson City Power Station is a nominal 230 MW (net) peaking station
consisting of two Siemens Westinghouse ("SWPC") 501D5A combustion turbine
generators ("CTG" or "CT") operating on simple cycle. The primary fuel is
natural gas, but the units have oil firing capability. The CTs are equipped with
dry low-NO\\x\\ burners for NO\\x\\ control while firing gas and will utilize
water injection for NO\\x\\ control while firing oil. The total installed cost
is estimated to be $99.0 million. This is equivalent to $423/kW installed based
on gross capacity. The cost appears attractive for a simple cycle peaking plant.
The project is now in commercial operation.
The Pinckneyville Power Station is a nominal 168 MW grassroots simple cycle
plant comprised of four GE LM6000PC CTGs to be packaged by S&S Energy Products,
which is a GE Power System business. The CTs will be fired on natural gas. The
total project cost was $99.7 million, or $593/kW installed, at summer rating.
The project is now in commercial operation.
[LOGO] S&W Consultants, Inc. A-11
The Gibson City and Pinckneyville Power Stations are operating in peaking mode.
The Joppa Power Station consists of three GE Frame 7B gas-fired CTGs, which have
been operational since 1974 and were recently refurbished and relocated to the
Joppa site. These three units have a combined capacity of 186 MW. Genco has
entered into a lease agreement with Ameren Energy Development Company
("Development") wherein these CTs are leased to Development for a minimum term
of 15 years. Under the lease agreement, Genco has no operational or performance
obligations, e.g., capacity, heat rate or availability, for these machines. The
scope of the refurbishment and upgrade, coupled with prudent operation and
appropriate maintenance by the lessee, should assure operation of the Joppa CTs
through the term of the Financial Model. The project is now in commercial
operation and its cost is estimated at $77.6 million or $417/kW.
1.2.2 Committed Units
The Committed Units are to be transferred to Genco only upon completion.
The repowered combined cycle Grand Tower Power Station will be comprised of two
Siemens Westinghouse ("SWPC") 501FD CTGs, new heat recovery steam generators
("HRSGs"), and the existing steam turbines. The CTs will be fired on natural gas
and the existing coal fired boilers will be retired. Upon completion of the
project, nominal gross plant output is expected to be approximately 492 MW net.
Total installed cost for the repowering project is estimated at $176.2 million
or $358/kW counting the existing steam turbines. Construction at the site began
in March 2000. Commercial operation dates ("COD") of the repowered Units 1/3 and
2/4 are expected to be June and July 2001, respectively. S&W Consultants
believes that these CODs are achievable.
The Grand Tower Power Station is projected to provide intermediate service.
The Kinmundy Power Station will consist of two Siemens Westinghouse W501D5A CTGs
operating on simple cycle. Nominal station capacity is 230 MW. The CTs will be
equipped with dual fuel combustors (i.e., will run on either gas or oil) and
will have water injection for NOx control (oil firing). The primary fuel for the
CTs will be natural gas. The total installed cost is estimated to be $96.25
million. This is equivalent to $418/kW installed based on gross capacity. The
cost appears attractive for a simple cycle peaking plant.
Project construction (site preparation) started on September 13, 1999 but was on
hold during the winter. The site is again under construction with the tanks,
building, and foundations well under way. The first CT has been delivered to the
rail siding along with the two step up transformers. The first generator is
expected on December 15, 2000 and the remaining CT and generator will arrive in
early 2001. The schedule as of August, 2000 indicates that Unit 1 will enter
commercial operations in April 2001 and the second unit will enter commercial
operations in June 2001.
The Kinmundy Power Station is projected to operate in peaking mode.
1.2.3 O&M
Genco will operate and maintain the Grand Tower Power Station. While the
detailed operating plan will not be fully developed until later this year, the
Financial Model reflects O&M budgets that S&W Consultants considers reasonable.
[LOGO] S&W Consultants, Inc. A-12
Ameren Intermediate Holding Co. Inc. (now Ameren Energy Resources Company) and
Siemens Westinghouse Operating Services Company ("Operator") have entered into
an Operations and Maintenance Agreement for the Gibson City, Kinmundy, and
Pinckneyville Power Plants. The agreement will remain in effect until May 31,
2010. The Operator will provide personnel to operate the plant and will
supervise repairs and contractors on behalf of the owner. We believe the
agreement is reasonable.
1.3 Project Agreements
S&W Consultants reviewed the major Genco agreements and contracts and is of the
opinion that, in general, the technical requirements are comprehensive,
reasonable, and achievable as well as consistent among and between the various
documents. The key technical aspects of the following documents were reviewed:
. Asset Transfer Agreement
. Electric Power Supply Agreements
. Agency Agreement
. Operation & Maintenance Agreement
. Fuel Supply Agreements
Capitalized terms not defined herein are assumed to have the same meaning as
defined in the respective contracts.
1.4 Conclusions
1.4.1 Coal-fired Stations
. The Newton, Coffeen, Meredosia and Hutsonville Power Stations were found to
be well maintained and generally in good condition as compared to similar
facilities of the same age. With the implementation of enhanced condition
monitoring programs and the forecasted capital improvements, these electric
generating facilities should continue to provide reliable power generation
through the term of the Financial Model.
. S&W Consultants reviewed the technical inputs to the Market Consultant's
dispatch simulation model. The key input data, such as claimed capacity,
scheduled and forced outage rates and heat rates were reasonable and
consistent with recent historical experience.
. The Assets are technically capable of performing at the capacity factors
projected by the Market Consultant.
. Genco's forecasted O&M expenses are consistent with Ameren's historical
expenditures and with other similar projects with which S&W Consultants is
familiar. The O&M expenses appear reasonable and adequate to meet Genco's
maintenance and performance objectives.
. The overhaul schedules developed by Ameren are prudent and consistent with
current operations. The overhaul and capital expenses forecasted in the
Financial Model are considered adequate to support the continued operation of
the Assets through 2020, assuming implementation and continuation of
condition assessment programs.
. The Assets are in compliance with current permit and consent order
requirements. Ameren's approach to the solutions to the environmental issues
identified is reasonable based on our experience.
. Genco plans to comply with current NO\\x\\ and SO\\2\\ emissions limitations
through the purchase of emissions credits and through capital expenditures,
e.g., SCR systems. These plans appear to be reasonable and adequate, based on
the currently available information.
[LOGO] S&W Consultants, Inc. A-13
. A Phase I environmental site assessment ("Environmental Site Assessment" or
"ESA") was conducted as part of this review, which indicated potential soil
and groundwater contamination at each of the Coal-fired Stations. Separately,
S&W Consultants notes that Central Illinois Public Service Company d/b/a
AmerenCIPS ("AmerenCIPS") has retained responsibility and indemnified Genco
with regard to all environmental damages or violation of any environmental
requirements attributable to or resulting from any action prior to the
Closing Date.
. S&W Consultants reviewed the major Genco agreements and contracts and is of
the opinion that, in general, the technical requirements are comprehensive,
reasonable, and achievable as well as consistent among and between the
various documents.
1.4.2 Gas-fired Stations
. The key input data to the Market Consultant's dispatch model, such as
capacity, availability and heat rates, were reasonable and consistent with
industry norms.
. Performance with respect to projected capacity factors is considered
achievable.
. The CT technologies (W501D5A, GE LM6000) are commercially proven and widely
used in the market.
. The SWPC 501FD (Grand Tower combined cycle), a refinement on the high
temperature W501F technology, incorporates advancements in low NO\\x\\
combustion technology, compressor and blade designs, and cooling technology.
These are typical of normal design improvements by manufacturers. The 501F
fleet, introduced in 1993, has a strong operational history, and several of
501FD units will have been in commercial operation for nearly a year by the
date which the Genco units are scheduled for start-up. Furthermore, the two-
year warranty under the CT supply contract with SWPC is considered
advantageous.
. If operated and maintained in accordance with the O&M agreement and
established operating plans and budgets, which are considered adequate, the
useful lives of the units are expected to exceed the term of the financing.
. A majority of the Gas-fired Stations' required permits have been acquired and
the permit acquisition plan for those permits not yet required is reasonable.
. The Phase I Environmental Site Assessments revealed no significant
environmental issues at the Gibson City, Pinckneyville and Kinmundy sites.
Grand Tower, as an existing station, is covered by the AmerenCIPS
indemnification referenced above.
. S&W Consultants reviewed the major Genco agreements and contracts and is of
the opinion that, in general, the technical requirements are comprehensive,
reasonable, and achievable as well as consistent among and between the
various documents.
1.4.2.1 Committed Units
- ------------------------
. The scopes of work, specifications and implementation plans in the available
equipment supply contracts, construction contracts, and design manuals were
reasonable and complete. Construction schedules are considered achievable.
Projected cost estimates appear to be reasonably consistent with costs of
comparable projects.
1.4.3 Financial Projections
. The availability, capacity and heat rate inputs used by the Market Consultant
to develop its projections of market prices and energy generation are
consistent with the values S&W Consultants has reviewed and found reasonable.
. The projected heat rate and capacity assumptions have been developed based on
historical data as modified to account for improvements that have been made
or are planned to be made to these
[LOGO] S&W Consultants, Inc. A-14
facilities. With continued capital investment, it is reasonable to expect
that the heat rates and capacities can be maintained over the period shown in
the Financial Model.
. Genco's maintenance and capital budgets, reflected in the Financial Model,
appear reasonable and adequate to meet the performance objectives safely and
reliably.
. S&W Consultants reviewed the technical and commercial assumptions and the
calculation methodology of the Financial Model. The technical assumptions
assumed in the Financial Model are reasonable and consistent with the
contracts reviewed. The Financial Model fairly presents, in S&W Consultants'
opinion, projected revenues and expenses under the base case assumptions.
. The projected revenues from the sale of capacity and energy are more than
adequate to pay the annual operating and maintenance expenses (including
provisions for major maintenance), other operating expenses, and debt
service. Under the base case assumptions, the average debt service coverage
ratio is calculated to be 5.4x from 2000 through 2010. The minimum debt
service coverage ratio is 4.4x and occurs in 2001 and 2003.
. Three sensitivity cases were prepared to test the impact of different market
forces on the energy and capacity prices forecast by the Market Consultant
and the associated impact on the DSCR. The market energy and capacity prices
were forecast assuming (i) the overbuilding of generation facilities in the
region, (ii) higher fuel prices, and (iii) lower fuel prices. The average
DSCR was most sensitive to the low fuel price sensitivity case. The average
DSCR in this case fell to 4.9x with a minimum of 4.4x in 2005. The average
DSCR is 5.3x in the overbuild sensitivity case and is 6.2x in the high fuel
price sensitivity case, with minimum DSCRs of 3.2x in 2003 and 4.0x in 2001,
respectively.
[LOGO] S&W Consultants, Inc. A-15
2 INTRODUCTION
S&W Consultants has prepared this Report of the Assets to be acquired by Genco
for Lehman Brothers, as Initial Purchaser for a Rule 144A bond offering by
Genco. This Report contains a description of the electric generating assets
acquired or to be acquired by Genco from AmerenCIPS and other affiliates, and
the results of an independent engineering assessment of these Assets. The Assets
acquired or to be acquired by Genco include the following:
. Newton Power Station
. Coffeen Power Station
. Meredosia Power Station
. Hutsonville Power Station
. Grand Tower Power Station
. Gibson City Power Station
. Kinmundy Power Station
. Pinckneyville Power Station
. Joppa Power Station
The Assets will have a combined electric generating capacity of approximately
3,976 MW (net), and are all fossil-fuel fired.
This Report, including the observations and conclusions presented herein, is
based on, among other things, our review of the available technical, performance
and cost data, visits to each facility and interviews with Ameren personnel
(some of whom are now Genco personnel). The Report presents our findings and
conclusions regarding the following:
. The condition and expected remaining life of the Coal-fired Stations;
. The design and construction schedules of the Gas-fired Stations;
. The projected capital costs, operating and maintenance expenses, and
environmental issues relating to the future operation and maintenance of
the facilities;
. The terms (technical) of the Electric Power Supply Agreements, O&M
Agreements and Fuel Supply Agreements; and
. The pro forma Financial Model, including Genco's cash flows and debt
service.
The principal considerations and assumptions used in completing this review
include:
. S&W Consultants has used data and information, provided to us, that we
assume to be accurate and reliable.
. S&W Consultants has assumed that the contracts, agreements, rules and
regulations associated with the transaction will be fully enforceable in
accordance with their terms and that all parties will comply with the
provisions of their respective agreements.
. S&W Consultants reviewed the operating plans and associated capital and
operating budgets summarized herein. We assume that Genco will operate the
assets in accordance with the operating plans.
2.1 Background
AmerenCIPS is an affiliated electric utility subsidiary of Ameren Corporation
that provides retail and wholesale electric service primarily in Illinois.
AmerenCIPS is restructuring its operations in compliance
[LOGO] S&W Consultants, Inc. A-16
with the Illinois Electric Service Customer Choice and Rate Relief Law of 1997.
In order to facilitate this restructuring, Ameren has formed an intermediate
holding company that will have several subsidiaries, including an exempt
wholesale generator, Genco, and a wholesale and retail marketing company, Ameren
Energy Marketing Company ("Marketing").
Pursuant to the restructuring, AmerenCIPS transferred all of its existing
electric generation units to Genco (Newton, Coffeen, Meredosia, Hutsonville and
Grand Tower Power Stations). In addition, Genco has acquired new CT units which
have recently entered commercial operation (Gibson City, Pinckneyville and Joppa
Power Stations), and will acquire combustion-turbine-based assets currently
under construction (Kinmundy and Grand Tower Power Stations).
Genco is certified as an Exempt Wholesale Generator ("EWG") under the Public
Utility Holding Company Act of 1935. As an EWG, Genco is prohibited by law from
making retail sales. Through December 31, 2004, Genco will sell the output of
its generating Assets to Marketing (except to the extent that Marketing releases
a portion of this capacity to Ameren Energy, Inc. ("Ameren Energy"), which will
then sell this capacity as agent for Genco). AmerenCIPS will then purchase all
of the electricity that is needed to meet the requirements of its customers from
Marketing. Any additional electricity not purchased by AmerenCIPS will be sold
by Marketing either directly to retail customers or to other wholesale
purchasers, or by Ameren Energy as previously described.
Operationally, the generation units of Genco and those of Union Electric Company
d/b/a/ AmerenUE ("AmerenUE"), an affiliated electric utility subsidiary of
Ameren that provides retail and wholesale electric service primarily in
Missouri, will continue to be operated on a single-system basis pursuant to an
Amended Joint Dispatch Agreement.
2.2 Scope of Services
S&W Consultants was retained to prepare a lenders' Independent Technical Review
for the financing being pursued by Genco. S&W Consultants' role as the
independent technical consultant is to review the principal aspects of the
assets to be financed. In general, S&W Consultants reviews work prepared by
others, and does not prepare original engineering design products or condition
assessments as part of the due diligence process. The review by S&W Consultants
is limited to technical issues and the possible impact of those issues on
commercial terms and conditions, and a review of Genco's principal commercial
contracts and Financial Model. A description of activities performed under each
task area follows.
TECHNICAL REVIEW OF COAL-FIRED STATIONS
- ---------------------------------------
Review of Condition Assessment
S&W Consultants visited the five Coal-fired Stations, formerly owned and
operated by AmerenCIPS, as part of the condition assessment review as shown
below:
Station Site Visit Date(s)
------------------------------------
Newton 2/14-15/2000
Coffeen 2/16-17/2000
Meredosia 2/10-11/2000
Hutsonville 2/9/2000
Grand Tower 2/17-18/2000
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The condition assessment results, summarized in this Report, are based on the
following:
. A visual inspection of each station and associated facilities;
. Interview with Ameren personnel (some of whom are now Genco personnel); and
. Review of available documentation.
We have included, to the extent applicable, our opinions on the adequacy of the
proposed O&M plans and remaining life, considering the current condition and
expected service duty. Retired-in-place or demolished units were not considered
under this review.
Historical and Projected Performance
S&W Consultants reviewed the historical performance (capacity, heat rate,
availability, capacity factor) of the units to evaluate the reasonableness of
the projected performance of the units. The effects of capital and operational
improvements were incorporated into the evaluation of the projected performance.
S&W Consultants also reviewed the technical ability of the Assets to provide
ancillary services, such as spinning reserves, non-spinning reserves, voltage
support and black start capability, although such ancillary revenues are not
included in the pro forma projections.
Review of O&M Plans and Budgets
S&W Consultants assessed the ability of the Assets to meet the projected
performance given the operation and maintenance plans and practices developed by
Ameren and/or Genco. We reviewed the planned outage schedule and commented on
the reasonableness of the projected availability figures. We reviewed the
operating and maintenance budget, including the planned maintenance and capital
projects plans, and provided opinions on the ability of Genco to meet the
associated performance and cost projections.
Contract(s) Review
S&W Consultants reviewed the technical issues of the various agreements
affecting the operations of the Plants. This included Electric Power Supply
Agreements, O&M Agreements and Fuel Supply Agreements. S&W Consultants reviewed
fuel supply issues within the site boundary for coal, oil and gas. Fuel
availability, commodity and transportation costs are the responsibility of
others.
TECHNICAL REVIEW OF GAS-FIRED STATIONS
- --------------------------------------
Design Review for Gas-fired Stations
S&W Consultants visited the project sites to confirm the overall suitability of
the site to accommodate the new projects:
Station Site Visit Date(s)
---------------------------------------------
Grand Tower 2/17/2000, 9/25/2000
Gibson City 2/16/2000
Kinmundy 2/16/2000, 9/25/2000
Pinckneyville 2/16/2000
The design review results, summarized in this Report, are based on the
following:
. A visual inspection of each site to determine suitability and ascertain
construction progress;
. Interview with Ameren personnel (some of whom are now
Genco personnel); and
. Review of available documentation.
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S&W Consultants reviewed the design of major equipment and systems with regard
to:
. Compatibility of design with operating requirements, site characteristics,
feedstock characteristics and quantities, and off-site transport
requirements.
. Ability of design to perform as required and projected in anticipated
operating modes.
. Capability of design to fulfill anticipated service life and meet
availability, reliability and performance requirements and projections.
. Conformance of design with "good engineering practice" (i.e., industry
standards).
PHASE 1 ENVIRONMENTAL
- ---------------------
Review of Environmental Assessment and Permitting Issues
S&W Consultants reviewed the available environmental documentation for the
Assets. We reviewed the technical requirements of operating permits and
discussed historical compliance with plant personnel. We determined whether
there were any significant non-compliance notifications in the recent past. We
reviewed and commented on the plans (including future emissions control
upgrades) for maintaining the Assets in compliance with their permits and the
cost associated with maintaining environmental compliance over the term of the
financing.
In addition, S&W Consultants subcontracted with Zephyr Environmental Corporation
("Environmental Consultant") for the conduct of a Phase I ESA, at each of the
new and existing generation sites. These Phase I ESAs focused on soil,
groundwater and other historic site contamination issues associated with
activities at these sites and at nearby properties. These Phase I ESAs also
considered current station practices which could potentially lead to future site
contamination issues.
FINANCIAL MODEL
- ---------------
Review of Financial Model
S&W Consultants conducted a detailed review of the Financial Model prepared by
Ameren and provided an opinion on the reasonableness of the operating costs,
capital expenditures, and availability assumptions over the term of the
financing. We confirmed that the Financial Model is consistent with the
operating program and project agreements. We commented on the adequacy of the
Financial Model to accurately reflect the expected revenues and expenses. S&W
Consultants reviewed the Resource Data International, Inc. ("Market Consultant")
report and other technical due diligence reports, as applicable, to verify the
reasonableness of model inputs. Sensitivity analyses have been conducted on
agreed-upon parameters.
[LOGO] S&W Consultants, Inc. A-19
3 COAL-FIRED STATIONS
The initial electric generating assets that have been transferred to Genco
include the following:
. Newton Power Station
. Coffeen Power Station
. Meredosia Power Station
. Hutsonville Power Station
. Grand Tower Power Station
These assets are all fossil fuel fired facilities (predominantly coal), and have
a combined electric generating capacity of approximately 2860 MW (net).
This section summarizes S&W Consultants' findings with respect to condition
assessment, remaining life, performance, O&M and environmental aspects of these
assets. The costs for planned projects and improvements described in the
following sections are included in Genco's O&M and capital expenditures budget
forecasts.
3.1 Condition Assessment
This condition assessment of these assets is based on a review of engineering
assessment reports prepared by the owners or third party technical advisors, and
supplemented with data gathered and observations made during limited site visits
to the stations. During the site visits, visual inspections were conducted to
assess the apparent condition, plant cleanliness, overall operability, and the
effectiveness of plant maintenance programs. S&W Consultants also interviewed
available key personnel, including technical specialists, O&M personnel, and
plant managers. In addition, S&W Consultants reviewed, to the extent made
available to us, the most recent inspection reports, outage and overhaul
reports, life assessment reports, and capital expenditure forecasts. These
observations, visual inspections, personnel interviews and additional data have
been used to update and complement the engineering assessment reports that form
the basis for the condition assessment and remaining life evaluation.
3.1.1 Newton Power Station
The Newton Power Station is located outside the town of Newton, Illinois. Access
to the site is by highway and rail. S&W Consultants visited the Newton Power
Station on February 14/th/ and 15/th/, 2000. The station appeared to be clean,
well maintained, and in good condition.
The station consists of two essentially identical steam-electric generating
units. Units 1 and 2 are balanced draft, reheat, coal-fired units each rated at
555 MW net. The units were placed in operation in 1977 and 1982. The major power
generation equipment is located indoors. Cooling water to supply the
once-through cooling system for the units is taken from and discharged back to a
man-made lake.
The units are equipped with electrostatic precipitators for control of
particulate emissions. Unit 1 uses low NO\\x\\ burners for NO\\x\\ control. Unit
2 currently employs the original burner design with two levels of close coupled
over-fire air ("CCOFA"), but the station plans to install a low NO\\x\\ burner
system in 2001. SO\\2\\ is controlled on Units 1 and 2 by firing compliance
coal, which is currently PRB coal.
Table 3.1-1 provides a summary of the major characteristics of Units 1 and 2.
The sections that follow detail our findings in the areas of mechanical,
electrical, and environmental systems condition and remaining life.
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TABLE 3.1-1
Newton Power Station Characteristics
==================================================================================================
PERFORMANCE UNIT 1 UNIT 2
--------------------------------------------------------------------------------------------------
Normal Summer Capacity (MW Net) 555 555
--------------------------------------------------------------------------------------------------
Minimum Load (MW) 200 220
--------------------------------------------------------------------------------------------------
Full Load Heat Rate, HHV (Btu/kWh) 10,103 10,099
--------------------------------------------------------------------------------------------------
PRIME MOVER
--------------------------------------------------------------------------------------------------
Manufacturer GE GE
--------------------------------------------------------------------------------------------------
Tandem Compound Tandem Compound
Type Four Flow Four Flow
--------------------------------------------------------------------------------------------------
Commissioned (Year) 1977 1982
--------------------------------------------------------------------------------------------------
HP Turbine Inlet Pressure/Temp (psig/(degrees)F) 2400/1000 2400/1000
--------------------------------------------------------------------------------------------------
Reheat Turbine Inlet Temp ((degrees)F) 1000 1000
--------------------------------------------------------------------------------------------------
ELECTRIC GENERATOR
--------------------------------------------------------------------------------------------------
Manufacturer GE GE
--------------------------------------------------------------------------------------------------
Cooling Hydrogen Hydrogen
--------------------------------------------------------------------------------------------------
MVA 686 686
--------------------------------------------------------------------------------------------------
STEAM GENERATOR
--------------------------------------------------------------------------------------------------
Manufacturer CE CE
--------------------------------------------------------------------------------------------------
No. of Boilers 1 1
--------------------------------------------------------------------------------------------------
Circulation Forced Forced
--------------------------------------------------------------------------------------------------
Draft Condition Balanced Balanced
--------------------------------------------------------------------------------------------------
Cycle Type Reheat Reheat
--------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal
--------------------------------------------------------------------------------------------------
OTHER
--------------------------------------------------------------------------------------------------
Cooling Water Source Lake Lake
--------------------------------------------------------------------------------------------------
Fuel Delivery Rail Rail
==================================================================================================
3.1.1.1 Mechanical Equipment and Systems
- -----------------------------------------
Major systems include the boilers, steam turbines, and balance of plant.
Boilers
The two boilers at the Newton Power Station are nearly identical Combustion
Engineering ("CE") single furnace, forced circulation, balanced draft, reheat
boilers and were placed into commercial operation in 1977 and 1982. The boilers
originally burned Midwest bituminous coal but presently burn PRB coal. Unit 1
was switched to PRB in May of 1998 and Unit 2 was switched in May of 1999. The
boilers presently operate primarily in intermediate service, but are capable of
and projected to provide base load service. There are no limitations on output
or steam conditions. Turndown is approximately 3 to 1 with a minimum of 200 MW
and 3 mill operation.
At the last inspection, the Unit 1 boiler had experienced a total of 324
start-ups. Of these 104 were classified as cold and 220 as hot (less than 48
hours off line). The boiler has operated a total of 148,124 hours since startup,
averaging 7,400 to 7,500 hours on line per year.
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Major overhaul of the Unit 1 boiler was last performed in the spring of 2000.
Major work performed during the last overhaul consisted of installation of long
retractable sootblowers at the superheater pendant assemblies, replacement of
transition welds, chemical cleaning and general repairs.
Overall the Unit 1 boiler is clean and in good condition. The boiler was running
at 550 MW during the site visit. The furnace lower slope is subject to ash
erosion. Chemical cleaning is done every 6 years and was last done in 1998. The
secondary (finishing) superheater is also considered in good condition.
Transition (dissimilar metal) welds in the final SH pendants are being replaced
during scheduled outages (about 150 per outage). All transition welds should be
replaced by 2002. The superheater division panels and platen superheater are
inspected and repaired during every scheduled outage. The reheater is in good
condition as well with the front and side radiant wall section considered in
excellent condition. The pendant/finishing sections are in fair condition. This
area is subject to sootblower erosion and flyash plugging/erosion. Shielding,
weld overlay and tube replacement are required every scheduled outage. This
section is to be redesigned and replaced within the next 5 years. The primary
superheater is considered in very good condition. Minimal maintenance is
required during scheduled outages. The economizer is in fair condition. The
economizer is a spiral fin/staggered tube design with insufficient spacing
especially for PRB coal. The economizer is subject to flyash plugging and
erosion and is to be redesigned and replaced within 5 years. Boiler ductwork is
in good condition.
The plant has been monitoring the condition of the superheater outlet leads,
reheat outlet leads and the economizer inlet header. Presently there are no
conditions requiring repairs. However, there have been high metal temperatures
in the reheater (1122(Degrees)F) and the reheat outlet leads are seamwelded.
Inspection of these leads must be done by 2001, according to the OEM, in order
to insure continued safe operation. The superheater outlet leads are not
seamwelded and are suitable for 5-7 year inspection intervals. They have been
subject to overheating but not as severe as the reheater. The economizer inlet
header is suitable for 5-8 years of additional service between NDT and internal
inspection. NDT inspection is done regularly including ultrasonic testing
("UT"), magnetic particle ("MP") and boroscopic examinations. Boiler water
treatment consists of hydrazine for oxygen control and ammonia for pH control.
Solids are controlled by blowdown.
NO\\x\\ control is accomplished with ABB's LNCFS Level 3 burner system utilizing
staged combustion and overfire air. Boiler output can be limited due to pluggage
of the economizer and resultant induced draft ("ID") fan runout. Although the
boiler has had a relatively easy start on PRB, flyash buildup and erosion should
be monitored closely to determine long term effects.
At the last inspection the Unit 2 boiler had experienced 196 cold starts and 121
hot starts. At that time the boiler had accumulated 84,191 hours of operation.
Major maintenance is performed every 24 months with cleaning outages as
necessary. The OEM is usually involved in each major boiler overhaul.
Major overhaul of the Unit 2 boiler was last performed in the spring of 1999.
The next major outage and inspection is scheduled for spring 2001. Major work
performed during the last overhaul consisted of air heater basket replacement,
replacement of transition welds, and reheater repairs.
Overall the Unit 2 boiler is clean and in good condition. The boiler was running
at 552 MW during the site visit. The boiler was burning Black Thunder PRB coal
which was limiting outlet superheat temperature to about 980(Degrees)F, somewhat
below the design temperature of 1005(Degrees)F. The furnace lower slope is
subject to ash erosion. Chemical cleaning is done every 6 years and was last
done in 1997. The secondary (finishing) superheater is also considered in good
condition. Transition (dissimilar metal) welds in the final SH pendants have all
been replaced. The superheater division panels and platen superheater are
inspected and repaired during every scheduled outage. The reheater is in good
condition
[LOGO] S&W Consultants, Inc. A-22
as well with the front and side radiant wall section considered in excellent
condition. The pendant/finishing sections are in fair condition. This area is
subject to sootblower erosion and flyash plugging/erosion. Shielding, weld
overlay and tube replacement are required every scheduled outage. This section
is to be redesigned and replaced within the next 10 years. The primary
superheater is considered in very good condition. Minimal maintenance is
required during scheduled outages. The economizer is in fair condition. The
economizer is a spiral fin/staggered tube design with insufficient spacing
especially for PRB coal. The economizer is subject to flyash plugging and
erosion. The economizer is to be redesigned and replaced within 5-10 years.
Boiler ductwork is in good condition.
The plant has been monitoring the condition of the boiler water wall tubing, and
superheater pendant division panel and the superheater pendant platen assembly
dissimilar metal welds. Presently there are no conditions requiring repairs or
affecting reliability. No significant degradation due to high temperatures was
found in the examined superheater areas during the most recent inspection
(1999). ABB recommended UT wall thickness mapping of the lower water wall slope
area in five years. Volumetric UT examination of the superheater division panels
and platen assemblies is recommended in 6 years. Boiler NDT inspection is done
regularly including UT, MP and boroscopic examinations. Boiler water treatment
consists of hydrazine for oxygen control and ammonia for pH control. Solids are
controlled by blowdown.
In 2001, new ABB TFS 2000R low NO\\x\\ burners with two levels of overfire air
will be installed on the Unit 2 boiler. New flame scanners and non-retractable
air cooled warmup guns will also be installed. As with boiler No. 1 the output
can be limited due to pluggage of the economizer and resultant ID fan runout.
Although the boiler has had a relatively easy start on PRB, flyash buildup and
erosion should continue to be monitored closely to determine long term effects.
Steam Turbines
The Newton turbine generators are duplicate General Electric 18 stage tandem
compound, four flow units with 30 inch last stage buckets. The units went into
commercial operation in 1977 and 1982 in an open cycle cooling system
configuration with a design back pressure of 3.5" Hg. They are very similar to
Coffeen Unit 2. The steam conditions are 2400 psig, 1000(Degrees)F main steam
and 1000(Degrees)F reheat. The units were purchased with 5% overpressure
capability but normally run at 2400 psi. The unit nameplate rating is 550,000 kW
with a normal output of 585,000 kW. The HP/IP section is an opposed double flow
element. The two low pressure ("LP") sections exhaust to separate two pass
condenser shells. There is a separate four-valve steam chest on the main
operating floor adjacent to the HP turbine. Steam is extracted from the IP
exhaust to supply two condensing boiler feed pump drive turbines.
Each turbine is equipped with the original Mark II electrohydraulic ("EH")
governor. Both units are equipped with a stop valve bypass for full arc
admission startup. The units were originally designed for base load operation
and are currently operated in load following mode. Unit 2 is equipped with a 5%
turbine bypass to the condenser for temperature matching on startup. The EH
governor provides the capability of selecting full arc or partial arc admission
on startup.
Records indicate that the units have the original shells and rotors. There is no
history of blade failures or shell cracking. Retractable HP/IP packing has been
added. The units have the required turbine water induction protection and the
extraction non-return valves are tested regularly.
The most recent Unit 1 LP turbine major overhaul was in 1992. Boresonic
inspections detected no reportable indications. Excessive inner shell horizontal
joint warpage and erosion was reported, along with some alignment difficulties.
Weld repair and machining was recommended at the next outage
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although potential replacement may become necessary. Progressive last stage
bucket erosion was reported. No shell defects were detected.
The most recent Unit 1 HP/IP turbine major overhaul was in 1994. Boresonic
inspection detected no reportable indications with reinspection recommended
within 10 years. Major 2/nd/ and 10/th/ stage diaphragm repairs were completed.
The 11/th/ stage bucket covers were replaced. A new nozzle box and 7/th/ stage
buckets and diaphragms were installed with a solid particle erosion resistant
design, which includes the blade setback modification.
The most recent Unit 2 HP/IP turbine overhaul was in 1995. A boresonic
inspection detected no significant indications. HP diaphragm partitions were
repaired. Minor cracks in the HP inner shell were repaired. The 11/th/ stage
bucket covers were replaced due to cracking. Major 2/nd/ stage diaphragm erosion
was repaired. A new nozzle box and 7/th/ stage buckets and diaphragms were
installed with a solid particle erosion resistant design with the blade setback
modifications.
The most recent Unit 2 LP turbine major overhaul was in 1997. Boresonic
inspections detected no reportable indications. Reinspection was recommended
within 10 years. A number of erosion repairs were completed on the LP B 13/th/
through 18/th/ stage diaphragm partitions. Similar partition repairs were
recommended for both LP sections at the next overhaul.
A visual inspection found both turbine areas reasonably clean with adequate
lighting and no accumulation of combustible materials. There were no active oil
leaks except a small area under a Unit 2 boiler feed pump turbine. There are no
curbs around the EH governor fluid and pumping module but both areas were very
clean and dry. The main turbine oil tanks are elevated without containment dikes
but are protected by fire nozzles.
Balance of Plant
The condenser cooling water is taken from and discharged to an onsite man-made
lake. The circulating water system consists of a common, unenclosed screenwell
structure for Units 1 and 2. Once ongoing upgrades are completed, the screens
should be in excellent condition.
The circulating water inlet piping between the screenwell and the powerhouse and
the discharge piping from the powerhouse to the lake is buried. After several
corrosion studies, portions of the circulating water system were internally
coated with cement in 1994 to provide greater corrosion protection. Smaller
in-plant carbon steel piping systems were replaced with stainless steel. The
Unit 1 and Unit 2 circulating water inlet piping and low pressure service water
lines were last inspected in 1996 by an outside contractor. The contractor
recommended additional protective linings for the circulating and service water
piping at the powerhouse end to combat ongoing corrosion. Reinspection at five
year intervals was recommended (next inspection would be due in 2001).
Each unit is equipped with a two-shell, two-pass, divided waterbox surface-type
condenser. The condensers are fitted with arsenical admiralty tubing in the main
condensing section and 90-10 Cu-Ni in the air offtake sections. The condensers
have not been retubed since their original installation. The Unit 1 condenser,
supplied by Southwestern, will be retubed in 2000. The Unit 2 condenser,
supplied by Westinghouse, was characterized by station personnel as being in
good condition. There are plans to retube the Unit 2 condenser in the 2003-2005
time frame.
The units have seven stages of feedwater heating, including the deaerating
heater. Replacements and/or retubing have been scheduled and budgeted
appropriately.
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Each unit has two identical 50% percent capacity DeLaval boiler feed pumps. Both
pumps are equipped with individual General Electric turbine drives. The pumps
are four-stage, centrifugal, barrel type machines. In general, the pumps have
proven to be reliable and were characterized as being in good condition by
station personnel.
In 1996, ABB C-E Services conducted a condition assessment of Unit 1 superheater
outlet and reheat outlet headers. The assessment included a limited portion of
the hot reheat piping. ABB found early indications of creep in a longitudinal
seam weld of the reheater outlet link piping. ABB concluded that the creep would
not affect the immediate serviceability of the piping, however ABB strongly
recommended that the remainder of the reheat piping be inspected at the next
scheduled outage. No records of subsequent inspections were found during S&W
Consultants' visit. No record was found of Unit 2 high energy piping inspections
during S&W Consultants' visit. Unit 2, five years younger than Unit 1, should
initiate inspections in the near future.
Electric Power Research Institute ("EPRI") guidelines recommend that all high
energy piping (both seamless and seam-welded) be inspected. Many utilities
included main steam, hot reheat, and cold reheat piping in their review. S&W
Consultants would recommend that future inspections be expanded for all stations
to include these other high energy systems. Replacement of some piping may be
required in the next 20 years as the effects of creep due to high
temperature/pressure exposure and metal fatigue manifest themselves.
Coal is delivered to the site by unit train and unloaded over a rail car hopper.
Typically a 45 to 60 day supply of coal is maintained on site. Normally coal is
directly transferred to the station coal bunkers on delivery. The system is
fully-automated from the rotary dump control room.
The PRB conversion included upgraded dust suppression, dust collection, and
washdown provisions to reduce the fire or explosion risk associated with the
dust-prone PRB coal. The in-plant coal trigger gallery area was found to be
particularly clean and dust free. There was very little fugitive coal dust
throughout the remainder of the boiler house. The plant personnel attributed
this to an aggressive cleaning program. The facilities were characterized as
being in very good condition.
Bottom ash generated in the coal-fired boilers is water-sluiced to an on-site
unlined settling pond. The pond has unlimited capacity for all practical
purposes.
Unit 1 is a 530'-0" concrete stack with a bottom diameter of 47'-4" and a top
diameter of 24'-2". The stack has 20'-0" diameter steel liner. Sargent & Lundy
inspected the stack in April, 1998. The findings indicated that the stack is
structurally sound with no major deficiencies and should be reinspected in 2003.
Unit 2 is a 544'-6" concrete stack with a bottom inner diameter of 43'-10" and a
top inner diameter of 34"-10". The stack has an independent brick liner that has
a bottom inner diameter of 29'-9" and a top inner diameter of 24'-2'. The stack
is in good condition with no significant structural defects and should be
scheduled for reinspection in 2003.
The station does not have an auxiliary boiler; the station relies on electric
heat for station heating.
3.1.1.2 Electrical Equipment and Systems
- -----------------------------------------
Electrical equipment and systems evaluated include, as applicable, generators,
transformers, breakers, switchgear, motor control centers, diesel generators, DC
systems, uninterruptible power system ("UPS"), and instrumentation and controls.
Significant findings are noted. Key generator characteristics are summarized in
the following table.
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Generator Unit 1 Unit 2
-------------------------------------------------------
Installation 1977 1981
Manufacturer GE GE
Rated kVA 686,000 686,000
Voltage (kV) 24 24
PF 0.90 0.90
Rated kW 617,400 617,400
Rpm 3600 3600
Cooling hydrogen hydrogen
Exciter solid state solid state
Control Auto/Manual Auto/Manual
Generator Rewind none none
Last Major Overhaul 1994 1999
The Unit 1 generator had its last major overhaul in 1994. The major work
performed included a layer separation modification, replacement of retaining
rings, replacement of main leads, full stator rewedge, installation of a flux
probe, new hydrogen seal rings and electrical testing of the generator field
stator and exciter. A new solid state exciter system was installed in 1996. A
robotic inspection, a stator wedge tightness partial test and installation of
Iris PD sensors in the stator were imminent at the time of the site visit.
Unit 2 generator had its last major overhaul in 1999. The major work performed
included a layer separation modification, replacement of retaining rings,
replacement of main leads, full stator rewedge, installation of a flux probe,
installation of Iris PD sensors, new hydrogen seal rings and electrical testing
of the generator field stator. In 1992 a new solid state exciter system was
installed.
The generator step up transformer ("GSU") for Unit 1 is a McGraw Edison oil
filled two winding transformer rated 672 MVA 24kV - 345kV and was placed in
service in 1977. The GSU for Unit 2 is an ABB oil filled two winding transformer
rated 690 MVA 24kV - 345kV and was placed in service in 1993 The transformers
appear to be in good condition and no evidence of constant oil leakage was
observed.
All the oil filled transformers both in the plant and in the switchyard are
under a routine maintenance plan with oil samples and gas tests every 6 months,
and every 2 years connections and other tests are performed. There are no
detectable PCBs present in the oil according to the utility.
Unit 1 is controlled by a Westinghouse WDPF Classic distributed control system
("DCS") added in 1994. The DCS system is scheduled for a full upgrade in
February of 2001. Unit 2 is controlled by a Westinghouse WDPF Ovation DCS added
in 1999. Presently the DCS is limited to data acquisition. The combustion
controls, the BMS and the balance of plant are scheduled to be upgraded into the
DCS in 2001. The Unit 1 and 2 turbine generators both have their original EHC's
and turbine supervisory instrumentation. Unit 1 is scheduled for an upgrade in 2
years and Unit 2 is scheduled for an upgrade in 3 years.
3.1.1.3 Emissions Control Equipment
- ------------------------------------
ESP and Flyash Handling System
For Newton Units 1 and 2, the induced draft ("ID") fans draw the flue gas from
the balanced-draft boiler, through the Ljungstrom regenerative airheaters,
electrostatic precipitator ("ESP"), and discharge to its own stack. Station
personnel reported that several different types of PRB coal (e.g. different coal
mine
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sources with different flyash compositions) are delivered to the Newton Power
Station, with some coal types being more difficult from the perspective of ESP
operation. The Unit 1 and 2 ESPs are of different design and manufacturer. Unit
1 was provided by Research Cottrell and commissioned in 1977. Unit 2 was
provided by Lodge-Cottrell and commissioned in 1982. Each ESP has four
mechanical fields in the direction of gas flow. Unit 1 has two ID fans, where
Unit 2 has three ID fans.
Flue gas conditioning ("FGC") is employed to enhance the flyash collection
performance within the ESP. The FGC system was provided by Wilhelm Environmental
Technologies, Inc. The SO\\3\\ is injected downstream of the airheaters (before
the ESP). The FGC system injection rate is equivalent to approximately 14 ppmv
SO\\3\\ at the inlet to each ESP.
The ESP dry fly ash is collected and dry pneumatic conveyed to an onsite ash
silo that is common to Units 1 and 2. The pneumatic conveyor system was provided
by ASH. Presently, the majority of the flyash from the flyash silo discharge
hopper is mixed with water in a single mixer/loader device, to form conditioned
flyash that is loaded into trucks for transport to an onsite landfill for
disposal.
Based on a visual inspection of the ESP systems and fly ash handling equipment,
a review of plant records, routine inspection reports, and discussions with O&M
staff, the ESP systems of Units 1 and 2 appeared to be in operational condition.
The station personnel indicated that the Units 1 and 2 ESP systems are capable
of remaining within compliance for stack opacity, with minimum derate of the
units, while employing specific compliance coals. Unit 1 and 2 ESPs will require
future modifications to ensure that boiler full load can be reliably maintained,
for the long-term basis, and if greater fuel flexibility is desired. These
modifications are planned for 2001.
For example, during the first day of the S&W Consultants' visit, station
personnel reported that Unit 1 load was derated to avoid possible ESP/stack
opacity problems. Several transformer rectifier ("TR") sets were shut down.
Also, problems with breakage of ESP wire type discharge electrodes, pluggage
problems with the FGC sulfur handling/feed system, and possible problems with
the manual rapping controls of the Unit 1 ESP were reported.
Station personnel reported that the Unit 1 stack opacity and Unit 2 stack
opacity values are routinely below the required permit value of 20.45 percent,
and that stack average opacity can vary from 14 to 20 percent depending on the
specific coal being burned. Emissions readings during our site visit are
summarized below:
Emissions Readings During Site Visit
Load (MW), Opacity (%) and SO\\2\\, NO\\x\\ (lb/mmBtu)
===============================================================================
Unit 1 Unit 2
Load Opacity SO\\2\\ NO\\x\\ Load Opacity SO\\2\\ NO\\x\\
- -------------------------------------------------------------------------------
Day 1 450* 17.27 0.38 0.142 571 16.13 0.4376 0.32
Day 2 547 11.5 0.4122 0.1396 569 17.6 0.5404 0.3067
===============================================================================
*derate to 450 MW due to ESP/FGC situation
The plant records indicate that the ESPs and fly ash handling systems have
historically experienced a normal level of inspections, maintenance, and design
improvements for units of this type.
NOx Control Equipment
AmerenCIPS installed low NO\\x\\ burners (ABB-CE LNCFS, Level 3) to control Unit
1 NOx emissions, in 1994. Unit 2 employs the original burner design, with two
levels of CCOFA, to control NO\\x\\ emissions.
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SO\\2\\ Control Equipment
Station personnel reported that Units 1 and 2 currently burn 100 percent PRB
coal, with a low sulfur content. For example, records (dated December 1999)
indicated that the average coal at the Newton Power Station had approximately
0.58 lb SO\\2/\\/mmBtu, on an as-received basis. The Newton Power Station does
not employ a flue gas desulfurization ("FGD") system.
3.1.1.4 Remaining Life
- -----------------------
There are only a few technical issues that can lead to a premature or
unpredicted end of life of an electric generating unit. In most cases the
decision to retire or decommission a generating unit is made for economic
reasons as a result of technical or environmental concerns. The underlying
economic factor is the ability to compete with other producers in the new
deregulated market. Major emissions compliance upgrades and major component
replacements are two of the most significant large potential capital
expenditures that could adversely impact large coal fired units similar to
Newton Units 1 and 2.
The 2000 Unit 1 and 1999 Unit 2 boiler inspection reports and the history of
recent component replacements and modifications indicated both boilers were in
good condition and could be operated for many more years. Both boilers require
economizer replacement within five years. Secondary superheater and pendant
finishing reheater replacements will be required in an estimated 10 years. The
normal base loading of the units has contributed to prolonging the life of
boiler components. The conversion to PRB coal in 1998 and 1999 was not without
some increased tube erosion and redistribution of heat absorption but the
transition has been reasonably smooth. Some acceleration of tube erosion will
require more tube shielding and more frequent tube wall thickness monitoring.
The capital budget for boiler improvements reflects expected replacements due to
normal aging.
The Newton turbine generators are of a class of General Electric units which
have a well documented class history. There is some evidence of LP inner shell
distortion which will require eventual major repairs along with HP and IP
stationary nozzle repairs during major overhauls between 2007 and 2019. There
has been some HP and IP turbine erosion that has required nozzle and blade
replacement with erosion resistant coated parts. Additional blade replacements
would be expected between 2012 and 2019. The rotor bores have been inspected
with no evidence of defects to date. As with the boilers, the turbine capital
budget reflects industry experience with this class.
Both Newton units are fully capable of reliable operation for 20 additional
years provided that a comprehensive non-destructive testing and inspection
program is followed. If the units were to be operated for a 30 year period and
beyond, they would then require some additional major component replacements in
the 2020's. The units are currently in very good condition and appear to be well
maintained. The Newton Power Station was found to be very clean when compared to
similar stations of this type and age. Previous inspection program findings
should be considered a baseline and should be reviewed to focus future
reinspections. The life projection is also dependent on the type of future
service. If the Newton units are shifted to more cycling service in the future
(this is not currently anticipated), then life consumption would be accelerated.
Metallurgical inspections and boiler and turbine component maintenance would
increase. The installation of a turbine bypass system on Unit 1 and the use of
sliding pressure would minimize cyclic stresses.
3.1.2 Coffeen Power Station
The Coffeen Power Station is located just outside the town of Coffeen in
Montgomery County, Illinois. Access to the site is by highway and rail. S&W
Consultants visited the Coffeen Power Station on
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February 16/th/ and 17/th/, 2000. The station appeared to be reasonably well
maintained and in good condition, although not as clean as the other stations
being evaluated.
The station consists of two steam-electric generating units. Units 1 and 2 are
balanced draft, reheat, coal-fired units rated at 340 MW and 560 MW net
respectively. The units were placed in operation in 1965 and 1972. The station
was originally constructed as a mine-mouth plant. The adjacent coal mine was
shut down in 1982 and the station was modified to receive coal by rail. Cooling
water for the main condensers is taken from and discharged to a man-made lake.
Units 1 and 2 are equipped with electrostatic precipitators for particulate
control. Units 1 and 2 have no special provisions for SO\\2\\ control. Unit 1
has no special provisions for NO\\x\\ control. Unit 2 presently employs cyclone
burners with an OFA system installed in December 1999.
Table 3.1-2 provides a summary of major Unit 1 and 2 characteristics. The
sections that follow detail our findings in the areas of mechanical, electrical,
and environmental systems condition and remaining life.
TABLE 3.1-2
Coffeen Power Station Characteristics
==========================================================================================
PERFORMANCE UNIT 1 UNIT 2
------------------------------------------------------------------------------------------
Normal Summer Capacity (MW Net) 340 560
------------------------------------------------------------------------------------------
Minimum Load (MW Gross) 178 280
------------------------------------------------------------------------------------------
Full Load Heat Rate, HHV (Btu/kWh) 9,800 9,900
------------------------------------------------------------------------------------------
PRIME MOVER
------------------------------------------------------------------------------------------
Manufacturer GE GE
------------------------------------------------------------------------------------------
Tandem Compound Tandem Compound
------------------------------------------------------------------------------------------
Type Four Flow Four Flow
------------------------------------------------------------------------------------------
Commissioned (Year) 1965 1972
------------------------------------------------------------------------------------------
HP Turbine Inlet Pressure\\Temp (psig/(degrees)F) 2620/1005 2500/1005
------------------------------------------------------------------------------------------
Reheat Turbine Inlet Temp ((degrees)F) 1005 1005
------------------------------------------------------------------------------------------
ELECTRIC GENERATOR
------------------------------------------------------------------------------------------
Manufacturer GE GE
------------------------------------------------------------------------------------------
Cooling Hydrogen Hydrogen
------------------------------------------------------------------------------------------
MVA 457.6 685
------------------------------------------------------------------------------------------
STEAM GENERATOR
------------------------------------------------------------------------------------------
Manufacturer B&W B&W
------------------------------------------------------------------------------------------
No. of Boilers 1 1
------------------------------------------------------------------------------------------
Circulation Once Through Once Through
------------------------------------------------------------------------------------------
Draft Condition Balanced Balanced
------------------------------------------------------------------------------------------
Cycle Type Reheat Reheat
------------------------------------------------------------------------------------------
Primary Fuel Coal Coal
------------------------------------------------------------------------------------------
OTHER
------------------------------------------------------------------------------------------
Cooling Water Source Lake Lake
------------------------------------------------------------------------------------------
Fuel Delivery Rail Rail
==========================================================================================
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3.1.2.1 Mechanical Equipment and Systems
- -----------------------------------------
Major systems include the boilers, steam turbines, and balance of plant.
Boilers
The Unit 1 boiler at Coffeen Power Station is a Babcock & Wilcox ("B&W") single
furnace, once through cyclone fired, balanced draft, reheat boiler which was
placed in commercial operation in 1966. The boiler was originally pressurized
and was converted to balanced draft operation in 1972. Both boilers are designed
to burn medium sulfur Illinois bituminous coal and presently burns the design
type fuel and petroleum coke. The petroleum coke is burned at up to 10% by
weight. Limestone is added for flux control (1% by weight). A test burn of PRB
resulted in a derating from 389 gross MW to 340 gross MW. Future plans do not
call for switching to PRB coal. The present coal supply contract will continue
until 2009.
The boilers historically have operated primarily in intermediate service mode,
but are capable of and projected to provide base load service. At the last
inspection the Unit 1 boiler had experienced a total of 614 start-ups. The
boiler has operated a total of 182,339 hours since startup, averaging 5,363
hours on line per year. Major maintenance is performed every 24 months for 4 to
8 weeks with minor 2 week outages in the off years. The OEM is not usually
involved in the boiler overhaul.
Major overhaul of the Unit 1 boiler was last performed in the fall of 1999. The
boiler was also cleaned and inspected in the fall of 1998. The next major outage
and inspection is scheduled for fall 2000, during which an overfire air system
will be installed. Major work performed during the last overhaul consisted of
installation of new ignitor piping and ignitors, installation of
SO//3//injection system for PRB test burn, cyclone repairs, furnace repairs,
casing repairs, primary superheater repairs, replacement of 1B gas recirculation
fan rotor, and hydro test boiler.
Overall the Unit 1 boiler is in good condition. The boiler area was fairly dirty
during the site visit. However, station personnel attributed this to a leaking
duct. UT surveys are performed on 5 year intervals with 500 to 1,000 ft. of
cyclone tubing being replaced during each scheduled outage. Approximately 10,000
pin studs are replaced in each cyclone at every scheduled outage. Flat stud
upgrades are performed as needed every scheduled outage. In 1997 the boiler
furnace was fully inspected; tube samples taken showed no structural
degradation. Tube samples are taken approximately every 3 years since the lower
walls are subject to ash erosion. Chemical cleaning is done every 7 to 8 years
and was last done in 1998. The secondary (finishing) superheater is also
considered in good condition since it was redesigned and replaced in 1997 due to
high temperature creep and erosion. The outlet header was upgraded from P11 to
P22 material. The inlet header was not replaced. The superheater is inspected
and repaired during every scheduled outage. The primary superheater tubes are
scheduled for replacement, half in 2001 and half in 2005. The primary
superheater inlet and outlet headers are considered in good condition The
reheater is in good condition; the tubes were replaced in 1997. The economizer
is in excellent condition. Boiler ductwork is in good condition.
NDT inspection is done regularly including UT, MP and boroscopic examinations.
Reports were reviewed. Boiler water treatment consists of oxygenated treatment
(converted in 1998) with ammonia for pH control.
NOx control will be accomplished with overfire air, to be installed in the fall
of 2000. There are no limitations on boiler output due to boiler related issues.
The Unit 2 boiler at Coffeen Power Station is a B&W single furnace, once
through, cyclone fired, balanced draft, reheat boiler which was placed in
commercial operation in 1972. At the last inspection the
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Unit 2 boiler had experienced a total of 447 start-ups. The boiler has operated
a total of 171,700 hours since startup, averaging 6,359 hours on line per year.
Major maintenance is normally performed every 24 months for 4 to 8 weeks with
minor 2 week outages on the off years. The OEM is not usually involved in the
boiler overhaul.
Major overhaul of the Unit 2 boiler was last performed in the fall of 1998. The
boiler was also inspected in the fall of 1999. The next outage and inspection is
scheduled for fall 2000 during which new 2A and 2B gas recirculation fan rotors
will be installed. Major work performed during the last overhaul consisted of
installation of OFA, finishing superheater outlet pendant replacement, cyclone
repairs, furnace repairs, casing repairs, replacement of the 2C gas
recirculation fan rotor, and boiler hydro testing.
Overall the Unit 2 boiler is in good condition. The boiler area was fairly dirty
during the site visit and station personnel attributed this to a leaking duct.
UT surveys are performed on 5 year intervals with 500-1000 ft. of cyclone tubing
being replaced during each scheduled outage. Approximately 10,000 pin studs are
replaced in each cyclone at every scheduled outage. Flat stud upgrades are
performed as needed every scheduled outage. In 1999 the boiler furnace was fully
inspected; tube samples taken showed no structural degradation. Chemical
cleaning was last done in 1996. The secondary (finishing) superheater is also
considered in good condition since the outlet pendants were replaced in 1999
with 304H due to high temperature creep and erosion. The inlet and outlet header
was not replaced. The superheater is inspected and repaired during every
scheduled outage. The primary superheater tubes are original and considered in
good condition. The primary superheater inlet and outlet headers are also
considered in good condition. Moderate sootblower erosion is present in the
upper superheater bank. Erosion shields are installed/repaired each scheduled
outage. The reheater is in fair condition. Upper portions of outlet pendants
suffer from flyash plugging and have moderate to severe sootblower erosion. Tube
replacements are planned and performed during scheduled outages based on prior
inspections with 81 tubes (2100 ft.) replaced during 1999. The reheater tubes
are scheduled for replacement in 2003. The economizer is in excellent condition.
The economizer inlet header has no ligament cracking. Boiler ductwork is in good
condition.
NDT inspection is done regularly including UT, MP and boroscopic examinations.
Inspection reports were available. Boiler water treatment consists of hydrazine
for oxygen control with ammonia for pH control.
NOx control is accomplished with overfire air, installed in the fall of 1999.
There are no limitations on boiler output due to boiler related issues.
Steam Turbines
Coffeen Unit 1 turbine generator is a General Electric 17 stage tandem compound,
four flow exhaust unit with 26 inch last stage buckets. The unit went into
commercial operation in 1965 in a closed cycle cooling system configuration on a
cooling lake with a design back pressure of 3.5" Hg. The normal operating steam
conditions are 2400 psig, 1000 (degrees)F main steam and 1000 (degrees)F reheat.
The unit was purchased with 5% overpressure capability but has operated at rated
pressure over the last 10 years. The unit nameplate rating is 330,000 kW with a
maximum capability of 360 MW (gross). The HP/IP section is an opposed flow
element. The two LP sections exhaust to separate two pass condenser shells.
There is a separate four valve steam chest on the operating floor adjacent to
the HP turbine.
The turbine is equipped with the original mechanical hydraulic governor. It is
equipped with a stop valve bypass for full arc admission startup. It was
originally designed for base load operation and is currently operating in
intermediate service. There is a startup bypass system which discharges to the
condenser.
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Steam is extracted from the IP exhaust to supply two non-condensing 7,370 HP
boiler feed pump drive turbines.
Records indicate that the unit has the original turbine shells and rotors. There
is no history of shell cracking or blade failure except for a single replacement
LP blade failure in 1999 which is unexplained. Retractable HP/IP packing has
been added. The turbine has the recommended turbine water induction protection.
The most recent Unit 1 major HP/IP turbine overhaul was in 1995. A rotor bore
and periphery sonic inspection was performed with no significant defects
reported. Reinspection in ten years was recommended by the contractor. New
1/st/, 8/th/, and 9/th/ stage buckets were installed along with 7/th/ stage
bucket covers. The 8/th/ stage diaphragm blade setback was completed along with
9/th/ and 10/th/ stage erosion repairs. A new erosion resistant nozzle box was
installed. The HP and IP inner shells were removed to machine the horizontal
joints to correct leakage. Rubbed and broken spill strips were replaced. Some
minor upper HP outer shell cracking was removed by grinding. No indications were
detected in the lower outer shell. Some minor indications were removed by
grinding on the IP inner shells.
The most recent major Unit 1 LP turbine overhaul was in 1997. The last stage
buckets and diaphragms were replaced with Parsons components on all four exhaust
ends. This retrofit required significant machining. The LP A 13/th/ stage
buckets were replaced. The contractor recommended complete inspection of both LP
rotors, including the bores, at the next overhaul along with bucket replacement
on three LP A stages and five LP B stages. The LP inner shells were fully NDE
inspected. LP A diaphragms on stages 12 through 16 required major repairs.
Coffeen Unit 2 turbine generator is a General Electric 18 stage tandem compound,
four flow exhaust unit with 30 inch last stage buckets. This unit is very
similar to Newton Units 1 and 2 with significant parts interchangeability. The
unit went into commercial operation in 1972 in a closed cycle cooling
configuration on a cooling lake with a design back pressure of 3.5" Hg. The
normal operating steam conditions are 2400 psig, 1000 (degrees)F main steam and
1000 (degrees)F reheat. The unit was purchased with 5% overpressure capability
but is operated at 2400 psig. The unit nameplate rating is 550,000 kW with a
maximum rating of 590,000 kW (gross). The HP/IP section is an opposed flow
element. The two LP sections exhaust to separate two pass condenser shells.
There is a separate four valve steam chest on the operating floor adjacent to
the HP turbine. It is equipped with an electrohydraulic governor which permits
selection of full or partial arc operation. Steam is extracted from the IP
exhaust stage to supply two half size condensing boiler feed pump drive
turbines. These turbines have separate condensers with condensate returned to
the main unit condenser hotwell.
A records review and plant interviews indicate that the rotors and shells are
the original components. The 12/th/ stage buckets were replaced in 1990 and the
four rows of last stage buckets were replaced in 1993. The 7/th/ stage buckets
and diaphragms were replaced in 1995.
The most recent major Unit 2 HP/IP turbine overhaul was in 1995. The HP/IP
turbine was completely dismantled and the generator was rewedged. A
reconditioned solid particle erosion resistant nozzle box was installed. Minor
upper HP shell cracking was removed by grinding. No HP lower shell indications
were detected. Upper and lower HP inner shell NDE detected minor indications
which were ground out. New HP/IP retractable packing was installed. Minor
cracking was left around the 1/st/ stage inner thermocouple. Minor surface
cracking on the IP inner shells was removed by grinding. The 1/st/,7/th/, 8/th/,
9/th/ and 10/th/ stage buckets were replaced with new erosion resistant coated
buckets. The 6/th/ and 11/th/ stage bucket covers were replaced. Cracks were
removed from the 7/th/ and 8/th/ stage interstage areas. The 11/th/
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stage bucket tenons were weld repaired. A rotor bore and dovetail inspection was
performed with no indications reported. Rotor reinspection after 10 years was
recommended.
The most recent Unit 2 major LP turbine overhaul was in 1996. Sonic inspection
was performed on both LP rotor bores and wheels. No significant defects were
reported. Both LP shell were found in good condition with no visible defects. A
number of shallow cracks in the LP shells were ground out and weld repaired.
Some horizontal joint erosion was noted on both LP shells. These areas were
repaired through damming the affected areas.
Asbestos has been removed from the Coffeen turbine shells and replaced with
removable blankets. There is no fire protection at each turbine bearing. There
is a deluge fire protection system on each of the main turbine oil tanks but no
dike enclosure around the tanks. There were no recent oil leaks under each
turbine but the lower elevations have a buildup of what appears to be coal dust
and congealed oil. There is little evidence of recent floor cleaning. There is
no evidence of turbine generator concrete support pedestal cracking but there is
some foundation cracking under the boiler feed pump support plates. There are
some visible cracks in the Unit 1 condenser support foundations. There is a
significant oil leak under 2C boiler feed pump turbine which is to be addressed
at the next overhaul.
There are no current turbine capacity deratings. The units are not equipped with
automatic variable pressure ramping.
Balance of Plant
The condenser cooling water is taken from and discharged to an onsite man-made
lake. The circulating water system includes a screenwell structure for Units 1
and 2. In general, the traveling water screens have been reliable, low
maintenance units. The overall condition of the screens was characterized as
good. The circulating water inlet and discharge piping is buried, and was last
inspected in 1995. The circulating water inlet piping required only minor
repairs and was characterized to be in good condition. The circulating water
discharge piping was found to be in poor condition. In the past only patchwork
repairs have been made to the piping. The budget projections include allocation
for repair. The Worthington circulating water pumps are typically overhauled
every 5 to 10 years. The pumps have been relatively trouble-free and were
characterized as being in good condition.
Each unit is equipped with a Worthington two-pass, divided waterbox surface-type
condenser. The condensers were originally furnished with arsenical admiralty
tubing in the main condensing section and stainless steel in the air offtake
sections. The Unit 1 condenser was entirely retubed in 1981 with Cu-Ni tubing
because of "condensate grooving" at the tube sheet and tube support plates.
Ameren estimated that less than 2% of the Unit 1 condenser has been plugged to
isolate leaks. However the Unit 1 condenser has, in the last year, seen
increased tube leakage in the air offtake sections. Retubing the air outlet
sections is included in the budget projection. The Unit 2 condenser has not been
retubed since its original installation and has not seen the same "condensate
grooving" problem. Ameren estimated that less than 5% of the Unit 2 condenser's
tubes have been plugged. The Unit 2 condenser will be retubed with all stainless
steel in 2001.
The units each have seven stages of feedwater heating, including the deaerating
heater. Replacements and/or retubings have been scheduled and budgeted
appropriately.
Both units have two 50% capacity Pacific six-stage, centrifugal boiler feed
pumps. Both pumps are equipped with individual General Electric turbine drives.
A 30% capacity Pacific twelve-stage, motor-driven centrifugal boiler feed pump
is used for startup operations. The pumps and drives have proven to be reliable
and are currently in fair to good condition, with future overhauls scheduled.
[LOGO] S&W Consultants, Inc. A-33
The Unit 1 hot reheat piping was inspected in the 1980's in response to
industry-wide concern about high energy pipe failures, particularly in seam-
welded hot reheat piping. Station personnel have indicated that the inspections
were limited to hot reheat seam-welded piping and that any defects found were
repaired as necessary. During the 1998 outage, as a followup to the earlier
inspections, B&W inspected approximately 50% of the hot reheat steam line. B&W
used replication, ultrasonic shearwave and thickness, and magnetic particle
inspection techniques. None of the replications showed any signs of creep or
creep-related problems. B&W characterized the hot reheat piping as being in good
condition, but recommended that the piping be reinspected in five years.
Reinspection of Unit 1 hot reheat piping has been scheduled for 2000.
There is reportedly no seam welded piping on Unit 2 therefore no similar
inspections have been performed. However, as more operating hours are
accumulated, a formal inspection program should be initiated. As is the case for
Unit 1, replacement of some piping may be required in the next 20 years as the
damaging effects of high temperature/pressure exposure and metal fatigue
manifest themselves.
Coal is delivered to the site by a 105-car unit train and unloaded over a 6-car
rail hopper. Rail cars are bottom discharge and two car shakers are provided to
facilitate rail car coal removal. The rail cars are owned by Ameren. An active
coal pile of approximately 35,000 to 55,000 tons is maintained. On site storage
(active and reserve) at the time of visit was approximately 350,000 tons. This
amounts to a fuel supply of approximately 60 days. Limestone is delivered by
truck and dumped into a limestone hopper and a small amount fed into this coal
stream to help alleviate slagging in the boilers. The coal handling system is
fully automated. A bunker unloading system is in place. There are no major
chronic problems associated with the coal receipt and handling systems.
Bottom ash generated in the coal-fired boilers is water-sluiced to dewatering
bins where the ash is removed and trucked offsite. The water is decanted by
gravity to a recycling pond for reuse. The bottom ash system requires routine
maintenance. No significant operating or maintenance problems were noted.
Units 1 and 2 have a single Custodis 500' concrete stack with a bottom diameter
of 46'-9" and a top diameter of 31'-6". The stack has a steel liner with a
29'-0" top diameter and a 34'-0" bottom diameter. Sargent & Lundy inspected the
stack in April 1997. The findings indicated that the stack is structurally sound
with no major deficiencies and should be reinspected in 2001.
No. 2 fuel oil is used as an ignition fuel in the Unit 1 and 2 boilers and as
the main fuel for firing the auxiliary boiler. The fuel is delivered to the
station by truck and stored in two 100,000 gallon storage tanks and one 46,000
gallon day tank. All tanks are aboveground, in enclosed berms. The tanks are
inspected visually on a monthly basis and the shell thickness is measured by a
single-point ultrasonic test annually. Station personnel characterized the
condition of the tanks as fair.
The 180,000 pound per hour, oil-fired Nebraska boiler was installed in 1991. The
auxiliary boiler is used primarily for station heating, but can be used for unit
start-up if required. The boiler was characterized by station personnel as being
in good condition.
3.1.2.2 Electrical Equipment and Systems
- -----------------------------------------
Electrical equipment and systems include, as applicable, generators,
transformers, breakers, switchgear, motor control centers, diesel generators, DC
systems, UPS, and instrumentation and controls. Significant findings are noted.
Key generator characteristics are summarized in the following table.
[LOGO] S&W Consultants, Inc. A-34
Generator Unit 1 Unit 2
-----------------------------------------------------
Installation 1966 1972
Manufacturer GE GE
Rated kVA 457,600 685,000
Voltage (kV) 13.8 13.8
PF 0.85 0.9
Rated kW 388,960 616,500
Rpm 3600 3600
Cooling hydrogen hydrogen
Exciter rotating rotating
Control Auto/Manual Auto/Manual
Generator Rewind none none
Last Major Overhaul 1998 1995
The Unit 1 generator rotor was removed in 1991 and new retaining rings were
installed. Also done was a layer separation modification. In 1998 the stator had
a full rewedge and an Iris PD monitoring system was installed. The Unit 2
generator rotor was removed in 1993 and new retaining rings were installed. Also
done was a layer separation modification. In 1995 the stator had a full rewedge
and an Iris PD monitoring system was installed.
The GSU for Unit 1 is a Westinghouse oil filled two winding transformer rated
232.4/310.4/388 MVA 22kV - 345kV and was placed in service in 1984. The
transformer is a replacement for the original Westinghouse transformer that had
a failure as a result of an internal fault. The generator step up ("GSU") for
Unit 2 is a McGraw Edison oil filled two winding transformer rated 580/650 MVA,
23.4kV - 345kV and was placed in service in 1972. These are two unit auxiliary
transformers for each unit. The transformers appear to be in good condition and
no evidence of constant oil leakage was observed.
The transformers are under a routine preventative maintenance program by the
utility. The transformer oil is tested annually and the equipment is serviced
during every boiler outage, which was on a yearly basis and has now been changed
to eighteen months. There are no detectable PCBs present in the transformer oil,
according to the utility.
Unit 1 is controlled by a Westinghouse WDPF DCS with a Wes Station interface,
all added in 1997. Unit 2 is controlled by a Westinghouse WDPF DCS Classic level
7, added in 1991.
Both Unit 1 & 2 turbines have shaft driven exciters. Excitation and controls
systems improvements will be implemented during overhauls scheduled and budgeted
in the 2001-2005 time frame.
In general, walking around the plant, the areas around the electrical equipment
were reasonably well lit. Inside some of the motor control centers there was a
coating of dust but there was no indication given that this resulted in any
outages.
3.1.2.3 Emissions Control Equipment
- ------------------------------------
ESP and Flyash Handling
At Coffeen, the ID fans draw the flue gas from the balanced-draft cyclone
boilers, through the tubular airheaters, ESPs, and discharge to a stack that is
common with Units 1 and 2. The Unit 1 ESP was rebuilt by Joy Manufacturing
Company in 1984. The ESP has five fields in the direction of gas flow. Station
personnel reported that the Unit 1 ESP employs new discharge electrodes
(installed in 1994) in the first two fields and has the original rigid
electrodes (installed in 1984) in the last three fields. The ESP
[LOGO] S&W Consultants, Inc. A-35
has 12 fly ash collection hoppers. No FGC is employed at Coffeen. The Unit 2 ESP
was provided by Buell Engineering Company and commissioned in 1972. The ESP has
four fields in the direction of gas flow. The ESP has 24 fly ash collection
hoppers.
The common stack has a certified opacity monitor system for the combined Units 1
and 2 opacity. It was reported that the discharge ductwork of each unit's ESP
has a non-certified opacity monitor system that can be used for diagnostic
purposes.
The ESP dry fly ash is collected within the hoppers and pneumatically conveyed
to an onsite flyash silo that is common to Units 1 and 2. From the flyash silo,
the ash can be handled in two different modes. Normally, the flyash from the
discharge of the flyash silo is mixed with water in a rotary mixer to form
conditioned ash that is loaded into trucks for transport to an offsite landfill
disposal area. The discharge of the flyash silo can also be handled in dry form
and pneumatically loaded in dry form into trucks for transport offsite. It was
reported that the flyash usually contains a relatively high loss on ignition
("LOI") (e.g. 6 to 21 percent). The bottom ash slag is sold to a local company
for reuse (e.g. roofing shingles).
Based on a visual inspection of the ESP systems and fly ash handling equipment,
a review of plant records, routine inspection reports, and discussions with O&M
staff, the ESP systems of Units 1 and 2 appeared to be in operational condition.
