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Filed Pursuant to Rule: 424(b)(3)
Registration No.: 333-51464
333-51464-01
333-51464-02
333-51464-03
333-51464-04
PROSPECTUS
$727,850,000
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
OFFER TO EXCHANGE
$210,000,000 $297,850,000 $220,000,000
8.554% SERIES A EXCHANGE PASS 9.237% SERIES B EXCHANGE PASS 9.681% SERIES C EXCHANGE PASS
THROUGH CERTIFICATES DUE 2005 THROUGH CERTIFICATES DUE 2017 THROUGH CERTIFICATES DUE 2026
FOR ALL OUTSTANDING FOR ALL OUTSTANDING FOR ALL OUTSTANDING
8.554% SERIES A PASS 9.237% SERIES B PASS 9.681% SERIES A PASS
THROUGH CERTIFICATES DUE 2005 THROUGH CERTIFICATES DUE 2017 THROUGH CERTIFICATES DUE 2026
THE OFFER TO EXCHANGE We are offering to exchange pass through certificates
registered with the Securities and Exchange Commission for a
like principal amount of original pass through certificates
that we previously offered in an offering exempt from the
SEC's registration requirements. The terms and conditions of
the exchange offer are summarized below and more fully
described in this prospectus.
EXPIRATION DATE 5:00 p.m., New York City time, on March 16, 2001.
WITHDRAWAL RIGHTS Any time before 5:00 p.m., New York City time, on the
expiration date.
INTEGRAL MULTIPLES Original pass through certificates may only be tendered in
integral multiples of $1,000.
EXPENSES Paid for by Reliant Energy Mid-Atlantic Power Holdings, LLC.
NEW CERTIFICATES The exchange certificates will represent the same fractional
undivided interest in three pass through trusts as the
original and outstanding certificates. The exchange
certificates will have the same material financial terms as
the original certificates. The terms of the exchange offer
are described more fully in this prospectus. The exchange
certificates will not contain terms relating to transfer
restrictions because the exchange certificates will be
registered securities, or to interest rate increases because
those terms were effective only if an exchange offer was not
consummated by May 21, 2001.
CONSIDER CAREFULLY THE RISK FACTORS BEGINNING ON PAGE 27 OF THIS PROSPECTUS.
The exchange certificates represent interests in one of three pass through
trusts only and do not represent interests in or obligations of Reliant Energy,
Incorporated, Reliant Energy Mid-Atlantic Power Holdings, LLC or any other
affiliate of Reliant Energy, Incorporated.
We are relying on the position of the Securities and Exchange Commission
staff in some interpretive letters to third parties to remove the transfer
restrictions on the exchange certificates.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED THESE EXCHANGE CERTIFICATES OR DETERMINED THAT THIS
PROSPECTUS IS ACCURATE OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
The date of this prospectus is February 12, 2001.
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IMPORTANT NOTICE ABOUT INFORMATION PRESENTED IN THIS PROSPECTUS
You should rely only on the information provided in this prospectus. We
have not authorized anyone to provide you with different information. We are not
offering the exchange certificates in any state where the offer is not
permitted. We do not claim the accuracy of the information in this prospectus as
of any date other than the date stated on the cover.
We include cross-references in this prospectus to captions where you can
find further related discussions. The table of contents on page ii provides the
pages on which these captions are located.
AVAILABLE INFORMATION
We have filed with the SEC a Registration Statement on Form S-4 relating to
the exchange certificates. This prospectus is a part of the Registration
Statement, but the Registration Statement includes additional information and
also includes exhibits that are referenced in this prospectus. You can review a
copy of the Registration Statement through the SEC's EDGAR (Electronic Data
Gathering, Analysis and Retrieval) System that is available on the SEC's web
site (http://www.sec.gov).
After our Registration Statement becomes effective, Reliant Energy
Mid-Atlantic Power Holdings, LLC will be required to file publicly some
information under the Securities Exchange Act of 1934, as amended. All of these
public filings will also be available on EDGAR, including annual and quarterly
reports and other information. You may also read and copy all of our public SEC
filings at the SEC's Public Reference Room in Washington, D.C. or at their
facilities in New York and Chicago. Please call the SEC at (800) 732-0330 for
further information on the operation of the public reference rooms.
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TABLE OF CONTENTS
AVAILABLE INFORMATION...................... i
FORWARD-LOOKING STATEMENTS................. iii
PROSPECTUS SUMMARY......................... 1
RISK FACTORS............................... 27
USE OF PROCEEDS............................ 35
THE EXCHANGE OFFER......................... 35
CAPITALIZATION............................. 45
SELECTED HISTORICAL FINANCIAL DATA......... 46
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS............................... 48
REMA, REPG, RES, RERC AND RELIANT ENERGY... 53
OUR BUSINESS............................... 57
REGULATION................................. 65
MANAGEMENT................................. 73
RELATED PARTY ARRANGEMENTS................. 75
DESCRIPTION OF PRINCIPAL TRANSACTION
DOCUMENTS................................ 77
DESCRIPTION OF THE EXCHANGE CERTIFICATES... 84
DESCRIPTION OF LEASE DOCUMENTS............. 109
OUTSTANDING INDEBTEDNESS................... 126
MATERIAL UNITED STATES FEDERAL INCOME TAX
CONSEQUENCES............................. 128
ERISA CONSIDERATIONS....................... 134
PLAN OF DISTRIBUTION....................... 136
LEGAL MATTERS.............................. 137
EXPERTS.................................... 137
INDEPENDENT ENGINEER....................... 137
INDEPENDENT MARKET CONSULTANT.............. 137
INDEX TO FINANCIAL STATEMENTS.............. F-1
APPENDIX A -- INDEPENDENT ENGINEER'S
REPORT................................... A-1
APPENDIX B -- INDEPENDENT MARKET
CONSULTANT'S REPORT...................... B-1
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FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements that give our current
expectations about future events. You will recognize these statements because
they do not strictly relate to historical or current facts. These statements may
use words such as "anticipate," "estimate," "expect," "project," "intend,"
"think," "believe," "will," "should" and other words or terms of similar meaning
in connection with any discussion of our future performance. For example, we
make forward-looking statements relating to future actions, future plans or
performance, future expenses and the impact of the capital markets on our
liquidity in the future. From time to time, we also may provide oral or written
forward-looking statements in other material released to the public.