Station personnel reported that the combined Units 1 and 2 stack opacity, at
full load conditions, is routinely within the range of 18 to 23 percent (when
the present coal is employed), which is below the reported permit value of 30
percent. Emissions readings during our site visit are summarized below:
Emissions Readings During Site Visit
Load (MW), Opacity (%) and SO\\2\\, NO\\x\\ (lb/mmBtu)
======================================================================
Load Combined units 1 & 2
(MW) Opacity SO\\2\\ NO\\x\\
----------------------------------------------------------------------
Day 1 Unit 1: 255, Unit 2: 582 20.93 2.3615 0.7162
----------------------------------------------------------------------
Day 2 Unit 1: 352, Unit 2: 574 21 2.1385 0.8775
======================================================================
The plant records indicate that the ESPs and fly ash handling systems have
historically experienced a normal level of inspections, maintenance, and design
improvements for units of this type.
NO\\x\\ Control Equipment
Unit 1 presently employs the original burner design (cyclone burners, B&W
boiler). Station personnel reported that Unit 1 boiler is capable of producing a
NO\\x\\ level of approximately 1.2 lb NO\\x\\/mmBtu. Future NO\\x\\ controls at
Unit 1 are being planned, with considerations for a future OFA system combined
with an ammonia-based selective catalytic reduction ("SCR") system.
Unit 2 presently employs cyclone burners (B&W boiler) with an OFA system
installed in 1999. Station personnel reported that in the past, Unit 2 boiler
(without the use of the new OFA system) was also capable of producing a NO\\x\\
level of approximately 1.2 lb NO\\x\\/mmBtu, and that with the new OFA NO\\x\\
control system, the NO\\x\\ levels on Unit 2 can be reduced significantly.
During the S&W Consultants visit, the new OFA system was undergoing testing.
Test results provided by Ameren indicate that Unit 2 is capable of meeting
current NO\\x\\ emissions limitations with the new OFA system. Future NO\\x\\
controls at Unit 2 are being planned, with considerations for the use of the
recently installed OFA system combined with an SCR system.
[LOGO] S&W Consultants, Inc. A-36
SO\\2\\ Control Equipment
The station does not employ a FGD system. Units 1 and 2 routinely burn coals
with approximately 2 to 2.5 lb SO\\2\\/mmBtu. For example, records (dated
December 1999) indicated that the average coal at the Coffeen Power Station had
approximately 2.0 lb SO\\2\\/mmBtu, on an as-received basis.
3.1.2.4 Remaining Life
- -----------------------
As with the Newton Power Station, major age related component replacements and
emission compliance upgrades are two of the most significant large capital
expenditures that could impact the coal fired Coffeen units. The most recent
Coffeen boiler inspection and turbine generator overhaul reports were reviewed
along with plant walkdown visual inspections, staff interviews and original
design reviews.
The 1999 Unit 1 and 1998 Unit 2 boiler inspection reports were reviewed along
with the history of recent component replacements and modifications. Both
boilers are in overall good condition and could be operated for many more years
provided timely maintenance is performed and replacements are made. Superheater
and reheater tube replacements will be required in a 10 year time frame. The
current normal base loading of the units has contributed to prolonging the
useful life of boiler components. Unlike the Newton boilers, which were recently
converted to PRB coal with good results, a PRB test burn at Coffeen resulted in
nearly a 50 MW derate on each unit and PRB firing was suspended. The projected
Coffeen capital budget reflects normal replacements due to aging.
As with Newton Power Station, the Coffeen turbine generators each have a well
documented class history. HP and IP inlet stage erosion has been addressed by
periodic replacements with erosion resistant coatings. Gradual shell distortion
will require straightening and eventual replacement. The rotor bores have been
inspected with no potential end of life defects detected.
All four Unit 1 inner casings are distorted and major repair welding and rework
is expected around 2008. Severe solid particle erosion is occurring and repair
welding of stationary nozzles and blading can be expected. Unit 2 is also
experiencing inner casing distortion and severe solid particle erosion. Major
inner casing repair welding will be required in the period between 2007 and
2017. Replacement of the first three HP and IP stages would be expected between
2013 and 2019.
Both Coffeen units should be fully capable of reliable operation for 20
additional years provided that a comprehensive non-destructive testing and
inspection program is followed and used to schedule major maintenance and
replacements. The units are in good condition and appear to be well maintained.
The previous inspection results should be considered a baseline and should be
reviewed to focus future reinspections and maintenance. If the units are to be
operated for a 30 year period and beyond, they would then require some major
turbine component replacements in the 2020's. The life projection is also based
on the type of future service. If the Coffeen units are shifted to more cycling
duty (not currently anticipated), then life consumption would be accelerated.
Metallurgical inspections and component maintenance should increase. The use of
full sliding pressure and a turbine bypass system could minimize cyclic stress
damage.
3.1.3 Meredosia Power Station
The Meredosia Power Station is located on the Illinois River, in the town of
Meredosia, Illinois. Access to the site is by highway and river. The rail
facilities at the station are not in a functional condition. S&W Consultants
visited the Meredosia Power Station on February 10/th/ and 11/th/, 2000. The
station appeared to be well maintained and in good condition, considering the
age of Units 1 and 2 and the historically infrequent operation of Unit 4.
[LOGO] S&W Consultants, Inc. A-37
The station consists of four steam-electric generating units. Units 1 and 2 are
essentially identical, balanced draft, nonreheat, coal-fired units with nominal
capacity of 62 MW net. These units were placed in service in 1948 and 1949. Unit
3 is a balanced draft, reheat, coal-fired unit with a nominal capacity of 168 MW
net. Unit 3 is a twin furnace design utilizing a common steam drum, with the
superheat furnace performing the final superheating and the reheat furnace
performing the reheating along with one half of the primary superheating. Unit 3
was placed in service in 1960. Unit 4 is a pressurized, reheat, oil-fired unit,
nominally 168 MW net. Unit 4 was placed in service in 1975. The major power
generation equipment is located indoors with the exception of the Unit 4 boiler
which is located outdoors. Condenser cooling water for Units 1-3 is taken from
and discharged back to the Illinois River. Unit 4 utilizes a mechanical draft
cooling tower and closed-loop system for condenser cooling.
Units 1, 2, and 3 are equipped with electrostatic precipitators for control of
particulates; Unit 4 has no precipitator. Units 1, 2, and 3 have no special
provisions for NO\\x\\ control. Unit 3 has ABB-CE level 1 low NO\\x\\ burners
installed. The Unit 4 boiler is equipped with over-fire air and gas
recirculation to allow NO\\x\\ control. None of the units have provisions for
control of SO\\2\\ emissions.
Table 3.1-3 provides a summary of major characteristics of Units 1 through 4.
The sections that follow detail our findings in the areas of mechanical,
electrical and environmental systems condition and remaining life.
[LOGO] S&W Consultants, Inc. A-38
TABLE 3.1-3
Meredosia Power Station Characteristics
- --------------------------------------------------------------------------------------------------------------
UNITS 1 & 2
PERFORMANCE (Boilers 1-4) UNIT 3 UNIT 4
- --------------------------------------------------------------------------------------------------------------
Normal Summer Capacity (MW Net) 2x62 215 168
- --------------------------------------------------------------------------------------------------------------
Minimum Load (MW) 25 per unit 80 50
- --------------------------------------------------------------------------------------------------------------
Full Load Heat Rate, HHV (Btu/kWh) 13,157 9955 10,289
- --------------------------------------------------------------------------------------------------------------
PRIME MOVER 2
- --------------------------------------------------------------------------------------------------------------
Manufacturer GE Allis-Chalmers Westinghouse
- --------------------------------------------------------------------------------------------------------------
Tandem Compound Tandem Compound Tandem Compound Two
Type Two Flow Triple Flow Flow
- --------------------------------------------------------------------------------------------------------------
Commissioned (Year) 1948, 1949 1960 1975
- --------------------------------------------------------------------------------------------------------------
HP Turbine Inlet Pressure/Temp (psig/(degrees)F) 850/900 2000/1050 2286/1000
- --------------------------------------------------------------------------------------------------------------
Reheat Turbine Inlet Temp ((degrees)F) N/A 1000 1000
- --------------------------------------------------------------------------------------------------------------
ELECTRIC GENERATOR 2
- --------------------------------------------------------------------------------------------------------------
Manufacturer GE Allis-Chalmers Westinghouse
- --------------------------------------------------------------------------------------------------------------
Cooling Hydrogen Hydrogen Hydrogen
- --------------------------------------------------------------------------------------------------------------
MVA 81.25 281.6 233.0
- --------------------------------------------------------------------------------------------------------------
STEAM GENERATOR
- --------------------------------------------------------------------------------------------------------------
Manufacturer CE CE Foster Wheeler
- --------------------------------------------------------------------------------------------------------------
No. of Boilers 4 1 (twin) 1
- --------------------------------------------------------------------------------------------------------------
Circulation Natural Forced Natural
- --------------------------------------------------------------------------------------------------------------
Draft Condition Balanced Balanced Pressurized
- --------------------------------------------------------------------------------------------------------------
Cycle Type Non-Reheat Reheat Reheat
- --------------------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal Oil
- --------------------------------------------------------------------------------------------------------------
OTHER
- --------------------------------------------------------------------------------------------------------------
Cooling Tower, make
Cooling Water Illinois River Illinois River up from III River
- --------------------------------------------------------------------------------------------------------------
Fuel Delivery Truck or Barge Truck or Barge Truck or Barge
- --------------------------------------------------------------------------------------------------------------
3.1.3.1 Mechanical Equipment and Systems
- -----------------------------------------
Major systems include the boilers, steam turbines and balance of plant.
Boilers
There are six boilers at the Meredosia Power Station. Four of the six boilers
are identical CE single furnace, natural circulation, balanced draft, non-reheat
design and were placed into commercial operation in 1948 and 1949. The four
boilers supply steam to Units 1 and 2. The boilers are designed to burn
pulverized 3% sulfur Illinois bituminous coal. Light oil is used for ignition
fuel. The boilers presently operate as load following units with no limitations
on output or steam conditions and are projected to continue to provide
intermediate service.
Maintenance is performed every year during two week outages. No long-term major
outages are required. The latest outages occurred during October 1999 through
January 2000. The OEM is not usually involved as in-house expertise is
sufficient to maintain the boilers.
[LOGO] S&W Consultants, Inc. A-39
No major equipment modifications or replacements have been made within the last
twenty years on the Unit 1 and 2 boilers and auxiliaries. The waterwalls and
superheaters of every boiler are original and have had no significant problems
since startup. Unit 1, boiler No. 1, had an explosion in 1998 which required the
replacement of all insulation and lagging. All ductwork and buckstays were
straightened and repaired as required. The pressure parts were apparently
undamaged and no significant repairs were required. The cause of the explosion
was operator error in which No. 2 fuel oil, used for ignition, was inadvertently
introduced into the boiler. As a result of the subsequent repairs, Unit 1 boiler
is essentially asbestos free. The remaining Unit 1 and 2 boilers are estimated
to have 75% asbestos insulation remaining.
Overall the Unit 1 and 2 boilers are clean and in good condition considering
their age. Both units were running at 50 MW, about 285,000 lb/hr during the site
visit. According to plant records, tube leaks are rare. Chemical cleaning is
infrequent and was last done once on each boiler in the 1980's. Boiler ductwork
is considered to be in fair to good condition. No issues of significance were
noted for any pressure parts. Although water walls have been repaired through
the years, no sections have been replaced. Inspection is done visually with
hydrotesting used to confirm repair integrity. No NDT inspection reports were
available. NDT is rarely done, according to plant personnel. Boiler water
treatment consists of hydrazine for oxygen control and phosphate for solids and
pH control.
Boiler operation is conservative with no temperature limits being exceeded.
There are no specific NO\\x\\ control provisions other than combustion tuning. A
new DCS system is planned for boilers 1-4, however, which could also include a
Pegasus neural NO\\x\\ control. No limitations on boiler operation were noted
other than turbine seasonal limitations. Other than casing and ductwork air in-
leakage and fly ash erosion, which one would expect from boilers of this
vintage, there are no major issues.
The Unit 3 boiler at Meredosia is a CE twin furnace, forced circulation,
balanced draft, reheat design which was placed in commercial operation in 1960.
The boilers are designed to burn pulverized Illinois bituminous coal. Light oil
is used for ignition fuel. The boiler now operates as an intermediate service
unit, and is projected to continue in that mode, with no limitations on output
or steam conditions.
Major maintenance is performed bi-annually for approximately five weeks. A three
week-outage is performed during the off-years. The OEM is not usually involved
as in-house expertise is sufficient to maintain the boiler.
Overhaul of the Unit 3 boiler was last performed in the fall of 1999. The boiler
was last inspected in September of 1999 by the corporate boiler engineer. The
resultant recommendations included maintenance items that were completed during
the subsequent outage. Overall the Unit 3 boiler was found to be clean and in
good condition considering its age. The boiler was running at 1,080,000 lbs./hr
(160 MW) during the site visit. According to plant records tube leaks are rare.
Chemical cleaning was last done in 1994. Boiler ductwork is considered to be in
good condition. The final pendant section of the secondary superheater is
scheduled for replacement in the fall of 2000. According to recent inspection
reports all other sections of the secondary superheater are in good condition,
requiring only minor maintenance. Condition of the secondary superheater outlet
header is suspect and may be replaced in the near term. In 1991 the superheater
outlet header was assessed and it was determined that the header had experienced
temperature excursions and should be inspected every three years. This header
should be inspected at the next outage. In 1991 waterwall waterside corrosion
was detected. Water chemistry was determined to be the cause, especially during
transitional operation. No recent indications of this problem were noted. Aside
from the outlet superheater tube replacement, future boiler items include
chemical cleaning and superheater outlet header inspection.
[LOGO] S&W Consultants, Inc. A-40
The primary superheater is in good condition but subject to sootblower erosion.
This is controlled by shielding and removing sootblowers from service. A rebuild
of the primary superheater may be likely in less than five years if sootblower
use is continued. All replaced pressure parts are in good condition according to
plant personnel. Waterwall replacement in the 1970's and 1980's was due to
hydrogen embrittlement. The remainder of the pressure parts is original and
requires typical maintenance, primarily due to flyash erosion on superheater and
reheat tubes. Inspection is done visually with hydrotesting used to confirm
repair integrity. According to plant personnel, no recent NDT inspection reports
were available and NDT inspection is rarely done. Metallurgical sampling is done
only on an as-required basis. Boiler water treatment consists of hydrazine for
oxygen control and phosphate for solids and pH control.
Boiler operation is conservative. Due to a previous series of tube leaks in the
superheater there is a temporary self-imposed 1020(degrees)F temperature
limitation at the superheater outlet. There were load ramp rate limits of 1.5
MW/min during summer peak periods and a lower load limit of 125 MW (net) put
into effect in early 1997. However, these have been lifted to better serve plant
dispatch requirements. Replacement of the secondary superheater outlet tubes in
fall 2000 will eliminate the temperature restriction. No other limitations on
output or temperature exist. Other than sootblower erosion, fly ash erosion, and
refractory deterioration, which one would expect from a boiler of this vintage,
there are no ongoing issues.
The Unit 4 boiler at Meredosia is an outdoor Foster Wheeler single furnace,
natural circulation, pressurized, reheat design which was placed in commercial
operation in 1975. The boiler is designed to burn No. 2 or No. 6 fuel oil and is
presently burning No. 4 fuel oil. Ignition is by natural gas. Burners #1 and #2
are equipped to switch between #2 and #6 fuel oil.
The boiler now primarily operates as a peaking unit from early spring to late
fall due to the cost of oil. During the winter months it is placed into
maintenance outage due to the potential for freezing. Over its life, the boiler
has run only 17,569 hours and has been started 653 times. The majority of these
starts would probably be termed hot/warm starts. Maintenance is performed
annually during the winter outage period. The OEM is not usually involved as
in-house expertise is sufficient to maintain the boiler. Major overhaul of the
Unit 4 boiler was last performed in the winter of 1999 to 2000 and included
replacement of the hot side air heater baskets. Cold side baskets were replaced
in 1999.
Overall the Unit 4 boiler and auxiliaries were in good condition; however the
boiler was not as clean as the other Meredosia units. Boiler insulation and
lagging is in fair condition. The boiler was not running during the site visit.
All pressure parts were characterized by station personnel as being in excellent
condition. The last inspection was done in January 2000. No NDT was performed.
Due to its limited usage, no chemical cleaning has been done since 1976. Within
five years the plant expects to water wash the furnace. There is no asbestos
insulation on this boiler.
Boiler water treatment consists of ammonia for pH control and hydrazine for
oxygen control. There is no solids control other than blowdown.
Boiler operation is conservative with no temperature limits being exceeded. The
boiler is equipped with overfire air and gas recirculation for NO\\x\\ control.
Other than lagging, insulation, and ductwork repairs, no other issues exist with
this boiler.
Steam Turbines
Meredosia Power Station consists of four turbine generator units. Units 1 and 2
are each supplied by two duplicate half sized boilers, with all four boilers
being on a common header. Units 3 and 4 are supplied by separate full sized
boilers.
[LOGO] S&W Consultants, Inc. A-41
Units 1 and 2 are duplicate General Electric non-reheat units with a nameplate
rating of 50,000 kW. The normal maximum operating capability is 64,000 net kW.
They went into commercial operation in 1948 and 1949. They are tandem compound
units with a two flow exhaust section and 20-inch last stage buckets. The rated
steam conditions are 850 psig, 900(degrees)F. They were retrofitted with an
integral eight valve steam chests and new high pressure shells in 1976 and 1977,
at which time the 2/nd/ and 3/rd/ stages were removed to facilitate the
migration from the original 10 valves to 8, as the 9/th/ and 10/th/ valves
admitted steam to the 4/th/ stage directly. The units have been primarily in
cycling service since the 1960's. A 4-inch steam line bypass was added in the
1960's to permit full arc admission starting. These units were rebuilt in 1976
and 1977 with new HP shells and steam paths. Stages 2 and 3 were removed to
provide increased unit capacity. The last stage buckets were reportedly replaced
in 1982. The units currently do not have turbine supervisory instruments in
service.
The most recent Unit 1 major turbine overhaul was in December 1994, when the
turbine was fully abated of asbestos. The LP rotor was bottle bored and honed to
remove crack indications detected by boresonic inspection. HP nozzle partition
erosion was repaired. No HP inner or outer shell defects were detected and
distortion was reported as very slight for a machine of this vintage. HP and LP
shell NDE was recommended for the next outage. Turbine replacement has been
budgeted in 2009.
The most recent Unit 2 major turbine overhaul was in 1985. The packing was in
poor condition with brittle and cracked teeth due to heavy rubs from quick
starts and cycling. The LP exhaust hood ledges, struts and horizontal joints
were reported to be deteriorating due to continued water erosion. Extensive
repair or future replacement was recommended; turbine replacement has been
budgeted in 2010.
Meredosia Unit 3 is an Allis Chalmers reheat unit with a nameplate rating of
200,000 kW. The normal maximum capability is 215,000 net kW. It is a tandem
compound 27 stage reheat unit with three LP exhaust ends and 26-inch last stage
buckets. There are two separate three-valve steam chests beneath the main
operating floor. The unit went into commercial operation in 1960. The rated
steam conditions are 2,000 psig, 1050(degrees)F main steam and 1000(degrees)F
reheat. The unit is currently operated in intermediate mode and should continue
to provide reliable intermediate and base load service.
The HP inner shell has been stress relieved to reduce distortion. An ETST high
pressure EHC governor and control system was installed in 1998. The unit does
not have complete water induction protection. The left hand stop valve was
modified to include an internal pilot allowing full-arc starts in 1998. Asbestos
insulation on the turbine shell has been replaced with removable asbestos free
insulation blanket.
The most recent Unit 3 major turbine overhaul was in 1998. A boresonic
inspection of the HP rotor indicated no significant defects. The HP inner
cylinder is distorted and stress relieving was recommended at the next outage.
Many of the HP blade trailing edges were becoming thin from erosion and were
repaired. The HP rotor seals on stages 2 through 6 were replaced. IP blade rows
13 through 17 were significantly eroded and were repaired. The nozzle rings were
in good condition. The IP/LP rotor seals on stages 20 through 22 were replaced.
Stellite erosion shields on the last two stages were replaced. The LP stationary
blade rows were found in good condition. Stationary and rotating seals on stages
21 through 26 were replaced. The turbine area was relatively clean with one
small oil leak under the Unit 3 generator which was being contained and
absorbed. There were no visible foundation cracks or evidence of settling, and
we understand that the turbine foundation is inspected for settling on a
bi-annual basis.
Meredosia Unit 4 is a Westinghouse reheat unit with a nameplate rating of
180,000 kW. It has a maximum capability of 210,000 kW at 5% overpressure. It was
designed as an oil fired peaking unit with
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an expected capacity factor of 40%. It went into commercial operation in 1975 in
a closed cycle configuration with a cooling tower. It is a tandem compound unit
with a two flow exhaust and 23-inch last stage buckets. The rated steam
conditions are 2286 psig, 1000(degrees)F main steam and 1000(degrees)F reheat.
There are two separate three valve steam chests on either side of the unit.
The unit has been operated at less that 10% capacity factor in recent years and
is expected to continue to provide peaking service. It has not been operated
when the ambient temperature is below 32(degrees)F since the outdoor boiler is
not fully heat traced. It is not equipped to operate at sliding pressure, but
does have a turbine bypass system for startup. The original electrohydraulic
governor was upgraded to a digital ETSI system in 1992.
The last major Unit 4 turbine overhaul was in 1986. The HP/IP section was
dismantled but blast cleaning and NDE was not done. The rotor was not removed
from the lower shell so a full steam path inspection was not possible. Visual
inspection that was performed indicated that the rotor was in good condition.
There was light to moderate seal rub damage on HP stages 1 through 12 but no
evidence of significant erosion, deposits or cracks. The IP blade rings also
showed light to moderate seal rubbing and no erosion. The inner and outer upper
shells were in good condition. Minimal repair work was required due to the
overall good condition of the unit. Seal strip replacement and a rotor boresonic
inspection was recommended for the next unit overhaul. The stations plans to
fully overhaul Unit 4 in the spring of 2002.
Inspection of the Meredosia turbines indicated that there were no active oil
leaks except a small leak beneath Unit 3 generator which was being contained.
The turbine support pedestals were free of any visible cracks. Units 1 and 2 do
not have turbine supervisory instrumentation in use. Units 1, 2 and 3 do not
appear to have full water induction protection except extraction non-return
valves. The area was free of accumulated combustibles. The turbine lube oil
tanks are not enclosed but curbed to confine potential spills. A new ETSI system
based on Bailey Infi-90 will be installed on Unit 4 in winter 2000-2001.
Balance of Plant
The condenser cooling water is taken from and discharged back to the Illinois
River. The circulating water system includes a common screenwell structure for
Units 1, 2, and 3. The overall condition of the screens was characterized as
being good.
Units 1 and 2 each have two 50% capacity Worthington vertical-type axial flow
circulating water pumps, located in the powerhouse. The pumps were characterized
as being in good condition. Unit 3 has two 50% capacity C. H. Wheeler vertical,
mixed flow circulating water pumps. The shaft support and baseplate hold-down
details have been modified to correct problems with the original pump design.
These pumps have required periodic overhauls (typically every five years).
Units 1 and 2 share a common concrete intake tunnel. Unit 3 has a similar but
separate intake tunnel. The intake tunnels were dewatered and last inspected in
the 1960's. There have been no apparent signs of intake tunnel deterioration
since that time. The last internal inspection, if any, of the discharge tunnels
was unknown.
Unit 4 is equipped with a Marley mechanical draft 4 cell cooling tower for
condenser cooling. The cooling tower was characterized as being in good
condition. However the tower is marginally sized and the station is considering
increasing the tower's capacity. Unit 4 has two 50% capacity Allis-Chalmers
vertical, mixed flow circulating water pumps. The pumps were last overhauled in
1997-1998; their first overhaul. These pumps are located outside adjacent to the
cooling tower. The cooling tower and circulating water pumps run infrequently
because of the low capacity factors of Unit 4. The tower and pumps were
characterized as being in good condition.
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Units 1 and 2 are each equipped with a Worthington single pass, divided waterbox
surface-type condenser. The Unit 1 condenser was retubed in 1975 with arsenical
admiralty tubing in the main condensing section and 304 stainless steel in the
air offtake sections. The Unit 2 condenser was retubed in 1980 with 90-10 Cu-Ni
tubing in the main condensing section and 304 stainless steel in the air offtake
sections. The Unit 3 condenser was retubed in 1981 with 90-10 Cu-Ni tubing in
the main condensing section and 70-30 Cu-Ni in the air offtake sections. The
Unit 4 condenser has not been retubed since its original installation. It is
equipped with arsenical admiralty tubing in the main condensing section and 304
stainless steel in the air offtake sections. Station personnel characterized the
condensers as being in good to excellent condition (less than 1% of their tubes
being plugged). However it is probable that each of the condensers will have to
be retubed once more in the next twenty years.
Units 1 and 2 each have four stages of feedwater heating. There is no deaerating
heater on these units; deaeration is accomplished in the main condenser. It is
probable that each of the heaters will have to be retubed once more in the next
twenty years. Unit 3 has seven stages of feedwater heating, including the
deaerating heater. All the heaters were reported to be original with no tubes
plugged.
Unit 4 has six stages of feedwater heating, including the deaerating heater. All
the heaters are original. Heater No. 6 is scheduled to be replaced in 2001. In
response to industry concerns about cracks in pressure-part welds in deaerators,
the deaerator undergoes a visual examination annually and more extensive
nondestructive examinations every five years. No significant problems have been
found during the examinations.
Units 1 and 2 share four Worthington boiler feed pumps. The pumps are six-stage,
centrifugal machines and are tied into a common header for greater operating
flexibility. Three of the pumps are motor-driven; the other turbine-driven.
Three pumps are required to achieve full load on Units 1 and 2. The pumps have
proven to be reliable and are only overhauled when needed. Unit 3 has three
identical 50% percent capacity motor-driven Worthington boiler feed pumps. The
pumps are nine-stage, centrifugal machines. All three pumps were overhauled in
the early to mid 1990's. Unit 4 has two 50% capacity motor-driven Pacific boiler
feed pumps. The pumps have run infrequently because of the low capacity factors
of this unit. The pumps were characterized as being in good condition.
Unit 1 and 2 main steam piping from the boiler to the turbine was replaced in
the mid 1980's due to material degradation due to long-term exposure to high
temperatures. Future examinations should be conducted to monitor any ongoing
material degradation. The Unit 3 hot reheat piping was inspected in the 1980's
in response to industry-wide concern about high energy pipe failures,
particularly in seam-welded hot reheat piping. Station personnel have indicated
that the inspections were limited to hot reheat seam-welded piping and that any
defects found were repaired as necessary. No record of the original or any
subsequent inspection reports were found during S&W Consultants' visit. To date
Unit 4 had not accumulated sufficient operating hours to necessarily justify
inspections, but inspections should be conducted in the future as warranted by
the number of operating hours accumulated. Replacement of some piping may be
required in the next 20 years as the damaging effects of high
temperature/pressure exposure and metal fatigue manifest themselves.
All coal is presently delivered to the station either by truck or by barge. The
barge unloading facility was placed in service in 1960. The center steel-encased
concrete pylons at the dock are badly worn from the continuous scraping against
the barge.
The station maintains two coal piles: one for intermediate sulfur coal, the
other for high sulfur coal. Typically the station coal inventory is maintained
between 70,000 and 120,000 tons. The coal is
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reclaimed and fed by reclaim feeders and covered belt conveyors to a crusher
house. The coal is then crushed and transported again by covered belt conveyors
to the station coal bunkers. The system uses a single-belt system (no
redundancy). Historically, sufficient storage has been available in the coal
bunkers to sustain full load operation should an interruption in the coal feed
occur due to an equipment malfunction. The crusher receives periodic maintenance
in lieu of total overhauls. The coal handling is manually controlled. The
station plans to install bunker level devices and automate the tripper and other
belts in 2001. The coal handling system was characterized as being in fair
condition largely due to its age and the corrosion effects of medium to high
sulfur coal.
Bottom ash generated in the coal-fired boilers is water-sluiced to an on-site
pond. The ash is periodically removed from the pond and trucked offsite. The
bottom ash system requires routine maintenance. No significant operating or
maintenance problems were noted.
Units 1 and 2 (boilers 1-4) exhaust to a 526'6" gunite lined concrete
"California" stack. In 1999 International Chimney Co. inspected the stack, took
core samples and declared the stack to be in good condition. Unit 3 (boiler 5)
exhausts to a brick lined 157' carbon steel stack. International Chimney Co.
inspected the stack in 1999 and, other than light spalling of the inner brick
lining, found the stack to be in good condition. In 1997 the inner lining was
water washed with a low volume wash to remove ash deposits for inspection and
tuckpointing. These chimneys are inspected every 2 years. Unit 4 (boiler 6)
exhausts to an 81' unlined carbon steel stack. It was last inspected by Sargent
& Lundy in 1997, with no problems reported. This stack is inspected by plant
personnel due to its infrequent use. There are no problems associated with this
stack.
No. 4 fuel oil is used as the main fuel for Unit 4. The fuel is delivered to
the station by barge and stored in two 4.6 million gallon above ground storage
tanks. Tank 4-2 was visually inspected in 1999. Both tanks are characterized as
being in excellent condition. No. 2 fuel oil is used as an ignition fuel on the
coal-fired boilers. The fuel is delivered by truck and stored in seven 14,000
gallon aboveground tanks. The No. 2 fuel oil tanks were characterized as being
in excellent condition.
The station does not have an auxiliary boiler.
3.1.3.2 Electrical Equipment and Systems
- -----------------------------------------
Electrical equipment and systems includes, as applicable, generators,
transformers, breakers, switchgear, motor control centers, diesel generators, DC
systems, UPS, and instrumentation and controls. Significant findings are noted.
Key generator characteristics are summarized in the following table.
Generator Unit 1 Unit 2 Unit 3 Unit 4
- -----------------------------------------------------------------------------------------------------
Installation 1948 1949 1960 1975
Manufacturer GE GE Allis-Chalmers Westinghouse
Rated kVA 71,875 71,875 281,600 233,000
Voltage (kV) 13.8 13.8 19 19
PF 0.8 0.8 0.85 0.90
Rated kW gross 65,000 65,000 239,360 209,700
Rpm 3600 3600 3600 3600
Exciter Shaft Solid State Solid State Solid State
Control Auto/Manual Auto/Manual Auto/Manual Auto/Manual
Generator Rotor Rewind none 2000 1990 none
Last Major Overhaul 1995 2000 1997 none
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Unit 1 generator was put in service in 1948 and has its original shaft driven
exciter along with its original motor driven reserve exciter (which can also
serve Unit 2). The generator was last inspected in October of 1995. The stator
was inspected and girth cracking was noted in this test report, and was
similarly noted during its last inspection in 1982. Additionally the rotor was
removed and new retaining rings and new main leads were installed. Present plans
are to add Iris PD sensors in 2001.
Unit 2 generator was put in service in 1949. A solid state exciter was installed
in 1985. Unit 2 had its latest overhaul in February of 2000 when the rotor was
rewound, new retaining rings were installed, new main leads were installed, and
new collector rings were installed. The generator also has an Iris PD monitoring
system and a "flux" probe for rotor short detection.
Unit 3 generator was put in service in 1960. It has an ABB solid state exciter
installed in 1997. The rotor was rewound in 1990 and new retaining rings were
installed in 1998. The station has been contacted by the OEM and told that
stators of similar units have experienced lamination migration. Inspections to
date have not indicated any problems. Further monitoring is being conducted via
an Iris PD system. The stator may require a rewind in the next five years, but
turbine/generator ("T/G") replacement has been planned and budgeted for 2012.
Unit 4 generator has its original solid state exciter. The voltage regulator's
electro-mechanical components were updated with solid state in early 2000. The
generator rotor has never been pulled and no major overhauls have been
performed.
The GSUs for Units 1 and 2 are original. Each GSU consists of three single phase
transformers with an equivalent rating of 55/66.5 MVA 69kV - 13.8kV. Unit 1
transformer, manufactured by GE, visually shows its age. Additionally, the
transformer has some minor oil leaks around the instrument connections but no
constant oil leaks were observed. The transformer is scheduled for a major
overhaul in 2001. Unit 2 transformer is original, manufactured by Allis-
Chalmers. The transformer oil was replaced and the transformer was tested in
1999 and found to be in good condition.
Unit 3 GSU is a Westinghouse oil filled transformer rated 240 MVA 138kV - 19kV
and is original equipment. The transformer was installed in 1960 and had a major
overhaul in 1998. The transformer has a minor oil leak around a flow gauge but
no constant leaks were observed. Unit 4 GSU is a GE oil-filled transformer rated
235 MVA 138kV - 19kV and is original equipment. The transformer, installed in
1975, appears to be in fair to good condition, with minor oil leaks around the
instrument connections. All the switchgear and transformers appear to be in good
condition and are inspected and cleaned during outage opportunities. All the oil
filled transformers, according to the utility, have no detectable PCBs in their
oil. The transformers are under a routine preventative maintenance plan by the
utility. The oil is tested on an annual basis and the transformers are serviced
during Unit outages.
The Unit 1 and 2 motor control centers are original Nelson Electric MCCs. Some
of the MCCs in the basement near the fans are in a poor location and are in need
of service, although there was no indication given that this resulted in any
outages. The remainder of the MCCs do show their age but continue to run without
any major problems. The Unit 3 MCCs are Westinghouse and the Unit 4 MCCs are
Cutler Hammer. All the MCCs, considering their age and operating conditions,
appear to be in good condition.
Presently there are a number of control panels required to operate Unit 1 and 2
boilers and turbines. The present plan is to construct a combined control room
for Units 1 and 2 in two years, eliminating the individualized panels and
operating via the DCS. Additional instrumentation and controls ("I&C")
observations include:
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. Presently boilers 1 to 4 do not have a BMS and there are no future plans
for an upgrade.
. Motor operated valves exist on the condenser circulating water system and
the 4" main steam bypass valves to the turbines. Most other valves with
the exception of modulating "control" valves are operated manually. There
are future plans to convert to MOVs.
. Unit 3 is controlled by a Bailey Infi 90 system installed in 1998. This
completely replaced a Network 90 system originally installed in 1985 and
upgraded in 1990.
. Unit 4 has control on the Bailey Infi 90 DCS. The balance of plant
controls are hard wired with no plans to convert to the DCS. The BMS was
recently upgraded in 1999 to latest generation Forney system.
In general, walking around the plant, the areas around the electrical equipment
were well lit. Some of the motor control centers had a coating of dust but there
was no indication given that this resulted in any outages.
3.1.3.3 Emissions Control Equipment
- ------------------------------------
ESP and Flyash Handling Systems
At each Meredosia Boiler 1-4, the ID fan draws the flue gas from the balanced-
draft boiler, through the tubular airheater, and discharges into an ESP, which
operates under positive pressure. The discharge flue gas ductwork of the four
ESPs are tied to a common stack. Boiler 1-4 ESPs were provided by Joy
Manufacturing Company, and installed in 1971. Each ESP has four fields in the
direction of gas flow. The common stack of the four ESPs has a certified opacity
monitor system. Each ESP has fly ash collection hoppers of the pyramidal design.
No FGC is employed at Meredosia. The dry fly ash is collected and wet sluiced to
an onsite ash pond. The Hydroveyor wet ash sluice system was provided by United
Conveyor Corporation.
Based on a visual inspection of the ESP systems and fly ash handling equipment,
a review of plant records, routine inspection reports, and discussions with O&M
staff, the ESP systems of Units 1 and 2 appeared to be in operational condition.
The station indicated that the ESP systems routinely remain within compliance
for stack opacity, at boiler full load conditions, while employing the
medium/higher sulfur coal fuel in boilers 1-4. During the S&W Consultants visit,
the Units 1 and 2 common stack opacity (at a combined boiler load of 105 MW) was
indicated in the control room to be 3.06 percent. The SO\\2\\/NO\\x\\ levels
were indicated in the control room to be 1398 ppm SO\\2\\ and 0.49 lb
NO\\x\\/mmBtu, at 10.7% CO\\2\\.
At Unit 3 (boiler # 5), the ID fans draw the flue gas from the balanced-draft
twin- furnace boiler, through the Ljungstrom regenerative airheaters, ESPs, and
discharges to a Unit 3 stack. Fly ash is removed from the flue gas stream by an
ESP that was provided by GE Environmental Systems, and installed in 1992. This
new GE ESP completely replaced the old ESP. The new ESP has eight fields in the
direction of gas flow. The Unit 3 stack has a certified opacity monitor system.
The Unit 3 ESP dry fly ash is collected within the hoppers located beneath the
ESP and is wet sluiced to the onsite ash pond that is common to all the units.
The ESP system of Unit 3 appeared to be in good condition. It was reported that
the ESP system routinely remains within compliance for stack opacity, at boiler
full load conditions, while employing the lower-sulfur coal fuel in Unit 3.
During the S&W Consultants visit to the control room, the Unit 3 average opacity
was 14.2 percent in the stack (with the reheat furnace ESP opacity at 13 percent
and superheat furnace ESP opacity at 17 percent), with the Unit 3 load at a
lower-load of 120 MW. At this lower load, the SO\\2\\/NO\\x\\ levels were
indicated in the control room to be 704 ppm SO\\2\\ and 0.51 lb NO\\x\\/mmBtu,
at 9.7 percent CO\\2\\.
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The plant records indicate that the Unit 1-3 ESP and fly ash handling systems
have historically experienced a normal level of inspections, maintenance, and
design improvements for a unit of this type.
NO\\x\\ Control Equipment
Units 1 and 2 employ the original tangential fired CE burner design. Unit 3 had
new low NO\\x\\ burners installed in 1998, ABB C-E Low NO\\x\\ Concentric Firing
System, LNCFS-I (Level 1 type), designed to achieve 0.45 lb NO\\x\\/mmBtu at
full load conditions. Unit 4 (Boiler #6) operates on fuel oil and has no ESP.
Unit 4 retains its original over-fire air ports and a flue gas re-injection fan
for NO\\x\\ control.
Units 1, 2, 3, and 4 SO\\2\\ Control Equipment
Station personnel reported that Units 1 and 2 (boilers 1-4) burn medium sulfur
coals in order to maintain proper ESP performance and stack(s) opacity. For
example, records (dated December 1999) indicated that the average coal at Unit 1
had approximately 3.13 lb SO\\2\\/mmBtu, on an as-received basis. Unit 3
routinely burns a lower sulfur coal, since the new ESP was designed to
accommodate such coals. For example, records (dated December 1999) indicated
that the average coal at Unit 3 had approximately 2.14 lb SO\\2\\/mmBtu, on an
as-received basis. The station does not employ FGD.
3.1.3.4 Remaining Life
- -----------------------
Meredosia Units 1 and 2 are older, less efficient units that have been utilized
as peaking units in recent years. Unlike the larger units that may be faced with
additional costly NO\\x\\ reductions, Units 1 and 2 at Meredosia have attained
low NO\\x\\ emissions through combustion tuning. The expected capital
requirements would be to compensate for the effects of additional component
aging of the peaking boilers through planned replacements and maintenance as
long as they remain competitive. The boilers would be expected to require more
intensive non-destructive testing if they are to remain in service for an
extended period of up to 30 years.
The existing Unit 1 and Unit 2 turbines could be operated for an additional 20
years with significant expenditures. Peaking service has a detrimental effect on
turbines and their auxiliaries, and eventual HP shell and steam path
replacements would be likely. The present rotors may have only a limited life
remaining. Given these considerations, replacement steam turbines are included
in the budget forecast.
The Unit 1 and 2 precipitators could not be expected to operate reliably for an
additional 30 years without extensive rebuilding.
The current condition of Meredosia Unit 3 would permit an additional 20 years of
operation. NO\\x\\ levels were brought into compliance with the addition of low
NO\\x\\ burners and overfire air. Superheater and reheater pendants should be
replaced, within the superheater already scheduled in 2000. Extensive tube
erosion shield replacement will continue to be necessary to minimize tube
thinning failures. It is likely that the superheater and reheater outlet headers
would require replacement to achieve 20 years of additional reliable life. The
primary superheater will also require rebuilding in 3 to 5 years. It is
recommended that non-destructive testing be intensified to establish a condition
baseline for future economic operation.
The Unit 3 turbine has inner shell distortion and significant steam path
erosion. Major HP inner shell repairs or a complete shell replacement could be
expected as early as 2004 to 2008. Steam turbine replacement has been planned
and budgeted for 2013.
Meredosia 4 can continue in operation as a peaking unit for 20 years providing
that a comprehensive non-destructive testing and inspection program is
instituted. Peaking duty imposes more severe stresses and
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can result in accelerated component life consumption. The winter unit layup
periods must be done under dry conditions and boilers and other equipment should
be protected with a nitrogen blanket. It is unlikely that the unit would ever be
returned to base load service firing oil and natural gas is not currently
available at the site. The next scheduled overhaul (2009) should include a more
complete turbine dismantling to establish a baseline condition of shells, rotor
and steam path components. Although not anticipated at present, if the unit
remains on oil, a precipitator may eventually be required for particulate
control.
3.1.4 Hutsonville Power Station
The Hutsonville Power Station is located along the Wabash River, outside of
Hutsonville, Illinois. Access to the site is by highway. The station has no rail
facilities. S&W Consultants visited the Hutsonville Power Station on Wednesday,
Feb. 9, 2000. The station appeared to be well maintained and in reasonably good
condition, particularly considering its age.
The station currently consists of two steam-electric generating units (Units 1
and 2 were retired in place in 1982). Units 3 and 4 are identical balanced
draft, reheat, coal-fired steam-electric generating units with nominal
capacities of 76 and 77 MW net respectively. The units were placed in service in
1953 and 1954. The major power generation equipment is located indoors. Water
for the station's once-through cooling system is taken from and discharged back
to the Wabash River. The units are equipped with electrostatic precipitators for
control of particulate emissions. The units have no special provisions for
NO\\x\\ or SO\\2\\ control.
Table 3.1-4 provides a summary of the characteristics of Units 3 and 4. The
sections that follow detail our findings in the areas of mechanical, electrical,
and environmental systems condition and remaining life.
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Table 3.1-4
Hutsonville Power Station Characteristics
====================================================================================================
PERFORMANCE UNIT 3 UNIT 4
====================================================================================================
Normal Summer Capacity (MW Net) 76 77
- ----------------------------------------------------------------------------------------------------
Minimum Load (MW) 31 31
- ----------------------------------------------------------------------------------------------------
Full Load Heat Rate, HHV (Btu/kWh) 10,400 10,400
- ----------------------------------------------------------------------------------------------------
PRIME MOVER
- ----------------------------------------------------------------------------------------------------
Manufacturer GE GE
- ----------------------------------------------------------------------------------------------------
Tandem Compound Tandem Compound
Type Two Flow Two Flow
- ----------------------------------------------------------------------------------------------------
Commissioned (Year) 1953 1954
- ----------------------------------------------------------------------------------------------------
HP Turbine Inlet Pressure/Temp (psig/(0)F) 1450/1000 1450/1000
- ----------------------------------------------------------------------------------------------------
Reheat Turbine Inlet Temp ((0)F) 1000 1000
- ----------------------------------------------------------------------------------------------------
ELECTRIC GENERATOR
- ----------------------------------------------------------------------------------------------------
Manufacturer GE GE
- ----------------------------------------------------------------------------------------------------
Cooling Hydrogen Hydrogen
- ----------------------------------------------------------------------------------------------------
MVA 75.0 75.0
- ----------------------------------------------------------------------------------------------------
STEAM GENERATOR
- ----------------------------------------------------------------------------------------------------
Manufacturer CE CE
- ----------------------------------------------------------------------------------------------------
No. of Boilers 1 1
- ----------------------------------------------------------------------------------------------------
Circulation Natural Natural
- ----------------------------------------------------------------------------------------------------
Draft Condition Balanced Balanced
- ----------------------------------------------------------------------------------------------------
Cycle Type Reheat Reheat
- ----------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal
- ----------------------------------------------------------------------------------------------------
OTHER
- ----------------------------------------------------------------------------------------------------
Cooling Water Source Wabash River Wabash River
- ----------------------------------------------------------------------------------------------------
Fuel Delivery Truck Truck
====================================================================================================
3.1.4.1 Mechanical Equipment and Systems
- -----------------------------------------
Major systems include the boilers, steam turbines, and balance of plant.
Boilers
The two boilers at the Hutsonville Power Station are identical CE single
furnace, natural circulation, balanced draft, reheat design. The boilers are
designed to burn bituminous coal and presently burn Indiana coal. No. 2 oil is
used for ignition and burner stabilization. The boilers were converted from
pressurized to balanced draft operation with the addition of two induced draft
fans on each boiler in 1971 and 1972. The boilers presently operate as load
following units with no limitations on output or steam conditions.
Major maintenance is performed on an 18-month cycle including an annual air
preheater wash. A mini-outage is performed in off years. Recent (both units)
system maintenance and repairs include:
. A new primary superheater in 1997. Replaced due to the failure of the
original design superheater, due to structural problems. Replacement
included redesign of the support system and new integral tube shields.
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. Induced draft fan wheels in 1992, including variable speed hydraulic
couplings and new motors. The original fans were subject to flyash erosion.
The fanwheels were redesigned (airfoil design) to prevent recurrence of the
problem.
. Secondary superheater outlet pendant section, reheat outlet pendant section
and economizer in the 1980's.
Major overhaul of the Unit 3 boiler was last performed in the fall of 1998. The
boiler was last inspected in October of 1999. Major work performed during the
last overhaul included pulverizer and coal pipe maintenance. In August of 1998,
Storm Engineering performed an on-line test of the Unit 3 and 4 pulverizers to
evaluate opportunities for combustion optimization. The resultant
recommendations included maintenance items, which were completed during the 1998
outage.
Major overhaul of the Unit 4 boiler was last performed in the Fall of 1999 and
included a complete inspection by the company boiler engineer. Major work
included steam drum separator repairs, air preheater leak repairs, superheater
leak repairs, reheater shield replacements, economizer flyash erosion pads,
pulverizer inspection and minor repairs, and safety valve tests.
Overall the boilers and auxiliaries were clean and in good condition considering
age. The boilers were running at 245,000 lb/hr (30 MW) each during the site
visit. Chemical cleaning is infrequent and was last done in 1992 for Unit 3 and
over ten years ago for Unit 4. As with Unit 3, tube leaks are rare. Remaining
asbestos insulation was estimated by the plant to be 25% in the boiler area.
Boiler ductwork is considered in fair condition. No issues of significance were
noted for any pressure parts. Although waterwalls have been repaired through the
years, no sections have been replaced. Inspection is done visually with
hydrotesting used to confirm repair integrity. No NDT inspection reports were
available and metallurgical testing is rarely done, according to plant
personnel. Boiler water treatment consists of hydrazine for oxygen control and
phosphate for solids control. No pH control chemicals are required.
Boiler operation is conservative with no temperature limits being exceeded.
There are no specific NO\\x\\ control provisions other than combustion tuning.
No seasonal or other limitations on output or temperature exist. Other than
casing and ductwork air in-leakage and fly ash erosion, which one would expect
from a boiler of this vintage, there are no major issues. Sootblowers are aging
and should be replaced in the next five to ten years. Other future boiler items
include water wall replacement, reheat inlet pendants, and coal bunkers relined.
Both units are often out of service for days or weeks in the spring. They are
drained hot and blanketed with nitrogen for corrosion protection. Since
Hutsonville has no auxiliary boiler, one boiler is always in operation for
freeze protection during the winter months.
Steam Turbines
Hutsonville turbine generators are duplicate General Electric reheat units with
a nameplate rating of 60,000 kW. The normal operating capability is 77,000 kW.
They went into commercial operation in 1953 and 1954. They are tandem compound
units with a two flow exhaust section. The rated steam conditions are 1450 psig,
1000 (degrees)F main steam and 1000 (degrees)F reheat. They are configured with
upper and lower four-valve integral steam chests and are equipped with
conventional mechanical hydraulic governors. The turbines have 23 stages and
five extractions for feedwater heating. They have 20-inch last stage buckets.
The units have been operated primarily in cycling mode in recent years. The
units are sometimes out of service for days or weeks in the spring. They are
equipped with a stop valve bypass for full arc admission startup but do not
utilize sliding pressure. There is no turbine bypass system.
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The seals were converted from water seals to steam seals in 1979 and 1980. The
HP/IP rotors were replaced in about 1979, according to records. The only record
of significant shell cracking is in the upper steam chest areas and weld repairs
were completed. The Unit 4 shell has been heat treated once due to distortion.
There has been little evidence of blade and nozzle damage from solid particle
erosion. New extraction non-return valves were installed in 1999 but the units
do not have full water induction protection.
The units can be operated under automatic generation control within preset ramp
and load limits. Startup speed ramping is manually controlled through the bypass
servo operator.
The most recent Unit 3 major overhaul was in September 1997. The HP/IP and LP
sections and all admission valves were fully dismantled. HP/IP and LP rotor
boresonic inspections were performed. There were nine small indications detected
in six areas of the HP/IP and 160 small LP indications. The rotors were found
fit for continued service but reinspection was recommended within 2,000 starts
or 10 to 12 years. Both rotors required repair and replacement of various blade
tenons and shroud bands. The lower HP inner shell was removed for repair of
cracks behind the nozzle plates. Cracks in the nozzle plates were repaired.
Major cracks were repaired in the 2/nd/, 7/th/, 8/th/, 9/th/ and 15/th/ stage
diaphragms. The contractor recommended that the HP inner shell alignment
problems and 10/th/ stage diaphragm distortion be further investigated at the
next outage. Cracks around the HP lower inner shell first stage pressure tap
should be monitored for changes.
At the previous Unit 3 major overhaul in 1989, new 2/nd/ stage buckets and
covers were installed. Erosion shields were replaced on the last stage buckets.
A major stress relieved crack repair was done on the HP outer shell integral
steam chest. All of the steam packing was replaced, mostly with retractable type
packing.
The most recent Unit 4 major overhaul was in March 1998. The turbine was fully
dismantled for inspection. New 4/th/ stage buckets were installed due to heavy
foreign object damage. HP/IP and LP rotor boresonic inspections were performed.
There were three small HP/IP indications but a much larger number of small LP
indications. The rotors were found fit for continued service with reinspection
recommended within 2,000 starts or 10 to 12 years. Bucket covers were replaced
on the 16/th/ and 22/nd/ stages. No significant shell defects were found.
During the previous Unit 4 major overhaul in 1989, 2/nd/ and 7/th/ stage buckets
were replaced. Cracks in the last stage buckets and tie wires were repaired. New
erosion shields were installed on the last stage. The HP/IP rotor was
boresonically inspected with no indications reported.
An asbestos abatement initiative is continuing. The turbine shells have been
reinsulated with asbestos free removable blankets. New extraction non-return
valves were added in 1999 but turbine water induction protection is limited.
There is no turbine bearing area fire protection.
A turbine area visual inspection indicated that there were no significant recent
oil leaks. The area was free of combustibles and found to be clean for a coal
fired station of this vintage. Hutsonville has a new DCS system but on-line
turbine performance was not included. The turbine startup thermocouples are
monitored and alarmed through the DCS. There are no summer capacity limits due
to the cooling system. Minimum stable unit load is 31 MW which is equivalent to
two pulverizers in operation.
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Balance of Plant
Water for the main condenser cooling is taken from and returned to the Wabash
River in a once-through circulating water system. The circulating water system
includes an enclosed screenwell intake structure which houses the traveling
water screens (one for each unit). The screens were characterized as being in
good condition. Units 3 and 4 each have two 50% capacity vertical-type axial
flow circulating water pumps. Station personnel characterized the circulating
water pumps as being in good condition. Circulating water is carried to and from
the condensers in concrete tunnels. The tunnels were last inspected in 1994.
Based on the divers' observations there did not seem to be any structural
deterioration of either tunnel at that time. There is no indication of any
change in the condition of the tunnels since the last inspection.
The units are equipped with Foster-Wheeler cross-flow, divided waterbox,
surface-type condensers. The Unit 3 and 4 condensers were completely retubed
with 90-10 Cu-Ni tubing in 1976 and 1980 respectively. The condensers are
scheduled to be retubed again in 2003 and 2004.
Each unit has five stages of feedwater heating, including the deaerating heater.
There are two stages of low pressure feedwater heaters. It is probable that the
heaters will have to be replaced once more in the next twenty years.
Each unit has two 100 percent capacity motor driven boiler feed pumps. The pumps
are typically overhauled every fifteen years. All of the pumps were overhauled
in 1999, including an upgrade to mechanical seals. One spare rotating element
(common to both units) is maintained as a spare part. The spare element is
scheduled to be rebuilt in 2000.
The hot reheat piping was inspected in the late 1980's in response to industry
wide concern about high energy pipe failures due to creep damage, particularly
in seam welded hot reheat piping. Indications are that these inspections were
limited to hot reheat seam welded piping and that any defects found were
repaired as necessary. No record of any inspections on Unit 3 were found during
S&W Consultants' visit. However, a review of a 1987 report by Conam Inspection,
made available to S&W Consultants, confirms that a complete inspection of the
Unit 4 hot reheat piping was conducted. The report describes the piping as being
"seamless" and notes that the inspections showed no evidence of creep damage.
However Conam Inspection recommended that the piping be reinspected at three
year intervals. No records of subsequent inspections were found during S&W
Consultants' visit. Replacement of some piping may be required in the next 20
years as the damaging effects of high temperature/pressure exposure and metal
fatigue manifest themselves.
The station has no rail facilities. All coal is delivered by truck and dumped
onto the coal pile. A 45 to 60 day supply is typically maintained onsite. The
system uses a single-belt system (no redundancy). Historically, sufficient
storage has been available in the coal bunkers to sustain full load operation
should an interruption in the coal feed occur due to an equipment malfunction.
Coal handling is automatically controlled. The coal handling system was
characterized as being in fair to good condition.
Bottom ash generated in the coal-fired boilers is water-sluiced to an on-site
pond. The bottom ash system requires routine maintenance. No significant
operating or maintenance problems were noted. The bottom ash pond, however, is
nearing its capacity and the pond will either have to be cleaned out or a new
pond constructed.
Units 3 and 4 each have a 12' diameter 57' high gunite lined steel stack. In
1995 both stacks were inspected by Sargent & Lundy. The findings indicated that
the stacks were structurally sound with no major deficiencies. Repairs made to
the Unit 4 stack in 1986 for a buckle on the east side of the stack at
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the third WT ring stiffener are still in good condition. At the time Sargent &
Lundy recommended a reinspection in three years. This should be done within the
near future.
The station has no auxiliary boiler. If neither unit is running, and station
heating is required, a unit is "forced on-line" to provide the required heating.
3.1.4.2 Electrical Equipment and Systems
- -----------------------------------------
Electrical equipment and systems includes, as applicable, generators,
transformers, breakers, switchgear, motor control centers, diesel generators, DC
systems, UPS, and instrumentation and controls. Significant findings are noted.
The Hutsonville Units 3 and 4 turbine generators are duplicate machines with
General Electric hydrogen cooled generators. Key generator characteristics are
summarized in the following table.
Generator Unit 3 Unit 4
--------------------------------------------------------
Installation 1953 1954
Manufacturer GE GE
Rated kVA 75,000 75,000
Voltage (kV) 13.8 13.8
PF 0.8 0.8
Rated kW 60,000 60,000
Rpm 3600 3600
Exciter Solid State Solid State
Control Auto/Manual Auto/Manual
Generator Rewind none none
Last Major Overhaul 1992 1998
The Unit 3 generator was scheduled to have a major inspection in March 2000. The
rotor was to be removed, the retaining rings inspected, boresonic testing done
on the field, bore copper replaced, and the stator cleaned, inspected and
tested. Additionally, in 2000 an Iris PD monitoring system was installed to
monitor the stator condition. S&W Consultants will review the inspection report
when available. A major inspection previously was done in March of 1992. Upon
inspection of the stator, 30% of the wedges were loose and were restacked per
factory and field standards.
The Unit 4 generator rotor was removed in March 1998 and retaining rings were
inspected, bore sonic testing was completed on the field, bore copper was
replaced, stator was cleaned, inspected and tested. Also in March 1998, an Iris
PD system was installed. In December of 1999, a PD test report was issued on
Unit 4 indicating that for a unit of its winding age, it showed low PD activity
and overall there was no indication of any problems of concern in the data.
The generators had been inspected every 5 to 7 years but are now on a 9 to 10
year schedule. The GSU transformers for Units 3 and 4 are original. Each GSU
transformer is represented by parallel Westinghouse oil filled 40 MVA, 138kV -
13.2kV transformers. All four of the transformers appear to be in good condition
with the exception of a minor oil leak on each of the Unit 3 transformers around
the oil pump, which is scheduled to be corrected at the next outage.
All the oil filled transformers, according to the utility, have no detectable
PCB in their oil. The transformers are under a routine preventative maintenance
program by the utility. The transformer oil is tested annually and the equipment
is serviced during every boiler outage, which was on a yearly basis and has now
been changed to eighteen months.
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Unit 3 and 4 control systems were upgraded in 1989 to a Westinghouse WDPF
Classic system. Included in the controls are combustion controls, balance of
plant, sootblower controls, alarm and monitoring functions and the coal handling
system.
In general, walking around the plant, the areas around the electrical equipment
were well lit. Inside some of the motor control centers there was a light
coating of dust but there was no indication given that this resulted in any
outages.
3.1.4.3 Emissions Control Equipment
- ------------------------------------
ESP and Flyash Handling Equipment
At each boiler, the ID fans draw the flue gas from the balanced-draft boiler,
through the Ljungstrom regenerative airheaters, ESP, and discharge to its own
stack. The ESPs were provided by Joy Manufacturing Company, Western
Precipitation Division, and installed in 1970 and 1971, respectively. Each
unit's ESP is essentially the same and has four fields in the direction of gas
flow. No FGC is employed at the Hutsonville ESPs.
The ESP dry fly ash is collected within the hoppers located beneath the ESP and
is wet sluiced to an onsite ash pond. The Hydroveyor wet ash sluice system was
provided by United Conveyor Corporation. It was reported that the ash pond is
periodically dredged and the ash is given away.
The ESP systems of Unit 3 and 4 appeared to be in operational condition. The
station indicated that currently the ESP systems routinely remain within
compliance for stack opacity, while employing the higher sulfur coal fuel. It
was reported that the ESPs are relatively small in size (i.e., low surface
collection area) and to compensate, higher sulfur coal is routinely burned at
Hutsonville to assist the ESPs. It was reported that during 1998, an enforcement
action was brought against the Hutsonville Power Station for excessive opacity
exceedances. The problem was traced to improper coal and excessive air
inleakage. Use of proper coal and repair of the air leaks provided ESP
improvements. It was reported that opacity has not been a problem since
September 1998.
Station personnel reported that currently, the Unit 3 and 4 stack(s) opacity at
full load conditions is routinely 10 to 12 percent, which is well below the
permit value of 30 percent. During the S&W Consultants visit, the stack(s)
average opacity (at boiler lower-load conditions) was indicated in the control
room to be 3.0 percent (Unit 3 load at 30.1 MW) and 5.8 percent (Unit 4 load at
30.2 MW). The SO\\2\\/NO\\x\\ levels were indicated in the control room to be
3.8 lb SO\\2\\/mmBtu (Unit 4) and 0.57 lb NO\\x\\/mmBtu (Unit 4) at 30.2 MW.
The plant records indicate that the ESPs and fly ash handling systems have
historically experienced a normal level of inspections, maintenance, and design
improvements for units of this type.
NO\\x\\ Control Equipment
Units 3 and 4 employ the original C-E tangential firing burner design and the
NOx is capable of being maintained at approximately 0.52 lb NO\\x\\/mmBtu at
full load conditions, using combustion tuning.
SO\\2\\ Control Equipment
Units 3 and 4 routinely burn coals with approximately 4 lb SO\\2\\/mmBtu, in
order to maintain proper ESP performance and stack(s) opacity. For example,
records (dated December 1999) indicated that the average coal at the Hutsonville
Power Station had approximately 4.74 lb SO\\2\\/mmBtu, on an as-received basis.
The station does not employ an FGD system.
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3.1.4.4 Remaining Life
- -----------------------
Hutsonville Units 3 and 4, although found to be in apparent good condition for
their age, have operated in recent years at low capacity factors. This operating
mode involves more frequent cycling which tends to increase component stress
levels and consume remaining life at a more rapid rate. Both units are nearly 50
years old and the recent history of NDE and metallurgical testing is quite
limited. Steam turbine replacement has been budgeted. With this capital
expenditure and others that may be identified through a resumption of NDE, the
Hutsonville units can be operated reliably in intermediate service for another
20 years. A modern burner management system will also be required. It is likely
that some additional impacts of the low capacity factor cyclic operation will be
detected in both boilers. It will be necessary to perform tube, header and
piping inspections to identify other component replacements in order to operate
until 2020.
3.1.5 Grand Tower Power Station
- ----------------------------------
The Grand Tower Power Station is located on the Mississippi River outside the
town of Grand Tower, Illinois. Access to the site is by highway. The station has
no rail facilities. S&W Consultants visited the Grand Tower Power Station on
February 17/th/ and 18/th/, 2000. The station repowering is underway, with one
steam turbine dismantled for refurbishment and the other still in operation.
The station currently consists of two steam-electric generating units. The
boilers are to be retired in November 2000 and March 2001. Unit 3 is a balanced
draft, nonreheat, coal-fired unit rated at 85 MW net. Unit 3 was placed in
service in 1951. Unit 4 is a balanced draft, reheat, coal-fired unit rated at
105 MW net. Unit 4 was placed in service in 1958. Cooling water for the main
condensers is taken from and discharged back to the Mississippi River in a
once-through system. Units 3 and 4 are equipped with electrostatic precipitators
for control of particulate emissions. Units 3 and 4 have no special provisions
for NO\\x\\ or SO\\2\\ control.
The station is in the process of being repowered as a combined cycle unit
scheduled to go into commercial operation in 2001. The majority of the existing
fuel systems and steam generation equipment and auxiliaries will be retired in
place. The existing Unit 3 and 4 steam turbines will be repowered with two SWPC
501FD CTs. Each CT is rated approximately 176 MW (gross, 59(degrees)F). After
the repowering, the Unit 3 and 4 steam turbines will be rated at approximately
90 MW and 112 MW net respectively. Nomenclature for the two combined cycle
systems will be Unit 1/3 (239 MW net) and Unit 2/4 (253 MW net).
The units will be suitable for single fuel (natural gas) operation and will be
provided with facilities to support operation on gas. The generating units will
be designed for intermediate duty service. The repowering effort is described
further in Section 4.
3.1.5.1 Mechanical Equipment and Systems
- -----------------------------------------
The condition of existing equipment to be utilized in the repowered
configuration is briefly described in the following sections.
Boilers
The boilers and associated equipment (fans, mills, electrostatic precipitators,
ductwork, stacks, etc.) will be retired as part of the repowering project.
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Steam Turbines
Grand Tower Units 3 and 4 are similar Westinghouse tandem compound two flow
exhaust units. Unit 3 is a non-reheat unit with design steam conditions of 1250
psig and 950(degrees) F. Unit 4 is a reheat unit with steam conditions of 1450
psig, 1000(degrees) F main steam and 1000(degrees)F reheat. These units were
designated preferred standard units and belong to a large class of units
manufactured in the 1950's and 60's. The Grand Tower units have operated at
relatively low capacity factors, however, major overhauls have been performed at
appropriate intervals.
The Unit 3 turbine-generator is a Westinghouse tandem-compound, double-flow
nonreheat unit with a nominal rating of 85 MW. The design steam conditions are
1250 psig, 950(degrees)F main steam. The unit was commissioned in 1951. During
the early 1970's the last three rows of HP blades were removed which resulted in
the unit being uprated from the original 60,000 kW nameplate rating to 87,500
kW. The last major overhaul of the Unit 3 low pressure (LP) turbine was
performed in 1997-1998 and consisted of a complete disassembly and inspection of
the LP turbine. The HP/IP section was last overhauled in 1999.
This unit is an AIEE - ASME Preferred Standard Design, it is a two-case,
tandem-compound, condensing unit with 20 inch last stage blades. The unit has
two design features that, while typical of the era, are undesirable by today's
standards: (i) the two last stage wheels, of the low-pressure rotor, are shrunk
on the low-pressure shaft; and (ii) while the governor end high pressure casing
seal is steam sealed, the remaining seals are water seals. While the unit
inspection reports do not indicate stress corrosion problems at the last stage
wheel bores or casing cracks/shaft cracks in the water seal areas, these are
areas of concern.
The Unit 4 turbine-generator is a Westinghouse tandem-compound, double-flow,
reheat unit with a nameplate rating of 100 MW. The design steam conditions are
1450 psig, 1000(degrees)F /1000(degrees)F main steam. The unit was commissioned
in 1958.
The turbine's L-0 and L-1 blading was replaced in 1986. The turbine was in the
process of being overhauled during S&W Consultants' visit. The turbine was
overhauled previously in 1990.
This unit is an AIEE - ASME Preferred Standard Design, it is a two-case,
tandem-compound, condensing unit with 23 inch last stage blades. Like Unit 3,
the unit has design features that, while typical of the era, are undesirable by
today's standards. While the unit inspection reports do not indicate stress
corrosion problems at the last stage wheel bores or casing cracks/shaft cracks
in the water seal areas, these are areas of concern.
The 1999 Unit 3 outage inspection report was reviewed along with a 1993 Unit 3
steam path audit and a 1999 Unit 4 steam path audit. Unit 3 exhibits some
evidence of HP turbine cylinder distortion and horizontal joint leakage along
with heavy LP turbine erosion. The crossover piping from the HP to the LP
turbine had heavy erosion. Steam chest distortion seems to be a problem and some
chest cracks were detected. Unit 4 exhibited HP inner cylinder cracking and IP
inner cylinder distortion. The HP and IP blading shows some damage from caging
rubs and some LP blade erosion. Nozzle blocks and a number of seals need to be
replaced.
The rotor bores of both units were inspected between 1997 and 1999. Some
reportable indications were detected. The LP turbines are water rather than
steam sealed. Water seals are considered obsolete and create potential for rotor
damage with cyclic operation. It is reasonable to expect to be able to operate
these turbines for about five years or another overhaul cycle. Based on the data
provided, and the "industry" data that is available for this design, the steam
turbines are in reasonably good condition.
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However, with 49 and 42 years of service, respectively, the units are near the
end of their design lives. Steam turbine replacement is included in the capital
expense forecasts in 2005 (Unit 3) and 2006 (Unit 4).
Balance of Plant
The condenser cooling water is taken from and returned to the Mississippi River.
The circulating water system consists of separate screenwell structures for
Units 3 and 4. At the next overhaul, the intent is to upgrade all submerged
structural members to stainless steel. The overall condition of the screens was
characterized as good. The circulating water piping to and from the condenser is
buried. Plant personnel indicated that the piping has not been inspected but
indicated that there have been no significant signs of significant corrosion,
etc. The circulating water pumps are typically overhauled every 10 to 12 years.
The pumps have been relatively trouble-free and were characterized as in good
condition.
Unit 3 is equipped with a Worthington horizontal, single-pass, surface-type
condenser. The condenser was originally furnished with arsenical copper tubing.
The condenser was last retubed in 1980 with 70-30 Cu-Ni tubing. It is scheduled
to be retubed with all stainless steel in the scheduled fall 2000 outage. Unit 4
is equipped with a Foster-Wheeler horizontal, two-pass, divided water box,
surface-type condenser. The condenser was originally furnished with arsenical
copper tubing. The condenser was last retubed in 1984 with Alloy 722 (85-15
Cu-Ni with 0.5% Cr). The condenser was inspected by an outside contractor in
2000 and found to be in good condition. Plant personnel expect to achieve 20-25
years of useful life with the Alloy 722 tubing.
Unit 3 has five stages of feedwater heating, including the deaerating heater.
The deaerator was inspected by an outside contractor in 1999. No defects were
found. It is anticipated that the deaerator internals will be replaced with a
new configuration as part of the repowering project in order to achieve greater
dearation.
Downstream of the deaerator and boiler feed pumps are two stages of HP feedwater
heaters (Nos. 4 and 5). Heater No. 4 was rebundled and Heater No. 5 replaced in
the early 1980's. Both heaters have been upgraded with stainless steel tubing.
Their condition was characterized as being excellent. In the repowered
configuration, the high pressure heaters will be placed in service only at or
near full load due to backend steam flow limitations on the steam turbine.
Unit 4 currently has five stages of feedwater heating, including the deaerating
heater. However all the heaters, with the exception of the deaerator, will be
eliminated as part of the repowering project because of turbine backend steam
flow limitations. The deaerator was inspected during the current year 2000
outage by an outside contractor and no defects were found. The deaerator
internals are to be replaced with a new configuration as part of the repowering
project in order to achieve greater dearation.
Unit 3 is equipped with two Worthington 50% capacity motor-driven boiler feed
pumps and one Worthington 50% turbine-driven backup boiler feed pump. The
motor-driven pumps were last overhauled in the mid 1980's. The motors were
replaced in the late 1980's. Both motors were inspected and tested in 1997 with
no problems detected. The turbine-driven backup boiler feed pump was last
overhauled in the early 1980's. The boiler feed pumps are overhauled only when
needed and that is rarely. The motor-driven boiler feed pumps were characterized
as being in good condition.
The turbine drive on the backup boiler feed pump will be replaced with a motor
drive as part of the repowering project, again to relieve the steam turbine
backend steam loading. In addition, at the same time, the station's spare
rotating element will be installed in the backup boiler feed pump, and therefore
the backup pump should be in excellent condition when the unit is repowered. It
is the plant's intention
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to overhaul the present rotating element when it is removed and to use it as the
spare element. There were no reported chronic operating problems with any of the
boiler feed pumps.
Unit 4 is equipped with two Pacific 100% capacity motor-driven boiler feed
pumps. One pump was last overhauled in the late 1980's and the other in the
early 1990's. Motor 4-1 underwent major reconditioning in 1996. Motor 4-2 was
inspected in 1997 and no problems were found. The boiler feed pumps are
overhauled only when needed (approximately once every twenty years). The boiler
feed pumps were characterized as being in good condition. There is no spare
rotating element currently in stock.
A new water treatment plant is being installed as part of the repowering
project. The two existing deepwell pumps, which are the source of the station's
raw water, will be retained as will the station's four condensate storage tanks.
All the condensate storage tanks were characterized as being in good condition.
The Unit 3 and Unit 4 main steam piping will be replaced as part of the
repowering project (there is no reheat piping on Unit 3).
The coal and ash handling facilities will be retired as part of the repowering
project. The station currently uses No.2 fuel oil as ignition oil on both units.
The fuel oil system will also be retired as part of the repowering project.
The station does not have an auxiliary boiler; the station will rely on electric
heat for station heating.
3.1.5.2 Electrical Equipment and Systems
- -----------------------------------------
The controls are being converted for all-DCS control for operation in 2001. The
existing electrical distribution system will be modified for the addition of the
combined cycle units. Significant findings are noted below. Key generator
characteristics are summarized in the following table.
Generator Unit 3 Unit 4
- --------------------------------------------------------------------
Installation 1951 1958
Manufacturer Westinghouse Westinghouse
Rated kVA 93100 133689
Voltage (kV) 13.8 13.8
PF 0.87 0.85
Rated kW 81,000 113,636
Rpm 3600 3600
Exciter solid state Solid State
Control Auto/Manual Auto/Manual
Generator Rewind none none
Last Major Overhaul 1997 1990
The Unit 3 generator was put in service in 1951.The turbine was modified in 1973
increasing its capacity. The stator was rewound in 1973 and was rerated as a
result of the turbine modification to 93.1MVA. In 1985 the rotor was rewound,
new copper bars were installed and new retaining rings were installed. In 1989 a
new solid state exciter system was installed. In 1997 the stator was rewedged,
boresonic testing was done, flux probes and bus couplers were installed and Iris
PD sensors were installed.
Unit 4 generator was put in service in 1958. In 1990 the stator was rewedged and
boresonic testing was done. The rotor has never been rewound. There were some
indications ten years ago that there may have
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been some shorted turns in the rotor. This has been monitored since then and
various tests have been done but the results indicate that there is not a need
to rewind the rotor. The retaining rings have been inspected and were found to
be acceptable. Westinghouse characterized the generator as being in excellent
condition at the finish of the 1990 outage. In 1997 the core was re-tightened,
flux probes and bus couplers were installed and Iris PD sensors were installed.
An ABB solid state exciter system was added in 1999.
The planned boundary limits for the Genco does not include the Unit 3 generator
step up transformers (i.e., AmerenCIPS retains ownership). The Unit 4 GSU is a
Westinghouse oil-filled original installation transformer, rated 120MVA, 138 -
13.2kV. It recently had new fans installed. There have not been any problems
with the transformer and it appeared to be in good condition. There were no
constant oil leaks observed. The transformer oil is tested annually and has been
under a routine maintenance program.
UPS
The UPS will be all new under the repowering project.
3.1.5.3 Emissions Control Equipment
- ------------------------------------
The existing precipitators will be retired as part of the repowering project.
3.2 Performance
This section summarizes the historical and projected performance of the electric
generating stations acquired by Genco from AmerenCIPS. The key performance
parameters include capacity factors, equivalent availabilities, forced outage
rates, and average heat rates.
The historical performance data was obtained from AmerenCIPS' central office in
Springfield, Illinois. The historical data was augmented with the data and
reports received from the station operating staff during our site visits.
The historical performance of each station is summarized tabularly for the
period 1995 through 1999. Where appropriate, we have compared each station's
performance against historical availability statistics compiled by the North
American Electric Reliability Council ("NERC"). The NERC data is organized by
size of unit and the type of fuel fired. The most recent data available is
through 1998.
The projected performance is shown for the period 2000 through 2020 and is a
combination of assumptions and outputs of the Market Consultant's dispatch
simulation model.
The following definitions of terms were used to define the performance data
presented in this section:
Capacity Factor - The ratio of the actual net generation to the normal
claimed capacity operating for the entire 8,760 hours in a year.
Equivalent Availability Factor ("EAF") - 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 possible generation.
Equivalent Forced Outage Rate ("EFOR") - The ratio of forced outages
and restrictions to service hours. The fundamental difference between
availability and forced outage rate is that availability includes
outages and planned overhauls while forced outage rate is not affected
by planned overhauls.
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Heat Rate (Btu/kWh) - The ratio of the fuel energy input to the net unit
electric energy output.
In reviewing the historical and projected performance of electric generating
units, the reliability of the units are generally evaluated by looking at the
EAF and EFOR values. The EAF is an indication of the ability of a unit to
generate electricity regardless of whether it is dispatched. The EFOR is an
indication of the degree to which the unit was limited during operation by
forced outages and restrictions.
Also discussed in this section is the current capacity of the units and any
existing capacity deratings in place or which may potentially occur.
3.2.1 Newton Power Station
A summary of the historical and projected performance for the Newton Power
Station is shown in Table 3.2-1.
Table 3.2-1
Newton Power Station Performance
==================================================================================================================
Historical Performance (1995 - 1999) Projected Performance (2000 - 2020)
- -------------------------------------------------------------------- -------------------------------------------
Average Maximum Minimum Average Maximum Minimum
Capacity Factor (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 1 62.1% 69.8% 51.0% 82.7% 84.7% 77.3%
- -------------------------------------------------------------------- -------------------------------------------
Unit 2 56.8% 61.7% 50.0% 84.3% 85.5% 81.2%
- ------------------------------------------------------------------------------------------------------------------
EAF (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 1 82.6% 93.8% 68.4% 82.8% 87.5% 77.8%
- -------------------------------------------------------------------- -------------------------------------------
Unit 2 82.5% 92.0% 72.7% 88.5% 90.9% 80.8%
- ------------------------------------------------------------------------------------------------------------------
EFOR (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 1 6.2% 10.8% 3.1% 9.7% 12.1% 9.0%
- -------------------------------------------------------------------- -------------------------------------------
Unit 2 5.2% 7.3% 3.4% 9.0% 9.1% 8.7%
- ------------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh)
- ------------------------------------------------------------------------------------------------------------------
Unit 1 10,107 10,385 9,706 10,107 - -
- -------------------------------------------------------------------- -------------------------------------------
Unit 2 10,306 10,732 9,963 10,306 - -
=================================================================================================================
This performance was compared to NERC industry-wide data for similar sized units
with the same fuel type. The historical availabilities for both units are better
than industry average by one percent. Newton has had some problems with wet coal
and ash slag buildup since converting to PRB coal. As experience with this coal
is gained these problems should decrease. Also, the historic EFOR was increased
by a main transformer failure 3 years ago.
The projected EFOR is higher than the historic levels due to consideration, at
the time the projections were developed, of potential future operational
restrictions due to high cooling water discharge temperatures. However, a
supplemental cooling pond has since been constructed, and actual future EFOR is
likely to be lower than that projected. The EFOR projections are therefore
conservative.
[LOGO] S&W Consultants, Inc. A-61
The future capacity factors increase over the historic values because of the
change to the less expensive western coal. It will be feasible to achieve this
based on the projected EAF and EFOR. The future O&M and capital budgets have
allocated funding for the necessary repairs and equipment replacements for
maintaining this availability.
3.2.2 Coffeen Power Station
A summary of the historical and projected performance for the Coffeen Power
Station is shown in Table 3.2-2.
Table 3.2-2
Coffeen Power Station Performance
==================================================================================================================
Historical Performance (1995 - 1999) Projected Performance (2000 - 2020)
- -------------------------------------------------------------------- -------------------------------------------
Average Maximum Minimum Average Maximum Minimum
- ------------------------------------------------------------------------------------------------------------------
Capacity Factor (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 1 39.1% 51.2% 26.4% 63.6% 73.7% 50.4%
- -------------------------------------------------------------------- -------------------------------------------
Unit 2 51.0% 54.3% 48.1% 67.6% 76.4% 53.9%
- ------------------------------------------------------------------------------------------------------------------
EAF (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 1 67.8% 81.8% 51.7% 76.3% 84.5% 73.3%
- -------------------------------------------------------------------- -------------------------------------------
Unit 2 71.6% 80.0% 62.5% 78.7% 84.3% 72.8%
- ------------------------------------------------------------------------------------------------------------------
EFOR (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 1 13.3% 18.2% 6.5% 12.7% 13.4% 12.2%
- -------------------------------------------------------------------- -------------------------------------------
Unit 2 12.5% 16.7% 7.2% 13.0% 14.0% 12.4%
- ------------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh)
- ------------------------------------------------------------------------------------------------------------------
Unit 1 10,871 11,146 10,664 10,871 - -
- -------------------------------------------------------------------- -------------------------------------------
Unit 2 10,407 10,702 10,251 10,407 - -
==================================================================================================================
This performance was compared to NERC industry-wide data for similar sized units
with the same fuel type. The historical availabilities for Units 1 and 2 are
lower than industry average by 13% and 10% respectively. The scheduled outages
for cyclone boilers take longer to accomplish than for units with conventional
burners. This is inherent with the boiler design.
Even though the future capacity factors increase compared to the historic
capacity factors, they are considered achievable. The projected EFOR and EAF are
achievable based on the O&M and capital budgets. These budgets allow for
adequate repairs and equipment replacement to maintain the projected level of
availability.
3.2.3 Meredosia Power Station
A summary of the historical and projected performance for the Meredosia Power
Station is shown in Table 3.2-3.
[LOGO] S&W Consultants, Inc. A-62
Table 3.2-3
Meredosia Power Station Performance
===================================================================================================================
Historical Performance (1995 - 1999) Projected Performance (2000 - 2020)
- -------------------------------------------------------------------- --------------------------------------------
Average Maximum Minimum Average Maximum Minimum
- -------------------------------------------------------------------------------------------------------------------
Capacity Factor (%)
- -------------------------------------------------------------------------------------------------------------------
Unit 1 24.1% 36.3% 11.6% 30.6% 57.8% 12.3%
- -------------------------------------------------------------------- --------------------------------------------
Unit 2 21.6% 31.9% 12.8% 29.8% 58.0% 12.1%
- -------------------------------------------------------------------- --------------------------------------------
Unit 3 46.7% 54.3% 35.4% 44.1% 70.1% 20.6%
- -------------------------------------------------------------------- --------------------------------------------
Unit 4 2.5% 5.7% 0.2% 0.4% 0.9% 0.1%
- -------------------------------------------------------------------------------------------------------------------
EAF (%)
- -------------------------------------------------------------------------------------------------------------------
Unit 1 84.2% 97.0% 74.9% 86.4% 94.0% 81.0%
- -------------------------------------------------------------------- --------------------------------------------
Unit 2 84.7% 98.8% 69.6% 84.2% 94.0% 79.5%
- -------------------------------------------------------------------- --------------------------------------------
Unit 3 73.7% 87.3% 60.1% 87.2% 90.9% 79.9%
- -------------------------------------------------------------------- --------------------------------------------
Unit 4 57.8% 70.4% 36.5% 57.5% 59.2% 53.5%
- -------------------------------------------------------------------------------------------------------------------
EFOR (%)
- -------------------------------------------------------------------------------------------------------------------
Unit 1 22.3% 51.1% 0.7% 9.1% 12.2% 6.0%
- -------------------------------------------------------------------- --------------------------------------------
Unit 2 11.1% 33.9% 1.4% 9.1% 12.2% 6.0%
- -------------------------------------------------------------------- --------------------------------------------
Unit 3 8.9% 11.2% 5.3% 6.0% 6.0% 6.0%
- -------------------------------------------------------------------- --------------------------------------------
Unit 4 68.3% 96.1% 54.8% 28.3% 28.3% 28.3%
- -------------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh)
- -------------------------------------------------------------------------------------------------------------------
Unit 1&2 13,209 13,729 12,068 13,209 - -
- -------------------------------------------------------------------- --------------------------------------------
Unit 3 10,461 11,293 10,103 10,461 - -
- -------------------------------------------------------------------- --------------------------------------------
Unit 4 25,502 59,681 14,560 25,502 - -
===================================================================================================================
This performance was compared to NERC industry-wide data for similar sized units
with the same fuel type. The historical availabilities for all three units are
lower than the industry average. Units 1 and 2 were compared to 45 units and had
an EAF 1-2 % lower than average. Boiler 1 had an explosion in September 1998
that forced it out of service for 6 months (33 gross MW reduction to U1). Unit 3
was compared to 49 units and had an EAF 10% lower than average. Unit 3 had a
long planned outage that extended from October 1997 to March 1998 that decreased
the average EAF. This overhaul incorporated several capital additions including
a new control system, control room, and replacement of many field sensors and
control devices.
Unit 4 was compared to 10 units and had an EAF 23% lower than average. Unit 4 is
only operated during the peak summer season and is considered to be in forced
outage every year during about half of the year. This type of operation cannot
be compared to industry data since most other plants that operate seasonally are
considered to be in economic reserve, not forced out, and by definition are thus
available. Effectively, in either scenario, the units are not operated and there
is virtually no power sales or revenue. Therefore a comparison to industry
average EAF is not consistent with the Unit 4 mode of operation.
[LOGO] S&W Consultants, Inc. A-63
The future capacity factors are consistent with the historic capacity factors,
and considered achievable. The projected EFOR and EAF are consistent with
historical and the O&M and capital budgets are considered reasonable. These
budgets allow for adequate repairs and equipment replacement to maintain this
level of reliability.
3.2.4 Hutsonville Power Station
A summary of the historical and projected performance for the Hutsonville Power
Station is shown in Table 3.2-4.
Table 3.2-4
Hutsonville Power Station Performance
==================================================================================================================
Historical Performance (1995 - 1999) Projected Performance (2000 - 2020)
- -------------------------------------------------------------------- -------------------------------------------
Average Maximum Minimum Average Maximum Minimum
- ------------------------------------------------------------------------------------------------------------------
Capacity Factor (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 3 40.4% 64.0% 25.7% 20.3% 37.2% 8.7%
- -------------------------------------------------------------------- -------------------------------------------
Unit 4 37.8% 63.3% 18.6% 23.0% 39.6% 10.2%
- ------------------------------------------------------------------------------------------------------------------
EAF (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 3 82.2% 95.0% 67.8% 84.6% 90.9% 79.7%
- -------------------------------------------------------------------- -------------------------------------------
Unit 4 82.0% 90.7% 56.4% 88.5% 90.9% 80.8%
- ------------------------------------------------------------------------------------------------------------------
EFOR (%)
- ------------------------------------------------------------------------------------------------------------------
Unit 3 7.9% 23.9% 1.8% 7.0% 7.0% 7.0%
- -------------------------------------------------------------------- -------------------------------------------
Unit 4 8.0% 17.1% 2.1% 7.0% 7.0% 7.0%
- ------------------------------------------------------------------------------------------------------------------
Heat Rate (Btu/kWh)
- ------------------------------------------------------------------------------------------------------------------
Unit 3 11,006 11,634 11,497 11,006 - -
- -------------------------------------------------------------------- -------------------------------------------
Unit 4 10,921 11,396 10,365 10,921 - -
==================================================================================================================
This performance was compared to NERC industry-wide data for similar sized units
with the same fuel type. The historical availabilities for both units are
slightly lower than the industry average. Units 3 and 4 were compared to 45
units and had an EAF 4% lower than average. The Units 3 and 4 had opacity
restrictions in 1998 that were solved by blending their coals to achieve a
slightly higher sulfur content and by repairing duct leaks. These opacity
restrictions will not reoccur since the solution to these opacity restrictions
has been found with a blend of higher sulfur coal.
The future capacity factors decrease somewhat compared to the historic capacity
factors. The projected EFOR and EAF are consistent with historical and the O&M
and capital budgets are considered reasonable. These budgets allow for adequate
repairs and equipment replacement to maintain the projected level of
availability.
[LOGO] S&W consultants, Inc. A-64
3.2.5 Ancillary Services
Ancillary services capabilities for the existing assets are summarized in the
following table:
================================================================================
PLANT NAME Spinning Non-spinning Black Start
Reserve Reserve Voltage Support Capability
- --------------------------------------------------------------------------------
Coffeen Yes No Yes No
- --------------------------------------------------------------------------------
Newton Yes No Yes No
- --------------------------------------------------------------------------------
Meredosia Yes No Yes No
- --------------------------------------------------------------------------------
Hutsonville Yes No Yes Yes
- --------------------------------------------------------------------------------
Grand Tower Yes No Yes No
================================================================================
Grand Tower Power Station does not have black start capability at this time.
However, when the CTs for the new combined cycle are installed these new
generators will be capable of black start. The non-spinning reserve is not
provided by these plants because they do not start up fast enough to respond
within the time needed. The non-spinning reserve on the system is provided by
CTs. The voltage support is not usually needed at Newton Power Station and
Hutsonville Power Station because they have multiple connections to the
transmission system. The other three plants have more limited transmission
options so when their transmission lines need voltage support it can be
provided.
Ancillary services can be a significant source of revenue for peaking units.
However, these units are projected to provide primarily base load and
intermediate load service and are less dependant on ancillary services for
revenue.
No ancillary services revenues are included for the Genco Assets in the
Financial Model.
3.3 Operation & Maintenance
S&W Consultants reviewed the projected station staffing, O&M budgets, overhaul
schedules, and capital and overhaul expenses provided by Ameren. In addition, we
reviewed the station maintenance management practices and spare parts
inventories for effectiveness and adequacy.
The projections provided by Ameren were reviewed in relation to the projected
operation of the stations and, where appropriate, were compared to station
historical experience and industry data.
3.3.1 Newton Power Station
S&W Consultants reviewed the O&M information provided by Ameren and the plant
personnel for operation and maintenance of the each of the generating stations.
The information reviewed included relevant historical station data from the
AmerenCIPS office in Springfield, Illinois and data obtained at the plant.
3.3.1.1 Station Staffing Levels
- --------------------------------
The staffing level at Newton Power Station is currently 208 which includes 66
for plant operations, 67 for maintenance support, 35 for instrumentation and
electrical, 23 for technical and 17 for administrative and stores (150 of the
personnel are union represented). This staffing level has decreased by 22
positions by attrition over the past three years. The current union contract
commenced in July of 1999 and it expires in July of 2002. There are maintenance
shifts present 24 hours a day, which reduces overtime for critical work. The
future staffing level being planned remains consistent for 5 years into the
future.
[LOGO] S&W consultants, Inc. A-65
The overall condition of the plant appeared to be clean and well maintained.
Several changes were made to the coal handling system when the use of PRB coal
was started to reduce coal dust. The accumulation of PRB coal dust can cause
fires, however, the measures taken to reduce dust levels was shown to be
effective during our visit. The staffing level is adequate for the current mode
of operation. The numbers are typical of those found in similarly configured
plants that S&W Consultants has reviewed.
3.3.1.2 Operation and Maintenance Expenses
- -------------------------------------------
The historical O&M expenses, including labor are summarized in Table 3.3-1 along
with Ameren's projected O&M expenses. The projected expenses are an annual
average of the projected expenses from 2000 through 2020 excluding SO\\2\\
allowances.
Table 3.3-1
Newton Power Station
O&M Expenses (year 2000 $'s)
=================================
Year ($000)
---------------------------------
1994 $33,512
---------------------------------
1995 $24,335
---------------------------------
1996 $21,372
---------------------------------
1997 $25,001
---------------------------------
1998 $28,276
---------------------------------
1999 $40,904
---------------------------------
2000-2020 $31,522
=================================
The future budget for operation and maintenance is consistent with the historic
costs. The 1999 costs were higher than the other years due to major maintenance
expenses and equipment changes for the conversion to PRB coal. These budgeted
costs should be sufficient to maintain safe and reliable operation as projected.
3.3.1.3 Overhaul Schedule
- --------------------------
S&W Consultants reviewed Ameren's planned overhaul and maintenance schedule,
summarized below. The most recent overhauls for the Units 1 and 2 high pressure
turbines were in 1994 and 1995 respectively. The next high pressure turbine
overhauls are scheduled in 2000 and 2001 respectively. This is consistent with
the industry average time between turbine overhauls.
[LOGO] S&W Consultants, Inc. A-66
Table 3.3-2
Newton Overhaul Schedule
-------------------------------------------------------------------------------------------------------------
Unit 1 Unit 1 Unit 2 Unit 2
-------------------------------------------------------------------------------------------------------------
Year Weeks Description Weeks Description
-------------------------------------------------------------------------------------------------------------
2000 6 HP Turbine and Boiler 1 Short Boiler Outage
-------------------------------------------------------------------------------------------------------------
2001 1 Short Boiler Outage 9 HP Turbine and Boiler
-------------------------------------------------------------------------------------------------------------
2002 6 LP Turbine and Generator 1 Short Boiler Outage
-------------------------------------------------------------------------------------------------------------
2003 1 Short Boiler Outage 6 Boiler Chem. Cleaning
-------------------------------------------------------------------------------------------------------------
2004 7 Boiler Chem. Cleaning 1 Short Boiler Outage
-------------------------------------------------------------------------------------------------------------
2005 1 Short Boiler Outage 6 Generator Overhaul
-------------------------------------------------------------------------------------------------------------
3.3.1.4 Capital and Overhaul Expense Forecast
- ----------------------------------------------
The future capital budget includes the selected items shown below. The
justification for each of these projects is to prevent deterioration of the
forced outage rate, except for the environmental projects. The low NO\\x\\
burners for NO\\x\\ reduction and the precipitator work are to assure compliance
with the environmental regulations for emissions of NO\\x\\ and particulate.
Common projects include the supplemental cooling pond recently constructed
($20.5 million) and the fly ash disposal landfill ($2.9 million over the 2001-
2002 period).
Capital Projects: Newton Unit 1
Description $(000) Year
- ---------------------------------------------------------------------
. Boiler Waterwall 12,699 2002, 2007 and 2014
. Refurbish precipitator 10,000 2012
. Secondary Superheater Tube replacement 7,453 2011
. Low NOx burners and DCS controls 6,200 2001
. Reheater Tube replacement 5,902 2004
. Retube Main Condenser 4,206 2003
. Generator stator rewind 4,000 2007
Capital Projects: Newton Unit 2
Description $(000) Year
- ---------------------------------------------------------------------
. Boiler Waterwall replacement 12,699 2003, 2008 and 2015
. Refurbish precipitator 10,000 2015
. Secondary Superheater Tube replacement 7,453 2006
. Low NOx burners and DCS controls 6,200 2001
. Retube Main Condenser 4,206 2003
. Generator Stator rewind 4,000 2015
3.3.1.5 Maintenance Management and Spare Parts
- -----------------------------------------------
The maintenance information system used by AmerenCIPS to control maintenance
information was upgraded to a modern PC based system used at the AmerenUE plants
in Missouri following the Union Electric Company-CIPSCO Incorporated merger.
This system, named EMPRV, was purchased from
[LOGO] S&W Consultants, Inc. A-67
Electronic Data Systems Inc. The station has transferred maintenance and
inventory data to this new maintenance information system from the previous
mainframe based system. The historical data goes back to 1983, which is very
useful for preventing and solving recurring maintenance problems. The
functionality of the maintenance information system is satisfactory to support
maintenance control and reporting requirements.
S&W Consultants reviewed Ameren's summary spare parts inventory developed for
Newton. The spare parts inventory at the station appears to be sufficient and
adequate to support operations. The dollar value of parts and material inventory
is currently $8,168,000.
3.3.2 Coffeen Power Station
3.3.2.1 Station Staffing Levels
- --------------------------------
The staffing level at the Coffeen Power Station is currently 244 which includes
73 for plant operations, 103 for maintenance support, 29 for instrumentation and
electrical, 19 for technical and 20 for administrative and stores (200 of the
personnel are union represented). This staffing level has decreased by 22
positions over the past three years. There are maintenance shifts present 24
hours per day which reduces overtime for critical work. The future staffing
level being planned remains consistent for 5 years into the future.
The overall condition of the plant appeared well maintained however there was
coal dust that had accumulated throughout the plant and congealed oil/leaks in
the turbine room lower elevations. The staffing level is adequate for the
current mode of operation. The numbers are typical of those found in similarly
configured plants that S&W Consultants has reviewed.
3.3.2.2 Operation and Maintenance Expenses
- -------------------------------------------
The historical O&M expenses, including labor, are shown in Table 3.3-3 along
with Ameren's projected O&M expenses. The projected expenses are an annual
average of the projected expenses from 2000 through 2020 excluding SO\\2\\
allowances.
Table 3.3-3
Coffeen Power Station
O&M Expenses (year 2000 $'s)
=====================================
YEAR ($000)
-------------------------------------
1994 $25,030
-------------------------------------
1995 $30,024
-------------------------------------
1996 $22,323
-------------------------------------
1997 $29,188
-------------------------------------
1998 $26,282
-------------------------------------
1999 $34,312
-------------------------------------
2000-2020 $34,578
=====================================
[LOGO] S&W Consultants, Inc. A-68
The future budget for operation and maintenance is consistent with the historic
costs. The 1999 costs were higher than the other years due to major maintenance
expenses. These budgeted costs should be sufficient to maintain safe and
reliable operation as projected.
3.3.2.3 Overhaul Schedule
- --------------------------
S&W Consultants reviewed Ameren's planned overhaul and maintenance schedule,
summarized below. The most recent overhauls for the Units 1 and 2 high pressure
turbines were in 1995. The next high pressure turbine overhauls are scheduled in
2001 and 2002 respectively. This is consistent with the industry average time
between turbine overhauls. The units are scheduled to have a regular boiler
overhaul every other year. During the alternate year there is a short two week
boiler inspection. The regular boiler overhaul takes 8 weeks because of the
cyclone burners. These cyclones must have all the refractory removed followed by
extensive repairs to the cyclone internal tubing due to the high temperatures
and erosive condition in these cyclone burners.
Table 3.3-4
Coffeen Overhaul Schedule
------------------------------------------------------------------------------
Unit 1 Unit 1 Unit 2 Unit 2
------------------------------------------------------------------------------
Year Weeks Description Weeks Description
------------------------------------------------------------------------------
2000 8 Boiler and Piping 8 Circ. Water Piping
------------------------------------------------------------------------------
2001 2 Short Boiler Outage 8 HP Turbine and Boiler
------------------------------------------------------------------------------
2002 8 Boiler Chem. Cleaning 2 Short Boiler Outage
------------------------------------------------------------------------------
2003 2 Short Boiler Outage 8 Boiler Overhaul
------------------------------------------------------------------------------
2004 8 Boiler Overhaul 2 Short Boiler Outage
------------------------------------------------------------------------------
2005 2 Short Boiler Outage 8 Boiler Overhaul
------------------------------------------------------------------------------
3.3.2.4 Capital and Overhaul Expense Forecast
- ----------------------------------------------
The future capital budget includes the selected items shown below. The
justification for each of these projects is to prevent deterioration of the
forced outage rate, except for the environmental projects. The SCR for NO\\x\\
reduction and the precipitator work are to assure compliance with the
environmental regulations for emissions of NO\\x\\ and particulate. Common
projects include the supplemental cooling pond ($17 million in 2000 and 2001)
and the fly ash injection system ($400,000 in 2000) now under construction.
Capital Projects: Coffeen Unit 1
Description $(000) Year
- ---------------------------------------------------------------
. SCR for NOx reduction 45,000 2003
. Boiler Waterwall replacement 8,093 2004, 2009, and 2016
. Rehabilitate precipitator 8,000 2010
. SCR rehabilitation 5,000 2017
[LOGO] S&W Consultants, Inc. A-69
Capital Projects: Coffeen Unit 2
Description $(000) Year
- -------------------------------------------------------------
. SCR for NOx reduction 65,000 2002
. Boiler Waterwall replacement 12,605 2002, 2009, and 2014
. Rehabilitate precipitator 10,000 2009
. SCR rehabilitation 6,000 2016
. Generator stator rewind 4,000 2002
3.3.2.5 Maintenance Management and Spare Parts
- -----------------------------------------------
The maintenance management system was described in Section 3.3.1.5. The
functionality of the system is satisfactory to support maintenance control and
reporting requirements.
S&W Consultants reviewed Ameren's summary spare parts inventory developed for
Coffeen. The spare parts inventory at the station appears to be sufficient and
adequate to support operations. The dollar value of parts and material inventory
is currently $8,163,000.
3.3.3 Meredosia Power Station
3.3.3.1 Station Staffing Levels
- --------------------------------
The staffing level at the Meredosia Power Station is currently 139 which
includes 71 for plant operations, 43 for mechanical and electrical maintenance,
12 for technical and 13 for administrative and stores (113 of the personnel are
union represented). This staffing level has remained at a consistent level for
the past 5 years. The future staffing level being planned remains consistent for
5 years into the future. The current union contract commenced in July of 1999
and it expires in July of 2002. The plant staff does most of their own
maintenance without the use of contractors. Even the turbine generator overhauls
are mostly done with plant staff along with technical guidance from a
contractor. Plant operations staff may be assigned to the maintenance department
to perform repair work, when their units are in outage or not in operation.
The overall condition of the plant appeared to be clean and well maintained for
a plant of this age and type of operation. The staffing level is adequate for
the current mode of operation. The numbers are typical of those found in
similarly configured plants that S&W Consultants has reviewed.
3.3.3.2 Operation and Maintenance Expenses
- -------------------------------------------
The historical O&M expenses, including labor, are shown in Table 3.3-5 along
with Ameren's projected O&M expenses. The projected expenses are an annual
average of the projected expenses from 2000 through 2020 excluding SO\\2\\
allowances.
[LOGO] S&W Consultants, Inc. A-70
Table 3.3-5
Meredosia Power Station
O&M Expenses (year 2000 $'s)
=====================================
Year ($000)
-------------------------------------
1994 $11,216
-------------------------------------
1995 $ 8,825
-------------------------------------
1996 $ 9,155
-------------------------------------
1997 $10,607
-------------------------------------
1998 $13,437
-------------------------------------
1999 $16,189
-------------------------------------
2000-2020 $11,832
=====================================
The future budget for operation and maintenance is consistent with the historic
costs. The 1999 costs were higher than the other years due to major maintenance
expenses including the repair of Unit 1 boiler. These budgeted costs should be
sufficient to maintain safe and reliable operation as projected.
3.3.3.3 Overhaul Schedule
- --------------------------
S&W Consultants reviewed Ameren's planned overhaul and maintenance schedule,
summarized below. The most recent overhauls for the Units 1, 2, 3 and 4 high
pressure turbines were in 1994, 1999, 1997 and 1986 respectively. The next
high-pressure turbine overhauls for Units 2, 3 and 4 are scheduled in 2001, 2005
and 2002 respectively. The Unit 1 turbine overhaul has not been scheduled
however, the intention is to overhaul these small units on an interval of
approximately 10 years, which would be about the year 2004. The Unit 4 overhaul
in 1986 was a partial overhaul. Only the high pressure section was opened and
inspected.
Table 3.3-6
Meredosia Overhaul Schedule
- -----------------------------------------------------------------------------------------------------------------------
Unit 1 Unit 1 Unit 2 Unit 2 Unit 3 Unit 3 Unit 4 Unit 4
- -----------------------------------------------------------------------------------------------------------------------
Year Weeks Description Weeks Description Weeks Description Weeks Description
- -----------------------------------------------------------------------------------------------------------------------
2000 4 Boiler Overhaul 4 Boiler 2 Short Boiler 18 Turbine
Overhaul Outage Overhaul
- -----------------------------------------------------------------------------------------------------------------------
2001 4 Boiler Overhaul 8 Turbine 5 Boiler Overhaul 19 Continued
Overhaul Turbine Over.
- -----------------------------------------------------------------------------------------------------------------------
2002 2 Boiler Overhaul 2 Boiler 2 Short Boiler 21 Boiler
Overhaul Outage Overhaul
- -----------------------------------------------------------------------------------------------------------------------
2003 4 Boiler Overhaul 4 Boiler 5 Boiler Overhaul 21 Boiler
Overhaul Overhaul
- -----------------------------------------------------------------------------------------------------------------------
2004 2 Boiler Overhaul 2 Boiler 5 Boiler Overhaul 20 Boiler
Overhaul Overhaul
- -----------------------------------------------------------------------------------------------------------------------
2005 4 Boiler Overhaul 4 Boiler 2 Short Boiler 19 Boiler
Overhaul Outage Overhaul
- -----------------------------------------------------------------------------------------------------------------------
[LOGO] S&W Consultants, Inc. A-71
3.3.3.4 Capital and Overhaul Expense Forecast
- ----------------------------------------------
The future capital budget includes the selected items shown below. The
justification for each of these projects is to prevent deterioration of the
forced outage rate, except for the environmental projects. The precipitator work
is to assure compliance with the environmental regulations for emissions of
particulate.
Capital Projects: Meredosia Unit 1
Description $(000) Year
- --------------------------------------------------------------------------
. New turbine/generator 8,046 2008-2009
. Boiler Waterwall replacement 6,704 2002, 2008, 2014
. Purchase new turbine/generator materials 6,050 2008
. Refurbish precipitator 1,500 2009
. Secondary Superheater Tube replacement 1,240 2005
Capital Projects: Meredosia Unit 2
Description $(000) Year
- --------------------------------------------------------------------------
. New turbine/generator 8,046 2009-2010
. Boiler Waterwall replacement 6,704 2002, 2008, 2014
. Purchase new turbine/generator materials 6,050 2009
. Refurbish precipitator 1,500 2011
. Secondary Superheater Tube replacement 1,240 2008
Capital Projects: Meredosia Unit 3
Description $(000) Year
- ----------- ------ ----
. New turbine/generator materials 12,960 2012
. Boiler Waterwall replacement 5,685 2003, 2009, 2015
. Refurbish precipitator 5,000 2012
Capital Projects: Meredosia Unit 4
Description $(000) Year
- ----------------------------------------------------------------------
. Boiler Waterwall replacement 1,805 2013
. Primary Superheater Tube replacement 1,323 2015
. Generator Stator rewind 1,100 2009
3.3.3.5 Maintenance Management and Spare Parts
- -----------------------------------------------
The maintenance information system used by AmerenCIPS to control maintenance
information was upgraded to a modern PC based system as described earlier. The
functionality of the maintenance information system is satisfactory to support
maintenance control and reporting requirements.
S&W Consultants reviewed Ameren's summary spare parts inventory developed for
Meredosia. The spare parts inventory at the station appears to be sufficient and
adequate to support operations. The dollar value of parts and material inventory
is currently $2,954,693.
[LOGO] S&W Consultants, Inc. A-72
3.3.4 Hutsonville Power Station
3.3.4.1 Station Staffing Levels
- --------------------------------
The staffing level at the Hutsonville Power Station is currently 81 which
includes 34 for plant operations, 29 for maintenance support, 10 for technical
and 8 for administrative (60 of the staff personnel are union represented). This
staffing level has remained consistent for the past 5 years. The future staffing
level being planned remains consistent for 5 years into the future.
The overall condition of the plant appeared to be clean and well maintained. The
staffing level is adequate for the current mode of operation. The numbers are
typical of those found in similarly configured plants that S&W Consultants has
reviewed.
3.3.4.2 Operation and Maintenance Expenses
- -------------------------------------------
The historical O&M expenses, including labor, are shown in Table 3.3-7 along
with Ameren's projected O&M expenses. The projected expenses are an annual
average of the projected expenses from 2000 through 2020 excluding SO\\2\\
allowances.
Table 3.3-7
Hutsonville Power Station
O&M Expenses (year 2000 $'s)
====================================
Year ($000)
------------------------------------
1994 $5,556
------------------------------------
1995 $5,184
------------------------------------
1996 $5,175
------------------------------------
1997 $8,057
------------------------------------
1998 $8,882
------------------------------------
1999 $7,975
------------------------------------
2000-2020 $7,382
====================================
The future budget for operation and maintenance is consistent with the historic
costs. These budgeted costs should be sufficient to maintain safe and reliable
operation as projected.
3.3.4.3 Overhaul Schedule
- --------------------------
S&W Consultants reviewed Ameren's planned overhaul and maintenance schedule,
summarized below. Both Units 3 and 4 were last overhauled in 1998. The units are
scheduled to have a normal boiler overhaul every other year and the alternate
year there is a short one week boiler inspection. The most recent turbine report
recommends another inspection in 10 to 12 years. This is somewhat longer than
the industry average time between turbine overhauls.
[LOGO] S&W Consultants, Inc. A-73
Table 3.3-8
Hutsonville Overhaul Schedule
-------------------------------------------------------------------------------------------------------
Unit 3 Unit 3 Unit 4 Unit 4
-------------------------------------------------------------------------------------------------------
Year Weeks Description Weeks Description
-------------------------------------------------------------------------------------------------------
2000 8 Boiler and Generator 1 Short Boiler Outage
-------------------------------------------------------------------------------------------------------
2001 1 Short Boiler Outage 8 Replace Precipitator
-------------------------------------------------------------------------------------------------------
2002 8 Replace Precipitator 1 Short Boiler Outage
-------------------------------------------------------------------------------------------------------
2003 1 Short Boiler Outage 3 Boiler Overhaul
-------------------------------------------------------------------------------------------------------
2004 3 Boiler Overhaul 1 Short Boiler Outage
-------------------------------------------------------------------------------------------------------
2005 1 Short Boiler Outage 3 Boiler Overhaul
-------------------------------------------------------------------------------------------------------
3.3.4.4 Capital and Overhaul Expense Forecast
- ----------------------------------------------
The future capital budget includes the items shown below. The justification for
each of these projects is to prevent deterioration of the forced outage rate,
except for the environmental projects. The precipitator work is to assure
compliance with the environmental regulations for emissions of particulate.
Capital Projects: Hutsonville Unit 3
Description $(000) Year
- ------------------------------------------------------------------------------
. Purchase new turbine/generator materials 7,200 2010
. Boiler Waterwall replacement 5,685 2005,2009 and 2015
. Refurbish precipitator 2,000 2007
. Secondary Superheater Tube replacement 1,438 2009
Capital Projects: Hutsonville Unit 4
Description $(000) Year
- ------------------------------------------------------------------------------
. Purchase new turbine/generator materials 7,200 2011
. Boiler Waterwall replacement 5,685 2005, 2009, 2015
. Refurbish precipitator 2,000 2009
. Secondary Superheater Tube replacement 1,453 2005
3.3.4.5 Maintenance Management and Spare Parts
The maintenance information system used by AmerenCIPS to control maintenance
information was upgraded to a modern PC based system as described earlier. The
functionality of the maintenance information system is satisfactory to support
maintenance control and reporting requirements.
S&W Consultants reviewed Ameren's summary spares inventory developed for
Hutsonville. The spare parts inventory at the station appears to be sufficient
and adequate to support operations. The dollar value of parts and material
inventory is currently $1,836,000.
3.3.5 Grand Tower Power Station
3.3.5.1 Station Staffing Levels
- --------------------------------
The staffing level at Grand Tower Power Station is currently 96 positions. This
level will be reduced when the boilers are taken out of service and retired. The
projected staffing level for the new repowered
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combined cycle operation is 48 positions. This transition will take place during
the year 2001 when the new facility begins operation.
Contract personnel will be used for some maintenance work including major
overhauls. The projected staffing level is adequate for the planned mode of
operation. The numbers are typical of those found in similarly configured plants
that S&W Consultants has reviewed.
3.3.5.2 Operation and Maintenance Expenses
- -------------------------------------------
The O&M expenses for 1999 through 2005 are shown in Table 3.3-8. The 1999
expense is actual cost and the 2000 through 2005 is Ameren's projected O&M
expenses. The projected annual expenses are excluding SO\\2\\ allowances and
shown in year 2000 dollars.
Table 3.3-8
Grand Tower Power Station
O&M Expenses (year 2000 $'s)
====================================
Year ($000)
------------------------------------
1999 $ 8,700
------------------------------------
2000 $ 8,341
------------------------------------
2001 $ 7,489
------------------------------------
2002 $ 8,805
------------------------------------
2003 $10,061
------------------------------------
2004 $10,843
------------------------------------
2005 $10,675
====================================
The future budget for operation and maintenance is consistent with similar
plants that S&W Consultants has reviewed. These budgeted costs should be
sufficient to maintain safe and reliable operation as projected.
3.3.5.3 Overhaul Schedule
- --------------------------
S&W Consultants reviewed Ameren's planned overhaul and maintenance schedule. The
CT combustor overhaul will occur on an interval of every 8,000 equivalent
operating hours. Since the capacity factors are projected to be low, these
combustor overhauls are expected about every other year. The turbine hot path
inspections will be every 24,000 equivalent operating hours and the major CT
overhauls will be scheduled every 48,000 equivalent hours. These intervals have
been recommended by Siemens Westinghouse, the manufacturer of the CTs.
3.3.5.4 Capital and Overhaul Expense Forecast
- ----------------------------------------------
The future capital budget includes replacement of the steam turbine/generators
($13.8 million in 2005 for Unit 3, and $13.8 million for Unit 4 in 2006) and CT
overhauls.
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3.4 Environmental
Relevant regulatory, permitting, emissions compliance, hazardous waste handling
and site contamination issues are addressed.
3.4.1 Current and Emerging Air Quality Regulations
This section provides an overview of current and potential air quality
regulatory activities that could affect the operations of the Genco units.
Portions of the regulatory program descriptions are excerpted and/or summarized
from the US Environmental Protection Agency ("EPA") guidance documents and
notices.
3.4.1.1 National Ambient Air Quality Standards
- -----------------------------------------------
On July 16, 1997 the EPA published a final rule revising the National Ambient
Air Quality Standard ("NAAQS") for particulate matter ("PM") which adds
PM\\2.5\\ (particles with an aerodynamic diameter less than or equal to a
nominal 2.5 micrometers) to the regulation of PM. On the same day, the EPA also
published a final rule revising the NAAQS for ozone. Relative to the PM NAAQS,
the EPA has added a new 24-hour and an annual NAAQS for PM\\2.5\\ (65 and 15
ug/m/3/, respectively). The EPA also revised the form for the existing 24-hour
PM\\10\\ (particles with an aerodynamic diameter less than or equal to a nominal
10 micrometers) NAAQS. The EPA did not revise the magnitude of the annual
PM\\10\\ NAAQS but did revise some aspects of the form of the standard in terms
of how compliance is determined. The revised NAAQS for ozone has an 8-hour
averaging period (versus 1 hour for the previous NAAQS) and the concentration
has been revised from 0.12 ppm to 0.08 ppm. These revised NAAQS are generally
considered to be more stringent standards than the previous standards resulting
in more "nonattainment" areas than under the previous NAAQS. In May 1999 the DC
Circuit Court remanded the revised ozone and PM NAAQS to EPA for further
consideration.
3.4.1.2 NO\\x\\ State Implementation Plan ("SIP") Call
- -------------------------------------------------------
On September 24, 1998, the EPA finalized a rule requiring 22 states and the
District of Columbia to submit SIPs to address the regional transport of ground-
level ozone. These SIPs will address reductions in NO\\x\\ emissions from
utility boilers and non-utility point sources as a precursor to ozone formation.
The final EPA rule contains a state-by-state NO\\x\\ emissions budget that
applies to the ozone season (May through September) and the states will have the
flexibility to decide which sources are controlled and by how much. However,
electric utilities, large industrial boilers and turbines, and cement plants
were considered by EPA in the development of the state budgets and will likely
be affected by the SIP revisions. In May 1999, the U.S. Court of Appeals for the
District of Columbia Circuit issued an order staying the portion of the NO\\x\\
SIP Call which required states to submit rules by September 30, 1999. However,
this rule was challenged and submittal of the SIPs was deferred. In June 2000,
the Court rejected the challenges. Accordingly, these SIPs must be submitted by
the affected states, including Illinois, by November 2000. The Genco generating
units will be affected by the EPA SIP call rule.
3.4.1.3 Section 126 Petitions of the Clean Air Act Amendments of 1990 ("CAAA")
- -------------------------------------------------------------------------------
Clean Air Act Section 126(b) authorizes states or political subdivisions to
petition the EPA for a finding that major stationary sources in upwind states
emit in violation of the prohibition of section 110(a)(2)(D), by contributing
significantly to "nonattainment" problems in downwind states. Beginning on
August 14, 1997, EPA received eight petitions under Section 126 from
Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode
Island and Vermont. The petitions asked EPA to find that major sources of
NO\\x\\ emissions in states in the eastern half of the United States, from (and
including) Louisiana in the southwest, Minnesota in the northwest, and Georgia
in the southeast, contribute significantly to "nonattainment" in areas further
to the east and north.
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On December 17, 1999, the EPA decided to grant four of the eight petitions filed
in August, 1997 for the 1-hour ozone standard: Connecticut, Massachusetts, New
York and Pennsylvania. The result of this action is to require reductions in
annual NO\\x\\ emissions from 392 named facilities in 12 states and the District
of Columbia.
The Genco generating units have not been named in the 126 Petitions granted by
EPA on December 17, 1999. The EPA is planning on addressing the petitions from
Maryland, New Jersey, Delaware and the District of Columbia in the near future.
3.4.1.4 Title IV - Acid Rain
- -----------------------------
Title IV of the CAAA requires that nationwide SO2 emissions be reduced by 10
million tons per year and emissions of NO\\x\\ be reduced by 2 million tons per
year from 1980 levels, both by the year 2000. Title IV provides for a two-phase
approach in meeting these reductions. Phase I applies to 110 electric utilities
with 263 units named in the CAAA and Phase II applies to all utility units above
25 MW in the 48 contiguous states. Phase I began in 1995 and required the 263
affected units to reduce SO\\2\\ emissions to a number of allowances equivalent
to the unit's annual average baseline fuel consumption from 1985 to 1987 and an
emission rate of 2.5 pounds per million Btu (Phase I allowances). Each allowance
represents one ton of SO\\2\\. Phase II starts in the year 2000 and restricts
affected utility unit emissions to allowances based on an emission rate of 1.2
pounds per million Btu and the 1985 to 1987 baseline fuel usage. The Phase I
allowances were allocated in the CAAA and the EPA has published a list of Phase
II allocations to utility units that it believes will be affected by Phase II.
These allowances are a marketable commodity whereby a unit that emits less than
its allocated allowances may save the unused allowances for future growth,
transfer to other plants or sell to other utilities that exceed their allowance
allocations.
3.4.1.5 Hazardous Air Pollutants
- ---------------------------------
Title III of the CAAA virtually replaces the existing program for the control of
hazardous air pollutants known as the National Emission Standards for Hazardous
Air Pollutants ("NESHAPs"). Under Title III, EPA has published a list of source
categories that will be required to implement controls for 188 hazardous air
pollutants ("HAPs"). Electric utilities were deferred from regulation under
Title III of the CAAA until such time as EPA completed a comprehensive study on
the public health impact of the utility industry relative to HAP emissions and
reported the results to Congress. This utility report was completed in February
1998 and submitted to Congress. EPA is planning to make a decision on controls
by the end of the year 2000. It is impossible to predict the outcome of this
process at this time but there is a reasonable probability that some amount of
mercury control for coal-fired boilers will be required at the national level.
3.4.1.6 Regional Haze Initiative
- ---------------------------------
The goal of the regional haze initiative is to reduce visibility impairment in
and around 156 Class I protected areas (e.g., pristine areas such as national
parks and wilderness areas) caused by fine particulate and other pollutants
(SO\\2\\, NO\\x\\, and VOC). With no Class I areas being located in Illinois,
this rule is not likely to have a significant impact on the Genco generating
stations.
3.4.1.7 Global Warming - Greenhouse Gases
- ------------------------------------------
On December 11, 1997 in Kyoto, Japan, more than 150 countries came to an
agreement on target reductions of greenhouse gas emissions for the
industrialized nations of 6 to 8 percent from 1990 levels by the year 2012. The
next round of negotiations took place in Buenos Aires, Argentina in November
1998. These negotiations resulted in the Buenos Aires Action Plan which
established deadlines during the year 2000 for finalizing work on the Kyoto
Mechanisms (Joint Implementation, Emissions Trading and the Clean Development
Mechanism). The treaty restricts credits for emission reductions due to
afforestation, reforestation, and deforestation since 1990 but it is unclear how
these "sinks" would be
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measured or reported. There is much opposition to the treaty being expressed by
industry at this time. Therefore, it is difficult to ascertain the treaty's
impact on future power generation operations. However the treaty will likely
have some effect, perhaps in terms of improved system operating efficiency and
encouragement of the use of clean fuels and renewable energy sources. Some form
of carbon emissions cap and allowance trading is also a possible outcome of this
process.
3.4.2 Systemwide Air Emissions Compliance Programs
3.4.2.1 SO\\2\\ Compliance Plans
- ---------------------------------
All of the AmerenCIPS stations transferred to Genco are affected by Title IV
SO\\2\\ requirements. The annual Phase II SO\\2\\ allocations for these stations
are summarized below.
-----------------------------------------------------------------
SO\\2\\ SO\\2\\
Allocations Allocations
Generating Station (2000-2009) (2010-2019)
-----------------------------------------------------------------
Coffeen 20,459 20,500
-----------------------------------------------------------------
Grand Tower 3,029 3,035
-----------------------------------------------------------------
Hutsonville /(1,2)/ 4,523 4,533
-----------------------------------------------------------------
Meredosia 7,190 7,203
-----------------------------------------------------------------
Newton/(3,4)/ 29,548 29,608
-----------------------------------------------------------------
Total 64,749 64,879
-----------------------------------------------------------------
Notes:
(1) For the year 2000, Hutsonville's allocation is 5,827.
(2) For the years 2010 and 2020, Hutsonville's allocation is 3,881.
(3) For the year 2000, Newton's allocation is 30,108.
(4) For the years 2010 and 2020, Newton's allocation is 29,328.
The average annual SO\\2\\ emission rates for each of the former AmerenCIPS
generating units for the years 1997 through 1999 are summarized below.
------------------------------------------------------------------------------------------
Average Annual SO\\2\\ Emission Rate
Boiler (lb/MMBtu)
------------------------------------------------
Generating Unit Number 1997 1998 1999
------------------------------------------------------------------------------------------
Coffeen 1 1 2.30 2.42 1.97
------------------------------------------------------------------------------------------
Coffeen 2 2 2.08 2.39 2.23
------------------------------------------------------------------------------------------
Grand Tower 3 7 5.10 4.68 4.07
------------------------------------------------------------------------------------------
Grand Tower 3 8 4.94 4.60 4.02
------------------------------------------------------------------------------------------
Grand Tower 4 9 5.16 4.65 4.29
------------------------------------------------------------------------------------------
Hutsonville 3 5 4.36 4.28 4.35
------------------------------------------------------------------------------------------
Hutsonville 4 6 4.46 4.58 4.36
------------------------------------------------------------------------------------------
Meredosia 1 and 2 1 4.54 4.82 3.92
------------------------------------------------------------------------------------------
Meredosia 1 and 2 2 4.54 4.75 3.95
------------------------------------------------------------------------------------------
Meredosia 1 and 2 3 4.56 4.77 3.81
------------------------------------------------------------------------------------------
Meredosia 1 and 2 4 4.64 4.79 3.79
------------------------------------------------------------------------------------------
Meredosia 3 5 3.18 2.70 2.28
------------------------------------------------------------------------------------------
Meredosia 4 6 0.62 0.57 0.59
------------------------------------------------------------------------------------------
Newton 1 1 0.92 0.49 0.48
------------------------------------------------------------------------------------------
Newton 2 2 0.90 0.90 0.62
------------------------------------------------------------------------------------------
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There are no operating FGD systems at these generating units. However, an FGD
system was operated at Newton Unit 1 until December 1996. Newton Units 1 and 2
switched from Illinois Basin coal to PRB coal in 1998 and 1999, respectively.
Although PRB coal test burns have been performed at Coffeen Power Station, there
are no short term plans to switch to PRB coals at Coffeen. The planned
repowering of Grand Tower Power Station will lower SO\\2\\ emissions from this
station beginning in 2003.
Ameren, together with the Market Consultant, provided projections of annual
SO\\2\\ emissions from these units for the period 2000 to 2020. The projected
annual SO\\2\\ emissions exceed the SO\\2\\ allowance allocations for each year
of the forecast. Ameren has not included capital expenditures for future FGD
systems or fuel switching. Current SO\\2\\ compliance plans for the units
include the purchase or transfer of SO\\2\\ allowances, costs for which have
been included in the Financial Model as forecast by the Market Consultant.
Ameren has also forecast an annual average surplus of SO\\2\\ allowances for the
AmerenUE generating units for the period 2000-2004 of 6,302. Considering the
reported SO\\2\\ allowances held in the general account for the AmerenUE
generating units, and assuming the planned transfer of the surplus and "banked"
allowances to Genco occurs, Genco would then have sufficient SO\\2\\ allowances
to internally meet the projected SO\\2\\ allowance requirements of these units
through 2019. While this type of arrangement could conceivably provide some
advantage to Genco, the modeled pricing of allowances is based on the Market
Consultant's forecast as a conservative approach.
3.4.2.2 NO\\x\\ Compliance Plans
- ---------------------------------
Title IV NO\\x\\ Control Requirements
The Genco Coal-fired Stations are subject to the Title IV NO\\x\\ control
requirements. Ameren plans to utilize an averaging plan for the year 2000 for
compliance with the Acid Rain Phase II NO\\x\\ reduction requirements. The table
below summarizes the Phase II annual NO\\x\\ emission rate limits and Ameren's
projected annual NO\\x\\ emission rates for each of the coal-fired units.
-------------------------------------------------------------------
Average Annual NO\\x\\
Boiler Emission Rate (lb/MMBtu)
--------------------------------
Generating Unit Number Phase II Limit Projected
-------------------------------------------------------------------
Coffeen 1 1 0.86 1.20
-------------------------------------------------------------------
Coffeen 2 2 0.86 0.60
-------------------------------------------------------------------
Grand Tower 3 7 0.50 0.80
-------------------------------------------------------------------
Grand Tower 3 8 0.50 0.80
-------------------------------------------------------------------
Grand Tower 4 9 0.50 0.70
-------------------------------------------------------------------
Hutsonville 3 5 0.45 0.60
-------------------------------------------------------------------
Hutsonville 4 6 0.45 0.60
-------------------------------------------------------------------
Meredosia 1 and 2 1 0.45 0.55
-------------------------------------------------------------------
Meredosia 1 and 2 2 0.45 0.55
-------------------------------------------------------------------
Meredosia 1 and 2 3 0.45 0.55
-------------------------------------------------------------------
Meredosia 1 and 2 4 0.45 0.55
-------------------------------------------------------------------
Meredosia 3 5 0.45 0.55
-------------------------------------------------------------------
Newton 1 1 0.45 0.25
-------------------------------------------------------------------
Newton 2 2 0.45 0.35
-------------------------------------------------------------------
The sum of the annual NO\\x\\ emission limit times the projected annual heat
input for each unit equals 37,015 tons of NO\\x\\. The sum of the projected
annual NO\\x\\ emission rate and the projected annual heat input for each unit
equals 32,882 tons of NO\\x\\. The proposed averaging plan has more than a 10%
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compliance margin. The historical annual NO\\x\\ emission rates for the Genco
Coal-fired Stations are summarized below.
--------------------------------------------------------------------------------------
Average Annual NO\\x\\ Emission Rate
Boiler (lb/MMBtu)
-----------------------------------------------
Generating Unit Number 1997 1998 1999
--------------------------------------------------------------------------------------
Coffeen 1 1 1.28 1.17 1.19
--------------------------------------------------------------------------------------
Coffeen 2 2 1.28 1.17 1.19
--------------------------------------------------------------------------------------
Grand Tower 3 7 0.73 0.70 0.72
--------------------------------------------------------------------------------------
Grand Tower 3 8 0.76 0.72 0.80
--------------------------------------------------------------------------------------
Grand Tower 4 9 0.61 0.56 0.65
--------------------------------------------------------------------------------------
Hutsonville 3 5 0.53 0.53 0.56
--------------------------------------------------------------------------------------
Hutsonville 4 6 0.54 0.49 0.60
--------------------------------------------------------------------------------------
Meredosia 1 and 2 1 0.50 0.47 0.53
--------------------------------------------------------------------------------------
Meredosia 1 and 2 2 0.50 0.47 0.53
--------------------------------------------------------------------------------------
Meredosia 1 and 2 3 0.50 0.47 0.53
--------------------------------------------------------------------------------------
Meredosia 1 and 2 4 0.50 0.47 0.53
--------------------------------------------------------------------------------------
Meredosia 3 5 0.69 0.52 0.55
--------------------------------------------------------------------------------------
Meredosia 4 6 0.21 0.19 0.19
--------------------------------------------------------------------------------------
Newton 1 1 0.29 0.21 0.17
--------------------------------------------------------------------------------------
Newton 2 2 0.38 0.36 0.29
--------------------------------------------------------------------------------------
The table above indicates that the projected NO\\x\\ emission rates in the Title
IV NO\\x\\ averaging plan have been obtained by each of the Genco generating
units, with the exception of Coffeen Unit 2. However, Coffeen Unit 2 has been
retrofit with overfire air (OFA) ports and was in start-up at the time of the
site visit. Ameren reports that preliminary test results indicate that with the
OFA ports Coffeen Unit 2 will meet the projected NO\\x\\ emission rate of 0.60
lb/MMBtu. S&W Consultants has reviewed these results and notes that 75% OFA is
required to meet this emission limit. Continuous operation at this level of OFA
is feasible, provided Ameren closely monitors performance. Overfire air ports
are planned for Coffeen Unit 1 in the fall of 2000. In 1998, Meredosia Unit 3
(boiler 5) was retrofit with a Level I low NO\\x\\ concentric firing system
(LNCFS). Newton Unit 1 was retrofit with a Level III LNCFS NO\\x\\ control
system in 1994. The retrofit of a TFS 2000 system at Newton Unit 2 is planned
for the spring of 2001. The additional combustion NO\\x\\ control systems that
are planned for these Genco units will provide additional compliance margin for
meeting the NO\\x\\ reduction requirements of Title IV of the CAAA.
Future NO\\x\\ Control Programs
The former AmerenCIPS generating units are affected by the EPA SIP call rule.
Ameren has developed plans to comply with the requirements of a proposed SIP
call rule submitted by the Illinois EPA (IEPA). Based on the currently available
information, Ameren's estimate of NO\\x\\ allowance allocations for these
generating units equals 4,584 allowances for the years 2003 through 2005.
Beginning in 2006, the rule proposes flexible mechanisms to determine NO\\x\\
allowance allocations. The allocations for the years 2006 and beyond depend upon
a number of factors, including the operating characteristics of other generating
facilities in the state of Illinois. Based on the proposal, IEPA will determine
the number of allocations for 2006 by April 1 of 2003. At this point in time,
considerable uncertainty remains concerning the final outcome of the rule as
well as the number of allocations available after 2005.
Ameren's compliance strategy is based on the initial allocations for the 2003,
2004 and 2005 ozone seasons. The strategy will be adjusted as necessary in the
later years to accommodate both future allocations and changes in technology for
NO\\x\\ control. Ameren has identified the following NO\\x\\
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reduction options as a means of meeting the requirements of the proposed SIP
call rule. The capital costs associated with implementing these plans are
included in the Genco expense forecasts.
----------------------------------------------------------------------------------------
Controlled NO\\x\\
Emission Rate
Generating Unit NO\\x\\ Reduction Option (lb/MMBtu)
----------------------------------------------------------------------------------------
Coffeen 1 SCR Retrofit 0.06
----------------------------------------------------------------------------------------
Coffeen 2 SCR Retrofit 0.06
----------------------------------------------------------------------------------------
Grand Tower 3 Natural Gas Combined Cycle Repowering 0.094
----------------------------------------------------------------------------------------
Grand Tower 4 Natural Gas Combined Cycle Repowering 0.094
----------------------------------------------------------------------------------------
Hutsonville 3 TFS 2000 plus Combustion Optimization 0.22
----------------------------------------------------------------------------------------
Hutsonville 4 TFS 2000 plus Combustion Optimization 0.22
----------------------------------------------------------------------------------------
Meredosia 3 TFS 2000 plus Combustion Optimization 0.22
----------------------------------------------------------------------------------------
Newton 1 Combustion Optimization 0.12
----------------------------------------------------------------------------------------
Newton 2 TFS 2000 plus Combustion Optimization 0.12
----------------------------------------------------------------------------------------
Ameren developed a forecast of ozone season NO\\x\\ emissions based on ozone
season heat input projections provided by the Market Consultant and assuming the
above NO\\x\\ compliance plan is in place. This forecast is compared with the
estimated NO\\x\\ allowance allocations for the years 2003 to 2005 in the
following table.
----------------------------------------------------------------------------------------
2003 2004 2005
----------------------------------------------------------------------------------------
NO\\x\\ Emissions (tons/ozone season) 3,702 3,784 3,851
----------------------------------------------------------------------------------------
NO\\x\\ Allowance Allocation 4,584 4,584 4,584
----------------------------------------------------------------------------------------
Surplus (Shortage) of NO\\x\\ Allowances 882 800 733
----------------------------------------------------------------------------------------
Note: Allocations based on IEPA proposed rules with 5% deducted for new source set-aside.
If the allocations for the years 2006 through 2020 continue at the level for the
years 2003 - 2005, the Genco units will continue to generate surplus NO\\x\\
allowances each year. If Genco receives fewer allocations, Ameren could need to
purchase additional NO\\x\\ allowances or install additional NO\\x\\ control
equipment some point in the 2008 to 2020 time frame. However, it is unknown at
present what Genco's future allocations will be.
Refer also to the station-specific NO\\x\\ compliance plans in the following
sections.
3.4.3 Generating Station Environmental Compliance
S&W Consultants prepared an overview of current air and water permit
requirements, environmental limitations on current or future operations,
environmental compliance, and other significant environmental issues affecting
each of the former AmerenCIPS generating stations. These assessments are based
on the results of plant walk downs, interviews with key operating and staff
personnel, and limited primary compliance data and information.
3.4.3.1 Newton Power Station
- -----------------------------
Air Pollution Control Compliance
Newton Power Station holds operating air permits for the following emitting
units:
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. Unit 1 boiler
. Unit 2 boiler
. Upgraded coal handling system
. Newton storage tanks
. Lime and soda ash handling equipment (the use of this equipment is
discontinued)
. Fly ash dust collector
Newton also holds a joint construction/operating permit for the rail car dumper
dust collector and a Phase II Acid Rain Permit.
Ameren submitted an application for a Clean Air Act Permit Program ("CAAPP")
under Title V of the Clean Air Act Amendments of 1990 ("CAAA") to the Illinois
Environmental Protection Agency ("IEPA") in August of 1995. A completeness
determination has been issued by the IEPA, initiating an application shield for
the station. There are no reported or known issues preventing issuance of the
Title V Operating Permit.
The annual SO\\2\\ emissions for Newton Units 1 and 2 are projected to remain
well below the SO\\2\\ allowance allocations for these units. Current SO\\2\\
compliance plans for Newton Power Station are to continue burning low sulfur PRB
coal which will generate excess allowances for possible use at the other
stations. Units 1 and 2 are included in the planned Title IV averaging plan for
the former AmerenCIPS generating units for the year 2000. Additional details
concerning Ameren's system-wide SO\\2\\ and NO\\x\\ compliance plans are
provided in previous sections.
Emission limitations for each of the Newton generating units are summarized
below:
---------------------------------------------------------
Pollutant Unit 1 Unit 2
--------- ------ ------
---------------------------------------------------------
SO\\2\\ (lb/MMBtu) 1.2 1.2
---------------------------------------------------------
NO\\x\\ (lb/MMBtu) 0.7 0.7
---------------------------------------------------------
CO (ppmvd @ 50%) 200 200
---------------------------------------------------------
TSP (lb/MMBtu) 0.10 0.10
---------------------------------------------------------
Opacity (%, 6-minute) 20 20
---------------------------------------------------------
Units 1 and 2 use continuous emissions monitoring systems ("CEMS") which measure
and record opacity, CO\\2\\, NO\\x\\, SO\\2\\, and flue gas flow rate.
Units 1 and 2 limit SO\\2\\ emissions by using low sulfur coal, currently PRB.
Newton Unit 1 was retrofit with a Level III LNCFS NO\\x\\ control system in
1994. The retrofit of a TFS2000R system at Newton Unit 2 is planned for the
spring of 2001. Units 1 and 2 control particulate emissions with an ESP.
Additional discussion concerning the existing air pollution control systems at
Newton Units 1 and 2 are provided in Section 3.1.1.
On occasion, certain operating practices, such as load reductions, are employed
to avoid exceedances of opacity standards. Opacity monitoring reports for 1998
indicate excess emissions for only 0.05 and 0.58 percent of the operating time
for Units 1 and 2, respectively. No data are reported for 1999. These
percentages do not include excess opacity emissions during start-up, shutdown,
malfunctions, and breakdowns as these events are excluded relative to opacity
standards compliance.
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There are no outstanding air pollution control violations, enforcement issues or
consent orders for the Newton Power Station with IEPA or USEPA, nor reported
public complaints regarding air pollution from the station or its operational
activities. There are no reported or known issues preventing issuance of the
Title V Operating Permit.
Water Supply
Service water for plant wash water, boiler makeup, fire protection, and potable
and sanitary purposes is from the Rural Water District supply system.
Circulating water is taken from Newton Lake. The intakes for the circulating
water system do not experience significant sediment buildup, fish entrainment or
zebra mussel growth.
Wastewater Discharge Compliance
The IEPA has authority to issue NPDES permits for the USEPA in Illinois. The
Newton Power Station has a National Pollutant Discharge Elimination System
("NPDES") permit effective through August 31, 2003 to discharge to Newton Lake
in Jasper County Illinois.
The NPDES permit governs discharges at thirteen outfalls. The permit temperature
limitation for the main condenser cooling water outfall (002) is 102(degrees)F
(monthly average) with a daily maximum limit of 111(degrees)F. A variance was
issued to Newton Power Station that allows a monthly average discharge
temperature of 106(degrees)F and the daily maximum temperature to exceed
111(degrees)F for 110 hours during the months May through September. Violation
Notice M-2000-02001 was issued on January 7, 2000 for a thermal discharge that
caused water pollution and failure to meet the standards for dissolved oxygen on
July 23, 1999. The discharge resulted in a fish kill on July 28 and 29, 1999 and
penalties of $923.26 for both the fish kill value and investigation expenses
were assessed. The station was ordered to immediately comply with the thermal
limits set out by the Illinois PCB in PCB 78-271. This action revoked the
variance that was issued for discharge temperatures from outfall 002. Ameren has
completed construction of a supplemental cooling pond which should reduce
discharge temperatures to acceptable levels.
With the exception of the thermal discharge violation, there are no additional
water pollution control violations, enforcement issues or consent orders for the
station with IEPA or USEPA, nor reported public complaints regarding water
pollution from the station or its operational activities.
Ash Disposal
Newton Power Station has a 200-acre bottom ash settling pond, which is projected
by Ameren to serve the life of the station. The PRB coal that is used at Newton
Power Station produces a high quality Class C ash. Currently, approximately 10%
of the fly ash is sent to secondary markets. Fly ash is disposed of at an
on-site, 40-acre landfill. The landfill design includes a single liner with
leachate collection. Ameren has projected that the existing phase of the
landfill has a remaining life of approximately 6 to 10 years if 100% of the fly
ash production is placed in the landfill. On-going efforts to market the fly ash
may extend the useful life of the landfill. The amounts budgeted for future ash
disposal costs should be adequate.
Hazardous Materials
Several hazardous materials are managed at the Newton Power Station, including
the following:
. No. 2 fuel oil
. Diesel fuel
. Gasoline
. Lubricating oils
. Sulfuric acid
. Sodium hydroxide (caustic)
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. Hydrazine
. Ammonia
. Safety Kleen solvent
. Miscellaneous solvents
. Paint
. Chlorine (tablets and one-ton cylinders)
. Asbestos-containing materials ("ACM")
. Mercury
After use, these materials may be regulated as a hazardous waste. In addition,
the "mixture rule" contained in the federal Resource Conservation and Recovery
Act ("RCRA") regulations requires that mixtures of hazardous waste and other
materials, such as fresh fuels, rags and soils, must also be managed as
hazardous waste.
S&W Consultants noted that all of these hazardous materials and wastes were
being managed at the Newton Power Station in a manner that was generally
protective of the environment and in compliance with applicable regulations.
A number of wastes, including used oil and chemical cleaning wastes, are
typically placed on the active portions of the coal pile for disposal by
burning. This practice is specifically permitted by the plant's air permit.
The Newton Power Station is listed in the federal RCRA database as a Large
Quantity Generator ("LQG") of hazardous waste. S&W Consultants also noted that
the Newton Power Station is not conducting the administrative procedures
required of LQG facilities, but is conducting itself as a Small Quantity
Generator ("SQG"). The regulations require site registration for both SQG and
LQG facilities, and specific regulatory requirements are a function of actual
waste generation rate rather than generator class. Therefore, the station
practice appears to be acceptable.
The Newton Power Station maintains an inventory of ACM present and has an
ongoing program for the management of ACM. Typically, ACM is removed and
replaced with non-ACM only as required for equipment maintenance.
Lead-based paints are not currently used at the Newton Power Station; however,
such paints were used at this station in the past. The station (nor the other
Assets) does not maintain an inventory of surfaces coated with lead-based paint.
A few instruments, gauges and lighting ballasts containing mercury are still in
use at the Newton Power Station. However, the station (nor the other Assets)
does not maintain an inventory of items containing mercury. All waste mercury is
transported to the Ameren corporate laboratory in St. Louis, Missouri for
continued use. This is acceptable practice.
Site Contamination
S&W Consultants notes that AmerenCIPS has retained responsibility and
indemnified Genco with regard to all environmental damages or violation of any
environmental requirements attributable to or resulting from any action prior to
the closing date of the transfer of Assets to Genco.
For reference purposes, the Phase I ESA documented that surficial soils at the
Newton Power Station consist of sand, silt and gravel with some interbedded,
noncontinuous clay lenses. Bedrock consisting of limestones and sandstones are
encountered at a depth of approximately 150 feet below grade. The water
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table, which is hydraulically connected with Newton Lake, is typically
encountered at a depth of approximately 30 feet below grade.
The Phase I ESAs identified the following issues which were common to all of the
existing generating facilities:
. Underground piping has never been tested for integrity (leaks), although
some of the stations do maintain cathodic protection on their underground
piping. S&W Consultants notes that the Meredosia Power Station reports that
none of its oil piping is installed under ground. S&W Consultants
recommends that the stations document materials of construction for
underground piping, document the status of existing cathodic protection
systems, and conduct pressure testing of all underground piping.
. Oil and chemical storage tanks have never been tested for integrity
(leaks), although some of the stations do maintain cathodic protection on
their storage tanks. S&W Consultants recommends that the stations document
materials of construction for all aboveground and underground storage
tanks, document the status of existing cathodic protection systems, and
conduct non-destructive testing as appropriate to determine current tank
conditions.
In addition, the Phase I ESAs identified the following issues specific to Newton
Power Station:
. This station experienced a rupture of an underground fuel oil line in 1986.
. This station used an underground tank (since removed) for the storage of
used oil.
. A sample of sewage sludge taken in 1995 exhibited an unexpectedly high
concentration of mercury. This aberration was duly reported to the IEPA,
and subsequent sludge samples did not exhibit elevated concentrations of
mercury. At that time, sewage sludge was normally mixed with scrubber
sludge for combined disposal in an onsite landfill. S&W Consultants notes
that the pozzolanic content of the scrubber sludge should chemically fixate
any residual concentrations of mercury in the sewage sludge.
. The Newton Power Station is currently subject to a Consent Decree which
requires the station to monitor groundwater associated with the old
landfill (former ash disposal) area. S&W Consultants anticipates that the
Newton Power Station will continue to implement the dictates of this
Consent Decree.
Since the Phase I ESA has identified the potential for soil and groundwater
contamination at each of the Coal-fired Stations, S&W Consultants recommends
additional ESA activities at each station, e.g., soil and groundwater sampling
and analysis, in order to baseline and document the extent of any current
contamination. S&W Consultants' recommendation is for the commercial benefit of
Genco, and not meant to be based on current regulatory requirements, as Genco is
not under regulatory obligation to perform additional characterization.