Any or all of our forward-looking statements in this prospectus and in any
other public statements we make may turn out to be incorrect. They can be
affected by inaccurate assumptions or by known or unknown risks and
uncertainties. Many factors, which cannot be predicted with certainty, and some
of which are beyond our control, will be important in determining our future
results. These factors include
- governmental, statutory, regulatory or administrative changes or
initiatives affecting us, the guarantors, our facilities, the contracts
relating to such facilities, our primary electricity markets and the
United States electric industry generally
- demand for electric capacity, energy and ancillary services in the
markets served by our facilities
- competition from other power plants, including new plants that may be
developed in the future
- the cost and availability of fuel, fuel transportation services and
emissions credits for our facilities
- the timing and extent of changes in prices of power and other commodities
- our limited operating history as a stand-alone entity
- the limited marketing and procurement history specific to our facilities
of the affiliate of ours that is providing power marketing and fuel and
emissions procurement services to us
- the creditworthiness of our customers and other parties with whom we have
contracts
- the cost and availability of transmission capacity for the electrical
energy generated by our facilities or required to satisfy power sales
made on our behalf
- general economic conditions
- demographic changes, and
- technological changes
As a result of these factors, actual future results may vary materially.
Also, you should note that the factors we discuss in this prospectus are those
we think could cause our actual results to differ materially from expected and
historical results. Other factors besides those listed above or under "Risk
Factors" could also adversely affect us.
Some of these factors and others are more fully discussed under the caption
"Risk Factors."
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PROSPECTUS SUMMARY
This summary contains basic information about us and this exchange offer
but may not contain all the information that is important to you in deciding to
participate in the exchange offer. For a more complete understanding of this
exchange offer, we encourage you to read this entire prospectus.
The term "REMA" refers to Reliant Energy Mid-Atlantic Power Holdings, LLC,
in its individual capacity, unless otherwise specified. The words "we," "our,"
"ours" and "us" refer to REMA and its subsidiary guarantors on a combined basis
unless otherwise specified. The term "original certificates" refers,
collectively, to the outstanding 8.554% Series A Pass Through Certificates due
2005, the outstanding 9.237% Series B Pass Through Certificates due 2017 and the
outstanding 9.681% Series C Pass Through Certificates due 2026. The term
"exchange certificates" refers to $727,850,000 principal amount of exchange pass
through certificates that will be registered under the Securities Act and that
we are offering under the exchange offer, and the term "certificates" refers to
both the original certificates and the exchange certificates.
You should carefully consider the information under "Risk Factors." In
addition, we make various forward-looking statements in this prospectus that
involve risks and uncertainties. Please read "Forward-Looking Statements."
WHO WE ARE
REMA is an indirect wholly owned subsidiary of Reliant Energy Power
Generation, Inc., or REPG, which is in turn a direct wholly owned subsidiary of
Reliant Resources, Inc. Reliant Resources, Inc., or RRI, is a direct wholly
owned subsidiary of Reliant Energy, Incorporated. REPG, acting through an
indirect subsidiary, acquired us from Sithe Energies, Inc. and one of its
subsidiaries on May 12, 2000. The purchase price, including amounts paid for
preexisting intercompany debt we owed to the subsidiary of Sithe Energies, was
approximately $2.1 billion. By acquiring us, REPG effectively acquired our 21
electric power generating facilities. As of September 30, 2000, REPG had a net
investment in us of approximately $209 million.
Our headquarters and principal executive offices are located at 1111
Louisiana, Houston, Texas 77002. Our telephone number at that address is
713-207-3200.
OUR ELECTRIC POWER GENERATING FACILITIES
Our electric power generating facilities
- have an aggregate average net capacity of 4,262 megawatts, or MW, and are
located in Pennsylvania (16 facilities with an average net capacity of
2,745 MW), New Jersey (4 facilities with an average net capacity of 1,499
MW) and Maryland (1 facility with an average net capacity of 18 MW), in
what is known as the Pennsylvania-New Jersey-Maryland, or PJM, control
area and market
- provide us with a strong presence in the PJM market, with approximately
7% of the generating capacity in the PJM control area and access to
surrounding markets
- represent a diversified grouping of generating facilities, including
base-load, peaking and intermediate generation
- include low-cost, base-load coal-fired units
- have a diversified fuel profile, and
- include peaking units with flexibility to use oil or natural gas
The PJM control area is located in a region where the electric utility and
power generation business is being rapidly deregulated. The PJM market is the
largest centrally dispatched power exchange in North
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America. The PJM market is well established and among the most developed
domestic markets as a result of its fully functioning independent system
operator, or ISO. The PJM ISO facilitates market liquidity for buyers and
sellers of electric power and access to adjoining markets that are also rapidly
deregulating.
THE RELIANT ENERGY GROUP
We are members of the Reliant Energy group of companies. We show the
ownership structure of the Reliant Energy group of companies below as of January
1, 2001. Please read "REMA, REPG, RES, RERC and Reliant Energy" for more
information about the Reliant Energy group.
[Flow Chart]
- ---------------
(1) Reliant Resources, Inc. has filed a registration statement for the offer and
sale to the public of up to a 20% interest in that company.
(2) Held through two intermediate holding companies. Reliant Energy Northeast
Holdings, Inc. owns 100% of Reliant Energy Northeast Generation, Inc., which
owns 100% of REMA.
REMA is the lessee, and its subsidiaries shown above are the subsidiary
guarantors, in the lease transactions.
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OUR ORGANIZATION
Our facilities and other assets and our business are owned and operated by
REMA and its four wholly owned subsidiaries. REMA owns and operates all the
facilities located in Pennsylvania except for the leased facilities, which we
operate but do not own. Reliant Energy New Jersey Holdings, LLC and Reliant
Energy Maryland Holdings, LLC own and operate the facilities located in New
Jersey and Maryland, respectively. Reliant Energy Northeast Management Company
serves as operator of the Conemaugh and Keystone stations for us and the other
co-owners of these stations. Reliant Energy Mid-Atlantic Power Services, Inc.
serves as common paymaster for our employees. All four subsidiaries guarantee
REMA's obligations under the lease transactions.
The following diagram illustrates the contractual arrangements under which
REPG and RES provide services to us.
[Flow chart]
- ---------------
* Held through two intermediate holding companies. Reliant Energy Northeast
Holdings, Inc. owns 100% of Reliant Energy Northeast Generation, Inc., which
owns 100% of REMA.
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THE LEASED FACILITIES AND THE LEASE TRANSACTIONS
Each exchange certificate represents an undivided interest in one of three
pass through trusts. The property of each pass through trust consists solely of
nonrecourse secured lease obligation notes, referred to as lessor notes, issued
by three separate Delaware limited liability companies that lease interests in
power generation facilities to us.
In the lease transactions, REMA sold to and leased back from each of three
owner lessors in separate lease transactions its interests in each of the
following generating facilities:
- its 100% interest in the Shawville station with an average net generating
capacity of 613 MW
- its 16.45% undivided interest in the Conemaugh station representing an
average net generating capacity of 281 MW, and
- its 16.67% undivided interest in the Keystone station representing an
average net generating capacity of 285 MW
The owner lessors funded the $1.0 billion purchase price paid to REMA for
the facilities from investments in the owner lessors by owner participants and
by issuing the lessor notes. Each owner lessor issued up to three lessor notes
under a separate lease indenture. Each pass through trust used the proceeds of
the sale of the original certificates to purchase the lessor notes issued by
each of the three owner lessors bearing the same rate of interest. The
noneconomic terms of the lease and indenture documentation for each lease
transaction are substantially identical. For ease of discussion, the structure
we describe below refers to only one of the leases and lease indentures.