Other Environmental Issues
The amounts of chlorine and other regulated materials stored at the Newton Power
Station are greater than the threshold amounts listed in the United States
Environmental Protection Agency's Risk Management Program ("RMP") regulations.
Therefore, an RMP plan is in place for this station.
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3.4.3.2 Coffeen Power Station
- ------------------------------
Air Emissions Compliance
The Coffeen Power Station holds operating air permits for the following emitting
units:
. Unit 1 boiler
. Unit 2 boiler
. Auxiliary boiler
. Coal handling and organic liquids storage
. Fly ash silo
. Soda ash silo
Coffeen also holds a joint construction/operating permit for the Unit 2 overfire
air system and a Phase II Acid Rain Permit.
Ameren submitted an application for a CAAPP under Title V of the CAAA to the
IEPA in August of 1995. A completeness determination has been issued by the
IEPA, initiating an application shield for the station. There are no reported or
known issues preventing issuance of the Title V Operating Permit.
The annual SO\\2\\ emissions for Coffeen Units 1 and 2 are projected to exceed
the SO\\2\\ allowance allocations for these units by more than a factor of two.
Current SO\\2\\ compliance plans for the Coffeen Power Station are to purchase
SO\\2\\ allowances. Units 1 and 2 are included in the planned Title IV averaging
plan for the Genco generating units for the year 2000. Additional details
concerning Ameren's system-wide SO\\2\\ and NO\\x\\ compliance plans are
provided earlier in Section 3.4.
Emission limitations for each of the Coffeen generating units are summarized
below:
-------------------------------------------------------------------------
Pollutant Unit 1 Unit 2 Aux. Boiler
--------- ------ ------ -----------
-------------------------------------------------------------------------
SO\\2\\ (lb/hour) 55,555 for Units 1&2 0.3
-------------------------------------------------------------------------
NO\\x\\ (lb/MMBtu) 0.86** 0.86** None
-------------------------------------------------------------------------
CO (ppmvd @ 50%) 200 200 200
-------------------------------------------------------------------------
TSP (lb/MMBtu) 0.19 0.15 0.10
-------------------------------------------------------------------------
Opacity (%, 6-minute) 30 30 20
-------------------------------------------------------------------------
** Coffeen was exceeding these emissions limitations at the time of the site
visit, but has taken measures to correct.
Units 1 and 2 use continuous CEMS which measure and record opacity, CO\\2\\,
NO\\x\\, SO\\2\\, and flue gas flow rate. Units 1 and 2 burn local Monterey coal
and have no SO\\2\\ emissions controls. Coffeen Unit 2 has been retrofit with
OFA ports. Test results provided by Ameren indicate that Unit 2 is capable of
meeting the above NO\\x\\ emissions limitations with the new OFA system.
Overfire air ports are planned for Coffeen Unit 1 in the fall of 2000. Units 1
and 2 control particulate emissions with an ESP. Additional discussion
concerning the existing air pollution control systems at Coffeen Units 1 and 2
are provided in Section 3.1.2.
On occasion, certain operating practices, such as load reductions, are employed
to avoid exceedances of opacity standards. Opacity monitoring reports for 1999
indicate excess emissions for approximately 1.6 percent of the operating time
for Units 1 and 2. This percentage does not include excess opacity
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emissions during start-up, shutdown, malfunctions, and breakdowns as these
events are excluded relative to opacity standards compliance. A Consent Order
was entered into in 1987 for exceedances of SO\\2\\ emission limits.
There are no outstanding air pollution control violations, enforcement issues or
consent orders for the Coffeen Power Station with IEPA or USEPA, nor reported
public complaints regarding air pollution from the station or its operational
activities. There are no reported or known issues preventing issuance of the
Title V Operating Permit.
Water Supply
Service water for boiler makeup, circulating water and fire protection is from
Coffeen Lake. Potable and sanitary water is provided by the City of Greenville.
The intakes for the circulating water system does not experience significant
sediment buildup, fish entrainment or zebra mussels.
Wastewater Discharge Compliance
The IEPA has authority to issue NPDES permits for the USEPA in Illinois. The
Coffeen Power Station has a NPDES permit effective through September 30, 2003 to
discharge to Coffeen Lake in Montgomery County Illinois.
The NPDES permit governs discharges at 21 outfalls. The permit temperature
limitations for the main condenser cooling water outfall include 105(degrees)F
(monthly average) and a maximum of 112(degrees)F for *3% of hours from June to
September. A variance was issued to Coffeen Power Station that extends the
period for higher allowable discharge temperature limits at outfall 001 from
June through September to May through October. However, Violation Notice
M-2000-02002 was issued on January 7, 2000 for a thermal discharge that caused
water pollution and failure to meet the standards for dissolved oxygen on July
28, 1999. The discharge resulted in a fish kill on July 28, 1999 and a penalty
of $1794.28 for the fish kill value was assessed. The station was ordered to
immediately comply with the thermal limits set out by the Illinois PCB in PCB
78-158. This action revoked the variance that was issued for discharge
temperatures from outfall 001. Ameren has constructed a supplemental cooling
pond which should reduce discharge temperatures to acceptable levels.
With the exception of the thermal discharge violation, there are no additional
outstanding water pollution control violations, enforcement issues or consent
orders for the station with IEPA or USEPA, nor reported public complaints
regarding water pollution from the station or its operational activities.
Ash Disposal
Approximately 80% of the coal ash at Coffeen Power Station is removed as slag
from the cyclone burners. The slag is sluiced to dewatering bins. All of the
slag collected in the bottom ash pond is marketed under a long-term (7-year)
contract. The slag is sold as roofing grit and sand blasting abrasive.
Fly ash that is produced at Coffeen Power Station is typically handled dry and
sent off-site. The primary off-site option involves mine back filling, at a mine
located approximately 40 miles from the station. Ameren has submitted a permit
application to the IEPA for underground injection control ("UIC") of a fly ash
and mine water slurry. Issuance of the permit is expected in mid-2000. The life
of the UIC project is not known. However, Coffeen Power Station also has a
permit in place to build a 20-acre on-site landfill, and is also permitted to
send fly ash to the existing landfill at Newton Power Station. Coffeen's ash
disposal plan and budget should be adequate.
Hazardous Materials
The Coffeen Power Station is listed as a SQG of hazardous waste. Ameren has
advised S&W Consultants that wastes generated by maintenance contractors are
included in the annual total hazardous
* = Less than
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waste generation amount for the Coffeen Power Station. Several hazardous
materials are managed at the Coffeen Power Station, similarly to Newton Power
Station. S&W Consultants noted that all of these hazardous materials and wastes
were being managed at the Coffeen Power Station in a manner that was generally
protective of the environment (see Section 3.4.3.1, "Hazardous Materials").
S&W Consultants reviewed the results of PCB testing for oil-filled equipment at
each of the power stations. PCB results were not available for two pieces of
equipment at the Coffeen Power Station. The PCB results for the remaining
oil-filled equipment indicated that there are no "PCB transformers" at any of
these power stations; i.e., the concentration of PCBs in oil-filled equipment is
less than 500 ppm. Furthermore, PCB results indicate that all but four pieces of
equipment are "non-PCB" equipment; i.e., the concentrations of PCB in these
pieces of equipment are less than 50 ppm. Ameren has indicated that these pieces
of equipment are to be retested. S&W Consultants notes that oil-filled equipment
is being managed in an acceptable manner with regard to (potential) PCB content.
Site Contamination
For reference purposes, the Phase I ESA documented that surficial soils at the
Coffeen Power Station consist of sand, silt and gravel with some interbedded,
noncontinuous clay lenses. Bedrock consisting of limestones and sandstones are
encountered at a depth of approximately 60-150 feet below grade. The water
table, which is hydraulically connected with Coffeen Lake, is typically
encountered at a depth of approximately 20 feet below grade.
The Phase I ESA identified potential environmental issues common to all of the
existing generating stations as described previously in Section 3.4.3.1 "Site
Contamination".
The Phase I ESA did not identify any significant environmental issues at the
Coffeen Power Station in addition to those common to all stations.
Other Environmental Issues
The amounts of ammonia, chlorine and other regulated materials stored at the
Coffeen Power Station are greater than the threshold amounts listed in the
United States Environmental Protection Agency's Risk Management Program
regulations. Therefore, an RMP plan is in place for this station.
3.4.3.3 Meredosia Power Station
- --------------------------------
Air Pollution Control Compliance
The Meredosia Power Station holds operating air permits for the following
emitting units:
. Unit 1 boiler
. Unit 2 boiler
. Unit 3 boiler
. Unit 4 boiler
. Unit 5 boiler
. Unit 6 boiler
. Coal handling and oil storage facility
. Fuel oil storage tanks
. Open burning permit for fire fighting training
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Note that boilers 1 and 2 correspond with T/G Unit 1, boilers 3 and 4 correspond
with T/G Unit 2, boiler 5 corresponds with T/G Unit 3, and boiler 6 corresponds
with T/G Unit 4, as described earlier. "Unit" in this section refers to boiler.
Meredosia also holds a Phase II Acid Rain Permit.
Ameren submitted an application for a CAAPP under Title V of the CAAA to the
IEPA in August of 1995. A completeness determination has been issued by the
IEPA, initiating an application shield for the Meredosia Power Station. There
are no reported or known issues preventing issuance of the Title V Operating
Permit.
The annual SO\\2\\ emissions for Meredosia Units 1-6 are projected to exceed the
SO\\2\\ allowance allocations for these units by more than a factor of two.
Current SO\\2\\ compliance plans for the Meredosia Power Station are to purchase
SO\\2\\ allowances. Units 1-6 are included in the planned Title IV averaging
plan for the Genco generating units for the year 2000. Additional details
concerning Ameren's system-wide SO\\2\\ and NO\\x\\ compliance plans are
provided earlier in Section 3.4. Emission limitations for each of the Meredosia
generating units are summarized below:
========================================================================
Pollutant Boilers 1-4 Boiler 5 Boiler 6
(Units 1 and 2) (Unit 3) (Unit 4)
------------------------------------------------------------------------
SO\\2\\ (lb/hour) 23,000 lb/hr 23,000 lb/hr 0.8
plant limit plant limit lb/MMBtu
------------------------------------------------------------------------
NO\\x\\ (lb/MMBtu) None None 0.3
------------------------------------------------------------------------
CO (ppmvd @ 50%) 200 200 200
------------------------------------------------------------------------
TSP (lb/MMBtu) 0.20 0.10 0.10
------------------------------------------------------------------------
Opacity (%, 6-minute) 30 30 20
========================================================================
Boilers 1-6 use CEMS which measure and record opacity, CO\2\\, NO\\x\\, SO\\2\\,
and flue gas flow rate. Boilers 1-4 burn high sulfur coal and have no SO\\2\\
emissions controls. Boiler 5 burns intermediate sulfur (~1%) coal to generate
some SO\\2\\ credits and Boiler 6 fires low sulfur #4 oil (~0.4%). In 1998,
Meredosia Unit 3 (boiler 5) was retrofitted with ABB-CE Level I low LNCFS.
Boilers 1-5 control particulate emissions with an ESP. Boiler 6 has no
particulate control. Additional discussion concerning the existing air pollution
control systems at Meredosia is provided in Section 3.1.3.
On occasion, certain operating practices, such as load reductions, are employed
to avoid exceedances of opacity standards. Opacity monitoring reports for 1999
indicate excess emissions for approximately 0.3 percent of the operating time
for Boilers 1-4, 0.01 percent for Boiler 5, and 0.2 for Boiler 6. These
percentages do not include excess opacity emissions during start-up, shutdown,
malfunctions, and breakdowns as these events are excluded relative to opacity
standards compliance.
There are no outstanding air pollution control violations, enforcement issues or
consent orders for the Meredosia Power Station with IEPA or USEPA, nor reported
public complaints regarding air pollution from the station or its operational
activities. There are no reported or known issues preventing issuance of the
Title V Operating Permit.
Water Supply
On-site deep wells provide the raw source of water for the station
demineralizers, the majority of outdoor fire protection, and water for potable
and sanitary purposes. The Illinois River serves as the source of
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water supply for circulating water, miscellaneous cooling, indoor fire
protection, automatic sprinkler and deluge fire protection systems, and plant
wash water. The intakes for the circulating water system does not experience
significant sediment buildup, fish entrainment or zebra mussel growth. The
Illinois river also provides the make-up source to the cooling tower that serves
as the closed loop circulating water system for Unit 4 condenser.
Wastewater Discharge Compliance
The IEPA has authority to issue NPDES permits for the USEPA in Illinois. The
Meredosia Power Station has a NPDES permit effective through April 30, 2003 to
discharge to the Illinois River in Morgan County Illinois.
The NPDES permit governs discharges at nine outfalls. NPDES sampling data for
all discharge points are reported to indicate general compliance with permit
requirements. There have been some bottom ash pond discharge total suspended
solids exceedances in the past. However, at this time, there are no outstanding
water pollution control violations, enforcement issues or consent orders for the
station with IEPA or USEPA, nor reported public complaints regarding water
pollution from the Meredosia Power Station or its operational activities.
Ash Disposal
Bottom ash from Meredosia Units 1, 2 and 3 is sluiced to an unlined settling
pond. The bottom ash pond is cleaned out periodically as required. The recovered
bottom ash is given away for beneficial uses (primarily as anti-skid material).
Ameren has indicated that the demand for the beneficial use of bottom ash
exceeds the production rate at Meredosia Power Station.
Fly ash from Meredosia Units 1, 2 and 3 is sluiced to an unlined settling pond.
In 1998 approximately 80,000 yds/3/ of fly ash was removed from the pond and
back hauled to the Cedar Creek mine, approximately 30 miles from the station.
The fly ash pond currently has about two years of remaining capacity. Ameren is
in the process of planning the development of a new lined pond on site in 2002.
S&W Consultants considers Meredosia's ash disposal plan and budget to be
adequate.
Hazardous Materials
Hazardous materials issues at Meredosia are similar to those discussed earlier
for Newton and Coffeen Power Stations. See Section 3.2.3.2, "Hazardous
Materials" for detailed discussion.
Site Contamination
For reference purposes, the Phase I ESA documented that surficial soils at the
Meredosia Power Station consist of sand, silt and gravel with some interbedded,
noncontinuous clay lenses. Bedrock consisting of limestones and sandstones are
encountered at a depth of approximately 125 feet below grade. The water table,
which is hydraulically connected with the Illinois River, is typically
encountered at a depth of approximately 35 feet below grade.
The Phase I ESA identified potential environmental issues common to all of the
existing generating stations as described previously in Section 3.4.3.1 "Site
Contamination".
The Phase I ESA identified the following issues which were of concern at the
Meredosia Power Station:
. The former fly and bottom ash ponds were closed as landfills; i.e., with
wastes in place. Although "impermeable" caps were placed upon these ponds
at closure, the potential exists for residual migration of waste
constituents to groundwater.
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Other Environmental Issues
The amounts of ammonia, chlorine and other regulated materials stored at the
Meredosia Power Station are less than the threshold amounts listed in the United
States Environmental Protection Agency's Risk Management Program regulations.
Therefore, a RMP plan is not required for this station.
3.4.3.4 Hutsonville Power Station
- ----------------------------------
Air Pollution Control Compliance
The Hutsonville Power Station holds operating air permits for the following
emitting units:
. Unit 5 boiler
. Unit 6 boiler
. Coal handling/oil storage/diesel generator
Hutsonville also holds a Phase II Acid Rain Permit.
Ameren submitted an application for a CAAPP under Title V of the CAAA to the
IEPA in August of 1995. A completeness determination has been issued by the
IEPA, initiating an application shield for the Hutsonville Power Station. There
are no reported or known issues preventing issuance of the Title V Operating
Permit.
The annual SO\\2\\ emissions for Hutsonville Units 5 and 6 are projected to
exceed the SO\\2\\ allowance allocations for these units by more than a factor
of two. Current SO\\2\\ compliance plans for the Hutsonville Power Station are
to purchase SO\\2\\ allowances. Units 5 and 6 are included in the planned Title
IV averaging plan for the Genco generating units for the year 2000. Additional
details concerning Ameren's system-wide SO\\2\\ and NO\\x\\ compliance plans are
provided earlier in Section 3.4. Emission limitations for each of the
Hutsonville generating units are summarized below:
================================================
Pollutant Units 5&6
--------- ---------
------------------------------------------------
SO\\2\\ (lb/hour) 8,536
------------------------------------------------
NO\\x\\ (lb/MMBtu) None
------------------------------------------------
CO (ppmvd @ 50% excess) air) 200
------------------------------------------------
TSP (lb/MMBtu) 0.18
------------------------------------------------
Opacity (%, 6-minute ave.) 30
================================================
Units 5 and 6 use CEMS which measure and record opacity, CO\\2\\, NO\\x\\,
SO\\2\\, and flue gas flow rate. Units 5 and 6 burn local high sulfur (~2.5%)
coal and have no SO\\2\\ emissions controls. No additional combustion NO\\x\\
control systems are planned for the Hutsonville Power Station at this time.
Units 5 and 6 control particulate emissions with an ESP. Additional discussion
concerning the existing air pollution control systems at Hutsonville Units 1-6
are provided in Section 3.1.4.
On occasion, certain operating practices, such as load reductions, are employed
to avoid exceedances of opacity standards. Opacity monitoring reports for 1999
indicate excess emissions for approximately 0.2 percent of the operating time
for Unit 5 and 0.1 for Unit 6. These percentages do not include excess opacity
emissions during start-up, shutdown, malfunctions, and breakdowns as these
events are excluded relative to opacity standards compliance.
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There are no outstanding air pollution control violations, enforcement issues or
consent orders for the Hutsonville Power Station with IEPA or USEPA, nor
reported public complaints regarding air pollution from the station or its
operational activities. There are no reported or known issues preventing
issuance of the Title V Operating Permit.
Water Supply
Service water for plant wash water, boiler makeup, fire protection, and potable
and sanitary purposes is taken from on-site deep wells. Circulating water is
taken from the Wabash River. The intakes for the circulating water system do not
experience significant sediment buildup, fish entrainment or zebra mussel
growth.
Wastewater Discharge Compliance
The IEPA has authority to issue NPDES permits for the USEPA in Illinois. The
Hutsonville Power Station has a NPDES permit effective through April 30, 2004 to
discharge to the Wabash River in Crawford County Illinois. The NPDES permit
governs discharges at six outfalls. NPDES sampling data for all discharge points
are reported to indicate general compliance with permit requirements, with the
exception of TSS exceedances at the fly ash pond discharge. There is an
enforcement action pending with the IEPA in regard to ground water contamination
from the ash pond. Fines may result from this enforcement action. Ameren is
negotiating a compliance consent agreement with the IEPA on this issue. See the
"Site Contamination" section.
Ash Disposal
Hutsonville Power Station has an unlined bottom ash pond. Bottom ash is
periodically reclaimed from the pond for beneficial use, primarily as an
anti-skid material. The demand for bottom ash exceeds the production rate.
Fly ash is sluiced to an unlined pond. Plans are being developed for closure of
the existing unlined fly ash pond and construction of a new, lined fly ash pond
located adjacent to the existing fly ash pond. The budget allocation for
construction of the lined pond should be adequate. The fly ash at Hutsonville
does not qualify for beneficial use based on Illinois regulations, but does
qualify for beneficial use based on Indiana regulations. Ameren is evaluating
the possible use of fly ash from Hutsonville as structural fill in Indiana.
Hazardous Materials
Hazardous materials issues at Hutsonville are similar to those discussed
earlier. See Section 3.2.3.1, "Hazardous Materials" for detailed discussion.
Site Contamination
For reference purposes, the Phase I ESA documented that surficial soils at the
Hutsonville Power Station consist of sand, silt and gravel with some
interbedded, noncontinuous clay lenses. Bedrock consisting of limestones and
sandstones are encountered at a depth of approximately 20-30 feet below grade.
The water table, which is hydraulically connected with the Wabash River, is
typically encountered at a depth of approximately 8-10 feet below grade.
The Phase I ESA identified potential environmental issues common to all of the
existing generating stations as described previously in Section 3.4.3.1 "Site
Contamination". The Phase I ESA identified the following issues which were of
concern at the Hutsonville Power Station:
. The Hutsonville Power Station is subject to an ongoing enforcement action
concerning groundwater associated with the fly and bottom ash ponds. Ameren
has submitted a proposed remedial action plan to IEPA and the Illinois
Attorney General's Office and Ameren reports that a settlement-in-principle
has been reached. S&W Consultants reviewed the generic content of this plan
with station personnel and noted that it appears reasonable and appropriate.
S&W Consultants anticipates that IEPA will
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approve a final version of this plan (without undue revisions) sometime in
the near future, and that the Hutsonville Power Station will commence
implementation of the approved plan shortly thereafter.
. S&W Consultants noted that the wells used to obtain fresh water for potable
purposes at the station are located downgradient from the fly ash pond. S&W
Consultants further noted that sampling and analysis for organic contaminants
is not conducted on this well water. S&W Consultants recommends that the
Hutsonville Power Station begin sampling and analyzing for organic as well as
inorganic contaminants in its well water.
. Anecdotal information indicates that the agricultural property located to the
southwest of the Hutsonville Power Station was formerly used by the farm
bureau cooperative to fill and rinse herbicide and pesticide tankers. S&W
Consultants recommends that Ameren document the former usage of this adjacent
property and conduct soil and groundwater sampling and analysis along the
periphery of the station property to document the presence of any
contamination migrating from this adjacent property.
Other Environmental Issues
The amounts of ammonia, chlorine and other regulated materials stored at the
Hutsonville Power Station are less than the threshold amounts listed in the
United States Environmental Protection Agency's Risk Management Program
regulations. Therefore, a RMP plan is not required for this station.
3.4.3.5 Grand Tower Power Station
- ----------------------------------
Air Pollution Control Compliance
The Grand Tower Power Station holds operating air permits for the following
emitting units:
. Unit 7 boiler
. Unit 8 boiler
. Unit 9 boiler
. Coal handling/oil tanks/fly ash silos
Note that boilers 7 and 8 correspond with T/G Unit 3, and boiler 9 corresponds
with T/G Unit 4. "Unit" in this section refers to boiler.
Grand Tower also holds a Phase II Acid Rain Permit. (See also Section 4.4.4 for
the repowered configuration).
Ameren submitted an application for a CAAPP under Title V of the CAAA to the
IEPA in August of 1995. A completeness determination has been issued by the
IEPA, initiating an application shield for the Grand Tower Power Station. There
are no reported or known issues preventing issuance of the Title V Operating
Permit.
The annual SO\\2\\ emissions for Grand Tower Units 3 and 4 are projected to
exceed the SO\\2\\ allowance allocations for these units for the short period
remaining while firing coal before the repowering is completed. Current SO\\2\\
compliance plans for the Grand Tower Power Station are to purchase SO\\2\\
allowances. Units 3 and 4 are included in the planned Title IV averaging plan
for the Genco generating units for the year 2000. Additional details concerning
Ameren's system-wide SO\\2\\ and NO\\x\\ compliance plans are provided earlier
in Section 3.4. Emission limitations for each of the Grand Tower generating
units are summarized below:
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===============================================
Pollutant Units 3 & 4
--------- -----------
-----------------------------------------------
SO\\2\\ (lb/hour) 11,560
-----------------------------------------------
NO\\x\\ (lb/MMBtu) None
-----------------------------------------------
CO (ppmvd @ 50% excess) 200
-----------------------------------------------
TSP (lb/MMBtu) 0.20
-----------------------------------------------
Opacity (%, 6-minute ave.) 30
===============================================
Units 3 and 4 use CEMS which measure and record opacity, CO\\2\\, NO\\x\\,
SO\\2\\, and flue gas flow rate.
Units 3 and 4 burn local high sulfur coal and have no SO\\2\\ emissions
controls. No additional combustion NO\\x\\ control systems are planned for the
Grand Tower Power Station at this time. The NO\\x\\ emission rates of the
repowered units at Grand Tower are projected to be less than 0.01 lb/MMBtu. See
section 4 concerning further details on the air emission limits for the new
natural gas combined cycle units at Grand Tower Power Station. Units 3 and 4
control particulate emissions with an ESP. However, the existing emissions
control equipment will be retired as part of the repowering project.
On occasion, certain operating practices, such as load reductions, are employed
to avoid exceedances of opacity standards. Opacity monitoring reports for 1999
indicate excess emissions for approximately 0.04 percent of the operating time
for Unit 7, 0.04 for Unit 8, and 0.2 for Unit 9. These percentages do not
include excess opacity emissions during start-up, shutdown, malfunctions, and
breakdowns as these events are excluded relative to opacity standards
compliance.
There are no outstanding air pollution control violations, enforcement issues or
consent orders for the Grand Tower Power Station with IEPA or USEPA, nor
reported public complaints regarding air pollution from the station or its
operational activities. There are no reported or known issues preventing
issuance of the Title V Operating Permit.
Water Supply
Service water for plant wash water, boiler makeup, fire protection, and potable
and sanitary purposes is taken from on-site deep wells. Circulating water is
taken from the Mississippi River. The intakes for the circulating water system
do not experience significant sediment buildup, fish entrainment or zebra mussel
growth.
Wastewater Discharge Compliance
The IEPA has authority to issue NPDES permits for the USEPA in Illinois. The
Grand Tower Power Station has a NPDES permit effective through July 31, 2003 to
discharge to the Mississippi River in Jackson County Illinois. Additional
details concerning the expected permit conditions for the repowered Grand Tower
units are provided in Section 4.
The NPDES permit governs discharges at seven outfalls. NPDES sampling data for
all discharge points are reported to indicate general compliance with permit
requirements. There are no outstanding water pollution control violations,
enforcement issues or consent orders for the station with IEPA or USEPA, nor
reported public complaints regarding water pollution from the Grand Tower Power
Station or its operational activities.
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Ash Disposal
Grand Tower Power Station has an unlined bottom ash settling pond, which is
projected by Ameren to serve the remaining life of the station as a coal-fired
station. Demand for the dewatered bottom ash (primarily as anti-skid material)
exceeds the current production rate. The bottom ash pond may become a water
treatment pond for the planned natural gas repowering project at Grand Tower
Power Station.
Approximately 90% of the fly ash produced at Grand Tower Power Station has been
sold as feed stock to cement kilns located approximately 30 miles from the
station. The remaining fly ash is sent to the Newton Power Station landfill.
Hazardous Materials
Hazardous materials issues at Grand Tower are similar to those discussed
earlier. See Section 3.2.3.1, "Hazardous Materials" for detailed discussion.
Site Contamination
For reference purposes, the Phase I ESA documented that surficial soils at the
Grand Tower Power Station consist of sand, silt and gravel with some
interbedded, noncontinuous clay lenses. Bedrock consisting of limestones and
sandstones are encountered at depths ranging from approximately 10-150 feet
below grade. The water table, which is hydraulically connected with the
Mississippi River, is typically encountered at a depth of approximately 20-30
feet below grade.
The Phase I ESA identified potential environmental issues common to all of the
existing generating stations as described previously in Section 3.4.3.1 "Site
Contamination".
The Phase I ESA identified the following issues which were of concern at the
Grand Tower Power Station:
. An aboveground tank was formerly used to store No. 2 fuel oil at the Grand
Tower Power Station. This tank was removed in 1999.
. An underground tank was formerly used to store furnace fuel oil at the Grand
Tower Power Station. This tank was removed in 1986.
Other Environmental Issues
The amounts of ammonia, chlorine and other regulated materials stored at the
Grand Tower Power Station are less than the threshold amounts listed in the
United States Environmental Protection Agency's RMP regulations. Therefore, a
RMP plan is not required for this station.
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4 Gas-fired stations
The Gas-fired Stations that have been or will be transferred to Genco include
the following:
. Gibson City Power Station
. Pinckneyville Power Station
. Joppa Power Station
. Grand Tower Power Station (repowered)
. Kinmundy Power Station
These assets are all fossil fuel fired facilities (natural gas), and have a
combined electric generating capacity of approximately 1306 MW (net). Key
characteristics are summarized in Table 4-1.
Table 4-1. Summary of Asset Characteristics: Gas-fired Stations
===================================================================================================================
Total
Station Type Commercial Fuel Project Cost Capacity (MW)
Operation Date ($/kW) Summer (net)
- -------------------------------------------------------------------------------------------------------------------
Operating CT Units
- ------------------
- -------------------------------------------------------------------------------------------------------------------
Gibson City Power Station
- -------------------------------------------------------------------------------------------------------------------
Units 1 and 2 CT achieved Gas or oil $423/kW 230
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Pinckneyville Power Station
- -------------------------------------------------------------------------------------------------------------------
Units 1, 2, 3, 4 CT achieved Natural gas $593/kW 168
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Joppa Power Station
- -------------------------------------------------------------------------------------------------------------------
Units 1, 2, 3 CT achieved Natural gas $417/kW 186
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Committed Units
- ---------------
- -------------------------------------------------------------------------------------------------------------------
Grand Tower Power Station (repower)
- -------------------------------------------------------------------------------------------------------------------
Units 1/3, 2/4 Combined cycle 06-07/01 Natural gas $358/kW 492
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Kinmundy Power Station
- -------------------------------------------------------------------------------------------------------------------
Units 1 and 2 CT 06/01 Gas or oil $418/kW 230
- -------------------------------------------------------------------------------------------------------------------
This section summarizes S&W Consultants' findings with respect to design and
construction, performance, O&M, and environmental aspects of these assets.
4.1 Design and Construction
4.1.1 Operating CT Units
The Operating CT Units include those at Gibson City, Pinckneyville and Joppa.
4.1.1.1 Gibson City Power Station
- ----------------------------------
The Gibson City station, a nominal 230 MW simple cycle plant, is located within
the Jordan Industrial Park in Gibson City, Illinois. The project is now in
commercial operation, and ownership of the station
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has been transferred to Genco. The site consists of a 20-acre parcel purchased
from the city. The site is accessible from Jordan Drive of Illinois on Route 9,
west of Route 47. Railway access is through Illinois Central Gulf and
Northwestern railways.
The elevation of the graded site is 752 ft above sea level. The ambient
conditions for guarantee are 95(degrees)F dry bulb temperature and 75(degrees)F
wet bulb temperature. The range of design ambient is -5(degrees)F to
105(degrees)F. The facilities are being designed to Group III hazard exposure
criteria, with accelerations appropriate for Ford County, Illinois, in
accordance with the 1996 BOCA National Building Code.
The plant consists of two dual fuel SWPC W501D5A CTs operating in simple cycle.
Each CT is rated at approximately 114 MW gross output at 59(degrees)F. The CTs
are equipped with dry low-NO\\x\\ burners for NO\\x\\ control while firing gas
and will utilize water injection for NO\\x\\ control while firing oil. The
turbines will also be equipped with "wet compression," a relatively new product
available for W501D5A machines. Wet compression can augment power output during
warm and hot weather and may allow the machines to produce an estimated 117 MW
at time of peak. Additional major equipment includes two fuel oil storage tanks,
one demineralized water storage tank, electric switchyard, service building,
municipal water supply system, and associated balance of plant equipment and
systems. Make-up and potable water is supplied from the local municipal water
authority. Sanitary and storm sewer services is provided by the local municipal
services.
Station perimeter fence and switchyard perimeter fence are provided. Natural gas
metering is located at a remote location approximately six miles from the plant.
Pressure regulation and gas heating is located on the plant site.
Design Review
Combustion Turbine Generators
The January 1999 executed contract with SWPC for the supply of two 501D5A CTGs
is complete and typical in its scope of supply, division of responsibility, and
supply and service specifications. In addition to supplying the CTGs, SWPC was
also to provide technical field assistance for the installation, start-up,
check-up, and thermal performance testing of the CTs. This is a typical
arrangement.
The applicable design standards and codes encompass all major US codes such as
ANSI, ASME, ASTM, AWS, and BOCA. This is adequate and typical practice.
The primary fuel for the CTs is natural gas. Back-up fuel is No. 1 fuel oil. The
CTs require water injection for NO\\x\\ control when operated on fuel oil. The
CTs are designed to run intermittently for peaking power generation involving
daily starts and stops to meet peaking generation demand with minimal downtime
for inspections and maintenance. Water wash systems for the CT compressors was
to have been provided.
The Design Manual says each unit is intended to operate 1,400 hours annually and
is expected to have 100 annual starts. We believe there should be plenty of
built-in life to support the projected peaking service.
SWPC warrants the 501D5A CTs will be free from defects in design, workmanship
and material and will be Y2K compliant for two years after the date of
Provisional Acceptance or thirty months after the Actual Delivery Date or after
8,000 Total Equivalent Operating Hours, whichever first occurs. The warranty
period is reasonable and typical.
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Further, any spare parts supplied under the contract with SWPC will also have a
warranty identical to that of the CTs. Additionally, any repaired, replaced or
modified item under warranty will be further warranted for a period of 720
consecutive days from the date of completion of the original remedy or 90
consecutive days after the expiration of the original warranty period, whichever
is earlier. These are positive aspects.
Interconnections
All natural gas, fuel oil, and raw water piping systems are designed with
capacity to support the operation of two generating units operating at peak
rating for the station. Site noise design considered two CT units in
simultaneous operation. Fuel oil and demineralized water storage design was to
support the operation of two CT units. Since we understand there are no plans
for future expansion, the design should be acceptable.
Natural gas is supplied by pipeline of Natural Gas Pipeline Company of America
("NGPL") and fuel oil is to be provided by Champaign-Bloomington area terminals
(or others). The NGPL pressure regulator station was sized for two CT units
operating at peak load. This is adequate for the present design. The fuel oil
must comply with SWPC Liquid Fuel Specification 21T4424 to ensure it is suitable
for CT fuel oil operations. We assume that SWPC confirmed the acceptance of the
fuel oil specification, however, such confirmation was not provided to S&W
Consultants.
The existing city water supply is the source of plant process and domestic water
needs. Therefore, no raw water pumps or raw water storage tanks are required.
Ameren has confirmed to us that the capacity of the water supply to the plant
agreed with the City is based on the simultaneous demand of raw water to the CT
evaporative coolers, make-up to the mobile demineralizer and on-site domestic
demands. This is adequate.
The Design Manual indicates that mobile demineralizer equipment is used as the
water treatment system to condition raw water for CT water injection. The site
demineralized water storage tank was sized for five days of plant consumption
for two CTs operating at peak load at 4.3(degrees)F. Ameren has confirmed that
the maximum water consumption will occur at 4.3 (degrees)F when burning fuel
oil. The design basis is acceptable.
Auxiliary Power Supply
The auxiliary power supply system receives power from the switchyard via the
station transformer and steps it down to 4,160 volts for distribution to all of
the systems requiring AC electrical power for their operation. The design also
includes provisions for connecting to offsite backup power source through
automatic transfer of sources. Backup power is provided by Ameren to the Gibson
City site. The backup power source is connected to the plant auxiliary power
bus. This arrangement should be adequate.
Plant Controls
A central PLC-type digital control system is provided for balance of plant and
switchyard operation. Digital combustion turbine control is as provided by SWPC.
The primary turbine control communications for operation and diagnostics is
through the Supervisory Communication And Data Acquisition ("SCADA") interface
located in the service building and the local panel located in the CT electrical
enclosure. This is a typical arrangement. Remote operation capability is
provided to the Ameren dispatching office located in St. Louis.
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Fire Protection System
Fire water is to be supplied by the Gibson City municipal water system.
Therefore, the plant does not need fire water pumps. The fire protection system
design provides for fire water throughout the plant site as required by the fire
codes. In addition, a fire detection system will monitor and alarm upon
detection of smoke or fire. The detection system includes FM200 extinguishers
for the CT equipment, smoke detectors, alarms, controls and wiring, and alarm
panels. The design is typical for a simple cycle power plant.
Fuel Oil System
If the plant encounters natural gas curtailment, the CTs can operate on fuel
oil. The fuel oil system includes fuel oil unloading, storage, and distribution
to the CTs. One unloading pump, two full capacity forwarding pumps, and two
storage tanks are provided. The pumping capability is based on the peak demand
of two CTs. This is adequate design. Each of the two storage tanks is designed
for 700,000 gallons and is based on a five-day natural gas supply curtailment.
This should be adequate assuming the gas contract will address the mitigation of
gas curtailment.
Subsurface Investigation
According to the Design Manual, Ameren contracted Hanson Engineering to perform
the site subsurface investigation work. The contractor was required to provide
sufficient data to describe the soil characteristics to facilitate the design of
foundations and footings for plant facilities and to determine the criteria for
earthwork design and specification. The contractor was required to provide a
report of findings to summarize boring logs, test data, geotechnical evaluation
and design recommendations. This is a prudent approach for plant design,
however, we were not asked to review the contractor's report.
Project Costs
Ameren reported the total project cost to be $99.0 million. This is equivalent
to $423/kW installed based on gross capacity. The cost appears attractive for a
simple cycle peaking plant. The total capital cost reflected in the Financial
Model is $98.7 million. However, S&W Consultants understands that any project
costs in excess of those reflected in the Financial Model will be funded by 100%
equity.
Construction Status
Construction of the Gibson City project was reportedly begun on August 2, 1999,
and was well along in during our site visit on February 15, 2000. We observed
good progress on the foundations, the tanks, the buildings, and the transmission
line. The first CT was delivered to the site during the visit. Construction was
completed on schedule and both units are now in commercial operation.
4.1.1.2 Pinckneyville Power Station
- ------------------------------------
The Pinckneyville station, a nominal 168 MW grassroots simple cycle plant, is
located approximately three miles northeast of Pinckneyville, Illinois on White
Walnut Road. The site consists of approximately 70 acres. The site is accessible
from White Walnut Road and Illinois Highway 154 east of Pinckneyville. Site
elevation is approximately 450 ft above the sea level.
The project is now in commercial operation, and ownership of the station has
been transferred to Genco. The station is operating as a peaking plant, and
includes four GE LM6000PC CTGs which were packaged by S&S Energy Products, a GE
Power System business. The CTs are fired on natural gas fuel.
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Design Review
Combustion Turbine Generators
S&W Consultants reviewed the Contract Agreement between GE Packaged Power, Inc.
and Illinois Material Supply Co. for the provision of four LM6000 CTGs. The
scope of supply included some major balance of plant equipment, CT start-up
spares and training, and appeared to be complete. The applicable design
standards and codes encompassed all major US codes such as ANSI, ASME, ASTM,
AWS, and BOCA. This is acceptable and typical practice.
The design basis allowed for intermittent peaking service with daily start and
stop, i.e., 100 starts per annum and 2,000 to 3,000 hours annual operation. We
believe there should be plenty of built-in life to support the projected peaking
service.
The combustor requires a fuel gas supply of 675 psig +/-20 psig. The Design
Manual says the pipeline pressure ranges from 500-800 psig. Since the LM6000
unit typically requires high gas pressure, the adequacy of gas supply pressure
should be assured. We understand from Ameren that the plant will have gas
compressors for use when the pipeline pressure drops below required pressure.
GE warrants the CTs to be free from defects in material and workmanship. The
warranty period is one year following the initial synchronization or eighteen
months following the delivery date, whichever period shall first expire. This is
market practice for LM6000 CTGs.
Fuel Gas Supply
The plant is adjacent to two 30-inch natural gas pipelines. KN Energy is
installing a new gas metering station for the current plant design. This
metering station will be operated by KN Energy. The gas pipeline tie-ins are
based on the combined design fuel consumption of the four LM6000 and three
future 501D5A CTGs. The pipeline is owned by Natural Gas Pipeline Company of
America, the same company as the Gibson City and Kinmundy sites.
Three 50% capacity motor driven natural gas compressors will be installed to
supply fuel to the LM6000 units. This should be adequate.
Auxiliary Cooling Water System
Two 100% capacity cooling towers are to be installed to provide cooling water
for the plant auxiliary cooling water loads. Cooling water pumps are also 100%
each. The cooling system is winterized for year-round operation. This is
adequate design.
Raw Water System
Raw water is stored in two storage tanks with 550,000-gallon capacity each. One
tank is dedicated to raw water service and the other is shared with fire water
tank. The fire water tank is segregated into fire water storage and plant water
storage by internal piping. The raw water tank provides additional raw water
storage. Raw water storage capacity is nominally 50 hours at the design rate of
the plant.
Demineralized Water System
Demineralized water is required by the CT for NO\\x\\ emission control.
Demineralized water is produced by two 100% trailer-mounted ion exchange resin
bed systems. It is stored in the demineralized water tank of 550,000-gallon
capacity that provides 50 hours of demineralized water supply. The storage
capacity should be verified for adequacy to supply the maximum water injection
demand in the coldest weather
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anticipated for operation (e.g., ambient less than 40(Degree)F). Heat balance
simulations can provide the expected results to confirm.
Compressed Air System
The system provides dried control air required by the CTs, natural gas
compressors, and the balance of plant support system. The compressed air system
includes two 100% air compressors (300 scfm each) and associated air dryers
(-40(Degree)F dew point). This should be acceptable.
Fire Protection System
Hydrants and fire monitors connected to an underground fire water piping loop
protect the plant. Two 100% capacity motor driven main fire water pumps, a
pressure maintenance jockey pump, and a two-hour fire water supply are provided
in accordance with NFPA 850. One main pump operates on electricity generated by
the plant. The other main pump operated on electricity from an independent
source supplied to the facility. This is acceptable.
Instrument and Control System
The plant control systems and instrumentation are based on remote unattended
operation. A PLC and operator interface control balance of plant equipment and
interface with the CT controls. The primary CT control communications for
operation and diagnostics is through the SCADA interface located in the service
building and the local panel located in the CT electrical enclosure. This is
typical for a simple cycle plant.
Project Costs
Ameren's project cost estimate is $99.7 million, or $593/kW installed, at summer
rating.
Construction Status
According to the January 17, 2000 project schedule, construction mobilization
took place on 11/16/1999. S&W Consultants visited the site on February 16, 2000,
and the project was well under construction. Construction was completed on
schedule and all four units are now in commercial operation.
4.1.1.3 Joppa Power Station
- ----------------------------
The Joppa Power Station is a nominal 186 MW station comprising three recently
refurbished (spring 2000) GE Frame 7B CTG sets. The project is now in commercial
operation, and ownership has been transferred to Genco.
These three CTs had been in operation since 1974 at another location, and were
refurbished and relocated to the Joppa, Illinois site. S&W Consultants conducted
a review of the available documentation to determine the reasonableness of the
scope of the refurbishment and projected utilization of the units. A site visit
was not conducted as part of this review. S&W Consultants was not asked to
prepare an environmental site assessment report for this project.
Documentation provided to S&W Consultants included the terms and scope of
refurbishment work for the three GE Frame 7B CTG sets relocated to Joppa by
Midwest Electric Power, Inc. ("Midwest"), which acted as agent for Ameren. These
documents include the initial agreement between Midwest and PRECO Turbine &
Compressor Services ("PRECO") for the decommissioning, relocation, repair,
refurbishment, installation, start-up, and testing of the three CTG sets and
auxiliary equipment ("Refurbishment Agreement"). In addition, a brief analysis
by the consultant, LJB Associates, summarizing the historical operating and
maintenance records of the three units was reviewed. S&W Consultants has been
informed that the Refurbishment Agreement has subsequently been updated. The
most notable changes involve the
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conversion of the Refurbishment Agreement into a fixed price contract and the
removal of liquidated damages associated with the 195 MW performance guarantee
of the plant. S&W Consultants considers the objectives set forth in the above
documents to be achievable and consistent with industry practices for the
upgrading of this equipment.
Genco has entered into a lease agreement with Development wherein the CTs will
be leased to Development for a minimum of 15 years. Lease revenues are reflected
in the Financial Model. Genco has no performance, fuel supply or other
interconnection obligations under the lease agreement with Development.
Combustion Turbine Generator Design
Each CTG set utilizes a General Electric model MS7001B CT. The nameplate
capacity of the CTs is 53,833 kW each, or 161,499 kW total plant output. These
CTs are early vintage, large frame, industrial-type machines each with an axial
flow, multi-stage compressor and power recovery turbine mounted on a common
shaft. Generally, the frame 7B machines were manufactured during the time period
from 1971 through 1978 with nominal ISO outputs between 52 and 60 MW.
Significant advances in technology have occurred since the manufacture of these
units. These improvements have been incorporated into subsequent models to
achieve increased performance, useful life, and reliability. Many of these
technological improvements can also be applied as field unit upgrades to the 7B
machine, providing enhanced performance and reliability similar to that seen on
the later models.
Refurbishment and Upgrade
The refurbishment agreement establishes an upgraded plant output warrantee of
195,000 kW (gross) at ISO conditions, an approximate 20% increase. In addition,
the maximum NO\\x\\ emissions from the turbines is to be reduced to 42 parts per
million. The planned performance augmentation is to be accomplished by the
following:
. Increase the CT firing temperature to 1965(degrees)F;
. Increase the inlet airflow by upgrading the variable inlet guide vanes;
. Add an inlet fog cooling system; and
. Convert the combustion system from fuel oil to natural gas.
S&W Consultants notes that General Electric provides a "B-to-E" upgrade of the
MS7001B turbines which can increase the output of the machine by as much as
14.7% with a 2.7% thermal efficiency improvement. GE accomplishes this by
installing MS7001EA nozzles and buckets in the 7B machine to achieve the same
firing temperatures as proposed in the PRECO upgrade. In addition, GE installs
new reduced camber inlet-guide vanes similar to the PRECO upgrade. Based upon
the documented GE performance increases due to higher firing temperatures and
enhanced inlet air flows, S&W Consultants believes a 20% performance increase is
a reasonable objective considering that additional increases will be realized
with the inlet fog cooling system and the conversion to natural gas.
The reduction of NO\\x\\ emissions is accomplished by the addition of water
injection to the combustion system and the conversion to natural gas. Diluent
injection (usually with water or steam) into the combustor flame zone is an
accepted and proven method of reducing NO\\x\\ emissions. For the 7B machines,
S&W Consultants believes the maximum NO\\x\\ emissions of 42 parts per million
is achievable with water injection while firing natural gas. However, this level
of NOx emissions is probably approaching the best that can be achieved with this
machine. Usually, there is a small heat rate penalty associated with water
injection. However, output typically increases by approximately 3%, making water
injection particularly attractive in some applications such as peaking service.
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In addition, PRECO's scope included an overhaul of each of the three generators
and upgrade of the CTG control system. Planned refurbishment work was also to be
conducted on the switchgear, excitation & control cabinets, electrical support
building, RO system, fire detection/suppression system, and the demineralized
water system. These system upgrades should help to ensure performance and
reliability.
Operations Overview
According to the historical operating and maintenance information reviewed by
S&W Consultants, the CTs in question have been operated in simple cycle, peaking
service and have very low fired hours for units of this age. All of the units
have approximately 4000 fired hours at the time of the consultants' report in
June 1999. None of the three CTs have received a hot gas path or major overhaul
inspection. These units have a large number of starts relative to fired hours,
typical for units in peaking service, and combustion inspections have been
performed. The combustion inspections of all three units noted component
distress to all 1/st/ stage buckets and all 1/st/ stage nozzle assemblies. The
1/st/ stage buckets were found with bucket tip damage, and some of the buckets
had leading edge cooling air hole failures beyond the recommended limits
established by the OEM. Cracks have also been noted to all 1/st/ stage nozzle
assemblies. However, the major overhauls to have been performed by PRECO
addressed all of these issues. Provided PRECO exercised diligence in
workmanship, provided reliable replacement parts, and followed OEM recommended
practices, S&W Consultants believes the CTs should be capable of meeting
performance objectives. Furthermore, based upon the turbines being returned to
service in good condition, if the turbines are operated and maintained according
to OEM recommendations, S&W Consultants believes the units can remain in peaking
service for the anticipated term of the Financial Model.
The agreement establishes acceptance tests to be carried out to determine that
the plant is operational, i.e., each CTG has achieved a minimum output of 62 MW
(at ISO conditions) for 100 continuous running hours per the test procedures
described. The acceptance test establishes minimum output criteria for the plant
of 186 MW. This should easily be achieved considering the magnitude of the
proposed upgrade.
In addition, a warranted performance (as determined by the performance testing
requirements provided) for total plant output is established at 195 MW. S&W
Consultants believes the warranted performance can be achieved considering the
extent of the upgrade, and Ameren has represented that an incentive provision
(i.e., retention) is included in the revised agreement.
The lease agreement does not stipulate any operational performance guarantees
with regard to capacity, availability, or heat rate. Fuel and other
interconnections are the responsibility of the lessee.
Project cost was estimated to be $77.6 million or $417/kW.
4.1.2 Committed Units
4.1.2.1 Grand Tower Power Station (repowered)
- ----------------------------------------------
The Grand Tower station, a 492 MW (net) repowered combined cycle plant, is
located in southern Illinois on the Mississippi River, approximately 90 miles
southwest of Carbondale, Illinois. The plant is directly located about 2 miles
west of Illinois Route #3.
The elevation of the site is 363 ft above sea level. The plant is located on the
Illinois shore of the Mississippi River and has a levee protecting the plant
from flooding of the river. Ameren's construction manager at the site indicated
the plant did not flood during the 1993 flood. Nevertheless, the site
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construction manager represented that Ameren intends to increase the height of
the levee to that of the Corps of Engineers levee that is next to the plant.
The ambient conditions upon which the performance guarantees are based are
59(degrees)F dry bulb temperature and 60% relative humidity. The range of design
ambient is -5(degrees)F to 105(degrees)F. The site is on seismic zone of
Category III, ASCE 7-95.
The existing Grand Tower station consists of two coal fired units: Unit 3 (85 MW
net) and Unit 4 (105 MW net). The repowered project configuration includes two
Siemens Westinghouse 501FD CTGs, rated at a nominal 163 MW each in summer peak
conditions (176 MW at 59(degrees)F), to repower the existing steam turbines for
combined cycle operation. In the repowered arrangement, the existing coal fired
boilers will be retired. New HRSGs with duct firing capability will be installed
directly downstream of each CT to produce steam from the hot CT exhaust gases.
The steam will be used to power the existing steam turbines for power
production. After the repowering project is completed, the two CT units will be
named Unit 1 and Unit 2. Nomenclature for the two combined cycle systems will be
Unit 1/3 and Unit 2/4.
The CTs will burn only natural gas. Natural gas will be supplied to the plant by
Natural Gas Pipeline Company of America. The CTs will be furnished with on-line
or off-line water wash system for the compressors. Upon completion of the
project, nominal gross plant output is expected to be about 526 MW. The project
is being managed by Ameren Services, a subsidiary of Ameren Corporation.
Design Review
Combustion Turbine Generators
The September 1999 executed contract between Ameren Intermediate Holding Co.,
Inc. (now Ameren Energy Resources Company) and SWPC for the supply of two 501FD
CTs is complete and typical in its scope of supply, division of responsibility,
and supply and service specifications. In addition to supplying the CTs, SWPC
will also provide technical field assistance for the installation, start-up,
check-out, and thermal performance tests of the CTs. This is a typical
arrangement.
S&W Consultants views the SWPC 501FD technology as a refinement on the W501F
technology, which has been in operation since 1993, and is typical of normal
design improvements by manufacturers. The W501FD incorporates advances in low
NO\\x\\ combustion technology, compressor and blade designs, and cooling
technology. Recently, SWPC has identified operational issues affecting all units
in the F fleet and issued technical advisories to ensure that until the present
problems are solved, they do not cause damage to operating units.
Although the entire 501F fleet is impacted by these operational issues, the area
that most affects the Grand Tower units is potential cracking of the row 2
turbine blade. SWPC has issued a technical advisory on this matter and plans, as
a corrective measure, to add a circular notch in the trailing edge of the blade
in the platform area. SWPC computer analyses indicate that this would increase
blade life. The effectiveness of the planned corrective measure will ultimately
be determined by actual operation. However, S&W Consultants believes that a
similar modification resolved a similar problem that had previously affected the
501F row four turbine blade. SWPC expects that the entire fleet should have the
new row 2 blade by the end of February, 2001, prior to the scheduled start-up of
the Grand Tower units.
S&W Consultants believes that the recent problems with the 501F are not unusual.
All of the manufacturers of large, advanced combustion turbines encounter
problems. The responsiveness of SWPC to problems has been good. They have
encountered and resolved similar problems in the past, and are
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already working with Ameren to correct these problems either during
manufacturing or in the field after delivery. This approach is reasonable.
According to Division 17 of the specification to the Equipment Supply contract
with SWPC, the CTs are designed for an annual capacity factor of approximately
60%. The currently available Design Manual, however, says each unit is intended
to operate only 1,400 hours annually, a discrepancy we assume will be corrected
during detailed design. At the capacity factors currently projected, built-in
life should be more than adequate to support the intended intermediate service.
SWPC warrants the CTs will be free from defects in design, workmanship and
material and will be Y2K compliant for two years after the date of Provisional
Acceptance or thirty months after the Actual Delivery Date or after 8,000 Total
Equivalent Operating Hours, whichever first occurs. The warranty period is
reasonable and typical.
Further, any spare parts supplied under the contract with SWPC will also have a
warranty identical to that of the CTs. Additionally, any repaired, replaced or
modified item under the warranty period will be further warranted for a period
of 720 consecutive days from the date of completion of the original remedy or 90
consecutive days after the expiration of the original warranty period, whichever
is earlier. These are positive aspects.
Plant Power Output
The entire repowered plant is designed to comply with all U.S. EPA requirements
for long term operation. Plant life is expected to be at least 20 years. The
plant outputs are tabulated below:
---------------------------------------------------------------------------------
Capacity in MW (site average, 59(degrees)F) Unit 1/3 Unit 2/4
---------------------------------------------------------------------------------
Base load, gross output (MW) 242.0 257.0
---------------------------------------------------------------------------------
Base load, net output (MW) 238.8 253.0
---------------------------------------------------------------------------------
Maximum gross output, fired HRSG (MW) 268.0 288.7
---------------------------------------------------------------------------------
Maximum net output, fired HRSG (MW) 262.3 283.0
---------------------------------------------------------------------------------
Based on review of the preliminary heat balance data furnished on March 10,
2000, we found these expected capacities are slightly overstated due to steam
turbine generator efficiency, auxiliary load, condenser pressure and stack gas
temperature assumptions. However, considering the upside potential of the
available duct firing, the above base load outputs are reasonable input
assumptions for the Financial Model.
We note that by-pass dampers are not provided downstream of the CTs. Therefore,
the plant may not be able to operate in simple cycle when only the CT is
running. Although a high-pressure steam by-pass line is provided, it is only
designed for 25% of the normal flow. If the main condenser becomes unavailable,
the entire unit must be shut down. Ameren has confirmed that the steam bypass is
intended for unit start-up purposes only.
Water Quality
Based on the data currently available, we cannot determine whether the water
quality indicated in section 4-1.I of the Design Manual is acceptable for use in
the SWPC CT evaporative coolers (SWPC Equipment Supply contract Section 01010D).
Ameren should confirm the water quality with SWPC during the detail design
phase.
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Condensate Preheater
The existing Unit 4 feed water heaters will be removed from service as a result
of the repowering. Condensate from the hotwell is pumped to the HRSG condensate
preheater. At the preheater inlet, condensate returned from the fuel gas heater
(200(degrees)F-270(degrees)F) will mix with the incoming condensate. A concern
is the likelihood of corrosion on the condensate preheater due to low
temperature at its rear tube bank. Heat balance runs should be conducted
simulating a variety of condensate flows to verify and confirm, with the HRSG
vendor, whether cold end corrosion would occur.
Circulating Water System
We understand that the existing circulating water system is unchanged for the
repowering project. Since the old boilers are to be retired and new HRSGs with
duct firing capability will be installed, it would be appropriate to check the
condenser heat load under maximum steam inlet or dumping condition against
available cooling capacity. Ameren reports that Burns & McDonnell is reviewing
condenser concerns.
Natural Gas Fuel
Pipeline natural gas will be supplied to the CTs and HRSG duct burners. The
maximum fuel flow is designed for full load of the CTs at the site minimum
ambient temperature of 0(degrees)F and full duct firing. This is adequate.
SWPC requires the fuel gas pressure supplied at the unit should be 425 psig to
475 psig. This requirement should be readily met as the Design Manual indicates
the pressure reduction device to be used to lower the pipeline pressure of 600
psig to 900 psig to that suitable for the CTs. Naturally, no fuel gas compressor
will be needed.
Fire Protection System
The existing fire protection system will remain unchanged regarding the fire
water supply. The existing yard fire water loop will be expanded to encompass
the additional equipment provided on the project. Fire protection lines will be
provided to new buildings to be added to the site as required. Additional yard
fire hydrants will be added to accommodate the expanded fire protection loop.
This is acceptable practice. One concern is on the equipment level, namely the
fire water pumps. It would be appropriate to check the adequacy (capacity and
head) of the existing fire pumps for service in the repowered plant. This is
because the repower project may have revised the hydraulic requirements of the
fire pumps. It was reported that fire protection systems are currently under
review by Ameren and Burns & McDonnell.
Feed Water System
Unit 1 feed water system will have three main feed water pumps, assuming all are
existing. According to the Design Manual, all three pumps will be required to
run when the HRSG is at full firing condition. This means that at maximum plant
output, there is no spare capacity of the feed water pumps. Capacities of Unit 2
feed water pumps are currently unknown to us. It would be appropriate to review
the feed water pump capability and evaluate the system margin during detailed
design.
Compressed Air System
The instrument air system will be an expansion of the existing instrument air
system to provide air to control valves and equipment installed in the
repowering. An additional air dryer and air receiver will be installed as
required to support new and existing equipment. This philosophy should be
adequate.
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Control System
The plant will have a DCS and instrumentation will be designed to provide safe,
reliable, and efficient operation of the units. The DCS system includes a TXP
sub-system, which will be provided by SWPC for CTs and a BOP DCS sub-system,
which controls and monitors HRSGs, steam turbines and the balance of plant.
Local control units will be furnished and linked to the BOP DCS. This is a
typical design for combined cycle plant.
The existing controls will be upgraded and new controls will be consolidated
into one control room. An emergency shutdown panel will be located in the new
control room in the new control building instead of the existing control room.
All control permissives and trips will be hardwired to the central control DCS
system, and all local/remote situations will be indicated at the DCS. The
upgraded control system will enable the majority of the operator interfaces to
take place in the new control room. We believe this should provide safe and
effective man-machine interfaces ("MMI") for the repowered plant.
Project Costs
Total installed cost for the repowering project is estimated at $176.2 million.
This translates to a specific cost of $358/kW installed based on base load
capacity. This should be within the reasonable range assuming that this price
includes the necessary refurbishment work on the existing equipment and systems,
in addition to the installation of new CTs and HRSGs. The total capital cost
reflected in the Financial Model is $170 million. However, S&W Consultants
understands that any project costs in excess of those reflected in the Financial
Model will be funded by 100% equity.
The contingency of the project cost is estimated at $1.0 million. This is
equivalent to only 0.6% of the EPC cost and is low, even considering the
advanced stage of construction. Assuming adequately scoped supply and
construction contracts, we would anticipate a contingency of approximately 3% of
EPC cost to be adequate. The cost risk lies with the commissioning of the plant,
which involves some very old equipment, and in addition, the construction
contractor does not have any liability of performance and guarantees related to
equipment and materials supplied by Ameren. The project will be transferred to
Genco upon completion.
Construction Status
During our site visit on February 17, 2000, we found the site mobilized to begin
construction, with some earthwork being performed for site preparation. We
understand from Ameren that the air permit was received on February 25, 2000,
and pile driving/foundation construction began March 1/st/. On our second visit
on September 25, 2000, we found the foundations in place and erection of the
HRSGs well underway. Commercial operation dates of the repowered Units 1/3 and
2/4 are expected to be June, 2001 and July, 2001, respectively.
We understand that the equipment purchase contract was fully executed on
September 30, 1999. According to the project schedule dated August 16, 2000, the
early finish dates of the delivery of the two CTs are December 28, 2000 and
January 26, 2001 respectively. It may be a challenge to complete commissioning
and achieve commercial operation 6 or 7 months after the 501FD CTs are
delivered, considering the complexity inherent in repowered projects. However,
we believe that the CODs are achievable. As of our most recent visit, the
project is still on track to achieve the scheduled commercial operations dates.
4.1.2.2 Kinmundy Power Station
- -------------------------------
The Kinmundy Power Station, a nominal 230 MW simple cycle plant, will be located
approximately three miles east of Patoka on Kinoka Road. The site consists of a
60-acre parcel. The site is accessible from Kinoka Road and US highway 51.
Railway access is through Patoka via Illinois Central Gulf railway.
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The elevation of the site is 542 ft above sea level. The ambient conditions for
guarantee are 95(degrees)F dry bulb temperature and 75(degrees)F wet bulb
temperature. The range of design ambient is -18(degrees)F to 105(degrees)F. The
facilities are being designed to Group III hazard exposure criteria, with
accelerations appropriate for Ford County, Illinois, in accordance with the 1996
BOCA National Building Code.
The plant will consist of two SWPC W501D5A CTs operating on simple cycle. The
CTs will be equipped with dual fuel combustors and will have water injection for
NO\\x\\ control (oil firing). Additional major equipment includes two fuel oil
storage tanks, one demineralized water storage tank, one raw water storage tank,
electric switchyard, service building, municipal water supply system, and
associated balance of plant equipment and systems. Make-up and potable water
will be supplied from the local municipal water authority. Sanitary and storm
sewer services are not available. Therefore, sanitary drains will be discharged
into a storage tank. The storage tank contents will require periodic removal for
disposal off site. Storm runoff will be discharged into the existing township
drainage system.
Station perimeter fence and switchyard perimeter fence will be provided
(perimeter fencing is currently in place). Natural gas metering and pressure
regulation will be located within the fenced area. Space will be allocated on
the Kinmundy site for future expansion of a third CT.
Design Review
Combustion Turbine Generators
The January 1999 executed contract with SWPC for the supply of two 501D5A CTs is
complete and typical in its scope of supply, division of responsibility, and
supply and service specifications. In addition to supplying the CTs, SWPC will
also provide technical field assistance for the installation, start-up,
check-up, and thermal performance testing of the CTs. This is a typical
arrangement.
The applicable design standards and codes encompass all major US codes such as
ANSI, ASME, ASTM, AWS, and BOCA. This is acceptable and typical practice.
The primary fuel for the CTs will be natural gas. Back-up fuel will be No. 1
fuel oil. The CTs will require water injection for NO\\x\\ control when operated
on fuel oil. The CTs are designed to run intermittently for peaking power
generation involving multiple daily starts and stops to meet peaking generation
demand with minimal downtime for inspections and maintenance. On-line or off-
line water wash for CT compressors is to be provided.
The Design Manual says each unit is intended to operate 1,400 hours annually and
is expected to have 100 annual starts. We believe there should be plenty of
built-in life to support the projected peaking service.
SWPC warrants the 501D5A CTs will be free from defects in design, workmanship
and material and will be Y2K compliant for two years after the date of
Provisional Acceptance or thirty months after the Actual Delivery Date or after
8,000 Total Equivalent Operating Hours, whichever first occurs. The warranty
period is reasonable and typical.
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Further, any spare parts supplied under the contract with SWPC will also have a
warranty identical to that of the CTs. Additionally, any repaired, replaced or
modified item under warranty will be further warranted for a period of 720
consecutive days from the date of completion of the original remedy or 90
consecutive days after the expiration of the original warranty period, whichever
is earlier. These are positive aspects.
Interconnections
All natural gas, fuel oil, and raw water piping systems will be designed with
capacity to support the operation of three generating units operating at peak
-----
rating for the station. This is because future plan allows the addition of the
third CT to the station. Current site noise design will consider two CT units in
simultaneous operation. Fuel oil and demineralized water storage tanks are
presently designed to support the operation of two CT units.
Natural gas will be supplied by pipeline of NGPL and fuel oil will be provided
by St. Louis or central Illinois area terminals. The NGPL pressure regulator
station will be sized for two CT units operating at peak load with provisions
for future addition of a third identical CT unit. This is adequate. The fuel oil
information must comply with SWPC Liquid Fuel Specification 21T4424 to ensure it
is suitable for CT fuel oil operations. Again, SWPC should confirm the
acceptance of the liquid fuel from the terminals.
Raw water will be supplied to the plant by two 50% raw water pumps. Two raw
water storage tanks will be provided. We understand from Ameren that the design
criteria of the total raw water storage capacity is based on the simultaneous
demand of raw water to the two CT evaporative coolers, make-up to the mobile
demineralizer and on-site domestic demands. This is typical and should be
adequate.
The Design Manual indicates that mobile demineralizer equipment will be used for
water treatment to condition raw water for CT water injection. The site
demineralized water storage tank will be sized for five days of plant
consumption for two CTs operating at peak load at 4.3(Degree)F. Ameren has
confirmed that the max water consumption will occur at 4.3 (Degree)F when
burning fuel oil. The design basis is acceptable.
Ameren informs us that Burns & McDonnell has the analysis of water quality.
Water will be purchased from the local distribution company, FMC Water Company.
The water quality information should be used by the contractors for their design
of water treatment system and CT water injection and washing systems.
Auxiliary Power Supply
The auxiliary power supply system receives power from the switchyard via the
station transformer and steps it down to 4,160 volts for distribution to all of
the systems requiring AC electrical power for their operation. Design will also
include provisions for connecting to offsite backup power source through
automatic transfer of sources. Backup power will be from Tri-County Electric
Cooperative for the Kinmundy site. The backup power source will be connected to
the plant auxiliary power bus. This arrangement should be adequate.
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Plant Controls
A central digital control system of PLC type will be provided for the CTs,
balance of plant, and switchyard operation. The primary turbine control
communications for operation and diagnostics will be through the SCADA interface
located in the service building and the local panel located in the CT electrical
enclosure. Remote operation capability will be provided to the Ameren
dispatching office located in St. Louis.
Fire Protection System
The fire protection system will be designed in accordance with all applicable
fire protection codes. Fire water will be supplied from the on site fire water
storage tank. One main fire pump (electric driven) and a second main pump
(diesel driven) plus a jockey pump are provided. The fire protection system will
provide fire water for extinguishing fires throughout the plant site as required
by the fire codes. In addition, a fire detection system will monitor and alarm
upon detection of smoke or fire. The detection system includes FM200 for the CT
equipment, smoke detectors, alarms, controls and wiring, and alarm panels. The
detectors will be located in the service building, which includes electrical
equipment room and SCADA/control room, fuel oil pump building, fire pump room,
and CT enclosures. The alarm indications will be sent to the SCADA system. This
is a typical in plant design for simple cycle power plant. Revision 1 of the
P&ID 9482-X-146074 indicates an existing 6-inch buried water supply pipe, which
we understand will be connected to FMC Water Company and presumably can serve as
backup fire water supply.
Fuel Oil System
If the plant encounters natural gas curtailment, the CTs can operate on fuel
oil. The fuel oil system includes fuel oil unloading, storage, and distribution
to the CTs. One unloading pump, two full capacity forwarding pumps, and two
storage tanks are provided. The pumping capability is based on the peak demand
of two CTs. This is adequate design. Each of the two storage tanks is designed
for 700,000 gallons and is based on a five-day natural gas supply curtailment.
This should be adequate.
Subsurface Investigation
According to the Design Manual, Ameren has contracted Hanson Engineering to
perform the site subsurface investigation work. The contractor was required to
provide sufficient data to describe the soil characteristics to facilitate the
design of foundations and footings for plant facilities and to determine the
criteria for earthwork design and specification. The contractor was required to
provide a report of findings to summarize boring logs, test data, geotechnical
evaluation and design recommendations. This is a prudent approach for plant
design, however, we were not asked to review the contractor's report.
Project Costs
The budget as of August, 2000 indicates total cost (including sales taxes) of
$56.0 million for the two 501D5A CTGs. It also indicates that the total
installed cost is estimated to be $96.25 million. This is equivalent to $418/kW
installed based on gross capacity. The cost appears competitive for a simple
cycle peaking plant. We believe it is unlikely that the cost to complete this
plant will exceed the current budget forecast. The total capital cost reflected
in the Financial Model is $96 million. However, S&W Consultants understands that
any project costs in excess of those reflected in the Financial Model will be
funded by 100% equity.
Construction Status
Project construction (site preparation) started on September 13, 1999 but was on
hold during the winter. The site is again under construction with the tanks,
building, and foundations well under way. The first CT has been delivered to the
rail siding along with the two step up transformers. The first generator is
expected on December 15, 2000 and the remaining CT and generator will arrive in
early 2001. The
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schedule from August, 2000 indicates that Unit 1 will enter commercial
operations in April 2001 and the second unit will enter commercial operations in
June 2001. The commissioning period is expected to include dual fuel operations
and the satisfaction of the new technology of "wet compression" for power
augmentation.
4.2 Projected Performance
4.2.1 Operating CT Units
4.2.1.1 Gibson City Power Station
- ----------------------------------
SWPC guaranteed the following thermal performance for each of the two 501D5A CTs
supplied to the Gibson City station:
On natural gas:
a. Net output 113,075 kW
b. Net heat rate 10,061 Btu/kWh LHV
On fuel oil:
a. Net output 113,780 kW
b. Net heat rate 10,321 Btu/kWh LHV
Performance testing on natural gas has been completed. Ameren reported the Unit
1 thermal performance test results as follows:
Net Power: 119,673 kW (5.84% better than guarantee)
Net Heat Rate: 9,775 Btu/kWh (2.84% better than guarantee)
Ameren reported the Unit 2 thermal performance test results as follows:
Net Power: 114,467 kW (1.23% better than guarantee)
Net Heat Rate: 9,940 Btu/kWh (1.20% better than guarantee)
Performance testing on fuel oil is planned for November, 2000.
SWPC guaranteed the CT NOx and CO emissions were not to exceed 25 ppmvd @15%
oxygen on natural gas. These guarantees are reasonable and generally achievable
by the 501D5A CTs.
4.2.1.2 Pinckneyville Power Station
- ------------------------------------
GE S&S Energy Products guaranteed the following thermal performance for each of
the four LM6000PC CTs supplied to the Pinckneyville station:
a. Output at generator terminal 44,446 kW
b. Heat rate 8,811 Btu/kWh LHV
Performance testing has been completed. Ameren reported the Unit 1 thermal
performance test results as follows:
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Net Power: 46,809 kW (4.12% better than guarantee)
Net Heat Rate: 8,448 Btu/kWh (5.32% better than guarantee)
Ameren reported the Unit 2 thermal performance test results as follows:
Net Power: 45,559 kW (2.5% better than guarantee)
Net Heat Rate: 8,840 Btu/kWh (-0.33% worse than guarantee), accepted by
Ameren in part because no water wash was
completed on the unit prior to testing, as recommended. This is reasonable.
Ameren reported the Unit 3 thermal performance test results as follows:
Net Power: 46,372 kW (4.33% better than guarantee)
Net Heat Rate: 8,337 Btu/kWh (5.38% better than guarantee)
Ameren reported the Unit 4 thermal performance test results (retest) as follows:
Net Power: 45,559 kW (2.5% better than guarantee)
Net Heat Rate: 8550 Btu/kWh (2.96% better than guarantee)
GE also guaranteed the CT NOx emission not to exceed 25 ppmvd @15% oxygen on
natural gas fuel. This guarantee is reasonable and generally achievable by the
LM6000 CTs.