The pass through trustee will distribute the principal and interest paid
periodically on the lessor notes to the certificateholders of the pass through
trust in which such lessor notes are held. The owner lessor will obtain the
funds to pay interest and principal on the lessor notes and to make payments to
the owner participant from the rent and other payments made by REMA under the
lease.
As lessee, REMA leased each interest in the leased facilities from each
owner lessor under a facility lease agreement.
The lessor notes are secured by
- the relevant owner lessor's interest in
- the leased facility
- the facility lease to REMA, including the right to receive payments of
periodic rent under the lease (other than customary excepted payments
reserved to the applicable owner lessor, owner participant and other
participants in the lease transactions), and
- other lease documents, including the corresponding owner lessor's
interest in the facility site lease from REMA and its site sublease to
REMA, but excluding the participation agreement and tax indemnity
agreement, and
- an assignment of the subsidiary guarantees and such owner lessor's
interest in the collateral securing the lease obligations, which consists
of (1) a pledge by REMA of its equity and any debt interests in the
subsidiary guarantors and (2) credit support for the lease obligations in
an amount equal to the greater of the next six months' scheduled rental
payments under the lease or 50% of the scheduled rental payments due in
the next twelve months under the lease.
As a holder of certificates issued by the pass through trust that holds the
lessor notes, you and the other holders have the right to direct the exercise of
any enforcement rights for this collateral.
Rent payable under the facility leases will be paid directly to the lease
indenture trustees, which will first make payments on the lessor notes to the
pass through trustees and then pay any remaining balance to each owner lessor
for the benefit of each owner participant holding an investment in the relevant
owner
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lessor. Bankers Trust Company acts as pass through trustee of each of the pass
through trusts and as lease indenture trustee under each of the lease
indentures.
The following diagram generally illustrates the payment flows in each lease
transaction among REMA, the indenture trustee, the owner lessor, the owner
participant, the pass through trustee and the certificateholders. The pass
through trustee for the Series C pass through trust does not own any lessor
notes issued by the owner lessor of the Shawville station.
[Flow Chart]
- ---------------
(1) Bankers Trust Company serves as the indenture trustee under each of the
separate indentures for the three leased facilities.
(2) There is a separate owner lessor for each of the three leased facilities.
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THE EXCHANGE OFFER
On August 24, 2000, we completed an offering of $851 million principal
amount of pass through certificates that was exempt from the SEC's registration
requirements. Of the original amount, an aggregate of approximately $728 million
remains outstanding as of January 26, 2001. In connection with the initial
offering, we entered into an exchange and registration rights agreement and
agreed to deliver to you this prospectus and to complete the exchange offer for
each series of the pass through certificates within 270 days after the date we
issued the original certificates. In the exchange offer, you are entitled to
exchange your original certificates for a like principal amount of exchange
certificates with substantially identical terms. You should read the discussion
under the headings "-- Summary of Terms of the Exchange Certificates" beginning
on page 9 and "Description of the Exchange Certificates" beginning on page 84
for further information about the exchange certificates.
The Exchange Offer......... We are offering to exchange:
- $1,000 principal amount of Series A exchange
certificates for each outstanding $1,000
principal amount of Series A original
certificates,
- $1,000 principal amount of Series B exchange
certificates for each outstanding $1,000
principal amount of Series B original
certificates, and
- $1,000 principal amount of Series C exchange
certificates for each outstanding $1,000
principal amount of Series C original
certificates.
The form and terms of the exchange certificates
that we are offering are identical in all material
respects to the form and terms of the original
certificates, except that the exchange certificates
do not contain terms relating to transfer
restrictions or interest rate increases. The
exchange certificates will
- evidence the same fractional undivided interests
in three pass through trusts as, and may be
exchanged for, the original certificates, and
- will be issued under the same pass through trust
agreements
Procedures for Tendering
the Original
Certificates............. If your original certificates are held through The
Depository Trust Company, or DTC, and you wish to
participate in the exchange offer, you may do so
through DTC's automated tender offer program. If
you tender under this program, you will agree to be
bound by the letter of transmittal that we are
providing with this prospectus as though you had
signed the letter of transmittal. By signing or
agreeing to be bound by the letter of transmittal,
you will represent to us that, among other things:
- any exchange certificates that you receive will
be acquired in the ordinary course of your
business
- you are not our "affiliate," as defined in Rule
405 of the Securities Act of 1933, or, if you are
our affiliate, you will comply with any
applicable registration and prospectus delivery
requirements of the Securities Act of 1933 to the
extent applicable
- if you are not a broker-dealer, you are not
engaged in and do not intend to engage in the
distribution of the exchange certificates, and
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- if you are a broker-dealer that will receive
exchange certificates for your own account in
exchange for original certificates that you
acquired as a result of market-making activities
or other trading activities, you will deliver a
prospectus in connection with any resale of such
exchange certificates
Special Procedures for
Beneficial Holders......... If you beneficially own original certificates that
are held through a broker, dealer, commercial bank,
trust company or other nominee and you wish to
tender the original certificates in the exchange
offer, you should contact such person or other
nominee as soon as possible and instruct such
person or other nominee to tender on your behalf.
Guaranteed Delivery
Procedures................. You must tender your original certificates under
the guaranteed delivery procedures described in
"The Exchange Offer -- Guaranteed Delivery
Procedures" beginning on page 41 if any of the
following apply:
- you cannot comply with the applicable procedures
under DTC's automated tender offer program prior
to the expiration date
- you wish to tender your original certificates but
they are not immediately available, or
- you cannot deliver your original certificates,
the letter of transmittal or any other required
documents to the exchange agent prior to the
expiration date
Resales of the Exchange
Certificates............. Based on interpretations by the staff of the SEC in
no-action letters issued to third parties, we
believe that the exchange certificates may be
offered for resale, resold and otherwise
transferred by you without compliance with the
registration and prospectus delivery requirements
of the Securities Act as long as:
- you acquire any exchange certificates in the
ordinary course of your business
- you do not intend to participate in the
distribution of the exchange certificates
- you are not a broker-dealer who purchased
original certificates for resale under Rule 144A
or any other available exemption under the
Securities Act, and
- you are not an "affiliate," as defined in Rule
405 under the Securities Act, of ours
This prospectus may be used for an offer to resell,
resale or other retransfer of exchange certificates
only as specifically described in this prospectus.
Only those broker-dealers that acquired the
original certificates as a result of market-making
activities or other trading activities may
participate in the exchange offer. Each
broker-dealer that receives exchange certificates
for its own account in exchange for original
certificates, where the broker dealer acquired such
original certificates as a result of market-making
activities or other trading activities, must
acknowledge that it will deliver a prospectus in
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connection with any resale of such exchange
certificates. The letter of transmittal states
that, by making this acknowledgment and by
delivering a prospectus, a broker-dealer will not
be deemed to admit that it is an "underwriter"
within the meaning of the Securities Act. We have
agreed that, for a period of 90 days following the
completion of the exchange offer, we will make this
prospectus and any amendment or supplement to this
prospectus available to any broker-dealers for use
in connection with these resales.
In addition, any broker-dealer that acquired any of
its original certificates directly from us:
- may not rely on the applicable interpretation of
the staff of the SEC's position contained in
Exxon Capital Holdings Corp., SEC no-action
letter (April 13, 1988), Morgan, Stanley & Co.
Inc., SEC no-action letter (June 5, 1991) and
Shearman & Sterling, SEC no-action letter (July
2, 1983), and
- must also be named as a selling certificateholder
in connection with the registration and
prospectus delivery requirements of the
Securities Act relating to any resale transaction
Expiration Date............ The exchange offer will expire at 5:00 p.m., New
York City time, March 16, 2001, or such later date
and time to which we extend it.
Conditions to the Exchange
Offer...................... The exchange offer is not subject to any conditions
other than that, in our reasonable judgment:
- the exchange offer does not violate applicable
law or any applicable interpretation of the staff
of the Securities and Exchange Commission,
- no judicial or governmental actions or
proceedings relating to the exchange offer have
been instituted or threatened, and
- no law, statute, rule or regulation has been
adopted or enacted that can reasonably be
expected to impair our ability to proceed with
the exchange offer
Withdrawal Rights.......... You may withdraw the tender of your original
certificates at any time prior to 5:00 p.m., New
York City time, on the expiration date. We will
return to you, without charge, promptly after the
expiration or termination of the exchange offer any
original certificates that you tendered but that
were not accepted for exchange.
U.S. Federal Income Tax
Consequences............. The exchange of certificates will not be a taxable
event for United States federal income tax
purposes. For a discussion of other United States
federal income tax consequences resulting from the
exchange, acquisition, ownership and disposition of
the exchange certificates, please read "Material
United States Federal Income Tax Consequences" on
page 128.
Use of Proceeds............ We will not receive any proceeds from the issuance
of exchange certificates in the exchange offer. We
will pay all registration expenses incident to the
exchange offer.
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THE EXCHANGE AGENT
We have appointed Bankers Trust Company as exchange agent for the exchange
offer. Please direct questions and requests for assistance, requests for
additional copies of this prospectus or of the letter of transmittal and
requests for the notice of guaranteed delivery to the exchange agent. If you are
not tendering under DTC's automated tender offer program, you should send the
letter of transmittal and any other required documents to the exchange agent as
follows:
By Courier: By Mail (registered or By Hand:
BT Services Tennessee, Inc. certified mail recommended): Bankers Trust Company
Corporate Trust & Agency BT Services Tennessee, Inc. Corporate Trust & Agency
Services Reorganization Unit Services
Reorganization Unit P.O. Box 292737 Attn: Reorganization Department
648 Grassmere Park Road Nashville, TN 37229-2737 Receipt & Delivery Window
Nashville, TN 37211 123 Washington Street, 1st
Floor
New York, NY 10006
By Facsimile Transmission (eligible institutions only):
(615) 835-3701
Confirm by Telephone:
(615) 835-3572
SUMMARY OF TERMS OF THE EXCHANGE CERTIFICATES
The exchange certificates will be substantially identical to the original
certificates, except that the exchange certificates will be registered under the
Securities Act and freely tradeable. The exchange certificates will not have
registration rights or provisions for additional interest. The exchange
certificates will evidence the same fractional undivided interests in three pass
through trusts as the original certificates, and both the original certificates
and the exchange certificates will be governed by the same pass through trust
agreements. The following summary contains basic information about the exchange
certificates. It does not contain all the information that is important to your
investment decision. For a more complete description of the exchange offer, we
encourage you to read this entire document and the documents to which we refer
you.
Securities Offered......... $727,850,000 aggregate principal amount of exchange
pass through certificates, consisting of
$210,000,000 aggregate principal amount of Series A
exchange certificates due 2005, $297,850,000
aggregate principal amount of Series B exchange
certificates due 2017 and $220,000,000 aggregate
principal amount of Series C exchange certificates
due 2026.
Lessee..................... Reliant Energy Mid-Atlantic Power Holdings, LLC.
Owner Lessors.............. The owner lessors are three Delaware limited
liability companies. Wilmington Trust Company is
the sole manager of each owner lessor.
Pass Through Trusts........ Each of the three pass through trusts was formed
under a separate pass through trust agreement
between REMA and the pass through trustee. The
trustee under each pass through trust issued a
separate series of certificates.
Pass Through Trust
Property................... The property of each pass through trust consists
solely of lessor notes issued on a nonrecourse
basis by each of the three owner lessors in three
separate lease transactions. Each owner lessor
issued up to three lessor notes. The Series A and
Series B trusts purchased one of the lessor notes
issued by each of the three owner lessors, and the
Series C trust purchased one of the lessor notes
issued by two of the
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three owner lessors. Amounts of principal, interest
and any other payments received by the pass through
trustee on the lessor notes will be distributed to
the certificateholders.
Interest................... Interest will accrue on the principal amount of the
lessor notes at the applicable rate per annum
indicated below. Interest will be payable on the
lessor notes, and payments will be made under the
exchange certificates, semiannually in arrears on
January 2 and July 2 of each year.
LESSOR NOTES INTEREST RATE
------------ -------------
Series A........................................... 8.554%
Series B........................................... 9.237%
Series C........................................... 9.681%
Initial Average Life....... The lessor notes will amortize as provided in the
amortization schedules beginning on page 85. The
pass through of payments on the lessor notes will
result in an initial average life for each series
of original certificates approximately as follows:
ORIGINAL CERTIFICATE INITIAL AVERAGE LIFE
-------------------- ---------------------
Series A..................................... 2.3 years
Series B..................................... 8.1 years
Series C..................................... 20.7 years
Ratings.................... Standard & Poor's Ratings Services and Moody's
Investors Service, Inc. have assigned ratings to
the certificates of BBB and Baa3, respectively.
We cannot assure you, however, that a rating will
not be lowered, suspended or withdrawn entirely by
any rating agency if, in the rating agency's
judgment, circumstances so warrant. These ratings
do not represent a recommendation by the rating
agencies to purchase the exchange certificates.
Ranking.................... Lease rental payments under the facility leases are
the senior obligations of REMA secured by a pledge
of REMA's equity ownership interests in the
subsidiary guarantors and otherwise ranking at
least equal in right of payment with all other
unsecured and unsubordinated indebtedness of REMA.