4.2.1.3 Joppa Power Station
- ----------------------------
Joppa's performance test results from their refurbishment were not available,
but are not relevant since the lease agreement provides firm payments to Genco
regardless of the performance of the units.
4.2.2 Committed Units
4.2.2.1 Grand Tower Power Station
- ----------------------------------
Performance of Combustion Turbine Generator
SWPC guarantees the following thermal performance for each of their supplied CTs
(at ISO conditions):
a. Net output 176,450 kW
b. Net heat rate 9,326 Btu/kWh LHV
c. Exhaust flow 3,506,245 lbm/hr
d. Exhaust temperature 1,097(degrees)F
The guarantee basis is primarily consisted of the following:
1. Steady state continuous full load of the CTs,
2. Natural gas fuel with heating value of 20,379 Btu/lbm (LHV),
3. Evaporative cooler is off,
4. Ambient temperature of 59 (degrees)F.
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The performance guarantee is governed by ASME PTC-22 with test measurement
uncertainties in accordance with ASME PTC-19 using 95% coverage per ASME PTC-1
to demonstrate the thermal performance guarantees.
Likewise, SWPC guarantees the CT NOx and CO emissions not to exceed 25 ppmvd
@15% oxygen. The NOx and CO emissions are to be determined by the U.S. EPA
Method 20 and 10, respectively.
The above CT performance and guarantees appear reasonable. With dry low NOx
combustors on natural gas fuel, we believe these guarantees are generally
achievable for the 501FD CTs.
Performance of Plant
As indicated above the expected output of the plant is shown in the table below
(see comments in Section 4.1.1.1.) There does not appear to be a single
contractor point of responsibility for performance guarantees in terms of net
unit heat rate and net plant output for the repowered combined cycle plant.
However, performance guarantees are provided for major new components (e.g., CTs
and HRSGs).
--------------------------------------------------------------------
Capacity in MW (site average, 59(degrees)F) Unit 1/3 Unit 2/4
--------------------------------------------------------------------
Base load, gross output 242.0 257.0
--------------------------------------------------------------------
Base load, net output 238.8 253.0
--------------------------------------------------------------------
Maximum gross output, fired HRSG 268.0 288.7
--------------------------------------------------------------------
Maximum net output, fired HRSG 262.3 283.0
--------------------------------------------------------------------
The heat balance information furnished appears to be preliminary. Additional
refinement is expected during detailed design. S&W Consultants considers the
capacity and heat rate assumptions used to develop the Financial Model to be
reasonable.
4.2.2.2 Kinmundy Power Station
- -------------------------------
SWPC guarantees the following thermal performance for each of the two 501D5A CTs
supplied to the Kinmundy station:
On natural gas:
a. Net output 113,945 kW
b. Net heat rate 10,056 Btu/kWh LHV
On fuel oil:
a. Net output 114,650 kW
b. Net heat rate 10,320 Btu/kWh LHV
The guarantee basis is primarily consisted of the following:
1. Steady state continuous full load of the CTs,
2. Evaporative cooler is off,
3. Ambient temperature of 59 (degrees)F.
4. Water injection for guarantees based on fuel oil.
The performance guarantee is governed by ASME PTC-22 with test measurement
uncertainties in accordance with ASME PTC-19 using 95% coverage per ASME PTC-1
to demonstrate the thermal performance guarantees.
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Likewise, SWPC guarantees the CT NOx and CO emissions not to exceed 25 ppmvd
@15% oxygen on natural gas fuel. The NOx and CO emissions are to be determined
by the U.S. EPA Method 20 and 10, respectively. On fuel oil with water
injection, the guaranteed values are 42 ppmvd @15% for NOx and 30 ppmvd @15%
oxygen for CO.
The above CT performance and guarantees appear reasonable. We believe these
guarantees are generally achievable for the 501D5A CTs.
4.3 Projected Operation and Maintenance
Operation and maintenance for Gibson City and Pinckneyville (Operating CT Units)
and Kinmundy (Committed Unit) are provided for under a single contract,
described below. Genco will be responsible for operation and maintenance of the
Grand Tower Power Station (Committed Unit). Genco has no O&M responsibility for
the Joppa Power Station in accordance with the lease arrangement.
4.3.1 Gibson City, Pinckneyville and Kinmundy
S&W Consultants reviewed the Operations and Maintenance Agreement between Ameren
Intermediate Holding Co. Inc. (now Ameren Energy Resources Company) and Siemens
Westinghouse Operating Services Company ("Operator") for the Gibson City,
Kinmundy, and Pinckneyville Power Plants. The agreement is dated and effective
as of October, 1999 and will remain in effect until May 31, 2010 unless extended
by the parties or terminated earlier as allowed in the agreement.
4.3.1.1 Operator Scope of Work
- -------------------------------
The Operator will primarily provide personnel to staff each plant with a plant
manager over all three plants. There will be five technicians at Gibson City,
four at Kinmundy, and seven at Pinckneyville. There will be a single plant
manager over all the plants who will have an administrative assistant.
Therefore, there will be a total of eighteen staff. This is sufficient to
perform the duties of the Operator.
The plants will be staffed as peaking facilities. They will be staffed during
the peak period of the year from June 1/st/ to September 30/th/ and December
1/st/ through February 28/th/ during the hours of 7:00 am to 11:00 pm, Monday
through Friday only and during the off-peak period of the year from March 1/st/
through May 31/st/ and October 1/st/ through November 30/th/ during the hours of
8:00 am to 4:30 pm Monday through Friday only. The Operator is responsible for
training the personnel to operate the plant. The agreement anticipates the CTs
will not operate for more than 1,400 hours per year and will not have more than
100 starts per year each. Operation on liquid fuel is anticipated to be no more
than ten percent of the operating hours in any given year.
The Operator will keep the plant clean and arrange for removal of trash from the
plant site. The Operator will perform the work in a safe manner in accordance
with the plant procedures which shall conform with the applicable material
provisions of federal, state and local safety laws. The Operator will allow the
Owner access to the plant at any time to inspect and have access to the plant
provided all visitors shall adhere to the plant safety procedures. The Operator
has the right to subcontract any portion of the work, and is solely responsible
for the engagement and management of subcontractors.
The Operator will provide the office equipment as well as the machinery, tools,
and test equipment required for the Operator's use in performing the plant
operations and maintenance. The Operator will assist the Owner to obtain permits
provided it only requires the assistance of the plant personnel. The Owner may
request non-standard work hours, and the Operator will schedule the operators to
be at the
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plants, provided reasonable notice is given and the additional time is paid for
as a change order pursuant to the rates for the technicians in the agreement.
The Operator will recommend the quantity and types of CT spare parts necessary
for the maintenance of the CTs in accordance with the manufacturers
recommendations. The Operator will purchase the spare parts under a change order
or separate purchase agreement with the Owner. Repairs and maintenance on the
CTs will also be made under a change order for the repairs or maintenance.
At the expiration of the contract term, the Operator will provide the Owner with
the instruction books, operation records, maintenance history and records,
as-built drawings, generation records, and environmental records. The Operator
will also transfer all remaining balance of plant spare parts, all remaining CT
spare parts, all non-leased office equipment, all non-leased plant and machine
shop tooling, and the test equipment for the metering and environmental
reporting.
4.3.1.2 Owner Responsibilities
- -------------------------------
The Owner is responsible to pay the Operator the fixed fee, as well as paying
for the CT spare parts, CT repairs and maintenance, plant utilities such as
water, sewerage, electricity, telephone, ISDN lines and other utilities. The
Owner is also responsible for property and other taxes as well as insurance on
the plant equipment. The Owner is responsible for obtaining the necessary
permits for continuous operation of the plants. The Owner will provide the
Operator with access to all available operation and maintenance manuals,
drawings, specifications, diagrams, etc. The Owner will provide the fuel for the
plants as well as arrange for the sale of the electricity. The Owner will
provide the Operator with access to the site and associated easements as may be
necessary to operate the plants. The Owner is responsible for proper collection,
removal, and disposal of all hazardous materials.
4.3.1.3 Compensation and Terms of Payment
- ------------------------------------------
Prior to the start of commercial operations, the Owner will pay the Operator a
Pre-Operational Fee for each plant. The Pre-Operational Fee is as follows:
- --------------------------------------------------------------------------------
Plant Invoice Date Pre-Operational Fee
- --------------------------------------------------------------------------------
Gibson City October 1, 1999 $1,393,991
- --------------------------------------------------------------------------------
Kinmundy August 15, 2000 $1,392,341
- --------------------------------------------------------------------------------
Pinckneyville November 1, 1999 $1,293,082
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Pinckneyville May 1, 2001 - Dec. 31, 2001 $29,989/month
- --------------------------------------------------------------------------------
We assume the Pre-Operational Fees are for the purchase of the office equipment
and shop tooling as well as the hiring and training of the plant manager and
technicians.
The cost of the CT spare parts will be as follows:
- --------------------------------------------------------------------------------
Plant Cost of Spare Parts
- --------------------------------------------------------------------------------
Gibson City $2,972,749
- --------------------------------------------------------------------------------
Kinmundy $2,972,749
- --------------------------------------------------------------------------------
Pinckneyville $1,741,524
- --------------------------------------------------------------------------------
The provision of CT spare parts is more than adequate for the three plants.
The fixed operating fee for the plants will be paid on a monthly basis and
escalated each year. The monthly fee paid as follows:
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- --------------------------------------------------------------------------------
Amount Dates Description
- --------------------------------------------------------------------------------
$66,366/month May 1, 2000 - Dec. 31, 2001 Pinckneyville LM6000
- --------------------------------------------------------------------------------
$95,732/month June 1, 2000-March 31, 2001 Gibson City
- --------------------------------------------------------------------------------
$186,384/month April 1, 2001-Dec. 31, 2001 Gibson City and Kinmundy
- --------------------------------------------------------------------------------
$302,320/month January 1, 2002-May 31, 2010 All three plants
- --------------------------------------------------------------------------------
4.3.1.4 Warranties, Penalties, and Bonuses
- -------------------------------------------
The Operator warrants that the turbines will have a starting reliability of 92%
or better when the plants are normally staffed and the turbines are available
for dispatch. The start time is 30 minutes from receipt of the dispatch call to
the time the turbine is synchronized to the grid. The time to achieve full load
is not stated. Normally, the CTs being installed at the plants can achieve full
load within 30 minutes of the start request. The starting reliability guarantee
should be easily achieved.
The Operator also warrants the CTs' availability will be 95% or greater. The
definition of availability in the agreement is based on 365 days per year and
includes derating of the turbines below 90% of their rated output. The turbines
will be considered available only when they are capable of achieving at least
90% of their rated output.
At the end of each year, if the starting reliability of a CT is greater than
92%, the Operator will be paid a bonus of one sixth of one percent (1/6%) of the
fixed fee for each percent the starting reliability is greater than 92%. The
aggregate limit on the bonus is 5% of the fixed fee. The penalty for starting
reliability being below 92% is the reverse of the bonus, again with a cap of 5%
of the fixed fee.
At the end of each year, if the availability of the CTs has been above 95%
during the peak period of the year, the Operator will earn a bonus of one-third
of one percent (1/3%) for each one percent above 95% availability for each
turbine.
4.3.1.5 Termination
- --------------------
The Owner may terminate the agreement prior to its term for inability of
Operator to perform, failure of the Operator to perform, and for adverse
economic reasons. The Operator can be considered unable to perform if it is in
bankruptcy proceedings. If the Operator is in material default of any provision
of the agreement and the Operator has not commenced reasonable steps to cure the
default within 30 days after receipt of notice from the Owner, the Operator will
have failed to perform. If the continued operation of the plant is not
economically feasible due to high gas prices or low electricity prices, the
Owner may discontinue operation of the plants. However, the Owner may not
terminate the agreement for economic reasons and then operate the plants itself.
The Operator may terminate the agreement for failure of the Owner to perform or
if the Owner is in bankruptcy proceedings. Either party may terminate if there
has been damage to the plants that prohibits the plants from generating and
would take more than a year to repair.
4.3.1.6 Indemnification
- ------------------------
The Operator indemnifies the Owner for any loss, damage, liability, or judgement
resulting from claims for injury or death of person or damage to third party
property located at the site while Operator is performing the work. This does
not include claims for voltage or frequency fluctuation. The Operator will also
indemnify the Owner for loss or damage to the plant resulting from Operator
error with a limit of $3 million.
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4.3.1.7 Conclusion
- -------------------
We believe the agreement is reasonable. The Operator will provide personnel to
operate the plant and will supervise repairs and contractors on behalf of the
Owner. The fee paid to the Operator is at the high end of what S&W Consultants
considers an acceptable range, but does include indemnification against Operator
error.
4.3.2 Grand Tower
See section 3.3.5.
4.4 Environmental
S&W Consultants visited the sites for each of the new facilities, including the
repower site at Grand Tower Power Station. S&W Consultants also interviewed
Ameren corporate and site personnel with regard to permit status and
environmental conditions at each of these sites.
The Gibson City, Kinmundy and Pinckneyville sites are "greenfield" sites in that
the only previous usage documented for these sites is high-yield agriculture
(e.g., cornfields). S&W Consultants did not document any significant
environmental conditions with regard to these sites that could preclude their
development and usage as power generation sites. Details on each of these sites
are contained in the following sections. The Grand Tower site is a "brownfield"
site in that an operating utility station is located at this site. S&W
Consultants did document the potential for significant environmental conditions
at this site associated with the utility operations as described in Section
4.4.4.
4.4.1 Operating CT Units
4.4.1.1 Gibson City Power Station
Air Construction Permit No. 99020071 was issued on June 16, 1999 by the IEPA to
Union Electric Development Corporation for the Gibson City Power Station. S&W
Consultants reviewed a copy of this permit and has the following comments:
. The facility is permitted for the primary combustion of pipeline natural gas,
with distillate fuel containing less than 0.28 weight percent sulfur as
backup fuel.
. The owner has voluntarily committed to limit the annual operating schedule
for this facility to 12.5 hours per day, 3 days per week, 40 weeks per year
in order to avoid consumption of the Prevention of Significant Deterioration
("PSD") increment and designation of this facility as a major new source of
criteria air pollutants. Therefore, a federal PSD permit is not required for
the Gibson City Power Station.
. The facility is required to install CEMS for NO\\x\\ and SO\\2\\.
. This facility is subject to the federal New Source Performance Standard
("NSPS") for Stationary Gas Turbines promulgated at 40 CFR 60, Subparts A and
GG. S&W Consultants believes that this facility, if constructed in accordance
with its designs and permits, should be capable of complying with its state
air permit conditions.
. The CTs are affected units under the federal Acid Rain Deposition Control
Program. Ameren has obtained a Title IV Acid Rain Permit for operation of
this facility, which S&W Consultants has reviewed.
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All industrial and sanitary wastewaters from the Gibson City Power Station will
be routed to the municipal sewer system. The only "special discharge" to the
municipal sewer system will be compressor wash water, and the municipality has
reportedly agreed to accept this wastewater as long as the concentrations of the
"cleaners" are below designated levels (as recommended by the compressor
manufacturer).
Stormwater runoff will be routed to the stormwater collection system for the
industrial park. An Illinois Stormwater Pollution Prevention Plan ("SWPPP"),
Permit No. ILR104863 has been prepared for this site. S&W Consultants reviewed a
copy of this plan at the site and noted that construction was being conducted in
accordance with this plan.
Since there will not be any onsite treatment, storage or disposal ("TSD")
facilities for the management of hazardous waste, a RCRA permit for this site is
not required. A Material Safety Data Sheet ("MSDS") collection was maintained at
the site with regard to hazardous materials to be used during construction and
operations. There was no visual evidence of spills, leaks or unauthorized
discharge of materials onto the property. All solid wastes from construction
activities were being properly managed for offsite disposal.
4.4.1.2 Pinckneyville Power Station
- ------------------------------------
The Pinckneyville Power Station is currently in commercial operation. The
Pinckneyville site is located in an unincorporated section of Perry County,
Illinois approximately 3 miles east of the city of Pinckneyville.
Air Construction Permit No. 99020035 was issued on November 9, 1999 by the IEPA
to Union Electric Development Corporation for the Pinckneyville Power Station.
S&W Consultants reviewed a copy of this permit and has the following comments
regarding items differing from those presented earlier:
. The facility is permitted for the combustion of pipeline natural gas, only.
. The owner has further committed to a maximum of less than 200 tons per year
of any regulated air pollutant in order to avoid the requirement for public
notice.
. The facility is required to install CEMS for NO\\x\\ and SO\\2\\, even though
the use of liquid fuels is not permitted.
All industrial and sanitary wastewaters are routed to the municipal sewer
system. Stormwater will be routed from the site to adjacent drainages. An
Illinois SWPPP, Permit No. ILR105094 has been prepared for this site. S&W
Consultants reviewed a copy of this plan at the site and noted that construction
was being conducted in accordance with this plan.
Since there will not be any onsite TSD facilities for the management of
hazardous waste, a RCRA permit for this site is not required. Since construction
personnel were not on site, MSDS collections could not be reviewed. All solid
wastes from construction activities were being properly managed for offsite
disposal.
4.4.1.3 Joppa Power Station
- ----------------------------
Ameren has represented that the lessee, through Midwest has responsibility for
obtaining and maintaining the permits for Joppa.
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4.4.2 Committed Units
4.4.2.1 Grand Tower Power Station
- ----------------------------------
Grand Tower Power Station is an existing, coal-fired power station that has been
in operation since 1924. The coal-fired boilers are slated for retirement and
replacement with new gas-fired CTs and HRSGs. The existing steam turbines will
be mated to the new CTs. Construction work is underway with the near completion
of all the foundations and the near completion of erecting the HRSGs. We
understand that construction of the new units began 3/2/2000, with commercial
operation still expected for June/July 2001.
The air construction permit for the new units at Grand Tower Power Station has
been issued. S&W Consultants reviewed a copy of the air construction permit and
has the following comments:
. The CTs and HRSGs will be fired on natural gas only.
. The proposed project has been designated as a major source of CO and VOM and
is subject to PSD permitting for these air pollutants. Catalytic controls are
not required for the control of CO and VOM. Instead, operation in a manner
consistent with good air pollution control practice has been designated as
best available control technology for these units.
. The proposed project is not subject to PSD permitting for SO\\2\\, NO\\x\\ or
PM because emissions reductions associated with retirement of the existing
coal-fired boilers have been used to negate these emissions.
. The proposed project is required to install SCR for the control of NOx
emissions.
. The proposed project is required to install CEMS for NO\\x\\, only.
. This facility is subject to the federal NSPS for Stationary Gas Turbines
promulgated at 40 CFR 60, Subparts A and GG. S&W Consultants believes that
this facility, if constructed in accordance with its designs and permits,
should be capable of complying with its federal and state air permit
conditions.
. The CTs are affected units under the federal Acid Rain Deposition Control
Program, and the owner is required to obtain a Title IV Acid Rain Permit for
operation of this facility. S&W Consultants has reviewed a copy of the permit
application.
The Grand Tower Power Station has an existing NPDES permit with regard to
industrial and sanitary wastewaters. This permit will need to be revised in
order to cover the new units. Ameren submitted an application for revision of
this NPDES permit to IEPA on August 29, 2000, which should provide sufficient
time for negotiation of permit conditions and final issuance in advance of
startup for the new units.
In addition to the NPDES permit, S&W Consultants reviewed copies of the SWPPP
associated with NPDES General Permit No. ILR10 and the Spill Prevention,
Countermeasure and Control ("SPCC") plan for this station. S&W Consultants noted
that secondary containment for the contractor vehicle fuel tank and hay bail
berms for the new construction areas had not yet been installed at the time of
the site visit.
4.4.2.2 Kinmundy Power Station
- -------------------------------
Construction has begun at the Kinmundy site. The Kinmundy site is located in an
unincorporated section of Marion County, Illinois approximately 5 miles east of
the city of Patoka. Air Construction Permit No. 99020027 was issued on June 28,
1999 by the IEPA to Union Electric Development Corporation for the Kinmundy
Power Station. S&W Consultants reviewed a copy of this permit and noted items
identical to those presented in Section 4.4.1. Ameren has also received the Acid
Rain Program Phase II Permit.
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A NPDES permit will be required for the Kinmundy Power Station. Ameren submitted
an application for this NPDES permit to IEPA on August 15, 2000, which should
provide sufficient time for negotiation of permit conditions and final issuance
in advance of startup for the new units. Ameren has also represented that a
SWPPP has been prepared for this site.
Since there will not be any onsite TSD facilities for the management of
hazardous waste, a RCRA permit for this site is not required. Since construction
personnel were not on site during S&W Consultants' visit, MSDS collections could
not be reviewed. All solid wastes from construction activities were being
properly managed for offsite disposal.
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5 PROJECT AGREEMENTS
This section describes only portions of the relevant contracts and documents as
needed for discussion of the Assets' related technical issues. A complete
description or legal evaluation of the contracts and documents related to the
Asset transfer is beyond the scope of this Report.
5.1 Asset Transfer Agreement
S&W Consultants reviewed the Asset Transfer Agreement between AmerenCIPS and
Genco dated May 1, 2000. This agreement sets forth the terms and conditions for
transfer of assets used for the generation of electricity that is sold to
wholesale and retail customers from AmerenCIPS to Genco.
The asset transfer included all assets, properties, rights and interests owned,
used, or held, e.g., inventory, fixed assets, real property, leased property,
business records, contracts, permits and insurance, by AmerenCIPS in connection
with the generation of electricity sold to wholesale and retail customers.
Payment terms were specified. Assets to be retained by AmerenCIPS were also
identified.
Liabilities that were transferred to Genco include those listed on a balance
sheet prepared by AmerenCIPS as of the transfer date, trade payables, contracts
and employee matters. Retained liabilities were also defined. From the technical
perspective, Section 2.2(e)(ii) relating to Product, Environmental and Safety
Liability is of particular importance. AmerenCIPS retains all liability with
respect to Hazardous Material, Environmental Requirements or Environmental
Damages (each as defined in Section 5.1(e) of the agreement) based on events or
conditions occurring or existing prior to the Closing Date.
Furthermore, according to Section 11.2(b), AmerenCIPS indemnifies Genco with
respect to all Environmental Damages arising from the presence, use, generation,
storage, treatment, discharge, release or disposal of Hazardous Materials to the
extent attributable to any act or omission of AmerenCIPS prior to the transfer
date. In addition, in Section 11.2(a), AmerenCIPS indemnifies Genco for the
failure of AmerenCIPS to assume, pay, perform and discharge the Retained
Liabilities. S&W Consultants has summarized the findings of the Phase I
Environmental Site Assessment, conducted as part of this review, elsewhere in
this report.
5.2 Electric Power Supply Agreements
S&W Consultants reviewed the Electric Power Supply Agreement ("EPSA") between
Genco and Marketing dated May 1, 2000. The EPSA sets forth the terms and
conditions for the supply by Genco to Marketing of all electric capacity and
energy ("Energy") available from Genco's electric generating units. The EPSA
will remain in effect until terminated by either party with at least one year's
written notice, but may not be terminated prior to December 31, 2004.
A portion of the Energy supplied by Genco to Marketing will be resold to
AmerenCIPS for resale as bundled retail electric service or to existing
wholesale requirements customers ("Bundled Sales"), and the remainder shall be
sold either directly by Marketing or by AmerenCIPS at market-based prices
("Market Price Sales"). The Genco assets will be dispatched by an Agent pursuant
to the Amended Joint Dispatch Agreement among Genco, AmerenCIPS and AmerenUE.
The delivery point for Energy supplied under the EPSA is the bus bar connecting
each generation source to the AmerenCIPS transmission system (assets acquired
from AmerenCIPS) or the point of
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interconnection between the AmerenCIPS transmission system and the transmission
facilities over which the energy is being delivered (other generation sources).
Genco is responsible for making all necessary arrangements for transmission and
delivery of Energy to the delivery point. Marketing is to provide for testing of
the metering equipment (which is owned by AmerenCIPS) at suitable intervals.
S&W Consultants also reviewed the Electric Power Supply Agreement between
Marketing and AmerenCIPS also dated May 1, 2000. This Agreement defines the
terms of the supply of electric power and energy by Marketing to AmerenCIPS.
Marketing will supply and deliver all of the Energy needed by AmerenCIPS to
serve its native load, to operate its transmission and distribution system and
provide transmission and distribution services, to fulfill its obligation under
applicable federal and state tariffs or contracts, to satisfy regional
reliability requirements, and for any other purpose related to the provision of
wholesale or retail electric service. Pricing under this Agreement is identical
to that of the EPSA between Marketing and Genco.
S&W Consultants confirmed that the pricing defined in these contracts is
consistent with that reflected in the Financial Model.
5.2.1 Wholesale / Bilateral Contracts
Ameren has represented that certain bilateral contracts have been or will be
assigned to Marketing in conjunction with the asset transfer. S&W Consultants
reviewed the bilateral contracts currently reflected in the Financial Model and
confirmed that the demand capacity, length of engagement (term) and contract
pricing are consistent with those reflected in the Financial Model.
5.3 Agency Agreement
S&W Consultants reviewed the Agency Agreement Between Ameren Energy, AmerenUE,
Marketing and Genco, dated May 1, 2000. The agreement sets forth the terms and
conditions under which Ameren Energy will provide support services, as Agent, to
Genco (and others) in the areas of wholesale power trading of energy and/or
capacity for periods of less than one year; capacity management; business
reporting; transaction administration; contract and counter-party
administration; regulatory reporting, support and compliance; the negotiation,
execution and administration of related contracts; and other related activities
as requested.
Under the agreement, Ameren Energy will have the full power and authority to
transact business on behalf of Genco, including transactions for the purchase
and sale of electric energy. Compensation for services requested by Genco and
rendered by Ameren Energy will be made for chargeable or allocable costs (to be
provided at cost) and controlled through a work order procedure.
5.4 Operation and Maintenance
Key technical aspects of the Operation and Maintenance Agreement between Ameren
Intermediate Holding Co., Inc. (now Ameren Energy Resources Company) and Siemens
Westinghouse Operating Services Company for the Gibson City, Kinmundy and
Pinckneyville power plants are reviewed in Section 4.3.
5.5 Fuel Supply
The primary fuels are coal, natural gas and oil (Meredosia Unit 4). Financial
Model inputs related to fuel supply and pricing were provided by the Market
Consultant.
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AmerenCIPS currently has one long-term Coal Sale and Purchase Agreement in place
with Exxon Coal USA, Inc., for supply of coal to the Coffeen and Meredosia
plants. The effective date of the contract is January 1, 2000. The term of the
agreement extends through December 31, 2009.
The coal to be supplied is from Exxon's Monterey No. 1 mine. CIPS is obligated
to purchase 2,250,000 short tons in 2000, and 2,500,000 short tons per year from
Jan. 1, 2001 through December 31, 2009. The coal is to be washed and crushed to
two-inch maximum top size. The annual average as-received heating value is set
at 10,300 BTU/lb, with total moisture of 19.2%, ash 8.0% and sulfur at 1.0% by
weight. Appropriate provisions are included for measurement of coal quality and
quantity. The coal will be supplied by rail or truck (up to 450,000 tons/year),
as determined by AmerenCIPS.
Pricing (F.O.B. the Mine, plus sales or use taxes) is $21.25/Ton in 2000, and
gradually increases each year to $23.50/Ton by 2009. A "Super Inflation"
adjustment provision in included. Appropriate provisions are also included for
adjustment due to deviation from set quarterly average heating value or SO2
content limits.
Remaining coal and oil purchases are through short-term contracts and spot
purchases.
S&W Consultants reviewed the available gas transportation, storage and
interconnection agreements between Genco and NGPL:
. Firm Transportation Service Agreement #116646 (Grand Tower)
. Interruptible Transportation Service Agreement #116648 (Gibson City,
Kinmundy, and Pinckneyville)
. Firm No-Notice Storage Service Agreement #116593
. Point Operator Agreement #116595
The primary term of these agreements is April 1, 2000 through March 31, 2004.
Fixed costs for this period are $14.2 million. S&W Consultants reviewed these
draft contracts to ascertain the adequacy of design pipeline capacity and
construction schedule, which were found to be reasonable as described in Section
4.
Natural gas supply contracts between Ameren Services and various suppliers
including Occidental Energy Marketing, Anadarko Energy Services Company, and
PanCanadian Energy Services, are currently being negotiated for continued fuel
supply to the CTs. Short term agreements (1 to 3 month supply agreements) are
currently in place, and typical of gas supply agreements for peaking units.
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6 FINANCIAL PROJECTIONS
S&W Consultants reviewed the Financial Model developed by Ameren. S&W
Consultants has reviewed the assumptions, data, and the calculations necessary
to support the projections of cash flow available to support debt service. We
have verified that the underlying model assumptions are consistent with the
expected performance and the commercial terms of the Project Agreements. S&W
Consultants has validated key calculations to ensure that the resulting
revenues, expenses, cash flow, and debt service coverage ratios ("DSCR") were
correctly calculated. S&W Consultants has not reviewed the tax and depreciation
assumptions, which were provided by Ameren, nor the financing assumptions, which
were provided by Lehman Brothers.
In the review of the Financial Model, S&W Consultants made certain assumptions
with respect to conditions that may exist or events that may occur in the
future. In addition, S&W Consultants has used data and information, provided to
us, that we believe to be reliable. We believe that the use of these assumptions
and data are reasonable for the purpose of our Report. However, some assumptions
may differ significantly from actual future conditions due to unanticipated
events and circumstances. To the extent that actual future conditions differ
from those assumed herein, the actual results will vary from those forecasted.
Principal considerations and assumptions used by S&W Consultants in reviewing
the Financial Model include the following:
. S&W Consultants has assumed that all 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.
. The contract and market revenue projections were prepared by the
Market Consultant. S&W Consultants has reviewed the technical inputs
to the market pricing model, but was not asked to independently verify
the methodology used to develop the market pricing model. In addition,
S&W Consultants reviewed the wholesale and bilateral contracts which
form the basis for the revenue projections through 12/31/04, and finds
the demand capacity, term and pricing of the contracts consistent with
that reflected in the Financial Model. As projected by the Market
Consultant, all spot sales of energy and capacity are to be made
pursuant to Genco's arrangements with Marketing or Ameren Energy.
. The Financial Model assumes that only the Coal-fired Stations and Gas-
fired Stations described throughout this Report are included in the
projections.
. S&W Consultants reviewed the operating plans prepared by Ameren /
Genco. We assume that Genco will operate the Assets in accordance with
the operating plans.
. S&W Consultants has assumed that all licenses, permits and approvals
will be obtained and/or renewed on a timely basis.
. The Market Consultant developed fuel cost projections. The price of
fuel purchased is an output of the market pricing model. S&W
Consultants was not asked to review these fuel price forecasts.
. S&W Consultants has assumed that Genco will be able to purchase
SO\\2\\ emissions credits in order to comply with its emission limits
for SO\\2\\. We have assumed that emissions offsets will be available
for purchase by Genco and that sufficient demand exists for the sale
of certain emission credits by Genco at the prices forecast in the
Financial Model (allowance pricing was provided by Market Consultant).
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. S&W Consultants was not asked to evaluate the non-operating expenses
projected for the Assets. These expenses include, for example,
property taxes and insurance, and were provided by Ameren.
The following sections describe the key technical assumptions reflected in the
Financial Model followed by a discussion of project revenues and expenses,
presentation of the base case results and discussion of sensitivity analyses.
6.1 Technical Assumptions
S&W Consultants reviewed Ameren's inputs to the Market Consultant's dispatch
simulation model. These technical assumptions included capacity, equivalent
availability, forced outage rate and heat rate. The values we reviewed,
presented earlier in this report, accurately reflect the condition and
capability of the Assets.
The Financial Model capacity factors, provided as outputs of the Market
Consultant's model, were previously summarized in terms of 20-year averages. The
actual capacity factor profiles vary during that period, particularly for the
Coal-fired Stations, as shown in the following figure.
Figure 6.1-1. Projected Capacity Factors (Coal-fired Stations)
[Four separate line graphs illustrating the projected capacity factors for the
four coal-fired stations. The graphs illustrate the following: (1) Newton
capacity factors for Units 1 and 2 for the years 2000 through 2020; (2) Coffeen
capacity factors for Units 1 and 2 for the years 2000 through 2020; (3)
Meredosia capacity factors for Units 1, 2, 3 and 4 for the years 2000 through
2020; and (4) Hutsonville capacity factors for Units 3 and 4 for the years 2000
through 2020.]
Newton Capacity Factors, %
Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------
Newton 1 85% 84% 84% 85% 84% 83% 84% 84% 84% 84% 84%
- ----------------------------------------------------------------------------------------
Newton 2 86% 86% 86% 85% 85% 84% 84% 84% 84% 85% 85%
- ----------------------------------------------------------------------------------------
Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ---------------------------------------------------------------------------------
Newton 1 84% 85% 85% 85% 85% 85% 86% 86% 86% 86%
- ---------------------------------------------------------------------------------
Newton 2 85% 85% 85% 85% 85% 85% 85% 85% 85% 85%
- ---------------------------------------------------------------------------------
Coffeen Capacity Factors, %
Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------
Coffeen 1 61% 65% 60% 52% 52% 55% 57% 58% 59% 61% 62%
- ----------------------------------------------------------------------------------------
Coffeen 2 69% 73% 69% 59% 58% 59% 61% 61% 63% 65% 65%
- ----------------------------------------------------------------------------------------
Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ---------------------------------------------------------------------------------
Coffeen 1 71% 73% 73% 73% 73% 74% 74% 74% 74% 75%
- ---------------------------------------------------------------------------------
Coffeen 2 74% 75% 75% 76% 76% 76% 77% 77% 77% 77%
- ---------------------------------------------------------------------------------
Meredosia Capacity Factors, %
Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------
Unit 1 17% 19% 14% 14% 16% 19% 20% 22% 25% 27% 24%
- ----------------------------------------------------------------------------------------
Unit 2 16% 19% 15% 13% 16% 19% 20% 21% 25% 27% 24%
- ----------------------------------------------------------------------------------------
Unit 3 33% 44% 35% 24% 25% 30% 34% 35% 42% 45% 42%
- ----------------------------------------------------------------------------------------
Unit 4 0.9% 0.6% 0.4% 0.4% 0.4% 0.2% 0.2% 0.2% 0.2% 0.1% 0.1%
- ----------------------------------------------------------------------------------------
Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ---------------------------------------------------------------------------------
Unit 1 27% 29% 31% 35% 38% 38% 41% 43% 46% 49%
- ---------------------------------------------------------------------------------
Unit 2 27% 28% 30% 34% 38% 38% 41% 43% 46% 49%
- ---------------------------------------------------------------------------------
Unit 3 48% 48% 50% 54% 59% 60% 63% 66% 68% 70%
- ---------------------------------------------------------------------------------
Unit 4 0.1% 0.2% 0.1% 0.1% 0.6% 0.6% 0.7% 0.7% 0.8% 1.0%
- ---------------------------------------------------------------------------------
Hutsonville Capacity Factors,%
Year 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------
Unit 3 19% 17% 16% 15% 16% 21% 22% 22% 26% 25% 26%
- ----------------------------------------------------------------------------------------
Unit 4 23% 22% 19% 16% 18% 22% 23% 24% 28% 29% 29%
- ----------------------------------------------------------------------------------------
Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ---------------------------------------------------------------------------------
Unit 3 31% 31% 33% 37% 41% 42% 44% 46% 49% 51%
- ---------------------------------------------------------------------------------
Unit 4 32% 36% 38% 40% 45% 45% 48% 50% 53% 56%
- ---------------------------------------------------------------------------------
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The higher-than-historical capacity factors are attributable mainly to
reductions in the delivered price of coal due to recent fuel contract re-
negotiations and as reflected in the Market Consultant's coal pricing
projections relative to natural gas pricing. Newton additionally benefits from a
fuel switch to PRB coal, which has lower associated environmental compliance
costs. These stations were designed for base load service and should be able to
safely and reliably meet these capacity factor projections assuming that
appropriate operations and maintenance practices are followed and budgeted
capital projects implemented.
6.2 Financing Assumptions
Lehman Brothers provided the financing assumptions. The $425 million debt
issuance in 2000 consists of $225 million Series A senior notes due 2005 and
$200 million Series B senior notes due 2010. The $50 million debt issuance in
2001 matures in 2011. Both the 2000 and 2001 debt issuances are assumed to be
refinanced at maturity on substantially similar terms and conditions throughout
the term of the Financial Model. These constitute the "Senior Notes". The
"Senior Debt" is comprised of the Senior Notes and the tax-exempt bonds. The
interest payments on the Senior Debt average $43.6 million per annum during the
2000-2010 period.
6.3 Revenues
Revenues projections were provided by the Market Consultant. The projections
include contract sales, "spot market" energy and capacity sales and lease
revenues. The contract sales include sales under the Electric Power Supply
Agreements with Marketing and AmerenCIPS as described earlier, and sales in
accordance with certain bilateral contracts. Contract parties and agreements
include Illinois Municipal Energy Agency, Citizens, Clay Electric Cooperative,
Soyland Power Cooperative, WVPA Interchange Agreement, CILCO Interchange
Agreement, ADM, Farmington, Fredericktown and Owensville. S&W Consultants
reviewed these contracts as described earlier. S&W Consultants was not asked to
review the Joppa lease.
Full-year Asset revenues (rounded) for 2001, the first full calendar year of
operation, are shown in the following table:
Genco Projected Revenues, 2001
==================================================================
Revenue Item Amount % of Total
($ million)
------------------------------------------------------------------
Total Contracts Sales 531.9 95%
------------------------------------------------------------------
Spot Market
------------------------------------------------------------------
Energy Sales 11.8
------------------------------------------------------------------
Capacity Sales 15.4
------------------------------------------------------------------
Purchases (8.3)
------------------------------------------------------------------
Total Spot Market (Net) 18.9 3%
------------------------------------------------------------------
------------------------------------------------------------------
Lease Revenues 10.1 2%
------------------------------------------------------------------
------------------------------------------------------------------
TOTAL REVENUES 560.9 100%
==================================================================
[LOGO] S&W Consultants, Inc. A-126
Revenues average $654 million per year from 2000 through 2010, and increase from
$561 million in 2001 to $802 million in 2010. The contribution to total revenues
of contract sales and net spot market sales are shown in Figure 6.3-1.
Figure 6.3-1. Genco Revenues 2000-2010 ($000)
[A line graph showing the projected contribution of contract sales, net spot
market sales and lease revenues to Genco's total revenues for years 2000 through
2010.]
- ----------------------------------------------------------------------------------------------------------------------------------
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------------------------------------------------
Contract Sales $497,205 $531,925 $496,994 $439,963 $392,591 $ 28,935 $ 28,935 $ 28,747 $ 28,471 $ 28,471 $ 28,471
- ----------------------------------------------------------------------------------------------------------------------------------
Spot Market $ 12,214 $ 18,876 $ 73,728 $119,969 $189,510 $612,151 $640,844 $666,217 $709,842 $743,571 $763,806
Sales (Net)
- ----------------------------------------------------------------------------------------------------------------------------------
Lease Revenues $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
- ----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $519,511 $560,894 $580,815 $570,024 $592,193 $651,178 $679,871 $705,057 $748,406 $782,135 $802,370
- ----------------------------------------------------------------------------------------------------------------------------------
Total generation for each year is provided in the following table:
================================================================================
Year Generation Year Generation Year Generation
(GWh) (GWh) (GWh)
- --------------------------------------------------------------------------------
2000 15,033 2004 14,498 2008 15,683
- --------------------------------------------------------------------------------
2001 15,783 2005 14,820 2009 15,991
- --------------------------------------------------------------------------------
2002 15,529 2006 15,122 2010 15,905
- --------------------------------------------------------------------------------
2003 14,503 2007 15,202
================================================================================
6.4 Expenses
The major operating expenses shown in the Financial Model include fuel cost,
variable O&M, fixed O&M, G&A and property taxes.
The projected operating expenses and capital costs for 2001 are shown in the
following table:
Genco Operating Expenses, 2001
=====================================================
Cost Item Amount ($ million)
-----------------------------------------------------
Fuel Cost 202.8
-----------------------------------------------------
Variable O&M 34.5
-----------------------------------------------------
Fixed O&M 87.6
-----------------------------------------------------
G&A 32.1
-----------------------------------------------------
Property Taxes 22.8
-----------------------------------------------------
-----------------------------------------------------
Total Operating Expenses 379.8
=====================================================
[LOGO] S&W Consultants, Inc. A-127
Total operating expenses average $415.6 million per year from 2000 to 2010.
6.4.1 Fuel Cost
Fuel cost projections were developed by the Market Consultant. S&W Consultants
was not asked to review these forecasts. Coal is assumed to be purchased through
an existing long-term coal supply contract for Coffeen and Meredosia, and on the
spot market for Newton and Hutsonville. Natural gas and oil pricing projections
are based on spot market purchases. Fuel costs average $217 million per year
during the 2000-2010 period, and vary from a low of $183 million in 2000 to a
high of $250 million in 2010.
6.4.2 O&M Costs
O&M costs include fixed and variable components. S&W Consultants reviewed the
variable cost inputs as developed by Ameren, which were considered reasonable
and consistent with those of similar projects that we have evaluated. Variable
O&M costs (non-fuel) average approximately $2.77/MWh for the Coal-fired Stations
in 2000, and escalate at 3% per year thereafter for inflation. Variable O&M
costs average approximately $4.05/MWh for the Gas-fired Stations in 2000, and
escalate at 3% per year thereafter for inflation. Total non-fuel variable O&M
costs (all stations) average approximately $39 million per year during the 2000-
2010 period.
Total fixed O&M costs for the Genco Assets average $97.3 million during that
same period, and range from a low of $76 million in 2000 to a high of $126
million in 2010. This broad range is attributable to the variability of major
maintenance requirements coupled with the 3% inflation escalation factor.
As described earlier, Genco will operate and maintain the Newton, Coffeen,
Meredosia, Hutsonville, and Grand Tower stations. The detailed O&M budgets
developed by Ameren include operations expenses (labor and materials), routine
maintenance (labor and materials), major maintenance and SO\\2\\ compliance
costs. These projections are summarized in the following table.
O&M Budget Projections Summary ($ million)
===========================================================
Item Average (2000-2010)
-----------------------------------------------------------
Operations Expenses 42.2
-----------------------------------------------------------
Labor component 31.7
-----------------------------------------------------------
Routine Maintenance 49.0
-----------------------------------------------------------
Labor component 22.0
-----------------------------------------------------------
Major Maintenance 28.5
-----------------------------------------------------------
SO\\2\\ Compliance Costs 11.0
===========================================================
Ameren provided these forecasts on an all-in basis, i.e., operations and
maintenance expenses reflect both fixed and variable components, which is a
typical utility accounting practice. Major maintenance ranges from $18.6 million
in 2000 to $42 million in 2010. Major maintenance varies considerably from year
to year due to the cyclical nature of major maintenance projects.
The cost of SO\\2\\ compliance, i.e., SO\\2\\ allowance requirements and costs,
was provided by the Market Consultant. Annual costs, in millions of dollars, are
summarized in the following table.
[LOGO] S&W Consultants, Inc. A-128
================================================================================
SO\\2\\ SO\\2\\ SO\\2\\
Year Compliance Year Compliance Year Compliance
- --------------------------------------------------------------------------------
2000 8.8 2004 7.2 2008 14.3
- --------------------------------------------------------------------------------
2001 9.5 2005 8.9 2009 16.2
- --------------------------------------------------------------------------------
2002 8.8 2006 10.5 2010 18.8
- --------------------------------------------------------------------------------
2003 6.9 2007 11.4
================================================================================
As described earlier, Genco has outsourced operation and maintenance of the
Gibson City, Kinmundy, and Pinckneyville stations. O&M costs are comprised of
the contract fee with Siemens Westinghouse Operating Services Company, major
maintenance, other Owner costs (e.g., initial spares, utilities, etc.). There
are no capital expenditure requirements for these units, given the projected
peaking service and new construction. Total operating expenses for these units
average $10 million per annum during the period 2000-2010. Non-fuel variable O&M
averages approximately 10% of this amount.
Further discussion of O&M costs is provided in Sections 3.3 and 4.3. As
previously stated, S&W Consultants considers these O&M budget forecasts, coupled
with the planned capital expenditures budgets, to be adequate for continued safe
and reliable operation of the Assets.
6.4.3 Capital Expenditures
Total costs for capital expenditures average $55 million per annum during the
2000-2010 period. This ranges from a low of $27 million in 2007 to a high of $88
million in 2002. Average costs over this same period are shown in the table
below for the Newton, Coffeen, Meredosia, Hutsonville and Grand Tower (combined
cycle) stations.
Capital Expenditures Summary ($ million)
=====================================================
Station Average (2000-2010)
-----------------------------------------------------
Newton 13.4
-----------------------------------------------------
Coffeen 24.3
-----------------------------------------------------
Meredosia 8.1
-----------------------------------------------------
Hutsonville 5.2
-----------------------------------------------------
Grand Tower 3.7
-----------------------------------------------------
Total 54.7
=====================================================
Capital expenditures generally include such projects as precipitator
refurbishment, condenser retubing, low-NO\\x\\ burner upgrades, economizer
replacements, waterwall replacements, control systems upgrades, superheater tube
replacement, economizer tubes, turbine overhauls and replacements, generator
overhauls and rewinds, ash disposal ponds and landfills, and high energy piping
inspections. Station-specific capital expenditures include the supplemental
cooling ponds at Newton and Coffeen, SCR's at Coffeen, and new
turbine/generators at Hutsonville, Meredosia and Grand Tower. Capital
expenditures are also covered in detail in Section 3.3.
6.5 Base Case Results
The base case Financial Model summary, included as Figure 6.5-1, contains the
major operating revenue and expense projections that support the cash forecasted
to be used for debt service payments. Values in the year 2000 are presented on
an annualized basis. The DSCR is defined as the cash flow available for debt
service ("CFADS") to Senior Debt interest expense. CFADS is calculated after
major maintenance expenditures, but prior to capital expenditures. The DSCR is
shown for each year of the Financial Model.
[LOGO] S&W Consultants, Inc. A-129
For interest payments on the Senior Debt, the average DSCR during the period
2000-2010 for the base case is calculated as 5.4x, with a minimum DSCR of 4.4x
in 2001 and 2003. During the initial 5-year period during which the EPSAs are in
place, the DSCR averages 4.5x. During the 2005-2010 period, where merchant sales
predominate, the DSCR averages 6.2x.
6.6 Sensitivity Analysis
The following sensitivity analyses, defined by and with inputs provided by the
Market Consultant, were performed as variations of the base case:
. Case 1: Overbuild - represents the possibility of capacity additions well
in excess of historical reserve margins. 4000 MW of new capacity are
assumed to come on line in the Mid-American Interconnected Network (MAIN)
and 2,300 MW of new capacity are assumed to come on-line in the
East-Central Area Reliability (ECAR) region, over and above base case
levels.
. Case 2: High Fuel Price - reflects the potential volatility of fuel
markets. Natural gas prices were increased in each year by 25% relative to
base case levels, and coal prices were increased in each year by 10%.
. Case 3: Low Fuel Price - reflects the potential volatility of fuel markets.
Natural gas prices were decreased in each year by 25% relative to base case
levels, and coal prices were decreased in each year by 10%.
Debt service coverage ratios on Senior Debt interest payments are summarized for
these sensitivity cases in the following table:
Sensitivity Analysis - DSCR (2000-2010)
=====================================================================
Sensitivity Case Average DSCR Minimum DSCR
---------------------------------------------------------------------
1: Overbuild 5.3x 3.2x
---------------------------------------------------------------------
2: High Fuel Price 6.2x 4.0x
---------------------------------------------------------------------
3. Low Fuel Price 4.9x 4.4x
=====================================================================
The DSCRs for the base case and sensitivity cases, 2000 - 2010, are summarized
as Figure 6.5-2.
Figure 6.5-2. Base Case and Sensitivity Cases DSCR (2000-2010)
[A line graph summarizing debt service coverage ratios for the base case and
sensitivity cases for years 2000 through 1010. The graph compares the base case
and sensitivity cases (overbuild, high fuel and low fuel).]
- ----------------------------------------------------------------------------------------
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
- ----------------------------------------------------------------------------------------
Base Case 4.6 4.4 4.5 4.4 4.6 5.5 5.8 6.0 6.5 6.8 6.9
- ----------------------------------------------------------------------------------------
Overbuild 4.6 4.2 3.6 3.2 4.6 5.6 5.8 6.1 6.6 6.9 7.0
- ----------------------------------------------------------------------------------------
High Fuel 4.4 4.0 4.3 4.3 4.7 6.8 7.1 7.5 8.0 8.4 8.5
- ----------------------------------------------------------------------------------------
Low Fuel 4.9 4.9 4.9 4.6 4.7 4.4 4.6 4.8 5.0 5.2 5.4
- ----------------------------------------------------------------------------------------
[LOGO] S&W Consultants, Inc. A-130
The respective Financial Model summaries are provided as Figures 6.5-3, 6.5-4
and 6.5-5.
6.7 Conclusions
On the basis of our review and the assumptions set forth in the Report, S&W
Consultants is of the opinion that:
. The availability, capacity and heat rate inputs used by the Market
Consultant to develop its projections of market prices and energy
generation are consistent with the values S&W Consultants has reviewed and
found reasonable.
. The projected heat rate and capacity assumptions have been developed based
on historical data as modified to account for improvements that have been
made or are planned to be made to these facilities. With continued capital
investment, it is reasonable to expect that the heat rates and capacities
can be maintained over the period shown in the Financial Model.
. Genco's maintenance and capital budgets, reflected in the Financial Model,
appear reasonable and adequate to meet the performance objectives safely
and reliably in the ordinary course of business.
. S&W Consultants reviewed the technical and commercial assumptions and the
calculation methodology of the Financial Model. The technical assumptions
assumed in the Financial Model are reasonable and consistent with the
contracts reviewed. The Financial Model fairly presents, in S&W
Consultants' opinion, projected revenues and expenses under the base case
assumptions.
. The projected revenues from the sale of capacity and energy are more than
adequate to pay the annual operating and maintenance expenses (including
provisions for major maintenance), other operating expenses, and debt
service. Under the base case assumptions, the average DSCR is calculated to
be 5.4x from 2000 through 2010. The minimum DSCR is 4.4x and occurs in 2001
and 2003.
. Three sensitivity cases were prepared to test the impact of different
market forces on the energy and capacity prices forecast by the Market
Consultant and the associated impact on the DSCR. The market energy and
capacity prices were forecast assuming (i) the overbuilding of generation
facilities in the region, (ii) higher fuel prices, and (iii) lower fuel
prices. The average DSCR was most sensitive to the low fuel price
sensitivity case. The average DSCR in this case fell to 4.9x with a minimum
of 4.4x in 2005. The average DSCR is 5.3x in the overbuild sensitivity case
and is 6.2x in the high fuel price sensitivity case, with minimum DSCRs of
3.2x in 2003 and 4.0x in 2001, respectively.
[LOGO] S&W Consultants, Inc. A-131
Figure 6.5-2
Base Case Results
Ameren Energy Generating Company
Cash Flow Summary
Base Case page 1 of 2
(all values are $000's unless otherwise noted)
year ending December 31, 2000 2001 2002 2003 2004 2005 2006 2007
---- ---- ---- ---- ---- ---- ---- ----
Annual Generation (GWh) 15,033 15,783 15,529 14,503 14,498 14,820 15,122 15,202
Operating Revenues
Contract Revenues $ 497,205 $ 531,925 $ 496,994 $ 439,963 $ 392,591 $ 28,935 $ 28,935 $ 28,747
Market Sales (Net) $ 12,214 $ 18,876 $ 73,728 $ 119,969 $ 189,510 $ 612,151 $ 640,844 $ 666,217
Energy Sales $ 15,369 $ 11,849 $ 26,463 $ 51,822 $ 93,871 $ 381,558 $ 405,135 $ 424,877
Capacity Sales $ 2,178 $ 15,354 $ 51,396 $ 69,910 $ 96,615 $ 230,601 $ 235,715 $ 241,352
Purchases ($5,333) ($8,327) ($4,131) ($1,763) ($976) ($8) ($7) ($12)
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 519,511 $ 560,894 $ 580,815 $ 570,024 $ 592,193 $ 651,178 $ 679,871 $ 705,057
Operating Expenses
Fuel Costs $ 183,088 $ 202,833 $ 206,067 $ 196,388 $ 200,795 $ 211,880 $ 220,078 $ 225,052
Variable O & M $ 32,506 $ 34,516 $ 34,336 $ 34,215 $ 35,752 $ 37,726 $ 39,656 $ 41,476
Fixed O & M $ 76,074 $ 87,569 $ 81,546 $ 83,694 $ 88,995 $ 94,405 $ 99,990 $ 104,256
G&A Costs (net Property Taxes) $ 23,767 $ 32,082 $ 32,825 $ 37,707 $ 36,894 $ 38,001 $ 39,141 $ 40,315
Property Taxes $ 19,400 $ 22,800 $ 24,770 $ 24,850 $ 24,850 $ 25,596 $ 26,363 $ 27,154
Total Operating Expenses $ 334,835 $ 379,800 $ 379,545 $ 376,854 $ 387,286 $ 407,607 $ 425,228 $ 438,253
Cash Available for Debt Service $ 184,676 $ 181,094 $ 201,270 $ 193,170 $ 204,908 $ 243,571 $ 254,643 $ 266,804
Interest Charges: Senior Debt $ 40,096 $ 41,488 $ 44,271 $ 44,271 $ 44,271 $ 44,271 $ 44,271 $ 44,271
DSCR (x): CFADS/Senior Debt Interest 4.6x 4.4x 4.5x 4.4x 4.6x 5.5x 5.8x 6.0x
Average, 2000-2010 5.4x
Minimum, 2000-2010 4.4x
Average, 2000-2004 4.5x
Average, 2005-2010 6.2x
Senior Debt / Capitalization 55% 46% 46% 47% 48% 48% 48% 48%
Average, 2000-2010 48%
year ending December 31, 2008 2009 2010
---- ---- ----
Annual Generation (GWh) 15,683 15,991 15,905
Operating Revenues
Contract Revenues $ 28,471 $ 28,471 $ 28,471
Market Sales (Net) $ 709,842 $ 743,571 $ 763,806
Energy Sales $ 463,419 $ 491,376 $ 504,297
Capacity Sales $ 246,432 $ 252,201 $ 259,516
Purchases ($8) ($6) ($7)
Lease Revenue $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 748,406 $ 782,135 $ 802,370
Operating Expenses
Fuel Costs $ 237,786 $ 247,808 $ 250,191
Variable O & M $ 44,251 $ 46,426 $ 47,494
Fixed O & M $ 110,832 $ 116,829 $ 125,826
G&A Costs (net Property Taxes) $ 41,524 $ 42,770 $ 44,053
Property Taxes $ 27,969 $ 28,808 $ 29,672
Total Operating Expenses $ 462,363 $ 482,641 $ 497,235
Cash Available for Debt Service $ 286,044 $ 299,493 $ 305,135
Interest Charges: Senior Debt $ 44,271 $ 44,271 $ 44,271
DSCR (x): CFADS/Senior Debt Interest 6.5x 6.8x 6.9x
Average, 2000-2010
Minimum, 2000-2010
Average, 2000-2004
Average, 2005-2010
Senior Debt / Capitalization 48% 48% 47%
Average, 2000-2010
[LOGO] S&W Consultants, Inc. A-132
Figure 6.5-2 (continued)
Base Case Results
Ameren Energy Generating Company
Cash Flow Summary
Base Case page 2 of 2
(all values are $000's unless otherwise noted)
year ending December 31, 2011 2012 2013 2014 2015 2016
---- ---- ---- ---- ---- ----
Annual Generation (GWh) 16,816 17,044 17,120 17,445 17,666 17,691
Operating Revenues
Contract Revenues $ 28,471 $ 15,882 $ 15,882 $ 15,882 $ 0 $ 0
Market Sales (Net) $ 805,487 $ 858,040 $ 889,317 $ 937,853 $ 998,821 $ 1,026,858
Energy Sales $ 551,943 $ 593,391 $ 617,640 $ 660,511 $ 710,460 $ 731,623
Capacity Sales $ 253,544 $ 264,649 $ 271,677 $ 277,342 $ 288,361 $ 295,234
Purchases ($0) ($0) ($0) ($0) $ 0 $ 0
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 844,050 $ 884,015 $ 915,291 $ 963,827 $1,008,913 $ 1,036,950
Operating Expenses
Fuel Costs $ 261,257 $ 269,856 $ 275,727 $ 288,072 $ 297,268 $ 302,157
Variable O & M $ 52,522 $ 55,200 $ 57,009 $ 59,671 $ 62,309 $ 64,698
Fixed O & M $ 119,129 $ 123,990 $ 133,155 $ 138,867 $ 151,946 $ 163,379
G&A Costs (net Property Taxes) $ 45,375 $ 46,736 $ 48,138 $ 49,582 $ 51,070 $ 52,602
Property Taxes $ 30,562 $ 31,479 $ 32,424 $ 33,396 $ 34,398 $ 35,430
Total Operating Expenses $ 508,846 $ 527,262 $ 546,453 $ 569,588 $ 596,991 $ 618,267
Cash Available for Debt Service $ 335,205 $ 356,753 $ 368,838 $ 394,239 $ 411,922 $ 418,684
Interest Charges: Senior Debt $ 42,879 $ 40,096 $ 40,096 $ 37,449 $ 37,209 $ 37,209
DSCR (x): CFADS/Senior Debt Interest 7.8x 8.9x 9.2x 10.5x 11.1x 11.3x
Senior Debt/Capitalization 41% 38% 35% 30% 28% 25%
year ending December 31, 2017 2018 2019 2020
---- ---- ---- ----
Annual Generation (GWh) 17,948 18,072 18,143 18,310
Operating Revenues
Contract Revenues $ 0 $ 0 $ 0 $ 0
Market Sales (Net) $1,064,720 $ 1,101,404 $ 1,136,032 $ 1,173,202
Energy Sales $ 777,561 $ 810,735 $ 837,843 $ 882,430
Capacity Sales $ 287,159 $ 290,669 $ 298,188 $ 290,772
Purchases $ 0 $ 0 $ 0 $ 0
Lease Revenue $10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $1,074,812 $ 1,111,496 $ 1,146,124 $ 1,183,294
Operating Expenses
Fuel Costs $ 313,599 $ 321,801 $ 327,839 $ 338,437
Variable O & M $ 67,245 $ 69,510 $ 72,849 $ 75,120
Fixed O & M $ 169,585 $ 175,051 $ 185,678 $ 196,565
G&A Costs (net Property Taxes) $ 54,180 $ 55,805 $ 57,479 $ 59,204
Property Taxes $ 36,493 $ 37,588 $ 38,715 $ 39,877
Total Operating Expenses $ 641,101 $ 659,755 $ 682,560 $ 709,203
Cash Available for Debt Service $ 433,711 $ 451,741 $ 463,564 $ 474,092
Interest Charges: Senior Debt $ 37,209 $ 37,209 $ 37,209 $ 25,830
DSCR (x): CFADS/Senior Debt Interest 11.7x 12.1x 12.5x 18.4x
Senior Debt/Capitalization 23% 22% 20% 2%
[LOGO] S&W Consultants, Inc. A-133
Figure 6.5-3
Sensitivity Case 1: Overbuild
Ameren Energy Generating Company
Cash Flow Summary
Overbuild Case page 1 of 2
(all values are $000' unless otherwise noted)
year ending December 31, 2000 2001 2002 2003 2004 2005 2006 2007
---- ---- ---- ---- ---- ---- ---- ----
Annual Generation (GWh) 15,029 15,773 15,530 14,494 14,556 14,884 15,158 15,297
Operating Revenues
Contract Revenues $497,205 $531,925 $496,994 $439,963 $392,591 $ 28,935 $ 28,935 $ 28,747
Market Sales (Net) $ 11,055 $ 10,490 $ 33,316 $ 66,303 $191,466 $616,842 $644,949 $673,382
Energy Sales $ 15,254 $ 11,573 $ 26,164 $ 51,368 $ 96,329 $385,887 $408,879 $431,680
Capacity Sales $ 1,156 $ 7,275 $ 11,169 $ 16,715 $ 96,157 $230,963 $236,077 $241,714
Purchases ($5,355) ($8,359) ($4,017) ($1,781) ($1,020) ($8) ($8) ($11)
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $518,352 $552,507 $540,402 $516,358 $594,149 $655,869 $683,976 $712,222
Operating Expenses
Fuel Costs $183,095 $202,824 $206,101 $196,424 $202,565 $213,666 $221,144 $227,731
Variable O & M $ 32,499 $ 34,489 $ 34,366 $ 34,184 $ 35,936 $ 37,948 $ 39,824 $ 41,835
Fixed O & M $ 76,056 $ 87,498 $ 81,538 $ 83,458 $ 88,924 $ 94,338 $ 99,927 $104,492
G&A Costs (net Property Taxes) $ 23,767 $ 32,082 $ 32,825 $ 37,707 $ 36,894 $ 38,001 $ 39,141 $ 40,315
Property Taxes $ 19,400 $ 22,800 $ 24,770 $ 24,850 $ 24,850 $ 25,596 $ 26,363 $ 27,154
Total Operating Expenses $334,817 $379,693 $379,601 $376,622 $389,169 $409,548 $426,399 $441,527
Cash Available for Debt Service $183,536 $172,814 $160,802 $139,736 $204,980 $246,321 $257,577 $270,695
Interest Charges: Senior Debt $ 40,096 $ 41,488 $ 44,271 $ 44,271 $ 44,271 $ 44,271 $ 44,271 $ 44,271
DSCR (x): CFADS/Senior Debt Interest 4.6x 4.2x 3.6x 3.2x 4.6x 5.6x 5.8x 6.1x
Average, 2000-2010 5.3x
Minimum, 2000-2010 3.2x
Average, 2000-2004 4.0x
Average, 2005-2010 6.3x
Senior Debt / Capitalization 55% 46% 48% 50% 51% 51% 51% 51%
Average, 2000-2010 50%
year ending December 31, 2008 2009 2010
---- ---- ----
Annual Generation (GWh) 15,769 16,081 15,990
Operating Revenues
Contract Revenues $ 28,471 $ 28,471 $ 28,471
Market Sales (Net) $716,877 $751,251 $771,056
Energy Sales $470,092 $498,694 $511,909
Capacity Sales $246,794 $252,562 $259,155
Purchases ($8) ($6) ($8)
Lease Revenue $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $755,441 $789,814 $809,620
Operating Expenses
Fuel Costs $240,315 $250,294 $252,508
Variable O & M $ 44,573 $ 46,806 $ 47,823
Fixed O & M $110,987 $117,140 $126,412
G&A Costs (net Property Taxes) $ 41,524 $ 42,770 $ 44,053
Property Taxes $ 27,969 $ 28,808 $ 29,672
Total Operating Expenses $465,369 $485,818 $500,469
Cash Available for $290,072 $303,996 $309,151
Debt Service
Interest Charges: Senior Debt $ 44,271 $ 44,271 $ 44,271
DSCR (x): CFADS/Senior Debt Interest 6.6x 6.9x 7.0x
Average, 2000-2010
Minimum, 2000-2010
Average, 2000-2004
Average, 2005-2010
Senior Debt / Capitalization 50% 50% 49%
Average, 2000-2010
[LOGO] S&W Consultants, Inc. A-134
Figure 6.5-3 (continued)
Sensitivity Case 1: Overbuild
Ameren Energy Generating Company
Cash Flow Summary
Overbuild Case page 2 of 2
(all values are $000's unless otherwise noted)
year ending December 31, 2011 2012 2013 2014 2015
---- ---- ---- ---- ----
Annual Generation (GWh) 16,918 17,106 17,225 17,463 17,746
Operating Revenues
Contract Revenues $ 28,471 $ 15,882 $ 15,882 $ 15,882 $ 0
Market Sales (Net) $ 810,913 $ 863,162 $ 897,053 $ 937,551 $ 998,177
Energy Sales $ 558,454 $ 598,881 $ 626,112 $ 663,735 $ 717,396
Capacity Sales $ 252,458 $ 264,281 $ 270,941 $ 273,816 $ 280,781
Purchases ($0) ($0) ($0) ($0) $ 0
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 849,477 $ 889,137 $ 923,027 $ 963,526 $1,008,269
Operating Expenses
Fuel Costs $ 263,909 $ 271,915 $ 278,282 $ 288,997 $ 299,390
Variable O & M $ 52,941 $ 55,442 $ 57,405 $ 59,705 $ 62,612
Fixed O & M $ 119,780 $ 124,238 $ 134,016 $ 138,757 $ 152,620
G&A Costs (net Property Taxes) $ 45,375 $ 46,736 $ 48,138 $ 49,582 $ 51,070
Property Taxes $ 30,562 $ 31,479 $ 32,424 $ 33,396 $ 34,398
Total Operating Expenses $ 512,567 $ 529,809 $ 550,264 $ 570,438 $ 600,090
Cash Available for Debt Service $ 336,910 $ 359,327 $ 372,763 $ 393,088 $ 408,180
Interest Charges: Senior Debt $ 42,879 $ 40,096 $ 40,096 $ 37,449 $ 37,209
DSCR (x): CFADS/Senior Debt Interest 7.9x 9.0x 9.3x 10.5x 11.0x
Senior Debt / Capitalization 43% 39% 36% 31% 28%
year ending December 31, 2016 2017 2018 2019 2020
---- ---- ---- ---- ----
Annual Generation (GWh) 17,754 17,961 18,162 18,190 18,372
Operating Revenues
Contract Revenues $ 0 $ 0 $ 0 $ 0 $ 0
Market Sales (Net) $1,028,346 $1,067,653 $1,101,461 $1,138,096 $1,172,447
Energy Sales $ 736,902 $ 780,494 $ 818,372 $ 843,698 $ 889,255
Capacity Sales $ 291,444 $ 287,159 $ 283,089 $ 294,398 $ 283,192
Purchases $ 0 $ 0 $ 0 $ 0 $ 0
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $1,038,439 $1,077,746 $1,111,553 $1,148,189 $1,182,540
Operating Expenses
Fuel Costs $ 303,885 $ 314,513 $ 324,242 $ 329,549 $ 340,552
Variable O & M $ 64,921 $ 67,279 $ 69,887 $ 73,066 $ 75,369
Fixed O & M $ 164,069 $ 169,498 $ 176,411 $ 186,176 $ 197,284
G&A Costs (net Property Taxes) $ 52,602 $ 54,180 $ 55,805 $ 57,479 $ 59,204
Property Taxes $ 35,430 $ 36,493 $ 37,588 $ 38,715 $ 39,877
Total Operating Expenses $ 620,906 $ 641,963 $ 663,933 $ 684,986 $ 712,285
Cash Available for Debt Service $ 417,533 $ 435,783 $ 447,620 $ 463,203 $ 470,255
Interest Charges: Senior Debt $ 37,209 $ 37,209 $ 37,209 $ 37,209 $ 25,830
DSCR (x): CFADS/Senior Debt Interest 11.2x 11.7x 12.0x 12.4x 18.2x
Senior Debt / Capitalization 26% 24% 22% 20% 2%
[LOGO S&W] Consultants,Inc A-135
Figure 6.5-4
Sensitivity Case 2: High Fuel Price
Ameren Energy Generating Company
Cash Flow Summary
High Fuel Case page 1 of 2
(all values are $000's unless otherwise noted)
year ending December 31, 2000 2001 2002 2003 2004 2005 2006 2007
---- ---- ---- ---- ---- ---- ---- ----
Annual Generation (GWh) 15,421 16,038 15,954 15,415 15,524 16,036 16,276 16,322
Operating Revenues
Contract Revenues $ 497,205 $ 531,925 $ 496,994 $ 439,963 $ 392,591 $ 28,935 $ 28,935 $ 28,747
Market Sales (Net) $ 23,740 $ 23,447 $ 89,139 $ 154,891 $ 236,769 $ 717,162 $ 751,256 $ 781,237
Energy Sales $ 26,785 $ 20,023 $ 40,690 $ 86,461 $ 141,012 $ 486,562 $ 515,543 $ 539,528
Capacity Sales $ 1,936 $ 13,364 $ 51,396 $ 69,910 $ 96,615 $ 230,601 $ 235,715 $ 241,714
Purchases ($4,982) ($9,940) ($2,948) ($1,481) ($858) ($1) ($2) ($5)
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 531,037 $ 565,465 $ 596,225 $ 604,946 $ 639,452 $ 756,189 $ 790,284 $ 820,076
Operating Expenses
Fuel Costs $ 201,290 $ 222,323 $ 230,303 $ 227,634 $ 234,512 $ 250,534 $ 259,063 $ 264,833
Variable O & M $ 33,599 $ 35,318 $ 35,632 $ 37,152 $39,184 $ 41,805 $ 43,654 $ 45,423
Fixed O & M $ 77,397 $ 88,918 $ 83,455 $ 87,770 $93,918 $ 100,341 $ 106,257 $ 110,659
G&A Costs (net Property Taxes) $ 23,767 $ 32,082 $ 32,825 $ 37,707 $36,894 $ 38,001 $ 39,141 $ 40,315
Property Taxes $ 19,400 $ 22,800 $ 24,770 $ 24,850 $24,850 $ 25,596 $ 26,363 $ 27,154
Total Operating Expenses $ 355,453 $ 401,441 $ 406,985 $ 415,113 $ 429,358 $ 456,276 $ 474,479 $ 488,384
Cash Available for Debt Service $ 175,584 $ 164,024 $ 189,240 $ 189,833 $ 210,094 $ 299,913 $ 315,805 $ 331,693
Interest Charges: Senior Debt $ 40,096 $ 41,488 $ 44,271 $ 44,271 $ 44,271 $ 44,271 $ 44,271 $ 44,271
DSCR (x): CFADS/Senior Debt Interest 4.4x 4.0x 4.3x 4.3x 4.7x 6.8x 7.1x 7.5x
Average, 2000-2010 6.2x
Minimum, 2000-2010 4.0x
Average, 2000-2004 4.3x
Average, 2005-2010 7.7x
Senior Debt / Capitalization 55% 46% 47% 48% 49% 48% 46% 45%
Average, 2000-2010 46%
year ending December 31, 2008 2009 2010
---- ---- ----
Annual Generation (GWh) 16,715 16,966 16,753
Operating Revenues
Contract Revenues $ 28,471 $ 28,471 $ 28,471
Market Sales (Net) $ 830,712 $ 869,091 $ 891,434
Energy Sales $ 584,285 $ 616,532 $ 631,922
Capacity Sales $ 246,432 $ 252,562 $ 259,516
Purchases ($5) ($4) ($5)
Lease Revenue $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 869,276 $ 907,655 $ 929,998
Operating Expenses
Fuel Costs $ 278,179 $ 288,520 $ 296,426
Variable O & M $ 48,033 $ 50,198 $ 50,707
Fixed O & M $ 117,357 $ 123,692 $ 133,023
G&A Costs (net Property Taxes) $ 41,524 $ 42,770 $ 44,053
Property Taxes $ 27,969 $ 28,808 $ 29,672
Total Operating Expenses $ 513,062 $ 533,988 $ 553,882
Cash Available for Debt Service $ 356,215 $ 373,667 $ 376,116
Interest Charges: Senior Debt $ 44,271 $ 44,271 $ 44,271
DSCR (x): CFADS/Senior Debt Interest 8.0x 8.4x 8.5x
Average, 2000-2010
Minimum, 2000-2010
Average, 2000-2004
Average, 2005-2010
Senior Debt / Capitalization 43% 42% 40%
Average, 2000-2010
[LOGO] S&W Consultants, Inc. A-136
Figure 6.5-4 (continued)
Sensitivity Case 2: High Fuel Price
Ameren Energy Generating Company
Cash Flow Summary
High Fuel Case page 2 of 2
(all values are $000's unless otherwise noted)
year ending December 31, 2011 2012 2013 2014 2015 2016 2017
---- ---- ---- ---- ---- ---- ----
Annual Generation (GWh) 17,625 17,727 17,841 18,100 18,303 18,263 18,489
Operating Revenues
Contract Revenues $ 28,471 $ 15,882 $ 15,882 $ 15,882 $ 0 $ 0 $ 0
Market Sales (Net) $932,426 $ 980,883 $1,019,605 $1,055,684 $1,125,841 $1,158,651 $1,203,037
Energy Sales $685,009 $ 730,490 $ 763,124 $ 811,340 $ 871,590 $ 893,736 $ 946,198
Capacity Sales $247,418 $ 250,393 $ 256,482 $ 244,344 $ 254,251 $ 264,914 $ 256,839
Purchases ($0) ($0) ($0) $ 0 $ 0 $ 0 $ 0
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $970,990 $1,006,857 $1,045,580 $1,081,658 $1,135,934 $1,168,743 $1,213,130
Operating Expenses
Fuel Costs $308,421 $ 315,234 $ 322,849 $ 335,064 $ 345,297 $ 348,991 $ 361,687
Variable O & M $ 55,742 $ 58,077 $ 60,118 $ 62,633 $ 65,257 $ 67,505 $ 70,035
Fixed O & M $127,043 $ 131,696 $ 141,473 $ 147,214 $ 160,349 $ 171,713 $ 177,903
G&A Costs (net Property Taxes) $ 45,375 $ 46,736 $ 48,138 $ 49,582 $ 51,070 $ 52,602 $ 54,180
Property Taxes 30,562 $ 31,479 $ 32,424 $ 33,396 $ 34,398 $ 35,430 $ 36,493
Total Operating Expenses $567,143 $ 583,222 $ 605,001 $ 627,890 $ 656,372 $ 676,241 $ 700,298
Cash Available for Debt Service $403,847 $ 423,636 $ 440,578 $ 453,768 $ 479,562 $ 492,502 $ 512,832
Interest Charges: Senior Debt $ 42,879 $ 40,096 $ 40,096 $ 37,449 $ 37,209 $ 37,209 $ 37,209
DSCR (x): CFADS/Senior Debt Interest 9.4x 10.6x 11.0x 12.1x 12.9x 13.2x 13.8x
Senior Debt / Capitalization 34% 31% 29% 24% 22% 20% 19%
year ending December 31, 2018 2019 2020
---- ---- ----
Annual Generation (GWh) 18,626 18,611 18,748
Operating Revenues
Contract Revenues $ 0 $ 0 $ 0
Market Sales (Net) $1,246,909 $1,285,718 $1,324,844
Energy Sales $ 986,561 $1,017,849 $1,068,182
Capacity Sales $ 260,349 $ 267,868 $ 256,662
Purchases $ 0 $ 0 $ 0
Lease Revenue $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $1,257,002 $1,295,810 $1,334,937
Operating Expenses
Fuel Costs $ 370,725 $ 375,442 $ 386,804
Variable O & M $ 72,478 $ 75,513 $ 77,760
Fixed O & M $ 184,088 $ 193,100 $ 203,327
G&A Costs (net Property Taxes) $ 55,805 $ 57,479 $ 59,204
Property Taxes $ 37,588 $ 38,715 $ 39,877
Total Operating Expenses $ 720,684 $ 740,250 $ 766,972
Cash Available for Debt Service $ 536,318 $ 555,560 $ 567,965
Interest Charges: Senior Debt $ 37,209 $ 37,209 $ 25,830
DSCR (x): CFADS/Senior Debt Interest 14.4x 14.9x 22.0x
Senior Debt / Capitalization 17% 16% 2%
[LOGO] S&W Consultants, Inc. A-137
Figure 6.5-5
Sensitivity Case 3: Low Fuel Price
Ameren Energy Generating Company
Cash Flow Summary
Low Fuel Case page 1 of 2
(all values are $000's unless otherwise noted)
year ending December 31, 2000 2001 2002 2003 2004 2005 2006
---- ---- ---- ---- ---- ---- ----
Annual Generation (GWh) 14,352 15,334 15,144 13,646 12,931 12,507 12,960
Operating Revenues
Contract Revenues $ 497,205 $ 531,925 $ 496,994 $ 439,963 $ 392,591 $ 28,935 $ 28,935
Market Sales (Net) ($2,236) $ 13,732 $ 62,542 $ 94,020 $ 140,505 $ 496,446 $ 520,621
Energy Sales $ 7,850 $ 6,780 $ 14,911 $ 26,264 $ 46,079 $ 266,232 $ 285,283
Capacity Sales $ 2,952 $ 19,622 $ 51,396 $ 69,910 $ 96,463 $ 230,240 $ 235,354
Purchases ($13,038) ($12,669) ($3,766) ($2,154) ($2,036) ($25) ($15)
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 505,061 $ 555,750 $ 569,628 $ 544,075 $ 543,188 $ 535,473 $ 559,649
Operating Expenses
Fuel Costs $ 161,204 $ 182,112 $ 184,975 $ 168,413 $ 161,915 $ 160,959 $ 169,788
Variable O & M $ 30,630 $ 32,547 $ 32,150 $ 30,566 $ 29,840 $ 29,767 $ 31,859
Fixed O & M $ 73,730 $ 83,672 $ 76,867 $ 77,815 $ 81,254 $ 84,246 $ 89,082
G&A Costs (net Property Taxes) $ 23,767 $ 32,082 $ 32,825 $ 37,707 $ 36,894 $ 38,001 $ 39,141
Property Taxes $ 19,400 $ 22,800 $ 24,770 $ 24,850 $ 24,850 $ 25,596 $ 26,363
Total Operating Expenses $ 308,730 $ 353,213 $ 351,588 $ 339,351 $ 334,752 $ 338,569 $ 356,233
Cash Available for Debt Service $ 196,332 $ 202,537 $ 218,041 $ 204,724 $ 208,436 $ 196,905 $ 203,416
Interest Charges: Senior Debt $ 40,096 $ 41,488 $ 44,271 $ 44,271 $ 44,271 $ 44,271 $ 44,271
DSCR (x): CFADS/Senior Debt Interest 4.9x 4.9x 4.9x 4.6x 4.7x 4.4x 4.6x
Average, 2000-2010 4.9x
Minimum, 2000-2010 4.4x
Average, 2000-2004 4.8x
Average, 2005-2010 4.9x
Senior Debt/Capitalization 55% 45% 45% 46% 47% 48% 49%
Average, 2000-2010 50%
year ending December 31, 2007 2008 2009 2010
---- ---- ---- ----
13,231 13,754 14,062 14,522
Annual Generation (GWh)
Operating Revenues $ 28,747 $ 28,471 $ 28,471 $ 28,471
$ 542,568 $ 575,933 $ 600,811 $ 628,561
Contract Revenues $ 301,234 $ 329,511 $ 348,982 $ 369,415
Market Sales (Net) $ 241,352 $ 246,432 $ 251,839 $ 259,155
Energy Sales ($18) ($10) ($9) ($9)
Capacity Sales $ 10,093 $ 10,093 $ 10,093 $ 10,093
Purchases $ 581,408 $ 614,497 $ 639,375 $ 667,125
Lease Revenue
Total Operating Revenues
Operating Expenses $ 176,254 $ 187,423 $ 195,626 $ 200,340
Fuel Costs $ 33,882 $ 36,619 $ 38,726 $ 41,896
Variable O & M $ 93,153 $ 98,392 $ 103,183 $ 112,917
Fixed O & M $ 40,315 $ 41,524 $ 42,770 $ 44,053
G&A Costs (net Property Taxes) $ 27,154 $ 27,969 $ 28,808 $ 29,672
Property Taxes $ 370,758 $ 391,927 $ 409,113 $ 428,878
Total Operating Expenses
$ 210,650 $ 222,569 $ 230,263 $ 238,247
Cash Available for Debt Service
$ 44,271 $ 44,271 $ 44,271 $ 44,271
Interest Charges: Senior Debt
DSCR (x): CFADS/Senior Debt Interest 4.8x 5.0x 5.2x 5.4x
Average, 2000-2010
Minimum, 2000-2010
Average, 2000-2004
Average, 2005-2010
Senior Debt / Capitalization
Average, 2000-2010 51% 52% 54% 55%
[LOGO] S&W Consultants, Inc. A-138
Figure 6.5-5 (continued)
Sensitivity Case 3: Low Fuel Price
Ameren Energy Generating Company
Cash Flow Summary
Low Fuel Case page 2 of 2
(all values are $000's unless otherwise noted)
year ending December 31, 2011 2012 2013 2014 2015 2016
---- ---- ---- ---- ---- ----
Annual Generation (GWh) 15,878 16,058 16,112 16,443 16,493 16,510
Operating Revenues
Contract Revenues $ 28,471 $ 15,882 $ 15,882 $ 15,882 $ 0 $ 0
Market Sales (Net) $ 671,850 $ 713,993 $ 737,401 $773,832 $824,282 $846,174
Energy Sales $ 415,411 $ 446,396 $ 462,776 $494,648 $528,849 $543,923
Capacity Sales $ 256,439 $ 267,597 $ 274,625 $279,184 $295,433 $302,252
Purchases ($0) ($0) ($0) ($0) $ 0 $ 0
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 710,414 $ 739,967 $ 763,375 $799,806 $834,375 $856,267
Operating Expenses
Fuel Costs $ 215,876 $ 222,279 $ 226,728 $ 236,810 $241,726 $245,883
Variable O & M $ 48,818 $ 51,261 $ 52,888 $ 55,461 $ 57,290 $ 59,484
Fixed O & M $ 108,915 $ 112,674 $ 120,090 $ 124,379 $133,987 $143,261
G&A Costs (net Property Taxes) $ 45,375 $ 46,736 $ 48,138 $ 49,582 $ 51,070 $ 52,602
Property Taxes $ 30,562 $ 31,479 $ 32,424 $ 33,396 $ 34,398 $ 35,430
Total Operating Expenses $ 449,546 $ 464,429 $ 480,268 $ 499,628 $518,471 $536,659
Cash Available for Debt Service $ 260,869 $ 275,538 $ 283,107 $ 300,178 $315,904 $319,608
Interest Charges: Senior Debt $ 42,879 $ 40,096 $ 40,096 $ 37,449 $ 37,209 $ 37,209
DSCR (x): CFADS/Senior Debt Interest 6.1x 6.9x 7.1x 8.0x 8.5x 8.6x
Senior Debt / Capitalization 50% 47% 45% 39% 37% 34%
year ending December 31, 2017 2018 2019 2020
---- ---- ---- ----
Annual Generation (GWh) 16,809 16,897 16,893 17,120
Operating Revenues
Contract Revenues $ 0 $ 0 $ 0 $ 0
Market Sales (Net) $ 886,569 $ 917,979 $ 944,465 $986,535
Energy Sales $ 578,516 $ 602,486 $ 621,029 $656,923
Capacity Sales $ 308,053 $ 315,493 $ 323,436 $329,612
Purchases $ 0 $ 0 $ 0 $ 0
Lease Revenue $ 10,093 $ 10,093 $ 10,093 $ 10,093
Total Operating Revenues $ 896,661 $ 928,071 $ 954,558 $996,627
Operating Expenses
Fuel Costs $ 255,734 $ 261,668 $ 265,976 $275,801
Variable O & M $ 62,097 $ 64,066 $ 66,874 $ 69,204
Fixed O & M $ 147,479 $ 150,563 $ 157,453 $166,699
G&A Costs (net Property Taxes) $ 54,180 $ 55,805 $ 57,479 $ 59,204
Property Taxes $ 36,493 $ 37,588 $ 38,715 $ 39,877
Total Operating Expenses $ 555,983 $ 569,690 $ 586,498 $610,785
Cash Available for Debt Service $ 340,678 $ 358,381 $ 368,060 $385,842
Interest Charges: Senior Debt $ 37,209 $ 37,209 $ 37,209 $ 25,830
DSCR (x): CFADS/Senior Debt Interest 9.2x 9.6x 9.9x 14.9x
Senior Debt / Capitalization 32% 30% 28% 4%
[LOGO] S&W Consultants,Inc. A-139
APPENDIX A: DOCUMENTS REVIEWED
===========================================================================================================================
ITEM DATE
===========================================================================================================================
Grand Tower Unit 3 Turbine Generator Inspection-----------Westinghouse 10/97 -1/98
- ---------------------------------------------------------------------------------------------------------------------------
#5 Boiler Fall Outage Task List 1999
- ---------------------------------------------------------------------------------------------------------------------------
1999 Meredosia O&M Projects List 1998
- ---------------------------------------------------------------------------------------------------------------------------
1999 U2 scheduled outage 3/7/99-5/2/99
- ---------------------------------------------------------------------------------------------------------------------------
ABB Metallurgical Report Unit 3 Boiler Waterwalls Meredosia 2/93
- ---------------------------------------------------------------------------------------------------------------------------
Air Construction Permit and Application for Gibson City
- ---------------------------------------------------------------------------------------------------------------------------
Air Construction Permit and Application for Kinmundy
- ---------------------------------------------------------------------------------------------------------------------------
Air Construction Permit and Application for Pinckneyville
- ---------------------------------------------------------------------------------------------------------------------------
Air Construction Permit Application for Grand Tower
- ---------------------------------------------------------------------------------------------------------------------------
Ameren CIPS Plant Fuel Info 1998 data
- ---------------------------------------------------------------------------------------------------------------------------
Ameren CIPS T-G maintenance schedule 12/10/99
- ---------------------------------------------------------------------------------------------------------------------------
Annual summaries of SO2 and NOx emissions for the years 1997, 1998 and
1999 for UE and CIPs units
- ---------------------------------------------------------------------------------------------------------------------------
Asbestos Exposure - Controls and Work Practices (ES-REG-203)
- ---------------------------------------------------------------------------------------------------------------------------
Assorted P&IDs for Grand Tower, Gibson City and Kinmundy.
- ---------------------------------------------------------------------------------------------------------------------------
Balance of Plant Condition Assessment Newton 1&2 11/1995
- ---------------------------------------------------------------------------------------------------------------------------
Basis of estimate - Sargent & Lundy - Alternate F 6/8/94
- ---------------------------------------------------------------------------------------------------------------------------
Boiler #2 Fitness Survey 1985
- ---------------------------------------------------------------------------------------------------------------------------
Boiler 5 Interim Temperature Guidelines 4/5/99
- ---------------------------------------------------------------------------------------------------------------------------
Budget Report through Jan. 15, 2000 for Pinckneyville project, dated 1/18/00
1/18/2000, file: AMERCOST.WK4.
- ---------------------------------------------------------------------------------------------------------------------------
Circulating Water Supply Pipe Examination - Unit 1 -- Sargent & Lundy 12/20, 1996
- ---------------------------------------------------------------------------------------------------------------------------
Circulating Water Supply Pipe Examination - Unit 2 -- Sarge & Lundy 12/20, 1996
- ---------------------------------------------------------------------------------------------------------------------------
Coffeen Condition Based Maintenance - Equipment watchlist
- ---------------------------------------------------------------------------------------------------------------------------
Coffeen Station - Electrostatic Precipitator Drawings ESP Design Manuals, C.O. date through
ESP Inspection Reports, Flyash Handling Information, Planned SCR present.
Systems Documents, Boiler Cross Sectionals, and Aerial Photograph of Site.
- ---------------------------------------------------------------------------------------------------------------------------
Coffeen Unit 1 Phillips, Getshow Co. Report 1997
- ---------------------------------------------------------------------------------------------------------------------------
Comparison analysis - Coffeen performance indicators 1998-1999
- ---------------------------------------------------------------------------------------------------------------------------
Condition Assessment - Superheater and Reheat Outlet Headers - Newton March 1997
Unit 1, ABB C-E Services, Inc.
- ---------------------------------------------------------------------------------------------------------------------------
Condition Assessment Report - Coffeen Station - Unit 1 October 1998
- ---------------------------------------------------------------------------------------------------------------------------
Contract for the supply of four 501D5A combustion turbines for the Gibson 1/99
City project and the Kinmundy project; Union Electric Development
Corporation and Siemens Westinghouse Power Corporation signed in
January 1999.
- ---------------------------------------------------------------------------------------------------------------------------
Controllable losses - Coffeen - B&V
- ---------------------------------------------------------------------------------------------------------------------------
Copies of enforcement action letters for fish kills at Newton and Coffeen
- ---------------------------------------------------------------------------------------------------------------------------
Copies of operating air permits for CIPs units (single copy for identical
units)
- ---------------------------------------------------------------------------------------------------------------------------
Copy of corporate asbestos management plan or policy
- ---------------------------------------------------------------------------------------------------------------------------
Copy of corporate PCB management plan or policy
- ---------------------------------------------------------------------------------------------------------------------------
Copy of Executive Summary from S&L Cooling Lake Performance Project
for Coffeen and Newton (July 1995)
- ---------------------------------------------------------------------------------------------------------------------------
[LOGO] S&W Consultants, Inc. A-140
================================================================================================
ITEM DATE
- ------------------------------------------------------------------------------------------------
Copy of letter from IEPA and Attorney General concerning ash pond
discharge at Hutsonville
- ------------------------------------------------------------------------------------------------
Copy of pages from NPDES notebook noted with yellow paper
- ------------------------------------------------------------------------------------------------
Copy of Title IV Phase II NOx averaging plan for UE and CIPs units
- ------------------------------------------------------------------------------------------------
Copy of written description of environmental audit program if it exist
- ------------------------------------------------------------------------------------------------
Cost estimate summary, Grand Tower Repowering Project, dated 2/9/00, 2/9/00
file: GTCash.xls.
- ------------------------------------------------------------------------------------------------
Customer Final Report - Grand Tower Unit 4, Westinghouse Electric Sept-Dec 1990
Corporation
- ------------------------------------------------------------------------------------------------
Description sheet for 30 Pinckneyville project, dated 30 Sept 99. 9/30/99
- ------------------------------------------------------------------------------------------------
Design Manual for Gibson City project and Kinmundy project, Project 98-
650-1, Rev. B, File AMDM1_RB.DOC.
- ------------------------------------------------------------------------------------------------
Design Manual for Grand Tower Repowering Project, dated November 11/99
1999.
- ------------------------------------------------------------------------------------------------
Draft Contract Agreement between GE Packaged Power, Inc. and Illinois 1/26/00
Material Supply Co. for four LM6000 gas turbine generator sets, Rev. 7,
dated January 26, 2000.
- ------------------------------------------------------------------------------------------------
Envir.Management Procedures NPDES (water balance) 5/1/96
- ------------------------------------------------------------------------------------------------
Equipment and construction contract status, dated 2/9/00, file: 2/9/00
GTSTATUS.xls.
- ------------------------------------------------------------------------------------------------
Equipment Supply contract for two 501F combustion turbines for the Grand 9/99
Tower Repowering Project; Ameren Intermediate Holding Co., Inc. and
Siemens Westinghouse Power Corporation, signed in September 1999.
- ------------------------------------------------------------------------------------------------
Equivalent Forced Outage Rates 1994-1999
- ------------------------------------------------------------------------------------------------
Examination of Chimney Units 1&2 12/12/97
- ------------------------------------------------------------------------------------------------
Excess emissions summary reports for CIPs units for 1998 and 1999
- ------------------------------------------------------------------------------------------------
Exhibit A, Description of Sites for Gibson City and Kinmundy, dated, 30 9/30/99
Sept 99.
- ------------------------------------------------------------------------------------------------
Fact sheet, Grand Tower Repowering Project, file: gtfacts.doc.
- ------------------------------------------------------------------------------------------------
Grand Tower Unit 4 Turbine Generator Final Report------Westinghouse 9/90 -12/90
- ------------------------------------------------------------------------------------------------
Hanson Engineers Re: Sewage at Meredosia 11/13/90
- ------------------------------------------------------------------------------------------------
Heat Rate deviations - memo form T. Feigl 1/28/00
- ------------------------------------------------------------------------------------------------
Hot Reheat Steam Line Piping Inspection - Hutsonsville Power Station -
Unit #4, Conam Inspection
- ------------------------------------------------------------------------------------------------
Hutsonville Power Station NPDES - Average Daily Flows 7/6/94
- ------------------------------------------------------------------------------------------------
Hutsonville power station oil sampling schedule Jan-Dec
- ------------------------------------------------------------------------------------------------
Hutsonville Station - Electrostatic Precipitator Drawings, ESP Design C.O. date through
Manuals, ESP Inspection Reports, Flyash Handling System Documents, present.
Boiler Cross Sectionals, and Aerial Photograph of Site.
- ------------------------------------------------------------------------------------------------
Hutsonville Unit 3 (Boiler 5) Outage Report 10/99
- ------------------------------------------------------------------------------------------------
Hutsonville Unit 3 Boiler Inspection Report 10/14/97
- ------------------------------------------------------------------------------------------------
Hutsonville Unit 3 Boiler Inspection Report 11/97
- ------------------------------------------------------------------------------------------------
Hutsonville Unit 3 Generator Report---------G.E. 3/4/92
- ------------------------------------------------------------------------------------------------
Hutsonville Unit 3&$ Stack Examination 5/17/95
- ------------------------------------------------------------------------------------------------
Hutsonville Unit 4 Generator Report---------G.E. 3/13/90
- ------------------------------------------------------------------------------------------------
Hutsonville Unit 4 Partial Discharge Report-----------IRIS Power 12/16/99
Engineering Inc.
================================================================================================
[LOGO] S&W Consultants, Inc. A-141
=======================================================================================================
ITEM DATE
- -------------------------------------------------------------------------------------------------------
Latest 5 year forecast of NO\\x\\ emissions (tons/ozone season) and NO\\x\\
emission rates by unit for CIPs and UE units
- -------------------------------------------------------------------------------------------------------
Latest 5 year forecast of SO\\2\\ emissions (tons/yr) and SO\\2\\ emission rates by
unit for CIPs and UE units
- -------------------------------------------------------------------------------------------------------
Legal descriptions for all eight sites
- -------------------------------------------------------------------------------------------------------
Letter of Intent-Outlet Pendant SH -Meredosia Unit 3 Boiler 5 10/29/99
- -------------------------------------------------------------------------------------------------------
List of Future Budget Projects Meredosia No Date
- -------------------------------------------------------------------------------------------------------
Maintenance Schedule 2000 - 2007
- -------------------------------------------------------------------------------------------------------
Meredosia #3 start up procedures 3/8/98
- -------------------------------------------------------------------------------------------------------
Meredosia #5 Boiler Inspection 1/8/98
- -------------------------------------------------------------------------------------------------------
Meredosia #6 Boiler Inspection Memo 2/9/99
- -------------------------------------------------------------------------------------------------------
Meredosia 5 boiler Inspection 9/13/99
- -------------------------------------------------------------------------------------------------------
Meredosia Station - Electrostatic Precipitator Drawings, ESP Design C.O. date through
Manuals, ESP Inspection Reports, Flyash Handling Documents, Boiler Cross present.
Sectionals, and Aerial Photograph of Site.
- -------------------------------------------------------------------------------------------------------
Meredosia Unit 1 Generator Inspection Report------G.E. 1995
- -------------------------------------------------------------------------------------------------------
Meredosia Unit 3 Generator Rewind Report-------Siemens 1990
- -------------------------------------------------------------------------------------------------------
Meredosia Unit 4 Generator Inspection report-------Westinghouse 1978
- -------------------------------------------------------------------------------------------------------
MWH Load Reductions - Report 110 1998,1999
- -------------------------------------------------------------------------------------------------------
Newton Chimney Inspection Unit 1 5/18/98
- -------------------------------------------------------------------------------------------------------
Newton Chimney Inspection Unit 2 4/27/99
- -------------------------------------------------------------------------------------------------------
Newton Chimney Inspection Unit 2 8/18/99
- -------------------------------------------------------------------------------------------------------
Newton Dissimilar Metal Weld Inspection Unit 2 3/1999
- -------------------------------------------------------------------------------------------------------
Newton Power Station Unit 2 outage Boiler Report 1991
- -------------------------------------------------------------------------------------------------------
Newton Station - Electrostatic Precipitator Drawings, ESP Design Manuals, C.O. date through
ESP Inspection Reports, Flyash Handling, Low NO\\x\\ Burner Documents, present.
Boiler Cross Sectionals, and Aerial Photograph of Site.
- -------------------------------------------------------------------------------------------------------
Newton Unit 1 Condition Assessment Study 10/98
- -------------------------------------------------------------------------------------------------------
Newton Unit 1 Condition Assessment Study 4/97
- -------------------------------------------------------------------------------------------------------
Newton Unit 1 Generator Inspection Report ---- G. E. Sept -Nov. 1994
- -------------------------------------------------------------------------------------------------------
Newton Unit 1 Outage Inspection Report 1998
- -------------------------------------------------------------------------------------------------------
Newton Unit 1, Primary Superheater Inspection Report 11/94
- -------------------------------------------------------------------------------------------------------
Newton Unit 2 Condition Assessment 12/99
- -------------------------------------------------------------------------------------------------------
Newton Unit 2 Generator Inspection ---- Report G. E. 3/18/99
- -------------------------------------------------------------------------------------------------------
Newton Unit 2 Station Outage Report --- Newton Plant Engineer Sept -Nov. 1991
- -------------------------------------------------------------------------------------------------------
Newton Unit 2 Station Outage Report --- Newton Staff Electrical Engineer Sept -Nov. 1994
- -------------------------------------------------------------------------------------------------------
NO.5 Boiler - No.3 Turbine (good history of Hutsonville Cap.Projects) 1966-1999
- -------------------------------------------------------------------------------------------------------
No.6 Boiler 1997-1998 Outage List Work Done No Date
- -------------------------------------------------------------------------------------------------------
NO\\x\\ allowance allocations to CIPs units based on proposed Illinois NO\\x\\
budget for EGUs
- -------------------------------------------------------------------------------------------------------
NPDES Permit for Grand Tower
- -------------------------------------------------------------------------------------------------------
Outage Report-Newton 2 10/1990
- -------------------------------------------------------------------------------------------------------
Permit Application for UIC Well at Coffeen
- -------------------------------------------------------------------------------------------------------
Permit for Chemical/Putrescible and Non-Hazardous Waste Landfill at Newton
- -------------------------------------------------------------------------------------------------------
Permit for Chemical/Putrescible and Non-Hazardous Waste Landfill at Coffeen
- -------------------------------------------------------------------------------------------------------
[LOGO] S&W Consultants, Inc. A-142
========================================================================================================
ITEM DATE
- --------------------------------------------------------------------------------------------------------
Permit for Closure of Landfill at Newton
- --------------------------------------------------------------------------------------------------------
PMO Hardware 2/8/00
- --------------------------------------------------------------------------------------------------------
PMO team members 2/8/00
- --------------------------------------------------------------------------------------------------------
Post Unit 3 Outage Review -Meredosia 4/98
- --------------------------------------------------------------------------------------------------------
Project Design Manual for Pinckneyville project, Project 99-613-1, Rev. 1, 12/15/99
dated 12/15/99.
- --------------------------------------------------------------------------------------------------------
Project impacted schedule for Gibson City project, dated 1/1. 1/1
- --------------------------------------------------------------------------------------------------------
Project schedule for Pinckneyville project, run date: 18JAN00. 1/18/00
- --------------------------------------------------------------------------------------------------------
Project schedule, Grand Tower Repowering Project, run date 12/17/99. 12/17/99
- --------------------------------------------------------------------------------------------------------
Schematic of water flows - Coffeen - 1/27/98
- --------------------------------------------------------------------------------------------------------
Spreadsheet from Tim Feigl with dispatch data including a,b,c coefficients None
- --------------------------------------------------------------------------------------------------------
Staffing 1995 - 2004
- --------------------------------------------------------------------------------------------------------
Statement of SO2 allowance bank for CIPs and UE units as of 12/31/99
- --------------------------------------------------------------------------------------------------------
Superheater Outlet Header Assessment Final Report 10/26/91
- --------------------------------------------------------------------------------------------------------
Table of SO2 allowances by unit for 2000-2009 and 2010+ periods for UE
and CIPs units
- --------------------------------------------------------------------------------------------------------
Temporary variances letters related to NPDES for Coffeen and Newton
- --------------------------------------------------------------------------------------------------------
Turbine schedule - Newton - 7 years 2/14/00
- --------------------------------------------------------------------------------------------------------
Unit 1 ABB 1996 Outage Inspection Report 11/96
- --------------------------------------------------------------------------------------------------------
Unit 1 Boiler Fitness Report 1983
- --------------------------------------------------------------------------------------------------------
Unit 1 Boiler Fitness Report 1985
- --------------------------------------------------------------------------------------------------------
Unit 1 Boiler Outage 4/1992
- --------------------------------------------------------------------------------------------------------
Unit 1 Phillips, Getschow Co. Report 1998
- --------------------------------------------------------------------------------------------------------
Unit 1 Phillips, Getschow Co. Report 1999
- --------------------------------------------------------------------------------------------------------
Unit 2 Outage Inspection Report 4/99
- --------------------------------------------------------------------------------------------------------
Unit 2 Outage Inspection Report 4/97
- --------------------------------------------------------------------------------------------------------
Unit 2 Outage Report 11/1999
- --------------------------------------------------------------------------------------------------------
Unit 2 Phillips, Getshow Co. Report 1997
- --------------------------------------------------------------------------------------------------------
Unit 2 Superheater Condition Assessment 11/97
- --------------------------------------------------------------------------------------------------------
Unit 3 & 4 Boiler Pulverizer Letter 8/14/98
- --------------------------------------------------------------------------------------------------------
Unit 4 Boiler Outage Report 5/97
- --------------------------------------------------------------------------------------------------------
Unit 4 Hutsonville Outage Report 11/99
- --------------------------------------------------------------------------------------------------------
Unit capability - maximum - gross mw 10/7/99
- --------------------------------------------------------------------------------------------------------
Unit Inspection - HP Turbine - Grand Tower Unit 3, Westinghouse Electric 1999
Corporation
- --------------------------------------------------------------------------------------------------------
Unit Inspection - LP Turbine - Grand Tower Unit 3, Westinghouse Electric Oct 1997-Jan
Corporation 1998
- --------------------------------------------------------------------------------------------------------
USGS Map designations for all eight sites
========================================================================================================
[LOGO] S&W Consultants, Inc. A-143
Offices:
Boston, MA
Brisbane, Australia
Delhi, India
Denver, CO
Houston, TX
Kuala Lumpur, Malaysia
Manchester and Milton Keynes, UK
New York, NY
Pittsburgh, PA
Roseville, CA
Schenectady, NY
Washington, DC.
S&W Consultants, Inc.
1430 Enclave Parkway
Houston, TX 77077-2023
Phone: 281-368-4476, -4460
Fax: 281-368-4491 -4488
Independent Market Consultant's Report Annex B
Electricity Market Analysis of the
Midwest and Forecast of Revenues for the
Illinois Generating Assets of
Ameren Corporation
June 6, 2000
Prepared For:
Lehman Brothers
3 World Financial Center
New York, NY 10285
Prepared By:
RDI Consulting, A Financial Times Energy Company.
3333 Walnut Street
Boulder, CO 80301-2515
Tel: (720) 548-5000
Table of Contents
Table of Contents.......................................................... i
Executive Summary.......................................................... B-1
Introduction............................................................... B-10
Overview of the MAIN Region................................................ B-11
MAIN Transmission Interconnections and Flows.............................. B-12
MAIN Supply............................................................... B-13
MAIN Future Supply Overview............................................... B-16
Demand.................................................................... B-20
Institutional Market Structure............................................ B-21
Historic Pricing in MAIN.................................................. B-24
Forecast Assumptions....................................................... B-26
Existing supply........................................................... B-26
Nuclear generation........................................................ B-28
New Generation............................................................ B-29
Demand.................................................................... B-32
Reserve Requirements...................................................... B-33
Transmission Pricing...................................................... B-34
Coal Price Forecast....................................................... B-34
Environmental............................................................. B-38
Gas Price Forecast........................................................ B-39
Genco Contractual Obligations............................................. B-43
Methodology Overview....................................................... B-46
Energy Market Model....................................................... B-47
Capacity Price Model...................................................... B-48
Base Case Electricity Market Forecast...................................... B-50
Electricity Price Drivers................................................. B-50
Comparison to Current Market Prices....................................... B-52
Supply/Demand Balance..................................................... B-54
Electricity Price Forecast Sensitivity Analysis............................ B-58
Summary of Market Price Results........................................... B-58
Summary of Genco Revenues and Operations................................... B-61
Genco Generation by Asset Type and Scenario............................... B-62
Summary of Genco Revenues................................................. B-66
Appendix A: Genco Contract Load and Revenue Forecast
Appendix B: Summary of Genco Generating Unit Operations
Appendix C: Market Price Forecast Results for Sensitivity Cases
RESOURCE DATA INTERNATIONAL INC. . PAGE i
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Executive Summary
Ameren Corporation ("Ameren") has transferred its portfolio of existing Illinois
generating assets and will transfer future new builds into an unregulated
wholesale generation subsidiary ("the Genco"). Resource Data International,
Inc. (RDI) has prepared this independent lenders' assessment of Midwest
electricity markets and the economic competitiveness of Genco's current and
future generation assets. The analysis focuses primarily on the Mid-American
Interconnected Network (MAIN), which includes most of Illinois, eastern portions
of Missouri and Wisconsin, and much of peninsular Michigan (See Figure 1).
FIGURE 1
EASTERN INTERCONNECT
[A map of the Eastern United States showing the Eastern Interconnect. This
figure depicts the Mid-American Interconnected Network (MAIN), which includes
most of the State of Illinois, eastern portions of Missouri and Wisconsin and
much of peninsular Michigan and is the focus of this report. This figure also
depicts the following regions: MAPP, SPP, ERCOT, SERC, FRCC, ECAR, MAAC and
NPCC.]
This report provides a forecast of market clearing prices and dispatch profiles
for the Genco's current and certain future generation assets under a basecase
scenario and alternative scenarios. The report also describes the key
assumptions and the methodologies used in developing this assessment. During
the first five years of Genco's
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-1
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
operations, much of its capacity and energy will be sold under contracts paying
a fixed price for capacity and energy. Therefore, wholesale prices will not have
a significant impact on Genco's revenue stream until 2005 and beyond. This
report also addresses the impacts of the power purchase agreements on Genco's
future revenue streams. This report has been provided for Lehman Brothers, as
lead manager of the Rule 144A Bond financing by the Genco.
The base analytical tools utilized for this study were the Inter-Regional
Electric Market Model (IREMM) and an integrated capacity price model. IREMM is
a sophisticated production simulation model that simulates the Eastern
Interconnection bulk power supply system on an hourly basis for each year within
the time horizon of the forecast. The capacity price model is integrated with
IREMM and calculates the additional revenue required for maintenance of adequate
capacity reserves. Using these models, RDI forecasts the energy and capacity
price, and unit dispatch for Genco's assets.
SUMMARY OF RESULTS AND CONCLUSIONS
The following represents the conclusions and key findings of RDI's Midwest
market assessment and electricity price forecast:
i. The market for electricity in the Midwest is characterized by:
a. Sustained energy and peak demand growth expected to continue at an
annual average rate of 1.4% per year over the next twenty years,
compared to a weather normalized growth rate of 2.8% over the past five
years;
b. A well-developed electrical transmission system capable of transferring
high volumes of electricity throughout the Midwest;
c. Ready access to competitively priced gas and coal supplies from a
diversified range of sources;
d. A significant amount of baseload generation resources, with more than
80% of the capacity in the region currently consisting of coal and
nuclear base load facilities;
e. A shortage of generating capacity that has recently resulted in
electricity price spikes that are above the long run marginal cost of
constructing new generation facilities;
f. Up to 5,800 MW of new capacity, mainly peaking, coming on-line during
the next two summers; and
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-2
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
g. A need for as much as 24,000 MW of new generation capacity between 2000
and 2020
ii. RDI's base case electricity price forecast (including both energy and
capacity) for Southern Illinois, where Genco's assets are located, ranges
from $23 per MWh to $32.5 per MWh (in 2000 $) between 2000 and 2020 (See
Table 1 at the end of this section). Key aspects of the forecast include:
a. Table 2 and Table 3 summarize RDI's key assumptions used in developing
the forecast. The factors shown in Table 2 primarily influence the
capacity market forecast, with secondary influences on the energy
market forecast. Table 3 summarizes the factors that primarily
influence RDI's energy market forecasts, with secondary influences on
the capacity market forecasts.
b. RDI's price forecast (in 2000 dollars) never reaches a price level
higher than actual 1999 prices, and the price forecast for the year
2000 is also substantially lower than the current forward price;
c. Baseload coal generation currently sets the market price in MAIN during
as much as 80% of the hours in a year. By 2005, gas fired generation
will set market prices during as much as 35% of the hours, growing to
70% by 2010. This is primarily due to load growth and new gas capacity
coming on-line.
d. Sustained load growth in the Midwest and price spikes during peak
demand periods over the last two years have caused significant amounts
of new capacity to be added to the grid. RDI projects that over 5,800
MW of new capacity will be added by the summer of 2001, increasing
MAIN's generation supply by more than 10% and alleviating prior
shortage conditions in the region;
e. MAIN's reserve margin is likely to exceed 19% this summer and 20% next
summer, although some of this excess capacity will likely be needed in
neighboring regions;
f. Due to a moderate amount of excess capacity, RDI expects the region to
experience a near-term price decline from historic levels. RDI's
forecast indicates that prices could fall as low as $23 per MWh in 2000
and 2001. Because the region has significant amounts of low-cost
baseload capacity, RDI expects relatively low prices during periods of
excess supply. Conversely, when the region is close to a supply/demand
equilibrium, price spikes could be very high. This volatility in
pricing substantially increases the value of peaking, mid-merit, and
other units with cycling flexibility.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-3
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
g. RDI projects that the market will reach a supply/demand equilibrium by
the summer of 2002 and throughout the remainder of the forecast prices
approximate the cost of building new generation at $30 to $32 per MWh,
assuming a 60% capacity factor. The substantial price jump from 2001 to
2002 is caused by the market's move from a condition of short-run
excess supply in 2001 to a supply/demand balance in 2002. It is also
important to note that the market reaches a supply/demand equilibrium
well before the Genco's wholesale power contracts expire.
h. Over the 2002 to 2020 time frame moderate real growth in gas prices
(1.0% annually through 2012 in 2000 dollars) tends to push electricity
prices upward while expected technological improvements in the cost and
performance of new combined cycle and combustion turbine plants tend to
push prices downward. Overall, prices remain relatively constant in
real dollars.
iii. RDI's conclusions regarding its sensitivity analyses are as follows:
a. A 25% increase in gas prices and a 10% increase in coal prices results
in market price increases of 9.0% in 2000, rising to 13.2% by 2010-
2011. The effect of higher fuel prices tends to decline over time due
to the penetration of more efficient natural gas-fired generation.
b. A 25% decrease in gas prices and a 10% decrease in coal prices results
in market price declines. RDI's forecast shows progressive declines
from the base case starting at 5.3% in 2000, falling to 12% lower in
2005, and declining as much as 15% lower than the base case thereafter.
c. Capacity over-build could potentially cause price declines of as much
as 30% compared to the base case in years in which there is significant
excess capacity. Over the course of the next 20 years, it is RDI's
opinion that the region may experience periods of both capacity
shortages and excess capacity. During periods of shortages, price
spikes are likely to occur. Conversely, during periods of excess
capacity, the value of firm capacity may be diminished. Over the
duration of 20 years, RDI expects that average future electricity
prices should approximate RDI's forecasts.
d. It is important to note that RDI's overbuild scenario assumes that all
new announced capacity in the Midwest actually gets built in the time
proposed by the developer. In this scenario, the market does not reach
a supply/demand equilibrium until 2004. In reality, RDI believes it
will be difficult for all developers to build their plants within their
proposed time frames. First, with new power plant development in other
regions of the country creating a significant demand for turbines and
EPC contracts, developers have been
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-4
finding it increasingly expensive and difficult to acquire turbines and
enter into EPC contracts. Second, developers will need to obtain
environmental and other regulatory permits, acquire suitable sites,
appease local opposition, obtain increasingly scarce water resources
and interconnections, and obtain financing in a relatively short time
frame.
iv. RDI's findings regarding Genco's assets are as follows:
a. Ameren is the dominant generator in MAIN, controlling 24% of MAIN's
overall capacity. The second largest generator, Mission Energy,
controls approximately 20% of MAIN's capacity.
b. With the addition of 400 MW of peaking capacity in 2000 and 235 MW of
peaking capacity in 2001, Genco will be a diversified generation
enterprise with competitive baseload, intermediate, and peaking
generation. Figure 2 shows RDI's projected dispatch curve for the
summer of 2000. Genco has a combination of coal and natural gas units
that span the regional dispatch curve.
c. Through 2002, RDI forecasts that more than 86% of Genco's revenues will
be derived from its fixed price contract with Ameren's Marketing Co.
and other smaller long-term wholesale contracts. In 2004, RDI forecasts
that 67% of Genco's revenues will be derived from its fixed price
contracts. Although the Genco's strategy is to extend the fixed price
contracts or enter into replacement contracts, primarily of 1-3 years
duration, for the bulk of its output, our analysis assumes that Genco
will operate as a competitive generation company after 2004 and obtain
the wholesale price of power. In the overbuild scenario in which RDI
added all new proposed capacity to the grid, the market reaches an
equilibrium in 2004, which is one year before Genco will begin
operating primarily as a competitive generation company.
d. Due to the existence of substantial amounts of baseload capacity and a
shortage of peaking capacity in MAIN, RDI forecasts that it will be
more profitable to build combustion turbine facilities than combined
cycle facilities over most of the forecast horizon. This forecast is
consistent with Genco's plan to add primarily peaking capacity to its
portfolio.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-5
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 1
- --------------------------------------------------------------------------------
ELECTRICITY PRICE FORECAST FOR SOUTHERN ILLINOIS ($2000 PER MWH)
- --------------------------------------------------------------------------------
Base Case High Fuel Case Low Fuel Case Overbuild Case
Year Energy Capacity Total Energy Capacity Total Energy Capacity Total Energy Capacity Total
- ----------------------------------------------------------------------------------------------------------------------
2000 21.13 3.68 24.81 23.82 3.27 27.09 18.53 4.99 23.52 21.09 1.95 23.04
2001 20.52 4.37 24.90 23.50 3.81 27.31 17.77 5.59 23.35 20.47 2.07 22.54
2002 20.18 10.85 31.02 23.11 10.85 33.96 17.41 10.85 28.25 20.09 2.36 22.45
2003 19.90 10.75 30.64 23.04 10.75 33.78 17.47 10.75 28.22 19.88 2.57 22.45
2004 19.69 10.70 30.39 23.19 10.70 33.89 16.80 10.68 27.48 19.80 10.65 30.44
2005 20.23 10.47 30.70 23.98 10.47 34.44 16.48 10.45 26.93 20.31 10.48 30.80
2006 20.52 10.39 30.91 24.40 10.39 34.79 16.66 10.37 27.03 20.63 10.40 31.03
2007 20.76 10.32 31.09 24.71 10.34 35.05 16.70 10.32 27.03 20.94 10.34 31.28
2008 21.42 10.23 31.64 25.48 10.23 35.71 17.09 10.23 27.32 21.61 10.24 31.85
2009 21.71 10.16 31.87 25.81 10.18 35.98 17.32 10.15 27.47 21.95 10.18 32.12
2010 21.86 10.15 32.01 26.12 10.15 36.27 17.42 10.14 27.55 22.08 10.14 32.22
2011 22.20 9.63 31.83 26.38 9.40 35.78 17.61 9.74 27.35 22.37 9.59 31.96
2012 22.28 9.59 31.87 26.55 9.07 35.62 17.69 9.69 27.38 22.48 9.57 32.05
2013 22.45 9.55 32.00 26.85 9.02 35.87 17.79 9.66 27.45 22.70 9.53 32.23
2014 22.96 9.47 32.42 27.49 8.34 35.83 18.16 9.53 27.69 23.12 9.35 32.47
2015 23.16 9.29 32.45 27.74 8.19 35.93 18.32 9.52 27.84 23.36 9.05 32.41
2016 23.14 9.24 32.37 27.68 8.29 35.97 18.31 9.46 27.77 23.31 9.12 32.42
2017 23.67 8.72 32.40 28.23 7.80 36.03 18.60 9.36 27.96 23.82 8.72 32.54
2018 23.90 8.57 32.47 28.48 7.68 36.16 18.76 9.30 28.06 24.02 8.35 32.37
2019 23.93 8.54 32.47 28.65 7.67 36.32 18.81 9.26 28.07 24.09 8.43 32.52
2020 24.31 8.08 32.40 29.06 7.13 36.19 19.11 9.16 28.27 24.44 7.87 32.31
- -----------------------------------------------------------------------------------------------------------------------
* Capacity prices are converted to equivalent $/MWh values assuming a load or
capacity factor of 60%.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-6
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 2
- --------------------------------------------------------------------------------
INPUT VALUES AND ASSUMPTIONS FOR THE CAPACITY MARKET FORECAST
- --------------------------------------------------------------------------------
Parameter Input Values /1/
- --------------------------------------------------------------------------------
Demand
2000 Net Peak Projection (MW) 48,618
Annual Peak Growth 2000-2005 1.5%
Annual Peak Growth 2005-2020 1.5%
- --------------------------------------------------------------------------------
Energy
2000 Net Energy for Load (GWh) 245,561
Annual Energy Growth 2000-2005 1.4%
Annual Energy Growth 2005-2020 1.4%
- --------------------------------------------------------------------------------
Planning Reserve Margin (%) 2000-2004 15.0%
2005-2020 14.0%
- --------------------------------------------------------------------------------
New Power Plant Builds
Capital Costs ($2000/kW) CT CC
and Heat Rate (Btu/kWh) Cost Heat Rate Cost Heat Rate
2000 350.0 11,100 500.0 7,000
2005 333.0 11,100 475.7 7,000
2010 316.9 9,800 452.6 6,300
2015 301.5 9,800 430.7 6,300
2020 286.8 9,800 409.8 6,300
Fixed O&M ($2000/kW/yr) 5.0 19.0
- --------------------------------------------------------------------------------
Financial Costs for New Builds
Debt/Equity Ratio (%) 50/50
Nominal Cost of Debt (%) 8.5%
Nominal After Tax ROE (%) 15.0%
Marginal Income Tax Rate (%) 37.0%
Depreciation Schedule MACRS
General Inflation Rate 3.0%
- --------------------------------------------------------------------------------
New Capacity Additions Projected Firm Capacity Additions Plus
Additional Capacity Required to
Achieve Reserve Margin
- --------------------------------------------------------------------------------
Firmly Planned Capacity Additions MAIN ECSAR
(MW) Base Overbuild Base Overbuild
2000 3,981 5,181 3,870 4,770
2001 2,469 3,869 195 1,595
2002 575 1,975 - -
2003 326 - - -
Total Firmly Planned Additions 7,351 11,025 4,065 6,365
- --------------------------------------------------------------------------------
1. Input value for Base Case Unless otherwise noted.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-7
RDI Consulting. FT ENERGY
- --------------------------------------------------------------------------------
TABLE 3
- --------------------------------------------------------------------------------
INPUT VALUES AND ASSUMPTIONS FOR THE ENERGY MARKET FORECAST
- --------------------------------------------------------------------------------
Parameter Input Values/1/
- --------------------------------------------------------------------------------
MAIN Delivered Natural Gas Price Base Case High Fuel Low Fuel
($2000/MMBtu)
2000 2.62 3.28 1.97
2005 2.58 3.23 1.94
2010 2.78 3.47 2.08
2015 2.93 3.66 2.20
2020 3.07 3.83 2.30
- --------------------------------------------------------------------------------
Henry Hub Natural Gas Prices Base Case High Fuel Low Fuel
($2000/MMBtu)
2000 2.56 3.20 1.92
2005 2.52 3.16 1.89
2010 2.73 3.41 2.04
2015 2.88 3.60 2.16
2020 3.02 3.78 2.27
- --------------------------------------------------------------------------------
Delivered Oil Prices Base Case High Fuel Low Fuel
($2000/MMBtu)
2000 4.80 5.28 4.32
2005 4.80 5.28 4.32
2010 4.80 5.28 4.32
2015 4.80 5.28 4.32
2020 4.80 5.28 4.32
- --------------------------------------------------------------------------------
Delivered Coal Prices Base Case High Fuel Low Fuel
($2000/MMBtu)
2000 1.13 1.24 1.01
2005 0.97 1.07 0.88
2010 0.91 1.00 0.82
2015 0.85 0.93 0.76
2020 0.79 0.87 0.71
- --------------------------------------------------------------------------------
Central Illinois Southern
Appalachian Basin Powder River
Basin
Typical FOB Coal Prices
($2000/Ton)
2000 21.9 17.7 5.1
2005 20.8 16.5 5.7
2010 19.7 15.3 5.4
2015 18.9 14.4 5.2
2020 18.2 13.6 5.0
- --------------------------------------------------------------------------------
Nuclear Retirements Project 1,545 MW of early retirement
in 2001-2002; 1154 MW retire at
license expiration in 2013; 495 MW
in 2014
- --------------------------------------------------------------------------------
Fossil Retirements As indicated by Form 411 submissions
- --------------------------------------------------------------------------------
1. Input value for Base Case unless otherwise noted.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-8
RDI consulting . FT ENERGY
- --------------------------------------------------------------------------------
FIGURE 2
- --------------------------------------------------------------------------------
MAIN DISPATCH CURVE, SUMMER 2000
- --------------------------------------------------------------------------------
[A line graph illustrating the projected MAIN dispatch curve for Summer 2000.
This graph compares MAIN supply (MW) with the dispatch price ($/MWH),
pinpointing Genco coal and Genco gas/oil and illustrating peak demand and peak
plus reserve.]
- -----------------------------------------
MW Unit Price
- -- ---- -----
- -----------------------------------------
500 3.00
- -----------------------------------------
3,500 7.05
- -----------------------------------------
6,500 8.57
- -----------------------------------------
9,500 9.94
- -----------------------------------------
12,500 10.01
- -----------------------------------------
15,500 10.59
- -----------------------------------------
18,500 12.04
- -----------------------------------------
19,000 Newton 12.07
- -----------------------------------------
21,500 12.11
- -----------------------------------------
24,500 13.74
- -----------------------------------------
27,500 14.03
- -----------------------------------------
30,500 14.73
- -----------------------------------------
33,500 15.32
- -----------------------------------------
34,500 Coffeen 15.64
- -----------------------------------------
36,500 16.02
- -----------------------------------------
39,500 Hutsonville 21.52
- -----------------------------------------
40,500 Meredosia 3 22.14
- -----------------------------------------
41,500 Meredosia 1-2 25.21
- -----------------------------------------
42,500 25.21
- -----------------------------------------
44,500 Pinckneyville 34.12
- -----------------------------------------
45,500 34.79
- -----------------------------------------
47,500 Gibson 34.80
- -----------------------------------------
48,500 34.80
- -----------------------------------------
48,618 PEAK DEMAND
- -----------------------------------------
50,000 Meredosia 4 40.95
- -----------------------------------------
51,500 57.48
- -----------------------------------------
54,500 59.31
- -----------------------------------------
55,911 PEAK + RESERVE
- -----------------------------------------
57,500 117.12
- -----------------------------------------
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-9
RDO Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Introduction
Changes in the way the electric utility industry is regulated have motivated
dramatic corporate restructuring of traditional utilities, including functional
separation of electricity generation, transmission, and distribution, and
divestitures and spin-offs of generating assets. This has become abundantly
clear in Illinois, which passed The Electric Service Customer Choice and Rate
Relief Act in 1997, providing for retail competition starting in 1999, and
facilitating corporate restructuring of the state's electric utilities. Over the
past year, Unicom has sold the non-nuclear electric generating assets of
subsidiary Commonwealth Edison to national wholesaler Edison Mission Energy, and
commenced merger proceedings with PECO Energy, another retailer and operator of
nuclear assets. Unregulated energy providers Dynegy and AES Corp. acquired
Illinois Power (Illinova) and CILCORP, respectively. At the same time, Illinois
has seen growth in the construction of natural gas wholesale merchant power
plants to serve demand growth in Illinois and Wisconsin, as well as Indiana and
Ohio.
To capitalize on these trends, Ameren Corporation of St. Louis, Missouri
("Ameren") is transferring its portfolio of existing Illinois generating assets
and sites for future generation into an unregulated wholesale generation
subsidiary ("the Genco"). The Genco will remain a wholly owned subsidiary of
Ameren. This report has been provided for Lehman Brothers, as lead manager of
the Rule 144A Bond financing by the Genco.
STUDY OUTLINE
This report presents RDI's forecast in six sections. The first section presents
an overview of the MAIN region's market dynamics. The second and third sections
present RDI's forecast assumptions and methodology for projecting prices and
revenues, respectively. The fourth section provides the base case forecast of
market prices. The fifth section characterizes future risk by describing the
market forecast results of three sensitivity cases. Finally, the sixth section
presents the forecast operating results and revenues for the Genco under base
and sensitivity cases. Supporting analyses are provided in three Appendices.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-10
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Overview of the MAIN Region
This section presents an overview of the Mid-American Interconnected Network
(MAIN) region, the geographic area in which the Genco's assets operate. MAIN
comprises most of Illinois, eastern portions of Missouri and Wisconsin, and much
of peninsular Michigan. MAIN is centrally located within the Eastern
Interconnect (see Figure 3), the largest fully-integrated wholesale transmission
system in North America./1/
FIGURE 3
EASTERN INTERCONNECT
[A map of the Eastern United States showing the Eastern Interconnect. This
figure depicts the Mid-American Interconnected Network (MAIN), which includes
most of the State of Illinois, eastern portions of Missouri and Wisconsin and
much of peninsular Michigan. This figure also depicts the following regions:
MAPP, SPP, ERCOT, SERC, FRCC, ECAR, MAAC and NPCC.]
MAIN is the fourth smallest NERC region in terms of peak demand, but it borders
the two largest regions, ECAR and SERC (Table 4). As a whole, MAIN actively
imports and exports power from ECAR and SERC, as well as SPP and MAPP.
__________________
/1/ The Electric Reliability Council of Texas (ERCOT) region shown in Figure 3
is electrically isolated from the rest of the Eastern Interconnect, having only
a few AC-DC-AC interties with the Southwest Power Pool (SPP) and the Southeast
Electric Reliability Council (SERC).
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-11
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 4
NERC REGIONS BY SIZE OF MARKET (2000 PROJECTED PEAK DEMAND)
NERC Region Peak MW
-------------------------
SERC 151,085
ECAR 96,479
NPCC 95,719
MAAC 50,661
MAIN 48,618
SPP 39,135
FRCC 38,416
MAPP 38,074
-------------------------
MAIN TRANSMISSION INTERCONNECTIONS AND FLOWS
The MAIN region has large transmission interconnections with other regions.
Table 5 shows the expected summer 2000 normal base power flows and the total
transfer capability between MAIN and neighboring regions. MAIN's total export
capability is equal to 23% of its peak demand. Its import capability is equal to
11% of its peak demand. If UNICOM completes its accelerated upgrade of the
Lockport-Lombard interties to 345 kV this summer, MAIN's import capability will
increase to almost 18% of peak demand.
TABLE 5
NORMAL BASE FLOWS AND TOTAL TRANSFER CAPABILITY BETWEEN MIDWEST NERC REGIONS
-------------------------------------------------------------------------------------
Base Flow Export Capability
Region Neighbor Region (MW) (MW)
-------------------------------------------------------------------------------------
MAIN ECAR (61) 4,000
MAPP (235) 1,900
SERC (582) 3,950
SPP (112) 1,500
TOTALS (990) 11,350
-------------------------------------------------------------------------------------
ECAR MAIN /1/ 61 500
SERC (231) 3,300
TOTALS (170) 3,800
-------------------------------------------------------------------------------------
SPP MAIN 112 1,400
MAPP 147 500
SERC 93 1,400
TOTALS 352 3,300
-------------------------------------------------------------------------------------
SERC MAIN 582 3,600
MAPP 33 450
ECAR 231 2,700
SPP (93) 350
TOTALS 753 7,100
-------------------------------------------------------------------------------------
MAPP MAIN 235 1,450
SERC (33) 700
SPP (147) 2,000
TOTALS 55 4,150
-------------------------------------------------------------------------------------
(1) MAIN's Summer Assessment indicates that advance completion of scheduled
transmission upgrades may increase ECAR's export capability to MAIN to 3900
MW.
Under normal peak demand conditions, MAIN is a small net importer of power.
However, because MAIN's expected reserve margin is the highest among regions in
the Eastern
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MIDWEST ELECTRICITY MARKET ANALYSIS B-12
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Interconnection this summer, it will most likely be a net exporter
of power during peak demand conditions.
MAIN SUPPLY
MAIN has nearly 52,000 MW of installed capacity (as of January 1, 2000), with
significant amounts of new capacity expected to come on line over the next two
summers. Figure 4 breaks down MAIN's capacity by type of generation as of 1998.
One-quarter of MAIN's installed capacity is nuclear, the highest proportion of
nuclear capacity of all the NERC regions. In addition, nearly 60% of MAIN's
capacity is coal-fired. 15% of the region's capacity consists of natural gas or
oil-fired units. Many of these are older, inefficient steam units rather than
modern combustion turbines or combined-cycle units.
FIGURE 4
1998 GENERATING CAPACITY IN MAIN BY FUEL TYPE (% OF TOTAL CAPACITY)
[A pie chart illustrating the generating capacity in MAIN by fuel type. The
chart indicates the following break-down: coal, 58% of total capacity; nuclear,
25% of total capacity; gas, 12% of total capacity; oil, 3% of total capacity;
and hydro, 2% of total capacity.]
In 1998 power plants in MAIN generated approximately 220,000 GWh of electricity.
Nuclear and coal generation represent 95% of all generation in the region
(Figure 6). 3% of the electricity was generated with gas, and the remaining 2%
was generated with either oil, water, or other fuels. Consequently, baseload
coal sets prices in MAIN during most hours of the year. Figure 5 shows the
estimated percentage of hours per year each fuel type is on the margin for
determining market prices in MAIN.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-13
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
FIGURE 5
MARGINAL FUEL FOR GENERATION, 1998
[A pie chart showing the estimated percentage of hours per year that each fuel
type is on the margin for determining market prices in MAIN. The chart indicates
the following break-down: coal, 85%; natural gas, 10%; and oil, 5%.]
FIGURE 6
1998 GENERATION IN MAIN BY FUEL TYPE (% OF TOTAL GENERATION)
[A pie chart showing the composition of generation by fuel type. The chart
indicates the following break-down: coal, 62% of total generation in MAIN; uran,
33% of total generation in MAIN; gas, 3% of total generation in MAIN; and other
fuel sources, 2% of total generation in MAIN.]
Figure 7 shows MAIN's projected dispatch curve for the summer of 2000, with
markers indicating the dispatch position of the Genco's units. Approximately
39,000 MW of capacity have a dispatch price of under $20 per MWh. Based on RDI's
gas price assumptions, the dispatch price for a new combined cycle unit is
approximately $20 per MWh. The curve rises steeply after 50,000 MW, reflecting
older, less efficient oil- and gas-fired generation. The substantial amount of
relatively low cost baseload capacity in the region results in relatively low
electricity prices during many hours of the year, but also carries the potential
for great price spikes during unexpected electric system conditions. The option
value created by price spikes accruing to plants with cycling flexibility is an
important reason unregulated power providers have added peaking capacity in
MAIN.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-14
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
FIGURE 7
- --------------------------------------------------------------------------------
MAIN DISPATCH CURVE, SUMMER 2000
- --------------------------------------------------------------------------------
[A line graph illustrating the projected MAIN dispatch curve for Summer 2000.
This graph compares MAIN supply (MW) with dispatch price ($/MWH), pinpointing
Genco coal and Genco gas/oil and illustrating peak demand and peak reserve.]
- -------------------------------------------
MW Unit Price
-- ---- -----
- -------------------------------------------
500 3.00
- -------------------------------------------
3,500 7.05
- -------------------------------------------
6,500 8.57
- -------------------------------------------
9,500 9.94
- -------------------------------------------
12,500 10.01
- -------------------------------------------
15,500 10.59
- -------------------------------------------
18,500 12.04
- -------------------------------------------
19,000 Newton 12.07
- -------------------------------------------
21,500 12.11
- -------------------------------------------
24,500 13.74
- -------------------------------------------
27,500 14.03
- -------------------------------------------
30,500 14.73
- -------------------------------------------
33,500 15.32
- -------------------------------------------
34,500 Coffen 15.64
- -------------------------------------------
36,500 16.02
- -------------------------------------------
39,500 Hutsonville 21.52
- -------------------------------------------
40,500 Meredosia 3 22.14
- -------------------------------------------
41,500 Meredosia 1-2 25.21
- -------------------------------------------
42,500 25.21
- -------------------------------------------
44,500 Pinckneyville 34.12
- -------------------------------------------
45,500 34.79
- -------------------------------------------
47,500 Gibson 34.80
- -------------------------------------------
48,500 34.80
- -------------------------------------------
48,618 PEAK DEMAND
- -------------------------------------------
50,000 Meredosia 4 40.95
- -------------------------------------------
51,500 57.48
- -------------------------------------------
54,500 59.31
- -------------------------------------------
55,911 PEAK + RESERVE
- -------------------------------------------
57,500 117.12
- -------------------------------------------
The control of capacity in MAIN has become less concentrated than it was in
recent years. Figure 8 shows the market share of all generators in MAIN by
capacity. Ameren is the largest generator, followed by Mission Energy. Figure 8
also indicates the substantial degree to which assets have recently changed
hands, highlighting the following: AES' purchase of CILCORP, Dynegy's purchase
of Illinois Power, and Mission's purchase of Unicom's fossil fuel assets.
FIGURE 8
- --------------------------------------------------------------------------------
MAIN MARKET SHARE (% OF 1998 INSTALLED CAPACITY)
- --------------------------------------------------------------------------------
[A pie chart showing composition of the MAIN market share (as a percentage) by
installed capacity. The chart indicates the following break-down: Ameren, 24%
market share; Mission/CE, 20% market share; Unicom, 17% market share; WI Energy,
12% market share; Dynegy/IP, 10% market share; Alliant, 4% market share; WPS, 4%
market share; AES/CILCO, 2% market share; and other suppliers, 7% market
share.]
The East Central Area Reliability (ECAR) region, a region that connects to MAIN,
has market dynamics that are similar to MAIN's. The region, comprising Indiana,
Kentucky,
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MIDWEST ELECTRICITY MARKET ANALYSIS B-15
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Ohio, lower Michigan, and portions of states east, is almost twice the size of
MAIN, with over 100,000 MW of total installed capacity. The proportion of
baseload capacity in ECAR (92%, with the balance being peaking capacity) is even
higher than in MAIN, creating greater potential for price spikes and the
associated value for units with cycling flexibility. While peaking capacity is
being added in ECAR as well, higher delivered natural gas prices have resulted
in slower penetration of gas plants into the region than in MAIN. It is likely
that generating additions in MAIN are driven by load growth, access to lower gas
prices than neighboring regions, and the need for new capacity in both MAIN and
ECAR.
MAIN FUTURE SUPPLY OVERVIEW
This section presents RDI's outlook for MAIN supply over the forecast period,
including shifts in capacity mix, generation patterns, and plant dispatch.
Capacity Mix As with most other regions of the country, additions of capacity
- ------------
in MAIN are predominantly gas-fired combustion turbines and combined cycle
plants. This will shift the capacity mix over time toward gas-fired capacity.
Because MAIN has a shortage of peaking capacity, most of the new gas capacity is
expected to be combustion turbines. No new steam coal plants are planned for the
MAIN region, although uprates are possible at existing units. Nuclear capacity
is expected to decline moderately as older units retire in 2001 and 2014. Figure
9 shows the forecast capacity mix in 2005 and in 2015. New gas-fired capacity
additions are projected to reduce coal's share of total capacity from 53% to 46%
between 2005 and 2015.
FIGURE 9
- --------------------------------------------------------------------------------
MAIN CAPACITY SHARE BY PLANT TYPE 2005 AND 2015
- --------------------------------------------------------------------------------
[Two pie charts showing the forecast capacity mix in 2005 and 2015.
The 2005 pie chart indicates the following break-down: coal plants, 53% capacity
share; nuclear plants, 19% capacity share; new gas CT plants, 11% capacity
share; existing peaking plants, 9% capacity share; gas baseload plants, 5%
capacity share; hydro plants, 2% capacity share; and other sources, 1.1%
capacity share.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-16
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
The 2015 pie chart indicates the following break-down: coal plants, 46% capacity
share; nuclear plants, 14% capacity share; new gas CT plants, 12% capacity
share; existing peaking plants, 7% capacity share; gas baseload plants, 7%
capacity share; advanced CT plants, 6% capacity share; advanced CC plants, 5%
capacity share; hydro plants, 2% capacity share; and other sources, 1% capacity
share.]
Generation Mix Over time, RDI expects that coal fired generation will continue
- --------------
to be the dominant fuel used for electric generation in the region. Coal's share
of generation is forecast to be 65% in 2005 and 61% in 2015 (See Figure 10).
Nuclear generation is forecast to decline between today and 2015 as a few
retirements cause a nuclear generation decline. Gas fired generation is expected
to increase its share of total generation slightly, reaching 4% in 2005 and 15%
in 2015. It is important to note that even though substantial gas capacity
additions are currently being built in the MAIN region, gas' share of the market
is only forecast to increase to 4% by 2005, from 3% in 1998. This is primarily
because most additions are peaking capacity that is expected to operate at
relatively low capacity factors during most of the year.
FIGURE 10
- --------------------------------------------------------------------------------
MAIN GENERATION MIX BY PLANT TYPE 2005 AND 2015
- --------------------------------------------------------------------------------
[Two pie charts showing the forecast capacity mix in 2005 and 2015.
The 2005 pie chart indicates the following break-down: coal plants, 65% of
generation; nuclear plants, 30% of generation; gas baseload plants, 3% of
generation; new gas CT plants, 1% of generation; hydro plants, 1% of generation;
existing peaking plants, 0% of generation; and other sources, 0% of generation.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-17
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
The 2015 pie chart indicates the following break-down: coal plants, 62% of
generation; nuclear plants, 23% of generation; gas baseload plants, 12% of
generation; new gas CT plants, 2% of generation; hydro plants, 1% of generation;
existing peaking plants, 0% of generation; and other sources, 0% of generation.]
Marginal Fuel for Generation Because the increase in efficient gas-fired
- ----------------------------
generation coincides with growing loads, the percentage of hours natural gas is
on the margin for generation requirements grows rapidly. Figure 11 shows that
the percentage of hours natural gas is on the margin switches places with coal,
increasing from 35% of all hours in 2005 to 63% in 2015.
FIGURE 11
- --------------------------------------------------------------------------------
MARGINAL FUEL FOR GENERATION 2005 AND 2015
- --------------------------------------------------------------------------------
2005
[Two pie charts showing the percentage of hours that different fuel types are on
the margin for generation requirements.
The 2005 pie chart indicates the following break-down: coal, 64%; natural gas,
35%; and oil, 1%.]
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MIDWEST ELECTRICITY MARKET ANALYSIS B-18
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
[The 2015 pie chart indicates the following break-down: natural gas, 63%; coal,
36%; and oil, 1%.]
Changes in Dispatch MAIN's dispatch curve is not forecast to change
- -------------------
substantially for baseload units by 2005. The retirement of 1,500 MW of nuclear
capacity is offset by price declines at regional coal units, resulting in
approximately 40,000 MW still having a dispatch price under $20/MWh (in real
terms). By 2010, growth in demand results in higher cost capacity being called
on during more hours of the year than in the earlier years of the forecast. This
demand will be met by combustion turbines with dispatch prices of $40/MWh.
Figure 12 shows projected dispatch prices for MAIN's units, noting the position
of the Genco's assets on the curve.
FIGURE 12
- --------------------------------------------------------------------------------
MAIN PEAK PERIOD DISPATCH CURVE 2005 AND 2010
- --------------------------------------------------------------------------------
[Two line graphs comparing MAIN supply (MW) with dispatch price ($/MWH) for
years 2005 and 2010, pinpointing Genco coal and Genco gas/oil and illustrating
peak demand and peak plus reserve.]