Capitalization............. As of September 30, 2000, substantially all of our
capitalization consists of equity equal to
approximately $209 million and subordinated debt
due to an affiliate equal to approximately $962
million. This debt is subordinated to the payment
obligations of REMA under the leases as described
under "Outstanding Indebtedness -- Notes to
Affiliated Entities." Payments on this debt are
restricted by the covenant described in
"Description of the Exchange
Certificates -- Covenants -- Limitations on
Restricted Payments and Restricted Investments."
Subsidiary Guarantors...... Each subsidiary that REMA now owns is a guarantor
of the lease obligations and is referred to as a
subsidiary guarantor. If REMA cannot make rental
payments under the facility leases when they are
due, the subsidiary guarantors will be obligated to
make them. The subsidiary guarantors' obligations
rank equal in right of payment with their other
senior unsecured indebtedness, if any.
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Collateral for the Lessor
Notes...................... The lessor notes issued by each owner lessor are
secured by an assignment by such owner lessor to
the applicable indenture trustee of that owner
lessor's rights and interests in the following
collateral:
- the related leased facility
- the related lease, including the right to receive
payments of periodic rent under the lease, other
than customary excepted payments reserved to the
applicable owner lessor, owner participant and
other participants in the lease transactions
- the other lease documents, including the owner
lessor's interest in its facility site lease from
REMA and its corresponding site sublease to REMA,
but excluding the tax indemnity agreement and the
participation agreement, and
- the security for the lease obligations referred
to below
Security for Lease
Obligations.............. The obligations under the lease documents of REMA
are secured by
- a pledge of its equity and any debt interests in
the subsidiary guarantors, and
- uncollateralized, irrevocable, unconditional
stand-by letters of credit provided by a bank or
surety rated at least A- by Standard & Poor's and
A3 by Moody's, or guarantees of any of our
affiliates, other than the subsidiary guarantors,
rated at least BBB by Standard & Poor's and Baa2
by Moody's, in either case in an amount
representing the greater of the next six months'
scheduled rental payments under each of the
leases or 50% of the scheduled rental payments
due in the next twelve months under such lease.
Presently, the required amount of credit support
is $120 million in the aggregate for all the
leases.
No Cross-Collateralization
of Lessor Notes or Cross
Default Provisions....... The lessor notes issued by one owner lessor are not
cross-collateralized with, or generally
cross-defaulted to, the lessor notes of any other
owner lessor. The covenants under each set of lease
documents are identical except that
(1) we provide separate credit support as security
for each lease, and
(2) some facility specific covenants, such as
maintenance and insurance, relate to the
applicable facility interest being leased.
As a result, an event of default under one lease
indenture will not, by itself, trigger an event of
default under any other lease indenture. However,
REMA must make lease payments pro rata without
preference to any lease.
Subordinated Working
Capital Facility........... REMA has entered into an irrevocably committed
subordinated working capital facility with an
affiliated entity, Reliant Energy Northeast
Holdings, Inc., or RENH. RENH will fund REMA's
drawings under this facility through borrowings or
equity contributions irrevocably committed to RENH
by Reliant Energy Resources Corp.,
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or RERC, or another entity rated at least Baa2 by
Moody's and BBB by Standard & Poor's. REMA may
borrow under this facility in amounts necessary to
achieve a pro forma coverage ratio of at least 1.1
to 1.0 to pay operating expenditures, senior
indebtedness and rent, but excluding capital
expenditures and subordinated indebtedness. In
addition, RENH must make advances to REMA and REMA
must obtain such advances under such facility up to
the maximum available commitment in amounts
necessary to permit us to achieve a pro forma
coverage ratio of at least 1.1 to 1.0 at the time
rent under the leases is due. As of January 31,
2001, the amount available under each of the
subordinated working capital facility and the
related RENH facility was $120 million with no
outstanding balances. The amount available under
the facility declines to $0 in 2011. Please read
"Outstanding Indebtedness -- Subordinated Working
Capital Facility."
Option to Terminate Leases
and Mandatory Redemption of
Lessor Notes............. A lease may be terminated before its scheduled
expiration under some circumstances. If it is, the
lessor notes related to such lease will be subject
to mandatory redemption unless assumed as described
below, and any redemption proceeds received by the
pass through trustees will be distributed to you.
The terms of the leases require REMA to pay amounts
adequate to make such payments on the lessor notes.
Mandatory Redemption
Without Make Whole
Premium............... All lessor notes outstanding under the relevant
lease indenture will be redeemed, in whole but not
in part, at the principal amount of such notes,
plus all accrued and unpaid interest on such notes,
but without any premium, upon the receipt by the
indenture trustee of any amount under any of the
following circumstances:
- REMA exercises its right to terminate a lease of
a facility if its management committee determines
in good faith that such facility has become
economically or technologically obsolete as a
result of
- a change in law, regulation or tariff of
general application, or
- the imposition by any governmental entity of
any conditions or requirements upon the
continued effectiveness or renewal of any
license or permit required for the operation or
ownership of such facility
- termination of a lease of any facility upon the
occurrence of an event of loss under the lease
for which REMA does not elect to rebuild the
damaged facility or, in the case of a regulatory
event of loss (as described beginning on page
111), unless REMA assumes the applicable lessor
notes and purchases the owner lessor's interest
in the affected facility
- REMA exercises its right to terminate the lease
of a facility if a change in law causes it to
become illegal for REMA to continue such lease or
to make payments under such lease and the
transactions contemplated by such lease cannot be
restructured to comply with such change in law,
unless REMA assumes the
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applicable lessor notes and purchases the owner
lessor's interest in the affected facility
- REMA exercises its right to terminate a lease of
a facility if
- one or more events outside its control occurs
that gives rise to indemnity obligations by it
under the lease documents, such event, together
with the event in the preceding bullet point,
referred to as a burdensome event
- such indemnity obligations can be avoided if
REMA terminates such lease and the owner lessor
sells the applicable leased facility, and
- the present value of such avoided payments
would exceed 3% of the original purchase price
of the applicable leased facility
unless REMA assumes the applicable lessor notes
and purchases the owner lessor's interest in the
affected facility.
Mandatory Redemption
With Make Whole
Premium............... If REMA exercises its right to terminate a lease of
a facility, other than in the circumstances
described above for such facility, all lessor notes
outstanding under the related lease indenture will
be redeemed, in whole but not in part, at the
principal amount of such notes, plus all accrued
and unpaid interest on such notes, plus a make
whole premium. The make whole premium will be equal
to the discounted present value of all remaining
principal and interest payments scheduled to become
due on the lessor notes, less the outstanding
principal amount of the lessor notes being
redeemed. Such present value will be determined on
the basis of a discount rate equal to the sum of
(1) a treasury rate, plus (2) 50 basis points
(0.50%).