- --------------------------------------------------------
2005 Unit Price
- --------------------------------------------------------
500 (MW) 3.00
- --------------------------------------------------------
3,500 6.96
- --------------------------------------------------------
6,500 7.70
- --------------------------------------------------------
9,500 9.12
- --------------------------------------------------------
12,500 10.30
- --------------------------------------------------------
15,500 10.97
- --------------------------------------------------------
17,500 Newton 12.20
- --------------------------------------------------------
18,500 12.22
- --------------------------------------------------------
21,500 12.27
- --------------------------------------------------------
24,500 13.08
- --------------------------------------------------------
27,500 13.59
- --------------------------------------------------------
30,500 15.26
- --------------------------------------------------------
33,500 15.65
- --------------------------------------------------------
34,500 Coffeen 15.88
- --------------------------------------------------------
36,500 17.11
- --------------------------------------------------------
38,000 Meredosia 3 18.93
- --------------------------------------------------------
39,500 19.68
- --------------------------------------------------------
41,000 Hutsonville 21.68
- --------------------------------------------------------
41,250 Meredosia 1-2 21.82
- --------------------------------------------------------
41,500 GrandTower CC 22.45
- --------------------------------------------------------
42,500 24.58
- --------------------------------------------------------
45,500 Pinckneyville 31.12
- --------------------------------------------------------
45,750 Gibson 32.79
- --------------------------------------------------------
47,500 Kinmundy 34.05
- --------------------------------------------------------
48,500 34.33
- --------------------------------------------------------
50,000 Meredosia 4 34.34
- --------------------------------------------------------
51,500 38.02
- --------------------------------------------------------
52,314 PEAK DEMAND
- --------------------------------------------------------
54,500 56.98
- --------------------------------------------------------
57,500 69.20
- --------------------------------------------------------
59,638 PEAK + RESERVE
- --------------------------------------------------------
60,500 116.59
- --------------------------------------------------------
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-19
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
- --------------------------------------------------
2010 Unit Price
---- -----
- --------------------------------------------------
500 (MW) 3.00
- --------------------------------------------------
3,500 6.88
- --------------------------------------------------
6,500 6.95
- --------------------------------------------------
9,500 8.36
- --------------------------------------------------
12,500 9.98
- --------------------------------------------------
15,500 10.43
- --------------------------------------------------
17,500 Newton 11.65
- --------------------------------------------------
18,500 11.76
- --------------------------------------------------
21,500 11.85
- --------------------------------------------------
24,500 12.28
- --------------------------------------------------
27,500 13.16
- --------------------------------------------------
30,500 14.90
- --------------------------------------------------
33,500 15.12
- --------------------------------------------------
34,000 Coffeen 15.46
- --------------------------------------------------
36,500 18.16
- --------------------------------------------------
38,000 Meredosia 3 18.91
- --------------------------------------------------
39,500 21.07
- --------------------------------------------------
42,500 21.07
- --------------------------------------------------
43,000 Hutsonville 22.49
- --------------------------------------------------
43,750 Meredosia 3 22.50
- --------------------------------------------------
44,200 GrandTower CC 24.10
- --------------------------------------------------
45,500 26.33
- --------------------------------------------------
48,000 Pinckneyville 34.37
- --------------------------------------------------
48,500 Gibson 35.94
- --------------------------------------------------
49,000 Kinmundy 35.95
- --------------------------------------------------
51,500 36.53
- --------------------------------------------------
54,500 Meredosia 4 36.54
- --------------------------------------------------
56,291 PEAK DEMAND
- --------------------------------------------------
57,500 48.41
- --------------------------------------------------
60,500 56.59
- --------------------------------------------------
63,500 115.97
- --------------------------------------------------
64,172 PEAK + RESERVE
- --------------------------------------------------
DEMAND
MAIN has experienced weather-normalized load growth of approximately 2.8% since
1993. Peak demand during that period grew by 2.5%. MAIN's most recent
projections call for a slowdown in economic growth, which in turn slows load and
peak demand growth. Both load and peak demand is projected to increase at 1.4%
per year over the forecast period. Figure 13 shows the peak demand forecast for
MAIN compared to recent history and it shows the peak demand forecast versus
what the forecast would have been using historical growth rates as the basis for
the forecast. The trend line indicates that if growth continued per historical
trends since 1993, peak demand would be higher than forecast by approximately
7,600 MW in 2015, or 505 MW per year. Figure 14 shows the energy forecast for
MAIN, with similar history and similar trend line. If load growth continued per
historical trends, overall energy consumption would be 20% higher in 2015 than
forecast.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-20
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
FIGURE 13
MAIN HISTORIC AND PROJECTED PEAK DEMAND GROWTH
[A line graph showing historical demand growth from 1990 through 1999 and
projected demand growth through 2015. The graph charts the summer peak, the
winter peak and the history trend line.]
- --------------------------------------------------------------------------------
Summer Peak Winter Peak History Trend Line
----------- ----------- ------------------
- --------------------------------------------------------------------------------
1990 40,740 32,461
- --------------------------------------------------------------------------------
1992 38,819 31,289
- --------------------------------------------------------------------------------
1994 42,562 33,999 42,889
- --------------------------------------------------------------------------------
1996 46,402 37,162 44,818
- --------------------------------------------------------------------------------
1998 47,509 37,410 46,833
- --------------------------------------------------------------------------------
2000 48,618 39,019 48,940
- --------------------------------------------------------------------------------
2002 49,838 40,034 51,141
- --------------------------------------------------------------------------------
2004 51,439 40,848 53,441
- --------------------------------------------------------------------------------
2006 53,122 42,205 55,844
- --------------------------------------------------------------------------------
2008 54,670 43,451 58,355
- --------------------------------------------------------------------------------
2010 56,291 44,703 60,980
- --------------------------------------------------------------------------------
2012 57,894 45,926 63,722
- --------------------------------------------------------------------------------
2014 59,610 47,251 66,588
- --------------------------------------------------------------------------------
FIGURE 14
MAIN HISTORIC AND PROJECTED ENERGY GROWTH
[A line graph showing historical energy growth (GWh) from 1990 through 1999 and
projected energy growth through 2015. The graph charts a forecast line and a
history trend line.]
- -------------------------------------------------------
Forecast History Trend Line
-------- ------------------
- -------------------------------------------------------
1990 197,326
- -------------------------------------------------------
1992 200,250
- -------------------------------------------------------
1994 213,803 213,635
- -------------------------------------------------------
1996 234,300 224,632
- -------------------------------------------------------
1998 244,073 236,194
- -------------------------------------------------------
2000 245,561 248,352
- -------------------------------------------------------
2002 251,787 261,136
- -------------------------------------------------------
2004 258,617 274,578
- -------------------------------------------------------
2006 266,661 288,712
- -------------------------------------------------------
2008 274,054 303,573
- -------------------------------------------------------
2010 281,684 319,199
- -------------------------------------------------------
2012 289,526 335,630
- -------------------------------------------------------
2014 297,587 352,906
- -------------------------------------------------------
INSTITUTIONAL MARKET STRUCTURE
The two key trends influencing institutional change in the MAIN region are state
legislation deregulating utilities and progress toward the formation of an
independent regional transmission operator, or Midwest Independent System
Operator (MISO).
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-21
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
DEREGULATION
The three primary states making up MAIN have so far pursued divergent paths
toward deregulation of their respective utilities. Illinois has enacted
legislation allowing customer choice, which has in part prompted the rapid
development of merchant power in the state. Wisconsin has taken steps to
encourage merchant development, but has stopped short of customer choice.
Missouri has yet to enact legislation or promulgate orders related to
deregulation. Specific activities by states are as follows:
. Illinois. Illinois deregulated its electricity markets with the passage
of the "Electric Service Customer Choice and Rate Relief Act of 1997".
The first third of commercial and industrial consumers were able to
choose their supplier on October 1, 1999. The second third will choose
beginning June 1, 2000. The remaining third are open to the market on
October 1, 2000. Residential customers will receive a 5% rate reduction
by October 1, 2001, and all consumers will be able to choose their
supplier starting May 2002.
. Wisconsin. Legislative investigation regarding deregulation of
utilities is ongoing. In 1997, a regulatory order resolved to first
improve infrastructure and reliability among utility companies before
moving forward to retail competition. To deter power shortages and
increase reliability, legislation passed in April 1998 encouraged
merchant developed and allowed the formation of independent regional
system operators. It allows plants to be built with a maximum capacity
of 100 MW without Public Service Commission approval. Existing
utilities are required to join an ISO and, by 2000, generate 50 MW of
power using renewable resources. Pending legislation includes the
"Reliability 2000" proposal. Transmission rights would be turned over
to a non-profit organization, and low-income customers would receive
subsidization.
. Missouri. The Public Service Commission assembled the Retail Electric
Competition Task Force to investigate retail wheeling and related
deregulation issues. Its final report generally bypasses specific
recommendations, stating only that the Commission is satisfied with
regulatory change if it does not degrade safety, reliability, or
equitability to the customer. Proposed legislation calls for market
restructuring by January 2000 or January 2002. To date, the legislature
has taken no further action.
MIDWEST ISO
The second key trend affecting MAIN is the emergence of the Midwest Independent
System Operator (MISO) as a regional transmission organization (RTO). FERC
approved the formation of MISO in September 1998. MISO is currently in a
transition stage that is expected to last approximately six years, as members
relinquish control of their
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-22
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
transmission assets to the centralized ISO. Figure 15 shows the current members
and geographic coverage of the organization. In December 1999, MISO executed a
Memorandum of Understanding with the Mid-Continent Area Power Pool (MAPP), and a
Letter of Agreement with the Southwest Power Pool (SPP). These arrangements
would open the door for moving the transmission control functions of those NERC
regions over to MISO, essentially expanding the geographic coverage of MISO to
the western most portions of the Eastern Interconnection.
MISO transforms the Midwest transmission system from a series of independently
owned and operated, smaller transmission systems, to a single integrated
transmission system. MISO should foster reliability improvements in the region
by coordinating planning, security, maintenance and the provision of ancillary
services. As currently proposed, MISO will not operate as a single control area.
Thus, control area operators will determine their own plant dispatch independent
of the ISO. Moreover, MISO will not act as a Power Exchange or Power Pool such
as the ISO's in California, New England, New York and PJM. In other words,
members will not be required to sell their generating output into a single
exchange at a pool price. Rather, members will continue to transact bilaterally,
with MISO rules covering transmission pricing and provision of ancillary
services.
FIGURE 15
MIDWEST ISO CURRENT MEMBERSHIP
[A map of the United States listing the signatories of the Midwest Independent
System Operator and showing their geographic locations. This figure provides
the following information regarding the Midwest ISO:
. Operating in portions of fourteen states: Illinois, Indiana, Iowa,
Kentucky, Maryland, Michigan, Missouri, North Dakota, Ohio,
Pennsylvania, South Dakota, Virginia, West Virginia and Wisconsin.
. Overseeing 57,000 miles of transmission lines.
. Encompassing 87,000 megawatts of electric generation.
. Service territory covering more than 284,000 square miles.
Members of the Midwest ISO include: Allegheny Power, Ameren, CILCO, Cinergy,
Hoosier Energy Rural Electric Cooperative, Wabash Valley Power, Illinois Power,
Louisville Gas & Electric, Wisconsin Electric, SIGECO, NSP, Alliant Energy,
Commonwealth Edison and Southern Illinois Power Cooperative.]
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-23
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
For generators in MAIN, the most significant implication of MISO is the
elimination of the pancaking of transmission tariffs. Previously, a generator in
Missouri that intended to sell wholesale power to a utility in Ohio, would have
to pay a transmission tariff to use the transmission system of each utility
between Missouri and Ohio. In other words, if Utility A in Missouri had to pay a
$2.50 per MWh transmission fee to use the transmission systems of five different
utilities in order to transport its power to Utility B in Ohio, Utility A would
incur a $12.50 per MWh transmission cost. The cumulative impact of paying each
transmission tariff is referred to as the "pancaking" of transmission tariffs.
MISO would eliminate the cumulative effect of transmission tariffs by
instituting one uniform wheeling charge for transporting power within the ISO
based on an average transmission tariff within the system. Consider the previous
example. In order for Utility B to want to buy Utility A's power, it would have
to be more than $12.50 per MWh cheaper for Utility A to generate power than
Utility B. It must also be significantly cheaper for Utility A to generate power
than other utilities that are closer to Utility B via the transmission system.
The transmission tariffs act as an economic hurdle blocking Utility A from
selling power to Utility B. Now assume that MISO institutes one uniform
transmission charge of $2.50 per MWh for transporting power across the ISO. With
the elimination of pancaked transmission tariffs, Utility A can sell power in
Ohio if its power is only $3.00 cheaper than generation in Ohio. Moreover, it
will compete on equal footing with other MISO members that are closer to Utility
B via the transmission system.
In essence, this pricing scheme opens distant geographic markets to generators
within MISO. It may also have the affect of allowing low-sulfur, South Powder
River Basin (SPRB) coal to move east "by wire". Eastern utilities that have the
option of using low-sulfur SPRB coal to reduce sulfur emissions at their plants,
must currently weigh the considerable cost of transporting that coal by rail and
barge to their plants against the cost of generating with high sulfur coal and
buying allowances for emissions. The elimination of pancaked transmission
tariffs opens the possibility that eastern utilities can buy power generated by
SPRB coal from plants in the western portions of MISO at a lower cost than
buying the coal themselves and transporting it to their plants.
HISTORIC PRICING IN MAIN
In 1998 and 1999 wholesale electricity prices in MAIN average approximately $36
per MWh and $33 per MWh, respectively. Due to significant amounts of relatively
low cost baseload power, prices in the winter months ranged from $16 to $19 per
MWh. Average prices during the summer months were almost five times higher than
the winter prices. This is largely due to summer time price spikes.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-24
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 6
HISTORIC WHOLESALE ELECTRICITY PRICES IN MAIN
RDI CINERGY
MONTH 1998 1999 2000 2000
----------------------------------------------------
JAN 17.45 19.27 22.06 29.42
FEB 16.42 16.64 22.20 27.03
MAR 20.84 18.19 20.10 20.21
APR 19.89 21.79 17.92 22.84
MAY 31.80 19.86 19.24 29.39
JUN 144.99 31.77 29.62 64.87
JUL 81.04 149.89 29.63 145.21
AUG 26.51 44.17 46.04 127.27
SEP 23.45 16.98 21.33 32.45
OCT 18.08 18.43 18.36 24.47
NOV 18.80 17.82 19.95 24.94
DEC 17.99 17.62 20.00 26.00
----------------------------------------------------
AVERAGE 36.44 32.99 23.87 47.84
Source: Megawatt Daily, RDI
A combination of factors has led to these spikes in prices during peak demand
periods. These spikes are attributable both to fundamental trends and to
specific factors, including the following:
. Peak demand growth was not met with corresponding increases in
installed peaking capacity, so the relative scarcity of peak capacity
became more acute;
. Extended outages at nuclear plants made them unavailable during peak
demand periods, dramatically increasing the level of shortages in the
market;
. The absence of key nuclear units created transmission voltage support
problems, which tended to constrain the amount of power available to
import from other regions;
. The fragmentation of control over wholesale transmission systems made
it increasingly difficult to coordinate procedures such as Transmission
Line Relief (TLR), and;
. Many of these factors plagued the neighboring East Central Area
Reliability Coordination (ECAR) region, creating local constraints and
driving its prices up as well.
While some of these factors are likely to persist over the next two summers, the
availability of nuclear units and the addition of new peaking capacity in the
merchant development sector changes the outlook for MAIN in the near term, as
some of the market shortages begin to ease.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-25
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Forecast Assumptions
This section of the report provides a detailed accounting of the factors driving
the RDI's base case forecast. For this analysis, RDI modeled the entire Eastern
Interconnection. This section of the report, however, focuses primarily on the
MAIN region where Genco's assets are located.
EXISTING SUPPLY
The supply curves constructed by RDI for this analysis were built on a unit by
unit basis. The utility-owned unit data are based on the annual EIA-411 reports
supplied to the Department of Energy via the regional councils of the North
American Electric Reliability Council (NERC), and from RDI's proprietary
databases. RDI also verified the EIA-411 report by utilizing integrated resource
plans where available and RDI's internal databases. Information specific to
Ameren's current and planned generating units was obtained from Ameren. Key
assumptions relating to generating units were as follows:
. Unit Ratings The EIA-411 report was used to determine the summer and
winter capacity ratings of each unit on the grid.
. Primary and Alternate Fuel Types For non-coal burning plants, RDI
determined each type of fuel that can be used at a generating unit from
EIA-411 reports. Each month the relative price of alternate fuels is
compared to the primary fuel and the least expensive fuel is selected. Coal
fired plants are treated separately and are discussed later in this
section.
. Availability Availability statistics for all non-nuclear units were
obtained from aggregate NERC/GADS statistics by prime mover type. The
equivalent availability factor (EAF)/2/ and the equivalent forced outage
rate/3/ (EFOR) were used to calculate the scheduled outage factor (SOF) to
determine the maintenance period for each unit. Average 1998 availability
factors and forced outage rates are shown in Table 7. Unit specific EAFs
and EFORs are developed for all nuclear units based upon refueling
schedules, historic performance, technology type, and the probability of
encountering generic problems related to the technology type. This data was
developed through a study commissioned by RDI and conducted by an
independent engineering consultant. For Ameren's units, Ameren provided
___________________
/2/ EAF is the percentage of hours in the year that a unit is available to
operate.
/3/ EFOR is the percentage of hours in the year in which a plant will incur an
unplanned outage.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-26
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
forecasts of EAF and EFOR for planned and existing generating units.
Availability projections for coal-fired units of Commonwealth Edison were
also available from Standard & Poor's./4/
TABLE 7
1998 AVERAGE AVAILABILITY STATISTICS
EAF EFOR
- ------------------------------------------------
STEAM TURBINES 82% 7.0%
GAS TURBINES 83% 4.9%
================================================
. Heat Rates: Heat rate information was obtained from RDI's POWERdat
information system, based on a combination of EIA-411 and EIA-860
information. Ameren provided unit-specific full load heat rates.
. Non-Fuel Variable O&M: Variable O&M costs affect the dispatch price of
individual units. Variable O&M calculations vary across utilities. For
our analysis, RDI assumes a variable O&M of $1.20 per MWh for all steam
turbines and combined cycle units/5/ and $5 per MWh for all gas-fired
peaking turbines. The higher O&M cost for a gas turbine is intended to
reflect the additional start-up costs such units typically incur. Units
with scrubbers are assigned an additional $1 per MWh charge based on
information reported in the EIA-767 form by utilities.
. Fixed O&M: Fixed O&M expenses are used in RDI's model to evaluate
potential retirement decisions. Fixed O&M calculations for individual
plants were based on data filed with the Energy Information
Administration. For each plant and prime mover type, the fixed O&M was
calculated as the difference between total O&M less the assumed variable
costs. Since there can be significant year to year swings in O&M
expenses due to major overhauls or other major non-recurring costs, RDI
averaged fixed O&M expenses from 1996 through 1998.
The above approach was used to estimate fixed O&M expenses for all
utility owned generation. However, actual power plant O&M cost
information is not publicly available for non-utility owned plants. For
non-utility coal units, it is assumed that fixed O&M expenses equal $15
per kW. Based on previous work for independent power companies, RDI
believes this is a reasonable assumption. For non-utility generating
units that have contracts guaranteeing a fixed price for their output,
it was not necessary to make any assumptions regarding fixed O&M.
. Replacement Capital Costs: Since generating assets are assumed to
maintain operations over the forecast horizon (unless it is uneconomic
to do so), it is also assumed that replacement capital would have to be
invested to keep the plant in service. It is also necessary to include
replacement capital costs in the model
_________________
/4/ See Infrastructure Finance, November 1999, Table 5, page 9.
----------------------
/5/ This estimate is based upon analysis performed by an engineering consulting
firm in a previous RDI project.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-27
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
because many utilities account for operating expenses as capital costs to
be included in ratebase. The cost of replacement capital in this analysis
is based on the historic information and trends shown in Figure 16. It is
largely consistent with replacement cost information presented in numerous
utility Integrated Resource Plans as well. Replacement capital costs are
also used in the evaluation of potential plant retirements.
FIGURE 16
UTILITY ANNUAL CAPITAL ADDITIONS ($/KW-YR)
[A line graph showing historic information and trends about annual capital
additions for utilities for the years 1988 through 1995. The graph compares the
annual additions of steam, nuclear, hydro and other utilities.]
- -----------------------------------------------------------------------
Steam Nuclear Hydro Other
----- ------- ----- -----
- -----------------------------------------------------------------------
1988 6.50 10.75 3.00
- -----------------------------------------------------------------------
1989 7.00 36.50 8.75 2.00
- -----------------------------------------------------------------------
1990 7.50 35.00 9.00 3.00
- -----------------------------------------------------------------------
1991 9.00 28.50 9.00 7.00
- -----------------------------------------------------------------------
1992 9.50 25.00 10.00 4.50
- -----------------------------------------------------------------------
1993 10.00 25.50 9.50 4.50
- -----------------------------------------------------------------------
1994 15.00 22.50 9.50 3.50
- -----------------------------------------------------------------------
1995 10.00 20.00 8.00 8.00
- -----------------------------------------------------------------------
NUCLEAR GENERATING ASSUMPTIONS
The expected balance of nuclear plant capacity in MAIN and neighboring regions
can influence market prices and the mix of forecast generating capacity
additions. RDI reviewed and projected nuclear capacity for MAIN, ECAR and
NPCC-Canada.
Early Retirements Several nuclear units in MAIN have a history of operating
problems and extended outages, including Dresden, Quad Cities, and Clinton. RDI
assumed that Quad Cities and Clinton will continue to operate through the
remainder of their licenses, and that Dresden will close in September 2001 due
to the high cost of turbine overhauls needed to keep it running.
RDI assumed that all currently operating nuclear units in ECAR continue to
operate for the duration of the forecast. DTE's Fermi nuclear plant is a
candidate for closure due to high production costs relative to other nuclear
facilities. Absent major repair issues, however, RDI believes deregulation will
force improvements in Fermi's performance and Fermi will therefore continue to
operate through the remainder of its license.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-28
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
NEW GENERATION
According to RDI's NewGen database, nearly 10,500 MW of generating capacity has
been proposed to come on line between 1999 and 2001 in MAIN. An additional 6,000
MW has been proposed for ECAR during this time. These figures include all
announced projects, no matter how preliminary. Many of these projects face
significant development hurdles and are unlikely to be completed.
Only those announced merchant plant or utility projects that RDI considers
likely to be seen to completion given today's information are explicitly modeled
in the basecase scenario. In this case of MAIN, this consists almost exclusively
of units that are expected to come on line before 2002. Other future capacity
additions are added only as they are economically justified through the course
of the forecast. Projects that RDI considers likely to be seen to completion are
either under construction or have other strong indications of moving forward
such as the existence of:
. a signed firm power agreement for its output with a third party,
. a contract for fuel supply,
. an announced dedicated site with existing infrastructure or firm plans to add
infrastructure;
. approved permits;
. dedicated turbines that have been acquired for the specific project; or
. project financing.
Table 8 shows the new units explicitly modeled in RDI's base case./6/ Of the
6,421 MW explicitly added, 5,440 MW is scheduled to be added by 2001.
Approximately 4,000 MW are added to ECAR during this time as well.
________________
/6/ New capacity shown in Table 8 excludes 930 MW of new plant development by
Genco.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-29
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 8
- --------------------------------------------------------------------------------
NEW CAPACITY ADDED BY 2004 - BY PROJECT
- --------------------------------------------------------------------------------
NEW RDI
PRIME CAPACITY ONLINE PROJECT
NAME ST MOVER MW DATE STATUS
- ---------------------------------------------------------------------------------------------------------
AmerenUE / Meramec CTG2 MO CT 50 Jun-00 Advanced Development
CalEnergy / Cordova Energy IL CC 537 Jan-01 Under Construction
Dynegy / Rocky Road Power IL CC 250 Jun-99 Operating
EEI Joppa CTs IL CT 155 Jun-00 Advanced Development
Elwood Energy IL CT 600 Jul-99 Operating
Enron / Lincoln Energy Center IL CT 668 Jun-00 Under Construction
Illinois Power / Havana CTs IL CT 238 Jun-99 Restart of reserved units
Illinois Power / Tilton IL CT 176 Jun-99 Operating
LS Power / Kendall County IL CC 1,100 Jun-01 Firm Contracts
Madison Gas & Electric Wind WI WND 3 Jun-99 Operating
NRC Cogen (Equistar) IL CT 117 Jun-99 Operating
Reliant / Neoga IL CT 350 Jun-00 Advanced Development
SkyGen Energy / De Pere Energy WI CT 179 Jun-99 Operating
SkyGen Energy / Rockgen Energy WI CT 300 Jun-01 Site, Reg Approv, Infra.
Southern Energy / Neenah WI CT 525 Jun-00 Advanced Development
Southwestern / St. Elmo IL CT 45 Jun-00 Advanced Development
Soyland / Alsey IL CT 120 Jun-00 Operating
Trigen / St Louis Cogen (Ashley) MO CC 15 Jun-99 Operating
Trigen / Tuscola IL CC 6 Jan-00 Operating
New CTs - site unidentified IL CT 575 Jun-02 Planned
New CTs - site unidentified IL CT 326 Jun-03 Planned
Wisconsin Energy / Fond Du Lac Wind WI WND 0.3 Jan-00 Operating
WPS Resources / Kewaunee Wind WI WND 3 Jan-00 Operating
WPS Resources / West Marinette WI CT 83 Jun-00 Site, Reg Approv, Infra.
- ------------------------------------------------------------------------------------------------------------
TOTAL NEW CAPACITY BY JAN 2004: 6,421
It is important to note that the projects listed in Table 8 do not represent the
sum total of capacity added in RDI's modeling efforts. They simply represent
those new capacity projects that are explicitly modeled in RDI's electricity
market model, IREMM. The IREMM model will add additional capacity as it is
needed to maintain target reserve margins in the region. As a result of planned
additions, shown in Table 8, IREMM does not add additional capacity until 2004
and beyond in MAIN.
Cost of New Generation Technologies
The cost of new generation technologies has been determined through RDI's work
with other developers and a review of publicly available documents. These
assumptions are shown in Table 9. In an effort to decrease heat rates and
increase efficiency, combustion turbine (CT) technology has made substantial
technological progress in the last five years.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-30
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 9
- --------------------------------------------------------------------------------
COST OF NEW TECHNOLOGIES ($2000)
- --------------------------------------------------------------------------------
COMBINED COMBUSTION COAL
CYCLE TURBINE PLANT
- --------------------------------------------------------------
CONSTRUCTION PERIOD 2 YEARS 1 YEARS 3 YEARS
INITIAL CAPITAL COSTS 500 350 900
($/KW)
VARIABLE O&M ($/MWH) 1.2 5* 1.5
FIXED O&M ($/KW-YR) 19 5 20
AVAILABILITY FACTOR 92% 95% 88%
HEAT RATE 7,000 11,100 9,000
- --------------------------------------------------------------
*Variable O&M for combustion turbines consists primarily of start-up costs.
After 2010, RDI's modeling assumes that advanced series turbines are developed
and implemented in newly constructed combined cycle and combustion turbine
plants. These turbines are characterized by a 10% improvement in heat rates
(6,300 for combined cycle units and 9,800 for combustion turbines). Table 10
shows the cost and heat rate of new combined cycle and combustion turbine plants
from 2000-2020. The cost of building a new gas plant is assumed to decrease 1%
in real terms each year of the forecast. This applies to both current and
advanced vintage turbines.
TABLE 10
- --------------------------------------------------------------------------------
ANNUAL COST AND HEAT RATE OF NEW TECHNOLOGIES ($2000)
- --------------------------------------------------------------------------------
Combined Cycle Combustion Turbine
Cost Heat Rate Cost Heat Rate
Year ($/kW) (Btu/kWh) ($/kW) (Btu/kWh)
- --------------------------------------------------------------
2000 500 7,000 350 11,100
2001 495 7,000 347 11,100
2002 490 7,000 343 11,100
2003 485 7,000 340 11,100
2004 480 7,000 336 11,100
2005 476 7,000 333 11,100
2006 471 7,000 330 11,100
2007 466 7,000 326 11,100
2008 462 7,000 323 11,100
2009 457 7,000 320 11,100
2010 453 7,000 317 11,100
2011 448 6,300 314 9,800
2012 444 6,300 311 9,800
2013 439 6,300 308 9,800
2014 435 6,300 304 9,800
2015 431 6,300 301 9,800
2016 426 6,300 298 9,800
2017 422 6,300 296 9,800
2018 418 6,300 293 9,800
2019 414 6,300 290 9,800
2020 410 6,300 287 9,800
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MIDWEST ELECTRICITY MARKET ANALYSIS B-31
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
RDI made the following assumptions with regard to the financing of new power
plant additions:
Debt Financing: 50%
Nominal Cost of Debt: 8.5%
Nominal After Tax ROE: 15.0%
Marginal Income Tax Rate: 37%
Depreciation Schedule: MACRS
DEMAND ASSUMPTIONS
For the MAIN region, RDI used peak demand and energy forecasts from the North
American Electric Reliability Council's (NERC) compilation of EIA-411 data in
its Electricity Supply & Demand software (revision date April 1, 1999). After
2008 (the last year of NERC projections), demand and energy growth was set at
the average annual growth rates for the NERC forecast period (i.e. 1999-2008).
Aggregate annual energy and peak demand for these regions were then allocated to
individual utility load/market areas in the IREMM model based on percentages of
retail sales attributed to each utility market area. Historical retail sales
were taken from 1997 EIA Form 861 filings as compiled in RDI's POWERdat database
system.
Table 11 shows the peak demand and energy forecast RDI used in MAIN. MAIN has
experienced 3.5% annual peak demand growth over the last 7 years. Some of this
high growth is attributable to unusually warm weather; weather-normalized demand
growth is estimated at 2.5% per year, equaling the national average. The NERC
forecasts slower growth over the next eight years, roughly 1.4% annually through
2008. RDI used 1997 FERC Form 714 hourly load filings for each planning area to
simulate the shape of hourly demand profiles in each IREMM market area.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-32
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 11
---------------------------------------------------------------------------
DEMAND AND ENERGY FORECAST FOR MAIN
---------------------------------------------------------------------------
Summer Peak Annual % Winter Peak Annual % Annual %
Year MW Growth MW Growth Energy GWh Growth
---------------------------------------------------------------------------
1990 40,740 32,461 197,326
1991 41,598 2.1% 33,420 3.0% 205,880 4.3%
1992 38,819 -6.7% 31,289 -6.4% 200,250 -2.7%
1993 41,956 8.1% 34,966 11.8% 208,340 4.0%
1994 42,562 1.4% 33,999 -2.8% 213,803 2.6%
1995 45,782 7.6% 35,734 5.1% 224,380 4.9%
1996 46,402 1.4% 37,162 4.0% 234,300 4.4%
1997 45,887 -1.1% 34,973 -5.9% 236,143 0.8%
1998 47,509 3.5% 37,410 7.0% 244,073 3.4% HISTORY
8-YR AVG 1.9% 1.8% 2.7%
4-YR AVG 2.8% 2.4% 3.4%
---------------------------------------------------------------------------
1999 47,875 0.8% 38,170 2.0% 242,197 -0.8% FORECAST
2000 48,618 1.6% 39,019 2.2% 245,561 1.4%
2001 49,208 1.2% 39,574 1.4% 248,794 1.3%
2002 49,838 1.3% 40,034 1.2% 251,787 1.2%
2003 50,578 1.5% 40,711 1.7% 255,361 1.4%
2004 51,439 1.7% 40,848 0.3% 258,617 1.3%
2005 52,314 1.7% 41,552 1.7% 262,849 1.6%
2006 53,122 1.5% 42,205 1.6% 266,661 1.5%
2007 53,815 1.3% 42,742 1.3% 270,850 1.6%
2008 54,670 1.6% 43,451 1.7% 274,054 1.2%
2009 55,474 1.5% 44,071 1.4% 277,843 1.4%
2010 56,291 1.5% 44,703 1.4% 281,684 1.4%
2011 57,119 1.5% 45,343 1.4% 285,578 1.4%
2012 57,894 1.4% 45,926 1.3% 289,526 1.4%
2013 58,746 1.5% 46,585 1.4% 293,529 1.4%
2014 59,610 1.5% 47,251 1.4% 297,587 1.4%
2015 60,489 1.5% 47,929 1.4% 301,701 1.4%
---------------------------------------------------------------------------
RESERVE REQUIREMENTS
RDI developed reserve equilibrium levels for the MAIN region based on
historical requirements and an analysis of loss-of-load expectation (LOLE).
The loss-of-load expectation represents the probability of curtailing
demand owing to a generation shortfall. This probability is multiplied by
the value of lost load (VOLL), expressed in $/MWh, which represents the
economic cost to buyers of interruptions in supply. For its analysis, RDI
assumed that VOLL is $10,000/MWh; the reliability required reserve margin
is relatively insensitive to this value. The VOLL multiplied by hourly LOLE
is an hourly capacity value; that is, it represents the value of having an
additional megawatt of generating capacity in the region. The sum of this
hourly capacity value over all hours of the year is the annual capacity
value, in $/MW.
RDI used iterative IREMM runs to estimate annual capacity value for each
region varying reserve margins from 9% to 21%. The reserve margin yielding
capacity value equal to the annual cost of new combustion turbine capacity
was used as the reserve margin for each region. These inferred reserve
margins were taken as relative to each
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MIDWEST ELECTRICITY MARKET ANALYSIS B-33
region rather than absolute. They were calibrated to match known results of
more detailed analyses in a small number of benchmark regions.
The results of this process were used to determine the minimum reserve
margins required for reliability purposes through 2004. The reserve
equilibrium level after 2004 was set 1% below the targets through 2004,
assuming a moderate improvement in availability factors at peak of existing
generation. For the MAIN region, this results in reserve margins of 15%
through 2004, declining to 14% thereafter.
TRANSMISSION PRICING
RDI reflected pricing associated with a hypothetical regional transmission
organization (RTO) such as the Midwest ISO by eliminating the pancaking of
transmission tariffs between MAIN members. A $2.50 per MWh non-firm
transmission tariff for transmission within MAIN is applied. This data is
based upon RDI analysis of OASIS data. RDI assumed that all MAIN utilities
are subject to this pricing. While the actual timing of a single
transmission entity encompassing MAIN is uncertain, RDI believes that an
RTO pricing regime is likely over the majority of the study period as
discussed in the Midwest ISO section of the report in the MAIN Overview.
COAL PRICE FORECAST
RDI develops plant specific coal price forecasts for every power plant in
the country. This forecast is based upon analysis of coal supply/demand
fundamentals, existing coal and transportation contracts, transportation
options, emission allowance prices, coal quality, boiler design options,
and derate penalties for use of subbituminous coal where applicable. In
sum, each power plant's coal supply options are evaluated and RDI selects
the lowest cost option.
Key assumptions that drive RDI's forecast include contractual shipments,
SO2 allowance prices, transportation options, and FOB mine prices. Each of
these assumptions is discussed below.
CONTRACT SHIPMENTS
Existing coal contracts are forecast to continue at historic volumes
through the contract expiration date (except where noted). Future delivered
costs of contracted volumes are projected using historical price trends.
Upon the expiration of the contract, volumes are replaced by the least
expensive delivered coal available to the plant.
SULFUR DIOXIDE ALLOWANCE PRICES
Each coal type has a sulfur emission cost calculated based on the sulfur
content, scrubber efficiency at each plant (if any), and the forecast value
of SO\\2\\ emission allowances. This
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MIDWEST ELECTRICITY MARKET ANALYSIS B-34
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
approach increases the cost of higher sulfur coal relative to lower sulfur
coal. Allowance prices and the sulfur content of a coal also play a role in
determining the dispatch of individual power plants.
TRANSPORTATION
Transportation costs for various coal source regions are developed for each
coal plant. Actual transportation rates are used where known on existing
movements, and others are modeled where no prior movements have occurred.
The transport cost model takes into account such factors as the coal source
region, distance to plant, delivery options at the plant, and
transportation productivity improvement. Transportation rates in real terms
decline at various rates that range between 1.6% and 0.4%. Western rail
shipments decline at an average rate of 1.25% per year while eastern rail
rates average 1.05% decline per year.
MINE PRICES
FOB mine prices for each major supply region are taken from RDI's December
1999 Outlook for Coal and Competing Fuels. In general low sulfur prices are
forecast to decline approximately 1.5% per year over the forecast time
horizon whereas high sulfur prices are forecast to decline approximately
2.3% per year (in real terms). An exception to these generalities is the
forecast price of SPRB coal. Premium quality SPRB coal is forecast to rise
during the 1999 to 2005 time period, as an anticipated surge in demand and
slightly higher mining costs drives pricing higher during that time period.
Table 12 summarizes FOB mine coal price forecasts by region and coal
quality.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-35
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 12
---------------------------------------------------------------------------
FOB MINE COAL PRICE FORECAST ($2000/TON)
---------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
LBSO2/ LBSO2/
BTU/LB MMBTU BTU/LB* MMBTU* 1998 1999 2000 2001 2005 2010 2015 2020
-----------------------------------------------------------------------------------------------------------
CENTRAL APPALACHIA
## 12500 *** 1.2 12,928 1.07 27.88 25.47 25.12 24.85 24.07 23.09 22.42 21.93
## 12500 1.21 - 1.7 12,867 1.45 26.75 24.27 23.91 23.62 22.79 21.75 21.02 20.46
## 12500 1.71 - 2.5 12,846 2.01 25.50 22.69 21.94 21.64 20.76 19.66 18.86 18.22
** 12500 *** 1.2 12,128 1.09 25.64 24.01 23.51 23.25 22.53 21.60 20.98 20.52
** 12500 1.21 - 1.7 11,988 1.47 24.13 22.88 22.10 21.84 21.07 20.11 19.43 18.91
** 12500 1.71 - 2.5 11,986 2.05 23.80 21.40 21.21 20.93 20.08 19.02 18.24 17.62
SOUTHERN APPALACHIA
** 12000 *** 1.2 11,510 1.00 27.95 26.77 26.54 26.25 25.43 24.39 23.68 23.16
** 12000 1.2 - 2.5 11,669 1.72 25.37 25.51 25.22 24.88 23.87 22.61 21.68 20.95
** 12000 # 2.5 11,825 3.65 24.33 23.64 23.00 22.60 21.34 19.81 18.63 17.64
NORTHEASTERN APPALACHIA
## 12750 1.2 - 2.5 13,151 2.17 25.37 23.90 23.64 23.32 22.37 21.19 20.32 19.63
## 12750 # 2.5 13,169 3.45 23.81 21.08 20.76 20.40 19.26 17.88 16.81 16.06
** 12750 # 2.5 12,184 4.28 22.00 19.87 19.57 19.23 18.15 16.86 15.85 15.85
OHIO
## 11500 # 2.5 12,234 6.11 19.47 18.34 17.64 16.93 15.63 15.45 15.28 15.28
** 11500 # 2.5 11,176 6.83 16.93 16.30 15.68 15.05 15.05 15.05 15.05 15.05
ILLINOIS BASIN
## 11000 # 2.5 11,607 4.78 21.19 19.21 18.92 18.59 17.55 16.30 15.32 14.51
** 11000 # 2.5 10,686 5.02 18.90 18.01 17.73 17.43 16.45 15.28 14.36 13.60
SOUTHERN PRB
## 8600 *** 1.2 8,849 0.75 4.60 4.92 5.05 5.17 5.74 5.42 5.17 4.97
** 8600 *** 1.2 8,528 0.81 3.46 3.77 3.87 3.96 4.40 4.15 3.96 3.81
NORTHERN PRB
## 8800 *** 1.2 9,393 0.79 6.73 6.11 5.50 5.48 5.47 5.44 5.48 5.57
** 8800 1.2 - 2.5 8,733 1.72 5.95 5.60 5.58 5.55 5.48 5.39 5.36 5.38
CENTRAL ROCKIES - CO
## 11500 *** 1.2 11,902 0.87 15.01 14.26 13.50 13.45 13.42 13.36 13.46 13.66
** 11500 *** 1.2 10,864 0.79 13.98 13.25 12.50 12.46 12.43 12.37 12.46 12.65
CENTRAL ROCKIES - UT
## 11500 *** 1.2 11,951 0.79 17.08 16.56 16.25 16.19 16.16 16.08 16.20 16.45
** 11500 *** 1.2 11,339 0.71 16.52 15.98 15.92 15.82 15.63 15.37 15.29 15.33
SOUTHERN WYOMING
** 10800 *** 1.2 10,043 1.04 13.72 13.88 13.86 13.81 13.78 13.72 13.82 14.03
** 10800 1.2 - 2.5 9,557 1.24 13.34 13.45 13.40 13.32 13.16 12.94 12.88 12.91
FOUR CORNERS
## 9500 *** 1.2 9,858 0.90 16.21 16.20 16.14 16.04 15.85 15.58 15.51 15.55
* AVERAGE BTU/LB AND LBSO2/MMBTU FOR SPOT COALS IN EACH QUALITY CATEGORY
OVER THE 1997-1999 PERIOD
** LESS THAN
# MORE THAN
*** LESS THAN OR EQUAL TO
## MORE THAN OR EQUAL TO
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MIDWEST ELECTRICITY MARKET ANALYSIS B-36
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
RDI's forecast delivered coal prices for Ameren's plants is shown in Table 13.
Factors driving this forecast are discussed in the following section.
TABLE 13
- --------------------------------------------------------------------------------
DELIVERED COAL PRICES FOR AMEREN PLANTS (2000 CENTS/MMBTU)
- --------------------------------------------------------------------------------
PLANT
- ---------------------------------------------------------------
Year Coffeen Grand Tower/1/ Hutsonville Meredosia Newton
- ---------------------------------------------------------------
1997 183.68 120.49 126.62 184.08 186.69
1998 188.18 118.06 125.72 170.15 152.14
1999 189.10 104.49 111.47 106.51 129.16
2000 126.78 102.16 116.02 136.55 111.77
2001 125.05 113.63 129.99 111.54
2002 123.34 104.70 129.53 111.24
2003 121.60 102.80 127.20 110.67
2004 119.89 100.95 125.35 110.16
2005 118.17 99.09 123.47 109.59
2006 116.44 97.16 121.51 107.80
2007 114.71 95.23 119.53 105.88
2008 113.08 93.50 117.78 104.27
2009 111.54 91.94 116.19 103.03
2010 109.98 90.32 112.09 101.62
2011 97.53 88.77 110.52 100.21
2012 96.19 87.20 108.92 98.82
2013 94.65 85.58 107.25 97.22
2014 93.31 84.06 105.69 95.83
2015 91.90 82.54 104.12 94.36
- ---------------------------------------------------------------
(1) Grand Tower is repowered to natural gas in mid-2001.
(2) 1999 values represent forecast rather than historical values.
GENCO COAL CONTRACTS
Coffeen - This plant has historically purchased mid-sulfur ILB coal, and has a 2
million ton per year contract with Exxon that was renegotiated in 1999. The
contract covers all plant needs through 2010.
Grand Tower - No long-term contracts are in place at Grand Tower, a small plant
that has exclusively purchased local, high sulfur ILB coal. The forecast assumes
that the plant will be switched to natural gas in 2001.
Hutsonville - Hutsonville purchases small amounts of local coal from high sulfur
sources on a year-by-year basis. No significant changes are anticipated in fuel
sources or prices.
Newton - This plant recently switched from Colorado and Indiana bituminous coal
to nearly 100% SPRB coal in early 1999. Ameren terminated existing contracts
with previous bituminous coal suppliers in late 1999.
Meredosia - This plant has traditionally purchased ILB coal from Exxon's
Monterrey mine under a long-term contract extending through 2009. The contract
coal currently delivers to the plant at very competitive cost levels.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-37
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
INCREMENTAL FUEL COST
Ameren provided RDI with its 1999 incremental fuel cost for each generating unit
in AmerenUE and AmerenCIPS. These incremental fuel costs are used for
determining the dispatch price of each generating unit in hourly operations. RDI
used the incremental fuel cost for purposes of determining dispatch, escalating
this cost at the same rate as shown in its average fuel price forecast for each
plant shown above.
ENVIRONMENTAL ASSUMPTIONS
FUTURE SO\\2\\ REQUIREMENTS Phase II of EPA's Acid Rain Program began on January
1, 2000. Provisions for SO\\2\\ control are divided into two phases. Phase I is
currently in effect for 263 coal units and oil units in the U.S. Phase II of the
Acid Rain program applies to all coal and oil plants greater than 25 MW.
RDI's modeling establishes a baseline for SO\\2\\ emissions. RDI then constructs
a marginal cost curve for additional SO\\2\\ removal, including a plant by plant
analysis of scrubbing and fuel switching options. An SO\\2\\ allowance forecast
is established by calculating the additional SO\\2\\ emissions to be removed
beyond the baseline and applying that amount against the marginal cost of
removing emissions. This also provides a forecast of capital expenditures for
SO\\2\\ compliance at specific power plants. Figure 17 shows RDI's SO\\2\\
allowance price forecast. SO\\2\\ allowance prices have been depressed to levels
significantly below marginal cost. To account for this depression in current
markets, RDI assumes historical average annual prices for a starting point,
ramping up to long-run marginal costs of SO\\2\\ control over a period of three
years.
FIGURE 17
- --------------------------------------------------------------------------------
SO\\2\\ ALLOWANCE PRICE FORECAST ($2000 PER TON)
- --------------------------------------------------------------------------------
[A line graph showing the projected increase in the price of SO\\2\\ per ton for
the years 2000 through 2010.]
- -----------------------------
Price Forecast
--------------
- -----------------------------
2000 201
- -----------------------------
2001 229
- -----------------------------
2002 261
- -----------------------------
2003 297
- -----------------------------
2004 292
- -----------------------------
2005 294
- -----------------------------
2006 299
- -----------------------------
2007 302
- -----------------------------
2008 313
- -----------------------------
2009 318
- -----------------------------
2010 338
- -----------------------------
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-38
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
FUTURE NO\\X\\ REQUIREMENTS There is a great deal of uncertainty regarding
potential requirements for controlling Nitrogen Oxide (NO\\x\\) emissions from
generating units. The ability to determine the future cost of NO\\x\\
requirements is impaired by uncertainties regarding the implementation of EPA's
NO\\x\\ SIP Call, Section 126 petitions to address ozone transport between
states, individual state programs to attain 1 hour ozone standards, and on-going
lawsuits alleging new source review violations at specific plants.
Notably, RDI's base case assumes emissions trading for NO\\x\\ takes place only
within the currently existing Ozone Transport Commission (OTC) states. RDI
specifies two separate regional NO\\x\\ emission control schemes:
Northeast OTC States
. 2 Phase allowance trading program
. Summertime cap declines to 0.15 lb/mmBtu emission rate in 2003
. Forecast additional emission controls based on trading program for 2003
and beyond
Midwest and Southeast states (including states in MAIN)
. State by State NO\\x\\ Programs
. Programs start in 2003 set at 0.25 lb/mmBtu summertime emission rate
. Forecast additional emission controls based on system-wide averaging
plans
This regulatory scenario is expected to result in minimal compliance
requirements for the Genco's units. The repowering of Grand Tower into
natural-gas fired units creates reductions in system average NO\\x\\ rates that
fulfills much of the Genco's projected compliance obligations. The Coffeen
facility is forecast to install Selective Catalytic Reduction (SCR) to reduce
NO\\x\\ emissions, and the Newton facility is forecast to install low- NO\\x\\
burners and optimize boiler operations. These measures are expected to fulfill
the compliance requirements of the Genco even under the tightest NO\\x\\ budgets
implemented by EPA. Because Illinois is not within the OTC, the Genco's units
are not directly affected by NO\\x\\ emissions trading.
GAS PRICE FORECAST
RDI developed a gas price forecast to provide a projection of gas prices for the
Eastern Interconnect by blending published forecasts from leading forecasting
agencies. For this purpose, it was necessary to forecast commodity costs at two
price hubs and assign uniform basis differentials from those hubs to gas-fired
facilities in the regions analyzed for this study.
Commodity costs were derived from three publicly available gas forecasts. RDI
blended these forecasts at two major supply points in the Eastern U.S., Henry
Hub, and Chicago Hub. Henry Hub is currently the primary natural gas price point
for the Eastern U.S.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-39
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Chicago Hub will become increasingly important in the future, as it becomes a
major offloading point for Canadian gas. RDI's analysis blended forecasts from
the WEFA's 1999 Natural Gas Long-Term Outlook, DRI/Standard & Poors 1999 Natural
Gas Outlook, and Energy Information Administration's (EIA) 2000 Annual Energy
Outlook (AEO). /7/
Basis differentials vary from year to year and season to season depending on
pipeline capacity and other factors affecting supply and demand. For this
forecast, a three-year average of historic basis differentials, as derived from
price surveys published in Gas Daily, was used to calculate constant
transportation differentials in the forecast.
Natural gas prices at Henry Hub are projected to grow at 1.2% per year in real
terms from 1999 to 2010. The price of natural gas in real dollars escalates from
$2.40/mmBtu in 1999 to $2.73/mmBtu in 2010. See Table 14 and Figure 18.
_________________
/7/ EIA does not directly report a Henry Hub price, but does publish an average
wellhead cost for gas. Over the last nine years average wellhead costs have
typically been 0.17 cents/Mcf lower than Henry Hub prices. This differential
was added in every year to the EIA average wellhead forecast, and then
converted to mmBtu by dividing the result by 1.0269 - the conversion factor
1 Mcf = 1.0269 mmBtu.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS
B-40
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 14
- --------------------------------------------------------------------------------
HENRY HUB AND MAIN DELIVERED PRICE PROJECTIONS ($2000 PER MMBTU)
- --------------------------------------------------------------------------------
WEFA HENRY
HUB 1999 EIA HENRY HUB DRI HENRY HUB BLENDED
NATURAL GAS ESTIMATE AEO 1999 NATURAL HENRY HUB MAIN DELIVERED
YEAR OUTLOOK 2000 GAS OUTLOOK FORECAST PRICE FORECAST
----------------------------------------------------------------------------------------------
1995 $1.88 $1.88 $1.88 $1.88
1996 $3.01 $3.01 $3.01 $3.01
1997 $2.71 $2.65 $2.65 $2.67
1998 $2.21 $2.21 $2.21 $2.21
1999 $2.38 $2.37 $2.45 $2.40 $2.47
----------------------------------------------------------------------------------------------
2000 $2.51 $2.42 $2.76 $2.56 $2.63
2001 $2.53 $2.42 $2.45 $2.47 $2.53
2002 $2.47 $2.42 $2.41 $2.44 $2.50
2003 $2.49 $2.46 $2.43 $2.46 $2.52
2004 $2.53 $2.52 $2.41 $2.49 $2.55
2005 $2.60 $2.60 $2.37 $2.52 $2.58
2006 $2.64 $2.69 $2.38 $2.57 $2.63
2007 $2.68 $2.77 $2.40 $2.62 $2.67
2008 $2.72 $2.83 $2.43 $2.66 $2.71
2009 $2.76 $2.85 $2.47 $2.69 $2.75
2010 $2.80 $2.87 $2.51 $2.73 $2.78
2011 $2.84 $2.89 $2.55 $2.76 $2.82
2012 $2.86 $2.92 $2.61 $2.79 $2.85
2013 $2.87 $2.94 $2.66 $2.82 $2.88
2014 $2.88 $2.96 $2.71 $2.85 $2.90
2015 $2.90 $2.98 $2.76 $2.88 $2.93
2016 $2.91 $3.00 $2.81 $2.91 $2.96
2017 $2.93 $3.02 $2.86 $2.94 $2.99
2018 $2.94 $3.03 $2.91 $2.96 $3.02
2019 $2.96 $3.05 $2.96 $2.99 $3.04
2020 $2.97 $3.08 $3.01 $3.02 $3.07
----------------------------------------------------------------------------------------------
% Chg 99-2010 1.5% 1.8% 0.2% 1.2% 1.1%
% Chg 99-2020 1.1% 1.3% 1.0% 1.1% 1.0%
----------------------------------------------------------------------------------------------
FIGURE 18
HENRY HUB PRICE PROJECTIONS ($2000 PER MMBTV)
[A line graph showing the past and projected growth of natural gas prices for
years 1995 through 2010. The graph charts the WEFA Henry Hub 1999 Natural Gas
Outlook, the EIA Henry Hub Estimate AEO 2000, the DRI Henry Hub 1999 Natural Gas
Outlook and the Blended Henry Hub Forecast.]
- ------------------------------------------------------------------------------
WEFA Henry EIA Henry Hub DRI Henry Hub Blended Henry
---------- ------------- ------------- -------------
Hub 1999 Estimate AEO 1999 Natural Hub Forecast
-------- ------------ ------------ ------------
Natural Gas 2000 Gas Outlook
----------- ---- -----------
Outlook
-------
- ------------------------------------------------------------------------------
1995 $1.88 $1.88 $1.88 $1.88
- ------------------------------------------------------------------------------
1997 $2.71 $2.65 $2.65 $2.67
- ------------------------------------------------------------------------------
1999 $2.38 $2.37 $2.45 $2.40
- ------------------------------------------------------------------------------
2001 $2.53 $2.42 $2.45 $2.47
- ------------------------------------------------------------------------------
2003 $2.49 $2.46 $2.43 $2.46
- ------------------------------------------------------------------------------
2005 $2.60 $2.60 $2.37 $2.52
- ------------------------------------------------------------------------------
2007 $2.68 $2.77 $2.40 $2.62
- ------------------------------------------------------------------------------
2009 $2.76 $2.85 $2.47 $2.69
- ------------------------------------------------------------------------------
2011 $2.84 $2.89 $2.55 $2.76
- ------------------------------------------------------------------------------
2013 $2.87 $2.94 $2.66 $2.82
- ------------------------------------------------------------------------------
2015 $2.90 $2.98 $2.76 $2.88
- ------------------------------------------------------------------------------
2017 $2.93 $3.02 $2.86 $2.94
- ------------------------------------------------------------------------------
2019 $2.96 $3.05 $2.96 $2.99
- ------------------------------------------------------------------------------
________________________________________________________________________________
MIDWEST ELECTRICITY MARKET ANALYSIS B-41
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
FIGURE 19
- --------------------------------------------------------------------------------
AVERAGE BASIS DIFFERENTIALS FOR GAS PRICE FORECAST
- --------------------------------------------------------------------------------
[A map of the Eastern United States charting the price point locations described
in Table 15 and showing the average basis differentials for gas prices between
certain price points.]
TABLE 15
- --------------------------------------------------------------------------------
AVERAGE BASIS DIFFERENTIALS FOR GAS PRICE FORECAST
- --------------------------------------------------------------------------------
YEAR CHI - HH NYC - HH BR - HH FGT- HH NYC - CHI NE - NYC
--------------------------------------------------------------------------------------------------
1997 $0.13 $0.38 $0.32 $0.21 $0.24 $0.06
1998 $0.07 $0.27 $0.25 $0.19 $0.20 $0.06
1999 $0.05 $0.33 $0.28 $0.24 $0.27 $0.05
--------------------------------------------------------------------------------------------------
SERIES AVG. $0.13 $0.39 $0.33 $0.22 $0.29 $0.18
--------------------------------------------------------------------------------------------------
3 YEAR AVG. $0.08 $0.32 $0.28 $0.22 $0.24 $0.06
==================================================================================================
YEAR NYC - IQ NYC - BR BR - CHI CHI - VENT NIAG - CHI IQ - NIAG
--------------------------------------------------------------------------------------------------
1997 $0.13 $0.06 $0.19 $0.26 $0.07 $0.04
1998 $0.05 $0.02 $0.18 $0.13 $0.04 $0.11
1999 $0.05 $0.05 $0.23 $0.11 $0.08 $0.15
--------------------------------------------------------------------------------------------------
SERIES AVG. $0.02 $0.05 $0.20 $0.21 $0.07 $0.28
--------------------------------------------------------------------------------------------------
3 YEAR AVG. $0.08 $0.04 $0.20 $0.16 $0.06 $0.10
==================================================================================================
PRICE POINTS
---------------
BR - BROAD RUN,WV NE - NEW ENGLAND CITY GATES
CHI - CHICAGO HUB, IL NIAG - NIAGARA FALLS, NY
FGT - FLORIDA GATES VIA FGT,FL NYC - NEW YORK CITY HUB
HH - HENRY HUB, LA VENT - VENTURA, IA
IQ - IROQUOIS (ZONE 2), NY
________________________________________________________________________________
MIDWEST ELECTRICITY MARKET ANALYSIS B-42
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
The constant basis differentials used in this analysis are shown in Table 15 and
Figure 19. The differentials are calculated as the difference between the
average annual price at the pricing point from the average price at the pricing
hub in each year. Historical prices were examined for as many years as recorded
by Gas Daily. This varies by price location. Some price points had historical
data from as distant as 1990. All pricing points had data from at least 1996.
The series average shown in Table 15 represents the average basis over the
recorded price history at that point. RDI used the three year average to
complete its forecast.
GENCO CONTRACTUAL OBLIGATIONS
Although Ameren is establishing the Genco as an unregulated wholesale generation
company, the generating assets of the Genco are not subject to wholesale market
pricing for 100% of their output. During the first five years of operation, the
Genco will provide much of its capacity and energy under bilateral contracts to
customers in MAIN and ECAR. Major customers of the Genco include the following:
. The AmerenCIPS Disco, which will remain an all requirements customer of the
Genco through 2004, paying a fixed price for capacity and energy (this
contract represents approximately 83% of the total capacity under
contract);
. Five municipalities in Missouri formerly taking power from AmerenUE, four
of which will terminate by the end of 2002 and one which will terminate in
mid-2004;
. Archer Daniels Midland, which will take power through mid-2003; and
. CILCO, which will take power during the five peak months of each year
through 2003.
None of these customer's contracts are directly with the Genco. Some of the
agreements are with Ameren's Marketing Company, and some are with the Disco,
which in turn has an agreement with Marketing Company. In each case, the
Marketing Company then has a "back to back" agreement with the Genco. In
addition, in each case the load obligation for these contracts remains with the
Genco, and all revenues accruing from these contracts is passed through to the
Genco. The Marketing Company will act as the Genco's agent for all sales of
power from Genco assets into the wholesale markets. While these revenues and
associated costs are passed on to the Genco, the Genco incurs no costs and
receives no revenues for the power marketing activities of the Marketing Company
not explicitly linked to the Genco's assets or the contracts the Genco serves.
After 2004, most of the wholesale contracts of the Genco will terminate. Two
longer term agreements will remain in place: a 65 MW dispatchable contract with
the Wabash Valley Power Association expires in 2011, and a minimum take
agreement with the Illinois
________________________________________________________________________________
MIDWEST ELECTRICITY MARKET ANALYSIS B-43
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Municipal Energy Agency expires in 2014. Table 16 summarizes the forecast of
expected demand, energy, and revenues for these agreements./8/
TABLE 16
- -------------------------------------------------------------------------------
DEMAND, ENERGY, AND REVENUE FORECAST FOR EXISTING GENCO WHOLESALE AGREEMENTS
- -------------------------------------------------------------------------------
Revenues
Year Demand (MW) Energy (GWh) ($000)
- -------------------------------------------------------------------------------
2000 3,190 14,723 497,205
2001 3,141 15,760 531,925
2002 2,940 14,675 496,994
2003 2,657 12,610 439,963
2004 2,263 10,959 392,591
2005 174 965 28,935
2006 174 965 28,935
2007 173 958 28,747
2008 171 950 28,471
2009 171 950 28,471
2010 171 950 28,471
2011 171 950 28,471
2012 106 500 15,882
2013 106 500 15,882
2014 106 500 15,882
2015 - - -
2016 - - -
2017 - - -
2018 - - -
2019 - - -
2020 - - -
- -------------------------------------------------------------------------------
Revenues from the Genco's contracts are highest in 2000-2002, when most of its
installed capacity is committed. Both revenues and loads under contract decline
after 2002 as contracts expire; the expiration of the Disco supply agreement at
the end of 2004 leaves the Genco with only a small set of existing contracts to
serve. Although the strategy of the Genco is to renew or extend the bilateral
contracts upon expiration, the model assumes that all sales are made in the spot
market after the expiration of the existing contracts.
RDI assumed that the Genco would need to supply all of its contract obligations
in each hour before it could sell its excess capacity and energy in regional
wholesale markets. Additionally, the Genco is allowed to supply its contract
obligations with lower-cost energy available to it from its Joint Dispatch
Agreement (JDA) with AmerenUE and with economy purchases from the wholesale
markets. Under the JDA, each of the Genco and AmerenUE has a first call on
excess energy available from the other company in order to meet load
requirements. This system energy transfer is priced at marginal cost.
AmerenEnergy, as the Genco's agent, can also make economy purchases from the
wholesale markets to supplement the Genco's own generating capacity. RDI's
estimates of wholesale market transactions for the Genco assumed dispatch of
AmerenUE's plants at
______________
/8/ Appendix A contains a more detailed breakout of the Genco's existing
wholesale contracts.
________________________________________________________________________________
MIDWEST ELECTRICITY MARKET ANALYSIS B-44
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
projected market prices but did not attempt to model the positive or negative
effects that the JDA may have on the Genco's future revenues.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-45
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Methodology Overview
In general, most electricity market consultants will utilize one of three
different pricing models to predict competitive wholesale market prices. These
models are as follows:
. Reserve Requirement Model: In this model, which is the approach utilized by
RDI, a reserve requirement is imposed on each load serving entity (LSE) in
proportion to its load. To meet this requirement, the load serving entity
must enter into contracts with generators or procure its obligation through
a "capacity exchange" that is operated by a central clearing house, such as
an Independent System Operator (ISO). In such a model, a generator will
receive two separate payment streams. The first stream is an energy price
that is determined by the hourly interaction of supply and demand in the
spot market. The second stream is the capacity price that is determined by
the separately run capacity auction. This stream could be determined on a
monthly, seasonal, or annual basis. Such a market is currently operating in
the Pennsylvania-New Jersey-Maryland Interconnection (PJM), the New York
Power Pool (NYPP), and the New England Power Pool (NEPOOL).
. Explicit Capacity Adder Model: This model is similar to the reserve
requirement model in that market rules dictate that capacity will be priced
separately. One difference between these models is that, in an explicit
capacity adder model, retail suppliers do not have an obligation to secure
capacity. Also, the "capacity premium" is calculated on an hourly basis
rather than on a monthly or annual basis. The explicit capacity adder model
is currently employed in the United Kingdom (U.K.) electricity market. In
this model, all generators submit bids to a central clearing exchange,
specifying how much power they are willing to commit at a given price
during the next 24 hours. Generators have the potential to earn revenues
from two different payment streams. The first payment stream is received
for actual kilowatt-hour sales into a central power exchange (or spot
market). This price is determined by the bid of the highest cost unit
selected to supply power during each hour. This price is commonly referred
to as the system marginal price. The second payment stream is commonly
referred to as the capacity payment. This additional payment is equal to
the value of lost load multiplied by the loss of load probability. It is
paid to all generators available during the hour. The value of lost load is
determined administratively by the central pool. The loss of load
probability is a function of the forecast demand and the amount of
generation available to meet that demand.
. Energy Only Model: In this model, the hourly price of electricity is
determined purely through the interaction of supply and demand without the
interference of administratively determined installed reserve requirements
or a separate capacity payment. In the other two model structures, the
hourly price in the spot market is
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-46
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
always set by the highest cost unit (on a variable cost basis) dispatched
to meet demand (assuming no participant can exert market power). The key
distinction of the energy only model is that during some peak hours of
demand, the price would instead be set by the marginal cost of an outage to
customers. If regulators could estimate precisely the value of lost load on
an hourly basis and customers could curtail demand, the energy only model
market would result in pricing that is very similar to the explicit
capacity adder model. Moreover, if a regulator precisely predicted the
reserve requirement found in the energy only model, the reserve requirement
and energy only models would achieve similar annual prices for electricity.
In theory, each of these model structures results in similar prices on an annual
basis. Also, a mix of these market structures can exist. For instance, in an
energy only market bilateral transactions will exist between generators and
marketers where capacity and energy may be priced separately.
ENERGY MARKET MODEL
RDI employs an analytical approach that is based on the reserve requirement
model. First, RDI simulates the interaction of the energy market using IREMM.
This model performs many of the functions typically associated with electric
power production simulation programs such as marginal cost dispatching and
maintenance scheduling.
IREMM's methodology relies on the following concepts:
Incremental Production Cost The incremental cost of production is the cost of
- ---------------------------
producing an additional MWh of energy. To minimize costs, an efficient dispatch
center will dispatch its lowest cost generating units first. In the bulk power
market, a profit-maximizing company will produce energy as long as its
incremental cost of production is less than the additional revenue obtained from
the sale of that energy. Thus, if it can sell energy externally for more than
its incremental cost of production, the company will continue to produce after
its own load has been met. On the other hand, if the company can buy the energy
it needs to meet its load for less than the cost of its own generation, the
company will maximize profit by making the purchase. In general, IREMM assumes a
company always bids its generation at its marginal cost of production.
Supply and Demand Initially, units are dispatched to meet each individual
- -----------------
company's internal load. Once these loads are served with their available
resources, the quantities of surplus energy available for sale and the
quantities of displaceable energy can be calculated at various price levels.
From these prices and quantities, IREMM develops supply and demand curves for
each company. Energy supply and demand are balanced on an hourly basis.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-47
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Market Clearing Prices The basic premise of IREMM is that market forces exist
- ----------------------
and determine prevailing bulk power prices. Together with the cost of
transmitting energy between any two companies, the interactions of the supply
and demand functions determine the market clearing prices. These market prices
represent a spatial equilibrium where supply and demand are satisfied
simultaneously. Market clearing prices emerge as each system attempts to
maximize its "gains," defined as the sum of profits on sales and savings on
purchases.
Important outputs from the IREMM model that are used in this analysis include:
. Hourly energy market prices for the MAIN region,
. Capacity factors for existing and new power plants of the Genco,
. Calculations of hourly load served under contract by the Genco,
. Calculations of hourly market opportunities to buy from and sell into the
wholesale markets to maximize the Genco's profitability, and
. Estimates of the amount of new capacity added to the grid in each year in
MAIN.
CAPACITY PRICE MODEL
During the next step of the modeling process, RDI incorporates the results from
IREMM into a capacity price-forecasting model. The resulting capacity price is
calculated as: the amount of additional revenue required to keep enough
generation available to meet demand plus the reserve requirement. Each power
plant in a region is ranked according to the plant's operating profit - taking
into account only spot market revenues and variable operating costs. Consider a
hypothetical low cost coal plant. Such a plant is likely to achieve a
contribution margin as high as $50 per kW-yr (energy market revenues less
variable fuel and O&M). Accordingly, this plant covers its cash operating costs
from energy market revenues alone. Assuming perfect competitive conditions, its
bid into the capacity market will be close to zero.
Next, consider a combustion turbine. This plant will achieve only a small
contribution margin in the energy market since it only runs economically a few
hours of the year because of its higher operating cost. When it does run, it is
normally the price setting unit, receiving only its short-run marginal costs.
Therefore, it must recover the rest of its cash costs from the capacity market
if it is going to continue to be financially viable. It is this break-even
figure that determines the bid price of each generator in the capacity market.
The capacity price model makes two additional calculations. First, the model
calculates the break-even costs (including annualized investment costs and
return on equity) for new generating technologies. If the break even price for a
new plant is lower than the market clearing price of capacity, then the model
adds new capacity to the grid and the energy
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-48
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
market model is run again. The type of capacity added in each year is determined
by the overall profitability of competing generation technologies. This analysis
of new generator profitability takes into account our assumptions regarding
improvements in heat rates and the capital costs of constructing new plants. It
is also a dynamic process in that the type of additions from one market scenario
to another may differ. Second, the model determines which plants cannot recover
their cash costs from the market; these plants are retired if they cannot
generate positive cash flows over a period of several years.
Any new retirements or capacity additions resulting from the capacity price
model are put back into the IREMM model, and the model is re-run. This process
is continued until a converged solution is reached.
The capacity price model does not explicitly reflect revenues from ancillary
services such as spinning reserve, black start, or voltage support. To the
extent generators receive revenues from these services, these revenues would
allow generators to reduce their capacity revenue requirement. Generators do not
therefore receive additional revenues from ancillary services.
To summarize, the overall modeling approach accounts for the factors that affect
all markets: supply, demand, and transport capability. Ultimately, the model
ensures that prices reach a level that enables all generators within the
required reserve margin to recover their cash operating costs./9/ Over the long
term new capacity is built only if and when it is profitable to do so. Selecting
the mix of capacity additions that result in the lowest overall prices while
still maintaining generator profitability minimizes overall cost.
_____________________
/9/ After a power plant is built, cash operating costs include fuel, operation
and maintenance expenses, and capital replacement costs that are required to
keep the plant operating and available. Before a power plant is built, cash
costs include these costs as well as investment costs and a return on capital.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-49
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Base Case Electricity Price Forecast
Table 17 shows RDI's annual electricity price forecast for the MAIN region - the
region in which the Genco will buy and sell capacity and energy. Separate
capacity and energy price streams are forecast in each year (as described in the
Methodology section), which can be combined and expressed as a total price for
firm electricity. The respective drivers of energy and capacity prices are shown
below.
TABLE 17
ELECTRICITY PRICE FORECAST FOR SOUTHERN ILLINOIS ($2000)
----------------------------------------------------------------
ENERGY PRICES ($/MWh) CAPACITY PRICES
----------------------------------------------------------------
Energy
Capacity Equivalent
Rate Rate TOTAL PRICE
Year Off-peak On-peak Average ($/kW-yr) ($/MWh) ($/MWh)
=============================================================================
2000 17.09 23.33 21.13 19.34 3.68 24.81
2001 17.06 22.41 20.52 22.98 4.37 24.90
2002 16.81 22.01 20.18 57.01 10.85 31.02
2003 16.46 21.77 19.90 56.48 10.75 30.64
2004 16.19 21.60 19.69 56.23 10.70 30.39
2005 16.25 22.40 20.23 55.01 10.47 30.70
2006 16.38 22.78 20.52 54.59 10.39 30.91
2007 16.42 23.13 20.76 54.26 10.32 31.09
2008 16.83 23.92 21.42 53.75 10.23 31.64
2009 16.94 24.30 21.71 53.41 10.16 31.87
2010 17.15 24.43 21.86 53.36 10.15 32.01
2011 17.20 24.92 22.20 50.61 9.63 31.83
2012 17.17 25.07 22.28 50.39 9.59 31.87
2013 17.30 25.45 22.45 50.22 9.55 32.00
2014 17.71 25.81 22.96 49.77 9.47 32.42
2015 17.98 25.99 23.16 48.84 9.29 32.34
2016 17.81 26.04 23.14 48.54 9.24 32.37
2017 18.40 26.55 23.67 45.84 8.72 32.40
2018 18.64 26.77 23.90 45.05 8.57 32.47
2019 18.64 26.81 23.93 44.87 8.54 32.47
2020 19.04 27.19 24.31 42.48 8.08 32.40
=============================================================================
* Capacity prices are converted to equivalent $/MWh values assuming a load
factor of 60%.
ELECTRICITY PRICE DRIVERS
Energy Prices. Energy prices in the MAIN region are influenced primarily by two
factors. The first factor is fuel prices. Baseload coal and nuclear power plants
set the price of power during nearly 80% of the hours in 2000-2001. Peaking
plants set prices during the remainder of the period. However, natural gas is
forecast to increasingly represent the marginal generating fuel in MAIN as
growth in demand is forecast to be met by new
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MIDWEST ELECTRICITY MARKET ANALYSIS B-50
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
gas-fired capacity. The most efficient combined cycle plants in the region are
forecast to run during 35% of the hours of the year by 2005, 55% of the hours by
2010, and 70% by 2020. The greater prominence of natural gas in setting prices
tends to put upward pressure on prices. From 2002-2012, natural gas prices are
projected to increase at a rate of 1.2% annually.
However, despite increased gas prices, energy price growth over the forecast
horizon is minimal. This is attributable to the amount of new gas-fired peaking
and intermediate generation coming on-line during this period. Between 1999 and
2001, a total of 7,400 MW of gas-fired generation is forecast to come on-line in
MAIN. This generation displaces less efficient existing peaking generation and
reduces reliance on imported power during peak demand periods. These factors put
downward pressure on the on-peak energy price in the early years of the forecast
and in later years this factor tempers the impact of gas price increases.
Capacity Prices. Capacity prices represent the firm reliability component of the
total electricity price. If the market determines that capacity is scarce,
capacity prices will rise to a level high enough to encourage additions of new
capacity. Conversely, if the market finds capacity in surplus, capacity prices
will fall to levels that ensure recovery of fixed costs less operating profits
of the existing units required to meet reliability standards./10/ The two
primary drivers of capacity prices are therefore the relative scarcity or
surplus in capacity, and the expected cost of new capacity.