REMA may terminate a lease of any facility only
upon a determination by its management committee
that such facility is
- economically or technologically obsolete for any
reason (other than (1) a change in law,
regulation or tariff of general application or
(2) imposition by any governmental entity of any
conditions or requirements upon the continued
effectiveness or renewal of any license or permit
required for the operation or ownership of such
facility that renders such facility economically
or technologically obsolete)
- surplus to its needs, or
- no longer useful in its trade or business
Optional Redemption........ The lessor notes outstanding under a lease
indenture may be redeemed, in whole or in part, at
the principal amount of such notes, plus all
accrued and unpaid interest, plus a make whole
premium as described in "Mandatory Redemption With
Make Whole Premium" above.
Assumption of Lessor
Notes...................... In some situations, the lessor notes issued by each
owner lessor may be assumed by the owner
participant of that owner lessor or by the lessee.
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Assumption by Owner
Participant................ If a lease indenture event of default occurs as a
result of a lease event of default, the owner
participant of the related owner lessor will have
the right to assume on a recourse basis the lessor
notes issued under the related lease indenture. The
assumption right can be exercised only by an owner
participant that is a direct or indirect wholly
owned subsidiary of PSEG Resources Inc., currently
a subsidiary of Public Service Enterprise Group.
This right is also conditioned on
- the exchange certificates being rated, after
giving effect to the assumption, at least BBB+ by
Standard & Poor's and Baa1 by Moody's
- the cure of all monetary defaults under the
applicable lease documents, and
- the delivery by the owner participant of
documents containing covenants equivalent to
those in the lease documents
Assumption by
Lessee................ REMA, as lessee, has the right to purchase an owner
lessor's interest in a leased facility, terminate
the related lease and assume the lessor notes
related to such facility on a recourse basis if a
regulatory event of loss or a burdensome event
occurs.
Change of Control.......... A change of control constitutes an event of default
under each lease. If a change of control occurs,
the indenture trustees may exercise specified
rights and remedies, including an acceleration of
the lessor notes. If an indenture trustee
accelerates the applicable lessor notes, a change
of control premium equal to 1% of the principal
amount of the notes will be payable by REMA.
The term "change of control" means the consummation
of any transaction or series of related
transactions the result of which is that any person
or group other than
- Reliant Energy or any successor to Reliant Energy
by reason of merger, consolidation or transfer of
all or substantially all of its assets
- any person who becomes a beneficial owner of more
than 50% of the voting power of Reliant Energy or
any person described in the immediately preceding
bullet point, or
- any direct or indirect subsidiary of Reliant
Energy or any other person described in the two
preceding bullet points
becomes the beneficial owner of more than 50% of
REMA's voting power, or acquires, by contract or
otherwise, the power to direct or cause the
direction of REMA's management or policies.
However, a change of control will be deemed not to
have occurred if both Moody's and Standard & Poor's
confirm that the then current ratings of the
exchange certificates will not be lowered as a
result of these events.
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For purposes of this change of control provision,
the test for a change of control will cease to
refer to Reliant Energy and will instead refer to
the entity that satisfies the first bullet point
below, if
- the unsecured, senior long-term debt of REPG, or
of any person that directly or indirectly owns
beneficially 100% of the voting stock of REPG
(other than Reliant Energy), is rated at least
Baa2 by Moody's and BBB by Standard & Poor's
- the common equity of REPG or of the person that
directly or indirectly owns beneficially 100% of
the voting stock of REPG (other than Reliant
Energy) is listed for trading on a national
securities exchange or quoted on an automated
quotation system of a registered securities
association
- RES and each other subsidiary of Reliant Energy
that is a party to a procurement and marketing
agreement or a support services agreement with us
is or becomes a direct or indirect wholly owned
subsidiary of REPG or such person, and
- REPG or such other person beneficially owns
directly or indirectly 100% of the voting stock
of REMA
Covenants.................. The terms of the lease documents relating to the
lease transactions require us to, among other
things
- provide financial statements, default notices and
other notices to each pass through trustee
- maintain our existence and property
- maintain our tax status
- comply with applicable laws and contractual
obligations
- maintain insurance coverage, and
- cause future REMA subsidiaries that are not
designated as unrestricted subsidiaries to become
subsidiary guarantors
The terms of the lease documents restrict our
ability to, among other things:
- incur additional indebtedness
- make distributions, payments and investments,
unless and until lease obligations have been
guaranteed as described below
- incur liens on our property or pledge our assets
- engage in mergers, consolidations and sales of
assets
- assign the leases and the leased facilities as
described below
- sublease the leased facilities
- enter into some types of transactions with
affiliates
- enter into agreements that would impose
restrictions on subsidiaries of REMA to make
payments or loans to REMA, and
- engage in businesses other than the generation
and sale of energy, capacity and ancillary
services from our current generating facilities
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or other nonnuclear power generation facilities
in the United States and incidental activities
These restrictions are subject to a number of
important qualifications and exceptions that are
described under "Description of the Exchange
Certificates -- Covenants." In particular, the
covenant restricting distributions, payments and
investments will be suspended if
- any direct or indirect domestic parent of REMA
that has as one of its principal businesses
wholesale generation of electricity guarantees
the lease obligations, and
- at the time such guarantee is executed and
delivered,
- the long-term unsecured debt of such guarantor
is rated at least BBB by Standard & Poor's and
Baa2 by Moody's
- the sum of such guarantor's common
shareholders' equity and subordinated
indebtedness owed to affiliates, other than its
subsidiaries or REMA, is at least $2 billion,
and
- after giving effect to such guarantee and the
suspension of such covenant, each of Standard &
Poor's and Moody's confirms its then-current
rating for the exchange certificates
Assignments................ In some circumstances, REMA may assign its interest
in all the leases or in the lease relating to the
Keystone station or the Conemaugh station. Any such
assignment must be to a person that
- assumes REMA's lease obligations
- has, directly or through a guarantor of the
assigned lease obligations, a tangible net worth
of at least $750 million, and
- is, or its operating and maintenance obligations
under the applicable leases are, guaranteed by or
contracted to be performed, by an experienced,
reputable operator of coal-fired electric
generating facilities
In addition, assignments will be conditioned upon
- in the case of an assignment of all of REMA's
interest in all of the leases, the leased
facilities and the other lease documents,
- Moody's and Standard & Poor's both confirm that
the assignment will not result in a downgrade
of the then current credit rating of the
exchange certificates, and
- the exchange certificates are rated at least
Baa2 by Moody's and BBB by Standard & Poor's
- in the case of assignments of the interests of
REMA in the Keystone station or the Conemaugh
station and the related leases and other lease
documents
- concurrently with the assignment, the
then-existing exchange certificates must be
exchanged for new classes of exchange
certificates, which will represent (1)
undivided interests in lessor notes relating to
the assigned lease or leases and (2) undivided
interests in lessor notes relating to the
nonassigned lease or leases
- Moody's and Standard & Poor's both confirm that
the assignment will result in a credit rating
for all classes of new exchange certificates
being at least one level above the then current
rating of the existing exchange certificates,
and
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- all classes of the new exchange certificates
are rated at least as high as the initial
ratings by each of Moody's and Standard &
Poor's of the exchange certificates
Please read "Description of Lease Documents -- The
Leases -- Lease Assignment."