Because of the rapid influx of capacity additions, principally peaking
combustion turbines, RDI projects that MAIN will enter a period of regional
surplus capacity over the next four years. During this period, reserve margins
will range from 17-20%, 2-5% higher than the 15% reserve equilibrium level
indicated by studies of customer interruption. This results in low capacity
prices from 2000-2001. Reduced capacity additions after 2000 and demand growth
in MAIN and neighboring ECAR creates capacity scarcity by 2002, causing prices
to rise to levels associated with new plant construction.
RDI expects the cost of new capacity to decline in real terms over the study
period./11/ This factor places downward pressure on capacity prices.
Summary of Drivers - Total Price. The combination of factors associated with
energy and capacity prices drives RDI's total electricity price forecast.
Capacity surplus results in low prices in 2000-2001. As growth in demand absorbs
surplus capacity, prices increase beginning in 2002. After that time, increases
in natural gas prices are offset by declines in
_________________
/10/ Conditions of scarcity and surplus are defined with respect to reserve
requirements, discussed in the Base Case Assumptions section of this report.
/11/ Expectations for new technology cost and efficiency is discussed in greater
detail in the Base Case Assumptions section of this report.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-51
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
capacity prices to result in average annual growth of approximately 0.2%. Figure
20 shows total annual on-peak and off-peak electricity prices.
FIGURE 20
ON-PEAK AND OFF-PEAK ELECTRICITY PRICE FORECAST ($2000 PER MWH)
[A line graph charting total annual on-peak and off-peak electricity prices for
the year 1999 and projected price through 2020. The graph also charts an
average price of electricity.]
- -------------------------------------------------------------------------------
Off-Peak On-Peak Average
-------- ------- -------
- -------------------------------------------------------------------------------
1999 13.50 42.74 32.99
- -------------------------------------------------------------------------------
2001 17.06 26.78 24.89
- -------------------------------------------------------------------------------
2003 16.44 32.51 30.63
- -------------------------------------------------------------------------------
2005 16.23 32.86 30.69
- -------------------------------------------------------------------------------
2007 16.43 33.46 31.10
- -------------------------------------------------------------------------------
2009 16.93 34.47 31.87
- -------------------------------------------------------------------------------
2011 17.19 34.55 31.82
- -------------------------------------------------------------------------------
2013 17.30 34.80 32.00
- -------------------------------------------------------------------------------
2015 17.98 35.26 32.45
- -------------------------------------------------------------------------------
2017 18.40 35.26 32.39
- -------------------------------------------------------------------------------
2019 18.64 35.35 32.47
- -------------------------------------------------------------------------------
Notes: On-peak price is composed of on-peak energy price and capacity price at
an assumed 60% load factor. 1999 values are historical, 2000 forward are
projections.
COMPARISON TO CURRENT MARKET PRICES
RDI's price forecast for 2000 is significantly lower than historic wholesale
prices in the region. According to price information collected by Megawatt
Daily, the average round the clock price in the MAIN region in 1999 was $32.99
per MWh, approximately 30% higher, in today's dollars, than RDI's forecast for
the year 2000, and 6% higher than RDI's forecast for 2002. The average On-peak
price was $42.74 per MWh and the Off-peak price was $13.50 per MWh.
Comparison to the current forward curve is more difficult because there is not
yet a liquid forward curve (i.e. heavily traded futures contract) in the MAIN
region. The two most liquid trading hubs that are close to Illinois are Cinergy
and TVA. TVA has not sold a futures contract for the summer of 2000. The Cinergy
hub is trading at $125 per MWh for delivery in August 2000. A total of 147
contracts were entered into, indicating a thin market./12/ This price is well
above RDI's comparable on-peak forecast price of $69 per MWh for August 2000,
described below. Less than 0.3% of the power required to meet peak demand is
currently projected to be met by power traded through forward contracts.
____________
/12/ A contract typically calls for delivery of 1 MW per hour of the contract
month, or 744 hours in the case of August 2000 delivery.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-52
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
RDI believes that the amount of capacity that will be available this summer
will dampen price spikes seen in the last two summers. Participants in
forward markets clearly discount the effect of new generation, and seek
price insurance against the historically observed spikes.
It is also important to note that RDI's price forecast presents expected
prices under average conditions in a liquid market, which tends to discount
the possibility of price spikes such as those observed in the Midwest
during the last two summers. While the 1999 summer saw lower price spikes
than 1998, price levels were high enough to present significant risks to
wholesale traders. It is RDI's belief that those price spikes were driven
in part by specific events and the gradual development of liquid wholesale
trading markets. Transmission constraints, forced outages, and unusual
weather combined to create generation-constrained situations. Matched up
with institutional issues such as the lack of uniform transmission line
relief procedures, and uneven progress on deregulation, this situation
creates the possibility for continued price spikes in the future. RDI's
forecast does not account for these types of conditions.
Converting RDI's Forecast to Comparable Forward Prices As summarized above,
RDI forecasts wholesale market prices as two separate components - energy
and capacity. These two components, when added together, comprise the total
value of electricity. The energy price represents the spot price of non-
firm power. The capacity price represents the premium that must be paid to
assure firm supply or to acquire electricity supply during times of
shortages. Energy prices are projected in terms of dollars per megawatt
hour. Capacity prices are projected first in dollars per kilowatt year, and
then allocated to a specified number of hours to obtain values in dollars
per megawatt hour. For example, a capacity price of $52 per kW-yr, when
allocated over 100% of the 8,760 hours in a year is equivalent to $5.90 per
MWh. If the average energy price over the year is $20.00 per MWh, then the
average price of firm power over the year is $25 .90 per MWh. This is the
value of firm baseload power.
On an hourly basis, capacity has a value of zero in the vast majority of
hours. These include all hours in non-peak months, weekends, and off-peak
hours of every day. Even some prices during on-peak hours of peak months
will have a 12 A contract typically calls for delivery of 1 MW per hour of
the contract month, or 744 hours in the case of August 2000 delivery.
capacity value of zero. Capacity has a non-zero value in only 10% or fewer
of the hours of the year. A capacity price of $52 per kW-yr, when allocated
over 10% of the hours in a year, is equivalent to $59 per MWh. If energy
prices are, say, $5.00 per MWh higher on average during peaking hours than
the all-hours average, then the total price of firm peaking power is $84
per MWh ($20 + $5 + $59).
Total firm prices show a sharply pronounced seasonal profile. One place to
observe this is in futures prices. Futures prices typically reflect little
value for capacity during nine of the 12 forward months. The fundamental
concept underlying capacity prices is reliability.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-53
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Capacity prices are highest in hours, days, and months when the risk of
curtailment owing to a generating capacity shortfall is highest. Studies of
hourly loss-of-load-probability (LOLP) show that almost all of the hours
with non-zero LOLP are concentrated in only two or three months of the
year.
Figure 21 shows RDI's forecast using a methodology approximating the
forward curve observed on a NYMEX contract./13/ RDI's review of LOLP
research indicates that the annual value of capacity should be allocated
22% to June, 12% to July, 65% to August, and 1% to September. Again,
current prices for next summer delivery are greater than $100 per MWh,
compared to RDI's price projections of $69 per MWh in 2000.
FIGURE 21
---------------------------------------------------------------------------
MONTHLY FORWARD CURVE, 2000 (ON PEAK $/MWH)
---------------------------------------------------------------------------
[A line graph showing on-peak prices ($/MWh) by month for the year 2000. The
graph shows on-peak prices for capacity and energy.]
- -----------------------------------------------------------------
Capacity Energy Total
-------- ------ -----
- -----------------------------------------------------------------
January 0.00 24.44 24.44
- -----------------------------------------------------------------
February 0.01 25.52 25.53
- -----------------------------------------------------------------
March 0.00 22.31 22.31
- -----------------------------------------------------------------
April 0.00 19.00 19.00
- -----------------------------------------------------------------
May 0.00 21.24 21.24
- -----------------------------------------------------------------
June 12.21 26.94 39.14
- -----------------------------------------------------------------
July 6.65 30.68 37.33
- -----------------------------------------------------------------
August 35.13 33.80 68.93
- -----------------------------------------------------------------
September 0.57 23.23 23.80
- -----------------------------------------------------------------
October 0.00 19.23 19.23
- -----------------------------------------------------------------
November 0.00 21.74 21.74
- -----------------------------------------------------------------
December 0.00 22.10 22.10
- -----------------------------------------------------------------
SUPPLY/DEMAND BALANCE
Electricity demand growth in the Midwest has been at or slightly above
national averages over the last several years, and is forecast to remain so
in the near future. Until last year, additions of new capacity did not keep
pace with demand growth, creating significant volatility in wholesale
markets and contributing to summertime price spikes observed over the last
two years. Over the past year, increased power plant development has
resulted in high levels of new construction in the Midwest. Due to
perceived locational advantages for siting and permitting, and the
expectation of lower gas pricing and greater diversity of gas supply, much
of this new development has been sited in the MAIN region. To account for
these factors and the historical correlation between wholesale pricing in
MAIN and ECAR, RDI analyzed the supply and demand balance of both regions
as a whole, rather than looking at MAIN as an isolated region.
----------------
/13/On-Peak prices represent the average of prices during the On-Peak and
Mid-Peak periods of each day, usually 16 hours. Off-peak prices represent
the annual average of prices during the remaining load hours.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-54
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Taken as a whole, MAIN and ECAR have a combined reserve target of 15.7%
through 2004, which drops to 14.7% for the remainder of the period. Table
18 illustrates that MAIN and ECAR have surplus capacity in 2000 and 2001,
which is driven by capacity additions in both regions. From 2002-2003, the
regions taken together meet their reserve requirement with a slight
capacity surplus in MAIN and a slight capacity scarcity in ECAR. After
2003, both regions have achieved individual supply equilibrium. These
dynamics underpin RDI's expectation that MAIN's projected local surplus of
capacity is likely to be short term.
TABLE 18
---------------------------------------------------------------------------
CAPACITY BALANCE AND RESERVE MARGINS FOR MAIN AND ECAR
---------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------
Installed Capacity Capacity Additions Peak Demand Reserve Margins (%)
---------------------------------------------------------------------------------------------------
MAIN/ECAR
Year MAIN ECAR MAIN ECAR MAIN ECAR MAIN ECAR Combined
---------------------------------------------------------------------------------------------------
2000 53,946 109,200 3,981 3,870 48,618 96,946 19.1% 16.6% 17.5%
2001 56,776 113,613 2,469 195 49,208 98,786 20.4% 15.2% 16.9%
2002 58,201 113,205 575 2,199 49,838 100,646 17.9% 14.7% 15.7%
2003 58,731 115,856 326 2,050 50,578 102,342 16.8% 15.2% 15.7%
2004 58,978 117,913 197 2,275 51,439 103,611 15.0% 16.0% 15.7%
2005 58,942 119,795 696 2,166 52,314 106,053 14.0% 15.0% 14.7%
2006 59,630 121,952 929 1,655 53,122 107,485 14.0% 15.0% 14.7%
2007 60,474 123,601 875 1,639 53,815 108,904 14.0% 15.0% 14.7%
2008 61,343 125,152 981 2,459 54,670 110,966 14.0% 15.0% 14.7%
2009 62,317 127,604 923 2,209 55,474 112,881 14.0% 15.0% 14.7%
2010 63,235 129,806 937 2,238 56,291 114,821 14.0% 15.0% 14.7%
2011 64,165 132,036 951 2,285 57,119 116,801 14.0% 15.0% 14.7%
2012 65,110 134,313 889 2,398 57,894 118,879 14.0% 15.0% 14.7%
2013 64,838 136,702 2,132 2,361 58,746 120,924 14.0% 15.0% 14.7%
2014 66,468 139,056 1,487 2,401 59,610 123,006 14.0% 15.0% 14.7%
2015 67,947 141,448 1,010 2,445 60,489 125,124 14.0% 15.0% 14.7%
2016 68,951 143,884 1,018 2,486 61,377 127,278 14.0% 15.0% 14.7%
2017 69,963 145,488 1,042 3,404 62,285 129,471 14.0% 15.0% 14.7%
2018 70,998 148,882 1,050 2,570 63,200 131,698 14.0% 15.0% 14.7%
2019 72,042 151,443 1,064 2,616 64,128 133,964 14.0% 15.0% 14.7%
2020 73,100 154,050 1,085 2,663 65,075 136,273 14.0% 15.0% 14.7%
---------------------------------------------------------------------------------------------------
It should also be noted that given the current supply/demand balance
(including projected capacity additions), RDI believes it is more
profitable to build a combustion turbine than it is to build a combined
cycle plant in MAIN. MAIN and ECAR both have high levels of competitive
baseload generation relative to load and demand growth. In MAIN and ECAR,
more than 80% of the capacity consists of coal-fired, nuclear, or hydro
facilities. The relative scarcity of peaking capacity creates a profitable
niche for combustion turbines. While demand growth creates some
opportunities for intermediate units such as combined cycles, RDI projects
that the majority of capacity additions will be combustion turbines.
Expected near term capacity additions follow this trend as well.
Capacity Additions Table 19 contains a summary of forecast capacity
------------------
additions. These numbers include the new capacity explicitly added by RDI
as discussed in the Base Case Assumptions section and incremental capacity
added by IREMM. Over the next decade nearly 13,000 MW of new capacity
additions are likely to be required in MAIN. To the
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-55
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
extent this new capacity is not added and scarcity becomes acute, prices
may rise substantially higher than forecast by RDI. However, it is RDI's
expectation that in these events developers will respond to the price
signals sent by the market and that enough new capacity additions will be
made to keep the region in long-term supply equilibrium.
TABLE 19
---------------------------------------------------------------------------
BREAKDOWN OF FORECAST CAPACITY ADDITIONS IN MAIN
---------------------------------------------------------------------------
CAPACITY
CURRENT CURRENT ADVANCED ADVANCED TOTAL PRICE
YEAR VINTAGE CT'S VINTAGE CC'S CT'S CC'S ADDITIONS $/kW-yr
--------------------------------------------------------------------------------------------
2000 3,725 256 - - 3,981 19.34
2001 852 1,617 - - 2,469 22.98
2002 575 - - - 575 57.01
2003 326 - - - 326 56.48
2004 (78) 255 - - 177 56.23
2005 418 278 - - 696 55.01
2006 557 372 - - 929 54.59
2007 525 350 - - 875 54.26
2008 589 392 - - 981 53.75
2009 554 369 - - 923 53.41
2010 - - 562 375 937 53.36
2011 - - 571 380 951 50.61
2012 - - 533 356 889 50.39
2013 - - 1,279 853 2,132 50.22
2014 - - 892 595 1,487 49.77
2015 - - 606 404 1,010 48.84
2016 - - 611 407 1,018 48.54
2017 - - 625 417 1,042 45.84
2018 - - 630 420 1,050 45.05
2019 - - 638 426 1,064 44.87
2020 - - 651 434 1,085 42.48
--------------------------------------------------------------------------------------------
TOTAL 8,043 3,890 7,599 5,066 24,597
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-56
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Table 20 breaks down annual capacity additions, retirements, and cumulative
additions of capacity in the MAIN region.
TABLE 20
- --------------------------------------------------------------------------------
FORECAST CAPACITY ADDITIONS AND RETIREMENTS IN MAIN
- --------------------------------------------------------------------------------
CUMULATIVE
BEGINNING CAPACITY NET NET
YEAR OF YEAR ADDITIONS RETIREMENTS/1/ ADDITIONS ADDITIONS
- -----------------------------------------------------------------------------
2000 53,946 3,981 85 3,896 3,896
2001 56,756 2,469 1,171 1,298 5,194
2002 58,201 575 1,024 (449) 4,745
2003 58,731 326 45 281 5,026
2004 58,978 177 79 98 5,124
2005 58,942 696 213 483 5,607
2006 59,630 929 - 929 6,536
2007 60,474 875 77 798 7,334
2008 61,343 981 - 981 8,315
2009 62,317 923 - 923 9,238
2010 63,235 937 - 937 10,175
2011 64,165 951 - 951 11,126
2012 65,110 889 - 889 12,015
2013 64,838 2,132 1,154 978 12,993
2014 66,468 1,487 495 992 13,985
2015 67,947 1,010 - 1,010 14,995
2016 68,951 1,018 - 1,018 16,013
2017 69,963 1,042 - 1,042 17,055
2018 70,998 1,050 - 1,050 18,105
2019 72,042 1,064 - 1,064 19,169
2020 73,100 1,085 - 1,085 20,254
- -----------------------------------------------------------------------------
1. Includes expiration of firm purchases from neighboring regions.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-57
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Electricity Price Forecast Sensitivity Analysis
RDI relies on several analytical assumptions in forecasting electricity
market prices and unit generation. However, changes in fundamental market
variables may create substantial changes in operating results for a
wholesale generation company such as the Genco. Sensitivity analysis is the
principal tool by which the business risk associated with these variables
can be most reasonably characterized. RDI performed sensitivity analysis on
the following variables:
. To reflect the potential volatility of fuel markets, natural gas prices
in each year were increased and decreased by 25% relative to Base Case
levels, and coal prices were increased and decreased by 10%, and;
. To represent the possibility of capacity additions well in excess of
historical reserve margins (i.e., overbuilding), 4,000 MW of new
capacity was assumed to come on-line in MAIN (including 1,200 MW of
combined cycle and 2,800 MW of combustion turbines) and 2,300 MW of new
capacity was assumed to come on-line in ECAR (all combustion turbines),
over and above Base Case levels. This level of additions assumes that
every new power plant proposed in MAIN actually gets built by
developers.
Changes in fuel prices have the single greatest effect on electricity
market prices. The level of overbuilding specified results in reserve
margins in MAIN exceeding 25% through 2003.
SUMMARY OF MARKET PRICE RESULTS
Table 22 shows the relative change in annual market prices from the Base
Case. Appendix C shows the breakdown of prices into peak, off-peak, energy,
and capacity components for each scenario. Key results are as follows:
. The High Fuel Price case results in market price increases of 9.0% in
2000, rising to 13.2% by 2010-2011, and moderating slightly thereafter.
The effect of higher fuel prices tends to decline over time due to the
penetration of more efficient natural gas-fired generation.
. Conversely, the Low Fuel Price case results in prices 5.3% lower in
2000, falling to 12% lower by 2005, and falling below Base Case levels
by as much as 15% thereafter. The penetration of more efficient
technology has less effect on prices in the Low Fuel case, because the
price advantage of more efficient units is lower in a low fuel price
environment.
. The Overbuild case results in depressed prices through 2003, declining
by as much
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MIDWEST ELECTRICITY MARKET ANALYSIS B-58
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
as 29% compared to the Base Case in 2002-2003. In the Overbuild case, load
growth in the Midwest combined with a slower pace of capacity additions
results in a return to Base Case price levels in 2004. Price results are
similar to the Base Case after 2003.
FIGURE 22
- --------------------------------------------------------------------------------
ELECTRICITY MARKET PRICE RESULTS FOR SENSITIVITY CASES
- --------------------------------------------------------------------------------
[A line graph showing the total projected price of electricity for the years
2000 through 2020 and the relative change in annual market prices from the base
case. The graph compares the base case and overbuild, high fuel price and low
fuel price sensitivities.]
- ---------------------------------------------------------------------------------------------------------------------
Base Case Overbuild High Fuel Price Low Fuel Price
--------- --------- --------------- --------------
- ---------------------------------------------------------------------------------------------------------------------
2000 24.81 23.04 27.09 23.52
- ---------------------------------------------------------------------------------------------------------------------
2002 31.02 22.45 33.96 28.25
- ---------------------------------------------------------------------------------------------------------------------
2004 30.39 30.44 33.89 27.48
- ---------------------------------------------------------------------------------------------------------------------
2006 30.91 31.03 34.79 27.03
- ---------------------------------------------------------------------------------------------------------------------
2008 31.64 31.85 35.71 27.32
- ---------------------------------------------------------------------------------------------------------------------
2010 32.01 32.22 36.27 27.55
- ---------------------------------------------------------------------------------------------------------------------
2012 31.87 32.05 35.62 27.38
- ---------------------------------------------------------------------------------------------------------------------
2014 32.42 32.47 35.83 27.69
- ---------------------------------------------------------------------------------------------------------------------
2016 32.37 32.42 35.97 27.77
- ---------------------------------------------------------------------------------------------------------------------
2018 32.47 32.37 36.16 28.06
- ---------------------------------------------------------------------------------------------------------------------
2020 32.40 32.31 36.19 28.27
- ---------------------------------------------------------------------------------------------------------------------
The sensitivity analyses indicate that overbuilding has the greatest potential
to reduce electricity prices in any given year. RDI believes that the potential
for mild overbuilding exists in MAIN during 2000-2001; this is incorporated in
the Base Case price forecast. If an additional 6,300 MW of capacity is added in
MAIN and ECAR by 2001 as in the Overbuild case, a longer period of depressed
prices could result. However even with a significant overbuild, load growth is
sufficient to limit the length of time the market stays overbuilt. Table 21
illustrates that by 2004, MAIN and ECAR achieve supply equilibrium at the
combined reserve margin of 15.7%, consisting of surplus capacity in MAIN, and
deficient capacity in ECAR. Overall, MAIN and ECAR are likely to need over
35,000 MW of new capacity from 2000-2010, taking into account load growth and
expected retirements.
Given the increasing competitive dynamics of the generation markets and the
number of new entrants in the generation business, MAIN may experience overbuilt
conditions at times over the next 20 years. During these periods the value of
firm capacity may be diminished as shown in the Overbuild case, and in the Base
Case to a lesser extent. However, RDI also believes that price spikes due to
generation shortages are likely to occur as well. Over the duration of the
20-year period, average future electricity prices should approximate the long
run marginal cost of electricity.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-59
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
TABLE 21
---------------------------------------------------------------------------
CAPACITY BALANCE IN ECAR AND MAIN - OVERBUILD CASE
---------------------------------------------------------------------------
Installed Capacity Capacity Additions Peak Demand Reserve Margins (%)
-------------------------------------------------------------------------------------------------------------
MAIN/ECAR
Year MAIN ECAR MAIN ECAR MAIN ECAR MAIN ECAR Combined
-------------------------------------------------------------------------------------------------------------
2000 53,947 108,700 5,181 5,270 48,618 96,946 21.6% 17.6% 18.9%
2001 57,977 115,013 3,869 1,095 49,208 98,786 25.7% 17.5% 20.2%
2002 60,801 115,505 1,975 0 49,838 100,646 26.0% 14.8% 18.5%
2003 62,731 115,986 326 0 50,578 102,342 24.7% 13.3% 17.1%
2004 62,978 116,019 197 269 51,439 103,611 22.8% 12.2% 15.7%
2005 62,847 115,915 0 2,836 52,314 106,053 20.1% 12.0% 14.7%
2006 62,847 118,742 0 2,576 53,122 107,485 18.3% 12.9% 14.7%
2007 62,770 121,312 0 2,506 53,815 108,904 16.6% 13.7% 14.7%
2008 62,770 123,726 0 3,438 54,670 110,966 14.8% 14.6% 14.7%
2009 62,770 127,156 470 2,657 55,474 112,881 14.0% 15.0% 14.7%
2010 63,232 129,804 940 2,240 56,291 114,821 14.0% 15.0% 14.7%
2011 64,164 132,034 952 2,287 57,119 116,801 14.0% 15.0% 14.7%
2012 65,110 134,314 889 2,397 57,894 118,879 14.0% 15.0% 14.7%
2013 64,838 136,702 2,132 2,361 58,746 120,924 14.0% 15.0% 14.7%
2014 66,468 139,056 1,487 2,401 59,610 123,006 14.0% 15.0% 14.7%
2015 67,947 141,448 1,010 2,445 60,489 125,124 14.0% 15.0% 14.7%
2016 68,951 143,884 1,018 2,486 61,377 127,278 14.0% 15.0% 14.7%
2017 69,963 145,488 1,042 3,404 62,285 129,471 14.0% 15.0% 14.7%
2018 70,998 148,883 1,050 2,570 63,200 131,698 14.0% 15.0% 14.7%
2019 72,042 151,443 1,064 2,616 64,128 133,964 14.0% 15.0% 14.7%
2020 73,100 154,050 1,085 2,663 65,075 136,273 14.0% 15.0% 14.7%
------------------------------------------------------------------------------------------------------------
TABLE 22
---------------------------------------------------------------------------
ELECTRICITY MARKET PRICE CHANGES RELATIVE TO THE BASE CASE
---------------------------------------------------------------------------
Year High Fuel Low Fuel Overbuild
--------------------------------------------------
2000 9.2% -5.2% -7.1%
2001 9.7% -6.2% -9.4%
2002 9.5% -8.9% -27.7%
2003 10.2% -7.9% -26.7%
2004 11.5% -9.6% 0.2%
2005 12.2% -12.3% 0.3%
2006 12.5% -12.6% 0.4%
2007 12.7% -13.1% 0.6%
2008 12.8% -13.7% 0.7%
2009 12.9% -13.8% 0.8%
2010 13.3% -13.9% 0.6%
2011 12.4% -14.1% 0.4%
2012 11.8% -14.1% 0.6%
2013 12.1% -14.2% 0.7%
2014 10.5% -14.6% 0.1%
2015 10.7% -14.2% -0.1%
2016 11.1% -14.2% 0.2%
2017 11.2% -13.7% 0.4%
2018 11.3% -13.6% -0.3%
2019 11.9% -13.5% 0.2%
2020 11.7% -12.7% -0.3%
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-60
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Summary of Genco Revenues and Operations
The basecase price forecast provides the basis for RDI's forecast of the
hourly revenues the Genco can expect to achieve through its sales of
capacity and energy and the forecast capacity factors of its assets. The
specific Genco assets included in this evaluation, along with their modeled
capacity, is shown in Table 23./14/ The Genco's interactions with the
wholesale markets are characterized as follows:
. The Genco serves the capacity and energy requirements of its
bilateral contracts, and receives fixed revenues from those
contracts;
. The Genco can sell capacity and energy above the requirements of its
bilateral contracts into the spot wholesale markets;
. During those periods when economy energy is available at lower
prices than the Genco's marginal cost, the Genco can purchase
economy energy to serve its bilateral contracts. Alternatively,
economy energy may be available to the Genco through its JDA with
AmerenUE.
. The Genco's primary contract with the Disco expires after 2004.
Other wholesale contracts expire over the course of the forecast,
until 2014 when no current wholesale contracts remain.
TABLE 23
---------------------------------------------------------------------------
GENCO GENERATING ASSETS
---------------------------------------------------------------------------
-------------------------------------------------------
Capacity First Unit On Last Unit On
Plant (MW) line line
-------------------------------------------------------
Newton 1,110 1977 1982
Coffeen 900 1965 1972
Meredosia 507 1948 1975
Hutsonville 153 1940 1968
Grand Tower/1/ 190 1951 1958
Grand Tower CC 492 June 2001 -
Gibson City CTs 230 June 2000 -
Pickneyville CTs 168 June 2000 -
Kinmundy CTs 230 May 2001 -
-------------------------------------------------------
1. Retires in 2001 for CC repowering.
Table 24 shows RDI's forecast of revenues for the Genco, which combines the
bilateral contract forecast with RDI's forecast of the Genco's market
transactions, including purchases and sales, over the forecast period.
Prior to 2005, the Genco's bilateral contracts account for 79% of the
Genco's total revenue. After 2005, the primary contract with the Disco
expires and more than 95% of the Genco's revenues are assumed to be based
on wholesale market prices. After 2014, all of the Genco's revenues are
assumed to
___________________
/14/ The net dependable MW value used in RDI's analysis may differ slightly from
other representations of capacity.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-61
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
be based on wholesale market prices. The Genco's average annual revenue growth
(nominal) is projected at 4.1% annually through 2020.
Electricity supplied by the Genco increases through 2001 as its bilateral
contracts go into effect, and then declines through 2004. Declines in generation
used to serve wholesale contracts are not wholly offset by increased sales to
wholesale spot markets. This is attributable to projected new capacity
additions, which capture some generation from the Genco's assets. After 2004,
the Genco experiences generation growth of 1.4% annually, approximately equal to
forecast demand growth in MAIN.
The Genco's coal-fired generating assets, particularly Newton and Coffeen,
experience near-term growth in generation compared to historical utilization
levels. This is attributable mainly to reductions in the delivered price of coal
to each of these plants (due to recent fuel contract re-negotiations), which
improves their position in merit dispatch relative to their competitors in MAIN.
Newton additionally benefits from a full switch to PRB coal, which has a lower
environmental dispatch penalty than Illinois Basin coal due to its lower sulfur
content. Appendix B to this report presents RDI's forecast of unit specific
capacity factors in support of the Genco's overall electricity supply forecast.
TABLE 24
GENCO BASE CASE GENERATION AND REVENUE FORECAST ($ NOMINAL)
Generation (GWh) Revenues ($000)
=================================================================================================================================
Power Sales Spot Power Sales Spot Total
Year Contracts Spot Sales Purchases Total GWh Contracts Spot Sales Purchases Revenue
=================================================================================================================================
2000 14,723 579 (269) 15,033 497,205 17,547 (5,333) 509,419
2001 15,760 444 (421) 15,783 531,925 27,203 (8,327) 550,801
2002 14,675 1,072 (218) 15,529 496,994 77,860 (4,131) 570,722
2003 12,610 1,985 (92) 14,503 439,963 121,732 (1,763) 559,932
2004 10,959 3,589 (50) 14,498 392,591 190,486 (976) 582,101
2005 965 13,856 (0) 14,820 28,935 612,160 (8) 641,086
2006 965 14,158 (0) 15,122 28,935 640,851 (7) 669,778
2007 958 14,245 (1) 15,202 28,747 666,229 (12) 694,965
2008 950 14,733 (0) 15,683 28,471 709,851 (8) 738,314
2009 950 15,041 (0) 15,991 28,471 743,577 (6) 772,042
2010 950 14,955 (0) 15,905 28,471 763,813 (7) 792,278
2011 950 15,866 (0) 16,816 28,471 805,487 - 833,958
2012 500 16,544 (0) 17,044 15,882 870,732 - 886,614
2013 500 16,620 (0) 17,120 15,882 889,317 - 905,199
2014 500 16,945 (0) 17,445 15,882 937,853 - 953,735
2015 - 17,666 - 17,666 - 998,821 - 998,821
2016 - 17,691 - 17,691 - 1,026,858 - 1,026,858
2017 - 17,948 - 17,948 - 1,064,720 - 1,064,720
2018 - 18,072 - 18,072 - 1,101,404 - 1,101,404
2019 - 18,143 - 18,143 - 1,136,032 - 1,136,032
2020 - 18,310 - 18,310 - 1,173,202 - 1,173,202
- ----------------------------------------------------------------------------------------------------------------------------------
GENCO GENERATION BY ASSET TYPE AND SENSITIVITY CASES
Each sensitivity case has varying outcomes for the Genco's operating results.
The Genco's generating assets can be described in three categories: baseload
generation, including the Newton and Coffeen stations, and Meredosia unit 3;
intermediate generation, including
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MIDWEST ELECTRICITY MARKET ANALYSIS B-62
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
the Hutsonville and Grand Tower stations (both before and after repowering to
natural gas), and Meredosia units 1 and 2; and peaking generation, including all
of the Genco's new combustion turbine additions and the oil-fired Meredosia 4.
The effect of each case on each category of the Genco's generating assets is
described below. In general, the low fuel price case tends to reduce the
generation of the Genco's mostly coal-fired assets, while high fuel prices tend
to increase generation, primarily reflecting regional shifts in generation share
between coal-fired units and combined cycle plants in each case.
Baseload generation Figure 23 shows the projected generation of the Genco's
baseload assets under each scenario. The Genco's baseload generation declines
slightly in 2003 in the base case scenario, as combined cycle competition
captures some on-peak load the Genco was previously serving. This effect is much
more pronounced in the low fuel price case, when the dispatch price of combined
cycle units is competitive with coal-fired generation for a larger portion of
the year. Conversely, the high fuel price case increases the competitiveness of
baseload generation. Because the overbuild scenario does not introduce
significant new competition to the Genco's baseload generators, its effect on
baseload generation is minimal.
FIGURE 23
ANNUAL BASELOAD GENERATION BY CASE
[A line graph showing projected generation (GWh) of Genco's baseload assets for
the years 2000 through 2020, comparing base case and high fuel price, low fuel
price and overbuild sensitivities.]
- -----------------------------------------------------------------------------------------
Base Case Overbuild High Fuel Price Low Fuel Price
--------- --------- --------------- --------------
- -----------------------------------------------------------------------------------------
2000 14,104 14,102 14,322 13,632
- -----------------------------------------------------------------------------------------
2002 14,102 14,107 14,367 13,388
- -----------------------------------------------------------------------------------------
2004 13,118 13,103 13,900 11,605
- -----------------------------------------------------------------------------------------
2006 13,476 13,480 14,234 11,523
- -----------------------------------------------------------------------------------------
2008 13,848 13,851 14,415 12,181
- -----------------------------------------------------------------------------------------
2010 14,062 14,061 14,439 12,944
- -----------------------------------------------------------------------------------------
2012 14,966 15,007 15,224 14,355
- -----------------------------------------------------------------------------------------
2014 15,173 15,176 15,410 14,584
- -----------------------------------------------------------------------------------------
2016 15,350 15,359 15,521 14,671
- -----------------------------------------------------------------------------------------
2018 15,545 15,555 15,680 14,913
- -----------------------------------------------------------------------------------------
2020 15,639 15,647 15,734 15,038
- -----------------------------------------------------------------------------------------
Intermediate generation Figure 24 shows the projected generation of the Genco's
intermediate assets under each scenario. The general pattern of generation
growth is attributable to load growth and the improving relative dispatch price
of the Genco's coal-fired intermediate units (i.e., versus combined-cycle
plants). Initial growth in intermediate generation is attributable to the
conversion of Grand Tower to a higher capacity gas-fired unit in mid-2001.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-63
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
FIGURE 24
ANNUAL INTERMEDIATE GENERATION BY CASE
[A line graph showing the projected generation (GWh) of Genco's intermediate
assets for the years 2000 through 2020, comparing the base case and high fuel
price, low fuel price and overbuild sensitivities.]
- -----------------------------------------------------------------------------------------------
Base Case Overbuild High Fuel Price Low Fuel Price
--------- --------- --------------- --------------
- -----------------------------------------------------------------------------------------------
2000 818 815 993 599
- -----------------------------------------------------------------------------------------------
2002 1,286 1,242 1,413 1,588
- -----------------------------------------------------------------------------------------------
2004 1,250 1,255 1,457 1,173
- -----------------------------------------------------------------------------------------------
2006 1,501 1,469 1,845 1,269
- -----------------------------------------------------------------------------------------------
2008 1,694 1,696 2,090 1,416
- -----------------------------------------------------------------------------------------------
2010 1,721 1,739 2,129 1,436
- -----------------------------------------------------------------------------------------------
2012 1,961 1,935 2,338 1,579
- -----------------------------------------------------------------------------------------------
2014 2,196 2,154 2,551 1,754
- -----------------------------------------------------------------------------------------------
2016 2,281 2,283 2,606 1,746
- -----------------------------------------------------------------------------------------------
2018 2,480 2,500 2,803 1,903
- -----------------------------------------------------------------------------------------------
2020 2,632 2,630 2,878 2,009
- -----------------------------------------------------------------------------------------------
Peaking generation Figure 25 shows the projected generation of the Genco's
- ------------------
peaking assets under each scenario. The addition of new peaking generation
resources in mid-2001 causes the increase in generation from 2000-2001. In
mid-2000, the Genco will complete construction of 170 MW of high-efficiency
peaking units (LM6000 combustion turbines). These units capture additional
peaking generation during times of low fuel prices, and give up some generation
during times of high fuel prices. Through 2010, the Overbuild case results in
the highest level of generation for the Genco's peakers. This is because the
Overbuild case results in a greater weighting of peaking resources vs. new
combined cycle plants than the base case, allowing the Genco's more efficient
peakers to increase their generation share.
FIGURE 25
ANNUAL PEAKING GENERATION BY CASE
[A line graph showing the projected generation (GWh) of Genco's peaking assets
for the years 2000 through 2020, comparing the base case and high fuel price,
low fuel price, and overbuild sensitivities.]
- ----------------------------------------------------------------------------------------------
Base Case Overbuild High Fuel Price Low Fuel Price
--------- --------- --------------- --------------
- ----------------------------------------------------------------------------------------------
2000 111 112 106 121
- ----------------------------------------------------------------------------------------------
2002 170 181 175 168
- ----------------------------------------------------------------------------------------------
2004 163 198 168 152
- ----------------------------------------------------------------------------------------------
2006 180 209 196 167
- ----------------------------------------------------------------------------------------------
2008 187 222 209 157
- ----------------------------------------------------------------------------------------------
2010 164 190 185 142
- ----------------------------------------------------------------------------------------------
2012 138 164 165 123
- ----------------------------------------------------------------------------------------------
2014 125 133 139 106
- ----------------------------------------------------------------------------------------------
2016 108 112 136 93
- ----------------------------------------------------------------------------------------------
2018 101 106 142 82
- ----------------------------------------------------------------------------------------------
2020 88 94 135 74
- ----------------------------------------------------------------------------------------------
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MIDWEST ELECTRICITY MARKET ANALYSIS B-64
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
Figure 26 shows the Genco's total generation for each case. Overall, the Genco
gains generation when fuel prices rise, because of its relatively low-cost
generation mix. Conversely, the Genco loses generation when declining gas prices
allow gas-fired generation to compete with Genco's coal assets for load.
FIGURE 26
GENCO TOTAL GENERATION BY CASE
[A line graph showing Genco's total generation (GWh) for the years 2000 through
2020, comparing the base case and high fuel price, low fuel price and overbuild
sensitivities.]
- -------------------------------------------------------------------------------------
Base Case Overbuild High Fuel Price Low Fuel Price
--------- --------- --------------- --------------
- -------------------------------------------------------------------------------------
2000 15,033 15,029 15,421 14,352
- -------------------------------------------------------------------------------------
2002 15,559 15,530 15,954 15,144
- -------------------------------------------------------------------------------------
2004 14,531 14,556 15,524 12,931
- -------------------------------------------------------------------------------------
2006 15,157 15,158 16,276 12,960
- -------------------------------------------------------------------------------------
2008 15,729 15,769 16,715 13,754
- -------------------------------------------------------------------------------------
2010 15,947 15,990 16,753 14,522
- -------------------------------------------------------------------------------------
2012 17,095 17,106 17,727 16,058
- -------------------------------------------------------------------------------------
2014 17,494 17,463 18,100 16,443
- -------------------------------------------------------------------------------------
2016 17,739 17,754 18,263 16,510
- -------------------------------------------------------------------------------------
2018 18,126 18,162 18,626 16,897
- -------------------------------------------------------------------------------------
2020 18,360 18,372 18,748 17,120
- -------------------------------------------------------------------------------------
Figure 27 shows the Genco's total market-based sales under each case. Total
sales grow as the Genco's wholesale contracts expire, with the largest growth
taking place between 2004 and 2005. After 2014, all of the Genco's sales are
market-based. The Genco tends to make more sales in the High Fuel Price case,
because its predominantly coal based portfolio gains a greater cost advantage
against gas fired plants. In the Low Fuel Price case, the Genco's cost advantage
is eroded somewhat, and it makes fewer market sales.
FIGURE 27
ANNUAL MARKET BASED SALES BY CASE
[A line graph showing Genco's total market-based sales for the years 2000
through 2020, comparing the base case and high fuel price, low fuel price and
overbuild sensitivities.]
- ----------------------------------------------------------------------------------------------
Base Case Overbuild High Fuel Price Low Fuel Price
--------- --------- --------------- --------------
- ----------------------------------------------------------------------------------------------
2000 677 675 1,022 410
- ----------------------------------------------------------------------------------------------
2002 1,176 1,141 1,497 773
- ----------------------------------------------------------------------------------------------
2004 3,702 3,729 4,683 2,165
- ----------------------------------------------------------------------------------------------
2006 14,261 14,263 15,381 12,065
- ----------------------------------------------------------------------------------------------
2008 14,848 14,888 15,834 12,873
- ----------------------------------------------------------------------------------------------
2010 15,066 15,110 15,872 13,641
- ----------------------------------------------------------------------------------------------
2012 16,662 16,673 17,295 15,624
- ----------------------------------------------------------------------------------------------
2014 17,060 17,030 17,666 16,010
- ----------------------------------------------------------------------------------------------
2016 17,799 17,816 18,324 16,571
- ----------------------------------------------------------------------------------------------
2018 18,188 18,222 18,687 16,960
- ----------------------------------------------------------------------------------------------
2020 18,421 18,433 18,809 17,181
- ----------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-65
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
SUMMARY OF GENCO REVENUES
For purposes of assessing the effect of each sensitivity case on the Genco's
revenues, it is useful to look at the results from two time periods: 2000-2004,
when the large majority of the Genco's wholesale agreements are in effect, and
2005-2020, when the Genco's revenues are determined predominantly by market
prices.
Figure 28 shows the Genco's annual revenues through 2004 under each sensitivity
case. Through 2002, most of the Genco's output is needed to serve its wholesale
contracts, leaving little exposure to changes in open market prices. The effect
of each sensitivity case on total revenues is therefore small. From 2003-2004,
the Genco is selling more of its output in the spot markets, and a greater range
of revenues can be seen as a result. Figure 28 illustrates that the Overbuild
case creates the highest risk of reduced revenues. By 2004, supply and demand in
the Overbuild case are in balance, and the Overbuild revenues are similar to the
Base Case.
FIGURE 28
TOTAL GENCO REVENUES BY CASE, 2000-2004 ($ NOMINAL)
[A line graph showing Genco's annual revenues through 2004, comparing the base
case and overbuild, high fuel price and low fuel price sensitivities.]
- --------------------------------------------------------------------------------------------
Base Case Overbuild High Fuel Price Low Fuel Price
--------- --------- --------------- --------------
- --------------------------------------------------------------------------------------------
2000 509 508 521 495
- --------------------------------------------------------------------------------------------
2001 551 542 555 546
- --------------------------------------------------------------------------------------------
2002 573 530 586 560
- --------------------------------------------------------------------------------------------
2003 562 506 595 534
- --------------------------------------------------------------------------------------------
2004 584 584 629 533
- --------------------------------------------------------------------------------------------
Figure 29 shows the Genco's annual revenues from 2005-2020. As before,
Overbuild case revenues are similar to the Base Case. This is due to the fact
that by 2005, the market has reached a supply/demand equilibrium in the
overbuild scenario. The range in total revenues from the High Fuel and Low Fuel
cases grows from $220 million in 2005 to $340 million by 2019.
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MIDWEST ELECTRICITY MARKET ANALYSIS B-66
RDI Consulting . FT ENERGY
- --------------------------------------------------------------------------------
FIGURE 29
TOTAL GENCO REVENUES BY CASE, 2005-2020
[A line graph showing Genco's projected annual revenues from 2005 through 2020,
comparing the base case and overbuild, high fuel price and low fuel price
sensitivities.]
- -----------------------------------------------------------------------------------------------
Base Case Overbuild High Fuel Price Low Fuel Price
--------- --------- --------------- --------------
- -----------------------------------------------------------------------------------------------
2005 644 646 746 525
- -----------------------------------------------------------------------------------------------
2006 673 674 780 550
- -----------------------------------------------------------------------------------------------
2007 698 702 810 571
- -----------------------------------------------------------------------------------------------
2008 741 745 859 604
- -----------------------------------------------------------------------------------------------
2009 775 780 898 629
- -----------------------------------------------------------------------------------------------
2010 796 800 920 657
- -----------------------------------------------------------------------------------------------
2011 838 839 961 700
- -----------------------------------------------------------------------------------------------
2012 878 879 997 730
- -----------------------------------------------------------------------------------------------
2013 909 913 1,035 753
- -----------------------------------------------------------------------------------------------
2014 957 953 1,072 790
- -----------------------------------------------------------------------------------------------
2015 1,003 998 1,126 824
- -----------------------------------------------------------------------------------------------
2016 1,031 1,028 1,159 846
- -----------------------------------------------------------------------------------------------
2017 1,069 1,068 1,203 887
- -----------------------------------------------------------------------------------------------
2018 1,106 1,101 1,247 918
- -----------------------------------------------------------------------------------------------
2019 1,141 1,138 1,286 944
- -----------------------------------------------------------------------------------------------
2020 1,178 1,172 1,325 987
- -----------------------------------------------------------------------------------------------
It is important to note the interaction between revenues and net cash flow for
each of the sensitivity cases./15/ For the High Fuel and Low Fuel cases, changes
in the Genco's fuel costs tend to offset changes in general market prices. For
example, while higher market prices in the High Fuel case increase the Genco's
market revenues, a higher fuel bill offsets this increase. Overall, the Genco
benefits when increased gas prices drive market prices up. Conversely, net cash
flows fall when gas prices drive market prices down. Most notably, when prices
are low due to overbuilding, unit fuel prices do not offset revenue declines.
The Overbuild case therefore presents the highest overall risk to net cash flow
from market sales.
_____________________
/15/ This report does not provide specific projections of net cash flow for the
Genco.
- --------------------------------------------------------------------------------
MIDWEST ELECTRICITY MARKET ANALYSIS B-67
Appendix A
.
Genco Contract Load and Revenue Forecast
TABLE A.1
- ------------------------------------------------------------------------------
FORECAST OF GENCO CONTRACT LOADS AND REVENUES
- ------------------------------------------------------------------------------
CIPS Disco UE Municipals Illinois Munis/Coops Interchange Agreements/1/ Total
--------------------------------------------------------------------------------------------------------------------------------
Demand Energy Revenues Demand Energy Revenues Demand Energy Revenues Demand Energy Revenues Demand Energy Revenues
Year (MW) (GWh) ($000) (MW) (GWh) ($000) (MW) (GWh) ($000) (MW) (GWh) ($000) (MW) (GWh) ($000)
- -----------------------------------------------------------------------------------------------------------------------------------
2000 1990 9512 346,180 229 1205 37,708 506 2,548 70,967 465 1458 42,350 3,190 14,723 497,205
2001 2020 9743 353,309 229 1224 38,353 427 2,160 64,893 465 2633 75,370 3,141 15,760 531,925
2002 2020 9754 353,549 24 134 3,014 431 2,154 64,904 465 2633 75,528 2,940 14,675 496,994
2003 2050 9826 357,211 24 78 1,758 118 553 17,855 465 2154 63,140 2,657 12,610 439,963
2004 2080 9956 362,137 0 0 - 118 553 17,864 65 450 12,589 2,263 10,959 392,591
2005 0 0 - 0 0 - 109 515 16,346 65 450 12,589 174 965 28,935
2006 0 0 - 0 0 - 109 515 16,346 65 450 12,589 174 965 28,935
2007 0 0 - 0 0 - 108 508 16,158 65 450 12,589 173 958 28,747
2008 0 0 - 0 0 - 106 500 15,882 65 450 12,589 171 950 28,471
2009 0 0 - 0 0 - 106 500 15,882 65 450 12,589 171 950 28,471
2010 0 0 - 0 0 - 106 500 15,882 65 450 12,589 171 950 28,471
2011 0 0 - 0 0 - 106 500 15,882 65 450 12,589 171 950 28,471
2012 0 0 - 0 0 - 106 500 15,882 0 0 - 106 500 15,882
2013 0 0 - 0 0 - 106 500 15,882 0 0 - 106 500 15,882
2014 0 0 - 0 0 - 106 500 15,882 0 0 - 106 500 15,882
2015 0 0 - 0 0 - - - - 0 0 - - - -
2016 0 0 - 0 0 - - - - 0 0 - - - -
2017 0 0 - 0 0 - - - - 0 0 - - - -
2018 0 0 - 0 0 - - - - 0 0 - - - -
2019 0 0 - 0 0 - - - - 0 0 - - - -
2020 0 0 - 0 0 - - - - 0 0 - - - -
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Includes sales of capacity and energy to CILCO, WVPA, and ADM
Appendix B
.
Summary of Genco Generating Unit Operations
APPENDIX B
YEAR
GENERATING UNIT 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
COFFEEN 1
CAPACITY (MW): 340 340 340 340 340 340 340 340 340 340 340 340 340 340 340
GENERATION (GWH): 1829 1922 1765 1500 1496 1583 1637 1654 1710 1761 1762 2047 2116 2120 2148
CAPACITY FACTOR %: 61% 65% 59% 50% 50% 53% 55% 56% 57% 59% 59% 69% 71% 71% 72%
SO2 EMISSIONS (TONS): 17,999 18,910 17,363 14,761 14,724 15,577 16,107 16,272 16,826 17,327 17,339 10,612 10,972 10,933 11,137
COFFEEN 2
CAPACITY (MW): 560 560 560 560 560 560 560 560 560 560 560 560 560 560 560
GENERATION (GWH): 3373 3558 3402 2861 2815 2809 2891 2928 3015 3097 3107 3555 3592 3605 3660
CAPACITY FACTOR %: 69% 73% 69% 58% 57% 57% 59% 60% 61% 63% 63% 72% 73% 73% 75%
SO2 EMISSIONS (TONS): 32,790 34,588 33,072 27,813 27,365 27,307 28,104 28,464 29,310 30,107 30,204 18,211 18,400 18,467 18,749
GIBSON CITY 1
CAPACITY (MW): 115 115 115 115 115 115 115 115 115 115 115 115 115 115 115
GENERATION (GWH): 28 31 25 26 24 27 28 25 25 24 20 21 17 13 12
CAPACITY FACTOR %: 3% 3% 2% 3% 2% 3% 3% 3% 3% 2% 2% 2% 2% 1% 1%
SO2 EMISSIONS (TONS): - - - - - - - - - - - - - - -
GIBSON CITY 2
CAPACITY (MW): 115 115 115 115 115 115 115 115 115 115 115 115 115 115 115
GENERATION (GWH): 12 26 26 25 22 26 27 24 24 22 18 18 15 12 11
CAPACITY FACTOR %: 1% 3% 3% 2% 2% 3% 3% 2% 2% 2% 2% 2% 1% 1% 1%
SO2 EMMISSIONS (TONS): - - - - - - - - - - - - - - -
GRAND TOW CC CC3
CAPACITY (MW): 256 256 256 256 256 256 256 256 256 256 256 256 256 256
GENERATION (GWH): 237 421 415 428 478 487 498 530 551 551 569 576 590 639
CAPACITY FACTOR %: 11% 19% 19% 19% 21% 22% 22% 24% 25% 25% 25% 26% 26% 28%
SO2 EMISSIONS (TONS): - - - - - - - - - - - - - - -
GRAND TOW CC CC4
CAPACITY (MW): 256 256 256 256 256 256 256 256 256 256 256 256 256 256
GENERATION (GWH): 320 466 417 416 480 489 482 515 532 535 588 592 606 653
CAPACITY FACTOR %: 14% 21% 19% 19% 21% 22% 21% 23% 24% 24% 26% 26% 27% 29%
SO2 EMISSIONS (TONS): - - - - - - - - - - - - - - -
GRAND TOWER 3
CAPACITY (MW): 85
GENERATION (GWH): 108
CAPACITY FACTOR %: 14%
SO2 EMISSIONS (TONS): 3,486 - - - - - - - - - - - - - -
RDI CONSULTING FT ENERGY B-1
APPENDIX B
YEAR
GENERATING UNIT 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
GRAND TOWER 4
CAPACITY (MW): 105
GENERATION (GWH): 246
CAPACITY FACTOR %: 27%
SO2 EMISSIONS (TONS): 6,928 - - - - - - - - - - - - - -
HUTSONVILLE 3
CAPACITY (MW): 76 76 76 76 76 76 76 76 76 76 76 76 76 76 76
GENERATION (GWH): 128 128 107 98 107 138 144 147 167 176 172 205 209 218 241
CAPACITY FACTOR %: 19% 19% 16% 15% 16% 21% 22% 22% 25% 26% 26% 31% 31% 33% 36%
SO2 EMISSIONS (TONS): 3,471 3,471 2,639 2,462 2,685 3,455 3,608 3,673 4,195 4,413 4,315 5,138 5,238 5,459 6,050
HUTSONVILLE 4
CAPACITY (MW): 77 77 77 77 77 77 77 77 77 77 77 77 77 77 77
GENERATION (GWH): 152 150 127 111 119 149 155 162 183 195 194 222 237 251 284
CAPACITY FACTOR %: 23% 22% 19% 16% 18% 22% 23% 24% 27% 29% 29% 33% 35% 37% 42%
SO2 EMISSIONS (TONS): 4,062 4,014 3,128 2,745 2,950 3,685 3,826 4,001 4,528 4,828 4,803 5,480 5,851 6,203 7,019
KINMUNDY 1
CAPACITY (MW): 115 115 115 115 115 115 115 115 115 115 115 115 115 115
GENERATION (GWH): 21 25 27 23 27 28 26 27 25 18 19 15 13 12
CAPACITY FACTOR %: 2% 2% 3% 2% 3% 3% 3% 3% 3% 2% 2% 1% 1% 1%
SO2 EMISSIONS (TONS): - - - - - - - - - - - - - - -
KINMUNDY 2
CAPACITY (MW): 115 115 115 115 115 115 115 115 115 115 115 115 115 115
GENERATION (GWH): 20 27 26 21 25 26 24 24 22 17 16 14 12 11
CAPACITY FACTOR %: 2% 3% 3% 2% 3% 3% 2% 2% 2% 2% 2% 1% 1% 1%
SO2 EMISSIONS (TONS): - - - - - - - - - - - - - - -
MEREDOSIA 1
CAPACITY (MW): 62 62 62 62 62 62 62 62 62 62 62 62 62 62 62
GENERATION (GWH): 95 94 77 73 84 104 106 114 125 131 126 135 144 156 179
CAPACITY FACTOR %: 17% 17% 14% 13% 15% 19% 19% 21% 23% 24% 23% 25% 27% 29% 33%
SO2 EMISSIONS (TONS): 1,996 1,868 1,425 1,383 1,593 1,975 2,017 2,165 2,383 2,507 2,775 2,980 3,178 3,445 3,940
MEREDOSIA 2
CAPACITY (MW): 62 62 62 62 62 62 62 62 62 62 62 62 62 62 62
GENERATION (GWH): 89 91 79 70 81 100 102 109 120 128 124 134 140 152 172
CAPACITY FACTOR %: 16% 17% 14% 13% 15% 18% 19% 20% 22% 24% 23% 25% 26% 28% 32%
SO2 EMISSIONS (TONS): 1,873 1,816 1,456 1,341 1,545 1,900 1,940 2,087 2,280 2,436 2,731 2,955 3,094 3,359 3,788
RDI CONSULTING FT ENERGY B-2
APPENDIX B
YEAR
GENERATING UNIT 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
MEREDOSIA 3
CAPACITY (MW): 215 215 215 215 215 215 215 215 215 215 215
GENERATION (GWH): 629 822 676 446 447 531 605 634 711 781 755
CAPACITY FACTOR %: 33% 44% 36% 24% 24% 28% 32% 34% 38% 41% 40%
SO2 EMISSIONS (TONS): 10,047 12,355 9,484 6,439 6,454 7,671 8,726 9,144 10,267 11,266 12,584
MEREDOSIA 4
CAPACITY (MW): 168 168 168 168 168 168 168 168 168 168 168
GENERATION (GWH): 13 9 7 6 6 2 2 2 3 2 2
CAPACITY FACTOR %: 1% 1% 0% 0% 0% 0% 0% 0% 0% 0% 0%
SO2 EMISSIONS (TONS): - - - - - - - - - - -
NEWTON 1
CAPACITY (MW): 555 555 555 555 555 555 555 555 555 555 555
GENERATION (GWH): 4118 4102 4114 4122 4083 4080 4081 4087 4102 4110 4093
CAPACITY FACTOR %: 85% 84% 85% 85% 84% 84% 84% 84% 84% 85% 84%
SO2 EMISSIONS (TONS): 13,937 13,883 13,924 13,951 13,819 13,809 13,812 13,832 13,883 13,910 13,853
NEWTON 2
CAPACITY (MW): 555 555 555 555 555 555 555 555 555 555 555
GENERATION (GWH): 4157 4161 4161 4152 4160 4102 4104 4114 4126 4130 4124
CAPACITY FACTOR %: 86% 86% 86% 85% 86% 84% 84% 85% 85% 85% 85%
SO2 EMISSIONS (TONS): 14,064 14,077 14,077 14,047 14,074 13,878 13,885 13,918 13,959 13,972 13,952
PINCKNEYVILLE 1-2
CAPACITY (MW): 84 84 84 84 84 84 84 84 84 84 84
GENERATION (GWH): 31 43 31 30 34 38 39 41 44 45 40
CAPACITY FACTOR %: 4% 6% 4% 4% 5% 5% 5% 6% 6% 6% 5%
SO2 EMISSIONS (TONS): - - - - - - - - - - -
PINCKNEYVILLE 3-4
CAPACITY (MW): 84 84 84 84 84 84 84 84 84 84 84
GENERATION (GWH): 28 41 31 30 33 37 39 39 43 44 40
CAPACITY FACTOR %: 4% 6% 4% 4% 5% 5% 5% 5% 6% 6% 5%
SO2 EMISSIONS (TONS): - - - - - - - - - - -
GENERATING UNIT 2011 2012 2013 2014
MEREDOSA 3
CAPACITY (MW): 215 215 215 215
GENERATION (GWH): 835 843 892 960
CAPACITY FACTOR %: 44% 45% 47% 51%
SO2 EMISSIONS (TONS): 13,918 14,060 14,877 15,999
MEREDOSA 4
CAPACITY (MW): 168 168 168 168
GENERATION (GWH): 2 1 2 2
CAPACITY FACTOR %: 0% 0% 0% 0%
SO2 EMISSIONS (TONS): - - - -
NEWTON 1
CAPACITY (MW): 555 555 555 555
GENERATION (GWH): 4089 4107 4103 4121
CAPACITY FACTOR %: 84% 84% 84% 85%
SO2 EMISSIONS (TONS): 13,839 13,900 13,887 13,948
NEWTON 2
CAPACITY (MW): 555 555 555 555
GENERATION (GWH): 4113 4127 4123 4138
CAPACITY FACTOR %: 85% 85% 85% 85%
SO2 EMISSIONS (TONS): 13,915 13,962 13,949 14,000
PINCKEYVILLE 1-2
CAPACITY (MW): 84 84 84 84
GENERATION (GWH): 39 36 32 34
CAPACITY FACTOR %: 5% 5% 4% 5%
SO2 EMISSIONS (TONS): - - - -
PINCKEYVILLE 3-4
CAPACITY (MW): 84 84 84 84
GENERATION (GWH): 40 37 33 35
CAPACITY FACTOR %: 5% 5% 4% 5%
SO2 EMISSIONS (TONS): - - - -
RDI CONSULTING FT ENERGY B-3
APPENDIX B
GENERATING UNIT 2015 2016 2017 2018 2019 2020
COFFEEN 1
CAPACITY (MW): 340 340 340 340 340 340
GENERATION (GWH): 2143 2157 2175 2193 2193 2206
CAPACITY FACTOR %: 72% 72% 73% 74% 74% 74%
SO2 EMISSIONS (TONS): 11,111 11,183 11,280 11,371 11,371 11,438
COFFEEN 2
CAPACITY (MW): 560 560 560 560 560 560
GENERATION (GWH): 3654 3669 3718 3734 3739 3762
CAPACITY FACTOR %: 74% 75% 76% 76% 76% 77%
SO2 EMISSIONS (TONS): 18,718 18,795 19,046 19,128 19,153 19,271
GIBSON CITY 1
CAPACITY (MW): 115 115 115 115 115 115
GENERATION (GWH): 12 9 9 7 7 7
CAPACITY FACTOR %: 1% 1% 1% 1% 1% 1%
SO2 EMISSIONS (TONS): - - - - - -
GIBSON CITY 2
CAPACITY (MW): 115 115 115 115 115 115
GENERATION (GWH): 11 9 10 8 7 7
CAPACITY FACTOR %: 1% 1% 1% 1% 1% 1%
SO2 EMISSIONS (TONS): - - - - - -
GRAND TOW CC CC3
CAPACITY (MW): 256 256 256 256 256 256
GENERATION (GWH): 634 623 669 671 651 688
CAPACITY FACTOR %: 28% 28% 30% 30% 29% 31%
SO2 EMISSIONS (TONS): - - - - - -
GRAND TOW CC CC4
CAPACITY (MW): 256 256 256 256 256 256
GENERATION (GWH): 651 639 683 686 666 698
CAPACITY FACTOR %: 29% 28% 30% 31% 30% 31%
SO2 EMISSIONS (TONS): - - - - - -
GRAND TOWER 3
CAPACITY (MW):
GENERATION (GWH):
CAPACITY FACTOR %:
SO2 EMISSIONS (TONS):
RDI CONSULTING FT ENERGY
B-4
APPENDIX B
GENERATING UNIT 2015 2016 2017 2018 2019 2020
GRAND TOWER 4
CAPACITY (MW):
GENERATION (GWH):
CAPACITY FACTOR %:
SO2 EMISSIONS (TONS): - - - - - -
HUTSONVILLE 3
CAPACITY (MW): 76 76 76 76 76 76
GENERATION (GWH): 276 280 297 309 323 341
CAPACITY FACTOR %: 41% 42% 45% 46% 48% 51%
SO2 EMISSIONS (TONS): 6,920 7,016 7,452 7,753 8,091 8,553
HUTSONVILLE 4
CAPACITY (MW): 77 77 77 77 77 77
GENERATION (GWH): 303 307 319 338 353 375
CAPACITY FACTOR %: 45% 46% 47% 50% 52% 56%
SO2 EMISSIONS (TONS): 7,481 7,600 7,892 8,347 8,728 9,262
KINMUNDY 1
CAPACITY (MW): 115 115 115 115 115 115
GENERATION (GWH): 12 10 10 8 8 8
CAPACITY FACTOR %: 1% 1% 1% 1% 1% 1%
SO2 EMISSIONS (TONS): - - - - - -
KINMUNDY 2
CAPACITY (MW): 115 115 115 115 115 115
GENERATION (GWH): 10 9 9 7 7 7
CAPACITY FACTOR %: 1% 1% 1% 1% 1% 1%
SO2 EMISSIONS (TONS): - - - - - -
MEREDOSIA 1
CAPACITY (MW): 62 62 62 62 62 62
GENERATION (GWH): 184 189 206 213 231 248
CAPACITY FACTOR %: 34% 35% 38% 39% 43% 46%
SO2 EMISSIONS (TONS): 4,044 4,156 4,538 4,703 5,O95 5,454
MEREDOSIA 1
CAPACITY (MW): 62 62 62 62 62 62
GENERATION (GWH): 186 189 207 213 233 243
CAPACITY FACTOR %: 34% 35% 38% 39% 43% 46%
SO2 EMISSIONS (TONS): 4,095 4,167 4,571 4,685 5,133 5,494
RDI CONSULTING FT ENERGY
B-5
APPENDIX B
GENERATING UNIT 2015 2016 2017 2018 2019 2020
MEREDOSIA 3
CAPACITY (MW): 215 215 215 215 215 215
GENERATION (GWH): 1057 1080 1133 1198 1241 1278
CAPACITY FACTOR %: 56% 57% 60% 64% 66% 68%
SO2 EMISSIONS (TONS): 17,625 18,009 18,892 19,976 20,693 21,310
MEREDOSIA 4
CAPACITY (MW): 168 168 168 168 168 168
GENERATION (GWH): 8 9 10 11 11 13
CAPACITY FACTOR %: 1% 1% 1% 1% 1% 1%
SO2 EMISSIONS (TONS): - - - - - -
NEWTON 1
CAPACITY (MW): 555 555 555 555 555 555
GENERATION (GWH): 4145 4154 4158 4165 4161 4169
CAPACITY FACTOR %: 85% 85% 86% 86% 86% 86%
SO2 EMISSIONS (TONS): 14,029 14,059 14,073 14,096 14,083 14,110
NEWTON 2
CAPACITY (MW): 555 555 555 555 555 555
GENERATION (GWH): 4129 4136 4139 4144 4141 4148
CAPACITY FACTOR %: 85% 85% 85% 85% 85% 85%
SO2 EMISSIONS (TONS): 13,969 13,993 14,003 14,020 14,010 14,033
PINCKNEYVILLE 1-2
CAPACITY (MW): 84 84 84 84 84 84
GENERATION (GWH): 33 29 30 26 23 23
CAPACITY FACTOR %: 4% 4% 4% 4% 3% 3%
SO2 EMISSIONS (TONS): - - - - - -
PINCKNEYVILLE 3-4
CAPACITY (MW): 84 84 84 84 84 84
GENERATION (GWH): 33 30 30 27 24 23
CAPACITY FACTOR %: 5% 4% 4% 4% 3% 3%
SO2 EMISSIONS (TONS): - - - - - -
RDI CONSULTING FT ENERGY B-6
Appendix C
Market Price Forecast Results for Sensitivity Cases
TABLE C. 1
- -------------------------------------------------------------------------------------------------------
ELECTRICITY PRICE FORECAST, HIGH FUEL PRICE CASE
- -------------------------------------------------------------------------------------------------------
ENERGY PRICES ($/MWh) CAPACITY PRICES
-------------------------------------------------------------------------
Energy
Capacity Equivalent
Rate Rate TOTAL PRICE
Year Off-peak On-peak Average ($/kW-yr) ($/MWh) ($/MWh)
- -------------------------------------------------------------------------------------
2000 18.52 26.71 23.82 17.19 3.27 27.09
2001 18.80 26.06 23.50 20.00 3.81 27.31
2002 18.50 25.63 23.11 57.01 10.85 33.96
2003 18.35 25.59 23.04 56.48 10.75 33.78
2004 18.24 25.89 23.19 56.23 10.70 33.89
2005 18.52 26.95 23.98 55.01 10.47 34.44
2006 18.73 27.49 24.40 54.59 10.39 34.79
2007 18.69 27.99 24.71 54.34 10.34 35.05
2008 19.33 28.83 25.48 53.75 10.23 35.71
2009 19.40 29.30 25.81 53.49 10.18 35.98
2010 19.87 29.53 26.12 53.36 10.15 36.27
2011 19.62 30.07 26.38 49.39 9.40 35.78
2012 19.71 30.28 26.55 47.67 9.07 35.62
2013 20.26 30.45 26.85 47.41 9.02 35.87
2014 20.83 31.12 27.49 43.85 8.34 35.83
2015 21.05 31.39 27.74 43.06 8.19 35.93
2016 20.88 31.39 27.68 43.56 8.29 35.97
2017 21.59 31.85 28.23 41.00 7.80 36.03
2018 21.84 32.10 28.48 40.35 7.68 36.16
2019 22.12 32.21 28.65 40.31 7.67 36.32
2020 22.34 32.72 29.06 37.50 7.13 36.19
- -------------------------------------------------------------------------------------
* Capacity prices are converted to equivalent $/MWh values assuming a load
factor of 60%.
TABLE C. 2
- -------------------------------------------------------------------------------------------------------
ELECTRICITY PRICE FORECAST, LOW FUEL PRICE CASE
- -------------------------------------------------------------------------------------------------------
ENERGY PRICES ($/MWh) CAPACITY PRICES
-------------------------------------------------------------------------
Energy
Capacity Equivalent
Rate Rate TOTAL PRICE
Year Off-peak On-peak Average ($/kW-yr) ($/MWh) ($/MWh)
- -------------------------------------------------------------------------------------
2000 15.64 20.11 18.53 26.20 4.99 23.52
2001 15.41 19.05 17.77 29.37 5.59 23.35
2002 15.30 18.56 17.41 57.01 10.85 28.25
2003 15.35 18.62 17.47 56.48 10.75 28.22
2004 14.45 18.09 16.80 56.14 10.68 27.48
2005 13.77 17.96 16.48 54.92 10.45 26.93
2006 13.80 18.22 16.66 54.51 10.37 27.03
2007 13.68 18.35 16.70 54.26 10.32 27.03
2008 13.91 18.82 17.09 53.75 10.23 27.32
2009 14.02 19.12 17.32 53.33 10.15 27.47
2010 14.16 19.19 17.42 53.28 10.14 27.55
2011 14.14 19.50 17.61 51.19 9.74 27.35
2012 14.21 19.59 17.69 50.95 9.69 27.38
2013 14.32 19.68 17.79 50.76 9.66 27.45
2014 14.55 20.13 18.16 50.10 9.53 27.69
2015 14.80 20.24 18.32 50.03 9.52 27.84
2016 14.73 20.26 18.31 49.70 9.46 27.77
2017 14.97 20.59 18.60 49.18 9.36 27.96
2018 15.07 20.78 18.76 48.90 9.30 28.06
2019 15.10 20.83 18.81 48.67 9.26 28.07
2020 15.36 21.15 19.11 48.15 9.16 28.27
- -------------------------------------------------------------------------------------
* Capacity prices are converted equivalent to $/MWh values assuming a load
factor of 60%.
TABLE C. 3
- -------------------------------------------------------------------------------------------------------
ELECTRICITY PRICE FORECAST, OVERBUILD CASE
- -------------------------------------------------------------------------------------------------------
ENERGY PRICES ($/MWh) CAPACITY PRICES
-------------------------------------------------------------------------
Energy
Capacity Equivalent
Rate Rate TOTAL PRICE
Year Off-peak On-peak Average ($/kW-yr) ($/MWh) ($/MWh)
- -------------------------------------------------------------------------------------
2000 17.10 23.27 21.09 10.26 1.95 23.04
2001 17.05 22.34 20.47 10.89 2.07 22.54
2002 16.81 21.88 20.09 12.39 2.36 22.45
2003 16.47 21.74 19.88 13.50 2.57 22.45
2004 16.20 21.75 19.80 55.96 10.65 30.44
2005 16.20 22.56 20.31 55.10 10.48 30.80
2006 16.31 22.98 20.63 54.68 10.40 31.03
2007 16.40 23.41 20.94 54.34 10.34 31.28
2008 16.80 24.23 21.61 53.83 10.24 31.85
2009 16.98 24.65 21.95 53.49 10.18 32.12
2010 17.22 24.73 22.08 53.28 10.14 32.22
2011 17.06 25.26 22.37 50.40 9.59 31.96
2012 17.13 25.39 22.48 50.32 9.57 32.05
2013 17.36 25.61 22.70 50.08 9.53 32.23
2014 17.69 26.09 23.12 49.14 9.35 32.47
2015 17.96 26.31 23.36 47.55 9.05 32.41
2016 17.80 26.31 23.31 47.92 9.12 32.42
2017 18.38 26.78 23.82 45.84 8.72 32.54
2018 18.66 26.95 24.02 43.87 8.35 32.37
2019 18.64 27.06 24.09 44.30 8.43 32.52
2020 19.03 27.39 24.44 41.37 7.87 32.31
- -------------------------------------------------------------------------------------
* Capacity prices are converted to equivalent $/MWh values assuming a load
factor of 60%.
================================================================================
AMEREN ENERGY GENERATING COMPANY
Offer to exchange its
7.75% Senior Notes, Series C due 2005
for any and all of its outstanding
7.75% Senior Notes, Series A due 2005
and
8.35% Senior Notes, Series D due 2010
for any and all of its outstanding
8.35% Senior Notes, Series B due 2010
__________________________
PROSPECTUS
__________________________
April 18, 2001
Until August 27, 2001, 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 unsold
allotments or subscriptions.
================================================================================