Governing Law.............. The laws of the State of New York govern the pass
through trust agreements, the certificates, the
lessor notes and the lease indentures except to the
extent the laws of Pennsylvania are mandatory.
Indenture and Pass Through
Trustee.................. Bankers Trust Company acts as pass through trustee,
paying agent and registrar for the certificates
issued by each pass through trust. Bankers Trust
Company also acts as the indenture trustee for the
lessor notes.
ERISA Considerations....... Subject to the conditions described in this
prospectus under "ERISA Considerations," the
certificates may be purchased by any employee
benefit plan or other retirement arrangement
subject to the Employee Retirement Income Security
Act of 1974 or the Internal Revenue Code.
Risk Factors............... Investing in the exchange certificates involves
risks, including risks related to the uncertainties
associated with the competitive market in which we
operate, the structure of the lease transactions
and the operation of our generation facilities. A
description of these risks begins on page 27.
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SUMMARY OF THE INDEPENDENT ENGINEER'S REPORT
S&W Consultants, a division of Stone & Webster, Inc., our independent
engineer, prepared an independent engineer's report dated August 4, 2000, a copy
of which is attached as Appendix A to this prospectus. Stone & Webster is an
international engineering and consulting firm with expertise in the electric
power industry. The independent engineer's report contains a description of the
electric power generating facilities owned or leased by us, which we refer to as
the "facilities" in this section, and the findings of an independent engineering
assessment of the facilities. The independent engineer has not updated its
report since August 4, 2000.
The independent engineer's report includes Stone & Webster's independent
technical assessment of our electric power generating facilities, based on a
review of the available technical data, and presents their findings and
conclusions regarding the following:
- condition assessment of the facilities
- facility performance
- operating and maintenance program and expenses
- environmental issues relating to the future operation and maintenance of
the facilities, and
- the pro forma financial projections of cash flows and fixed charge
coverage ratios, or FCCRs, under base case and sensitivity assumptions
(collectively referred to as the "financial projections")
The independent engineer performed the following tasks:
- reviewed the facilities' performance
- reviewed the facilities' technical condition
- reviewed the environmental site assessment documents
- reviewed the operation and maintenance programs
- reviewed the applicable transition power agreements, and
- developed the financial model
Set forth below are the principal findings and conclusions that the
independent engineer reached regarding the facilities. For a complete
understanding of the assumptions upon which these findings and conclusions were
based, the independent engineer's report should be read in its entirety. On the
basis of the independent engineer's review and the assumptions set forth in the
independent engineer's report, the independent engineer opined, as of the date
of such opinion, that
- There are 21 facilities with an average combined generation capacity of
4,262 MW provided by 19 steam units, five hydroelectric units, 11 diesel
units, 39 simple cycle units and four combustion turbines and one steam
turbine in combined cycle configuration. The Keystone and Conemaugh
stations are in very good condition, the Sayreville, Warren, and Seward
stations are in fair to good condition and the remaining units are in
good condition. The facilities have been constructed, operated and
maintained according to good utility practice. They should operate as
projected provided they are operated and maintained in accordance with
good industry practice. The independent engineer believes we have proven
experience in operating power plants.
- The facilities are fully permitted and appear to be in material
compliance with their permits. We have developed a plan to address the
impacts of environmental compliance for the implementation of existing
and for anticipated regulation. The compliance plan includes a
combination of capital expenditures for unit modification and emission
credit purchases.
- REMA and its subsidiaries owning facilities in New Jersey and Maryland,
directly or through REMA's wholly owned subsidiary Reliant Energy
Northeast Management Company, will operate
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the facilities (in the case of the Conemaugh and Keystone stations, the
operating agreements expire December 31, 2002, and future operations will
be sent out for bid). The projected staffing levels are well suited for
the competitive market.
- The project agreements, including the acquisition agreement and
transition power purchase agreements, are technically reasonable.
- The facilities' operations and maintenance, or O&M, and major maintenance
budgets appear reasonable and adequate to meet our maintenance and
performance objectives, excluding any catastrophic failures.
- The overhaul schedules developed by REMA are prudent and consistent with
forecasted operations. The overhaul and capital expenses forecasted in
the financial model are adequate to support the continued operation of
the facilities through the remaining life projected by REMA.
- Based on the independent engineer's review, there are no existing
conditions that would preclude the operation of the facilities through
the remaining life assumed by REMA assuming the continuation of condition
assessments, maintenance and capital improvement programs as shown in the
financial projections.
- The independent engineer reviewed and provided data that was used as
inputs to the independent market consultant's market simulation model.
The key input data, such as claimed capacity, scheduled and forced outage
rates and heat rate were reasonable and were consistent with recent
historic experience.
- The projected performance of the facilities, as measured by the annual
capacity factors projected by the independent market consultant, is
consistent with recent historical performance. The facilities should be
technically able to perform at the levels projected by the independent
market consultant until the expected retirement dates.
- The technical assumptions assumed in the financial projections are
reasonable and are consistent with the agreements. The financial model
fairly presents, in the independent engineer's judgment, projected
revenues and projected expenses under the base case assumptions.
Therefore, the financial projections are a reasonable forecast of the
financial results under the base case assumptions.
- The projected revenues are sufficient to pay the annual operating and
maintenance expenses (including provisions for major maintenance), other
operating expenses and fixed charges (excluding payments that are
subordinated to fixed charge obligations) based on the independent
engineer's studies and analyses and the assumptions set forth in the
independent engineer's report. The average FCCR for the term of the
certificates is 6.34x. The minimum FCCR beginning with the first full
year over the term of the certificates is 2.12x, which occurs in the year
2001.
Due to uncertainties necessarily inherent in relying on assumptions and
projections, you should anticipate that actual operating results may differ,
perhaps materially, from those assumed and described in the independent
engineer's report. To demonstrate the impact of changes in some circumstances on
the financial projections, the independent engineer developed and performed
several sensitivity analyses using the pro forma financial model by increasing
the heat rates, increasing the O&M expenditures, increasing the capital
expenditures and lowering the capacity factors, each as outlined below:
- Increased Heat Rates. The heat rate for each of the units was increased
by 10%, which increased fuel expenses. The market model was not rerun to
develop new electricity generation and market prices based on the 10%
higher heat rates. The resulting average FCCR over the term of the
certificates is 5.92x and the minimum FCCR, beginning with the first full
year over the term of the certificates, is 1.99x, which occurs in the
year 2001.
- Increased O&M Expenditures. The annual labor, fixed O&M, variable O&M,
overhaul, and other O&M expenses were increased by 10%. The resulting
average FCCR over the term of the
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certificates is 6.06x and the minimum FCCR, beginning with the first full year
over the term of the certificates, is 2.05x, which occurs in the year 2001.
- Increased Capital Expenditures. The annual capital expenditures for each
of the units were increased by 10%. The resulting average FCCR over the
term of the certificates is 6.25x and the minimum FCCR, beginning with
the first full year over the term of the certificates, is 2.10x, which
occurs in the year 2001.
- Lower Capacity Factors. The annual electricity generation and fuel
expenses for each of the units were decreased by 10%. The market model
was not rerun to develop new energy prices based on the 10% lower
generation. The 10% lower capacity factors resulted in an average FCCR
over the term of the certificates of 5.24x and the minimum FCCR,
beginning with the first full year over the term of the certificates, is
1.80x, which occurs in the year 2001.
In addition, the sensitivity of the facilities to macroeconomic changes was
assessed. These case scenarios were taken from the independent market
consultant's sensitivity forecasts.
- Asset Overbuild Case. The independent market consultant prepared new
projections with additional electric generation capacity coming on-line
over that which was assumed in the base case projections as well as
continued operation of all nuclear plants. In this scenario, an
additional 12,447 MW of merchant capacity comes online by 2003 in the PJM
market and the Northeast Power Coordinating Council in addition to the
8,147 MW of confirmed new merchant capacity that is reflected in the base
case. Using these projections in the financial model results in an
average FCCR over the term of the certificates of 5.62x. The minimum
FCCR, beginning with the first full year over the term of the
certificates, is 1.78x, which occurs in the year 2001.
- Lower Fuel Prices. The independent market consultant prepared new
projections based on lower oil and gas prices than those used in the base
case projections. The base case 1999 gas and oil prices are reduced by
$0.50/mmBtu with escalation remaining unchanged (coal prices are not
changed). Using these projections in the financial projections results in
a lower average FCCR over the term of the certificates of 4.15x. The
minimum FCCR, beginning with the first full year over the term of the
certificates, is 1.82x, which occurs in the year 2001.
BASE CASE AND SENSITIVITY SUMMARY
MINIMUM AVERAGE
FCCR FCCR
(2001-2026) (2000-2026)
----------- -----------
Base Case................................................... 2.12 6.34
Increased Heat Rates........................................ 1.99 5.92
Increased O&M Expenditures.................................. 2.05 6.06
Increased Capital Expenditures.............................. 2.10 6.25
Lower Capacity Factors...................................... 1.80 5.24
Asset Overbuild Case........................................ 1.78 5.62
Lower Fuel Prices........................................... 1.82 4.15
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SUMMARY OF THE INDEPENDENT MARKET CONSULTANT'S REPORT
PA Consulting Group, formerly PHB Hagler Bailly, Inc., our independent
market consultant, prepared an independent market consultant's report dated May
5, 2000, a copy of which is attached as Appendix B to this prospectus. The
independent market consultant has not updated its report since May 5, 2000.
In the preparation of the independent market consultant's report, which we
refer to as the "power market report," and the opinion contained in the power
market report, the independent market consultant made the following
qualifications about the information contained in its report and the
circumstances under which the report was prepared:
- some information in the report is necessarily based on predictions and
estimates of future events and behaviors
- such predictions or estimates may differ from that which other experts
specializing in the electricity industry might present
- actual results may differ, perhaps materially, from those projected
- the provision of the power market report does not obviate the need for
potential investors to make further appropriate inquiries as to the
accuracy of the information included in the power market report, or to
undertake an analysis of their own
- the power market report is not intended to be a complete and exhaustive
analysis of the subject issues, and therefore will not consider some
factors that are important to a potential investor's decision making, and
- the independent market consultant and its employees cannot accept
liability for loss, whether direct or consequential, suffered in
consequence of reliance on its report, and nothing in the power market
report should be taken as a promise or guarantee as to the occurrence of
any future events
MARKET CHARACTERISTICS
The United States is currently experimenting with a variety of regional
market structures. Some regions currently have fixed reserve margin requirements
coupled with capacity markets, while others implicitly price capacity through
on-peak energy prices, ancillary service prices and bilateral option contracts.
In addition, some regions have developed bid-based markets for the provision of
energy, ancillary services and/or capacity, while others continue to rely on
bilateral contracts. It is not clear which model will eventually become more
widespread. Nevertheless, in both types of markets, new generating capacity will
be developed based on the revenue streams determined through competition. While
the type of market in place in a given region will determine the composition of
the revenue streams and will affect the mix and timing of new generating units,
the financial return on new assets is likely to be similar in both types of
markets, as generators seek to cover their total going-forward costs. The PJM
market has developed as a bid-based market.
The Northeast power markets are undergoing profound change. Many of the
vertically integrated utilities are divesting their generation assets, and power
pools (such as the PJM market, the New York Power Pool and the New England Power
Pool) are changing as well. Historically, these pools were formed to obtain the
benefits of economic efficiency and reliability through coordinated planning and
operation. Independent system operators with both system operations and market
operations functions are replacing the pools. Through the creation of the new
market institutions, the market participants intend to create an open and
competitive market where a large number of buyers and sellers of generation
services will be able to transact business.
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FORECASTING METHODOLOGY
The following is PA Consulting Group's description of its forecasting
methodology.
PA Consulting Group employs its proprietary market valuation process,
MVP(SM), to estimate the value of electric generation units based upon the level
of energy prices and their volatility. MVP(SM) is a three-step process. The
first step is to conduct the "fundamental analysis" to examine how the level of
prices responds to changes in the fundamental drivers of supply and demand. The
next step uses the results of the first step, but puts a real market price shape
on the price levels and characterizes the volatility in prices. The third step
examines how the generation unit responds to those prices and derives value from
operational decisions.
Note that MVP(SM) does not replace the fundamental analysis of market
drivers of supply and demand through a production cost model. The
production-cost model provides insights into the fundamental drivers (such as
fuel prices, demand, entry and exit) that a volatility analysis cannot address.
MVP(SM) integrates the two approaches to create a better estimate of the value
of a generating unit by accounting for volatility effects and changes in the
fundamental drivers of electricity prices.
Volatility analysis takes into account the annual trend of prices (from a
fundamental approach), and the patterns and fluctuations exhibited in the
marketplace.
MVP(SM) uses a real options approach to value electric generating capacity,
and thereby captures the value of price volatility. An electric generating unit
can be viewed as a strip of European call options on the spread between
electricity prices and the variable cost of production (which is largely fuel).
Unlike most option analyses, however, a generation unit does not have perfect
flexibility to adjust to the price-cost spread. A generation unit may have costs
that must be incurred to start up, as well as constraints on its operation that
may limit its ability to capture margins when the spread is positive (price is
greater than variable cost) or avoid losses when the spread is negative
(variable cost is greater than price). Hence, the second step of MVP(SM) focuses
on the ability of a generation unit to capture margins, given its cost structure
and constraints on operation.
PA Consulting Group's fundamental model, which is a driver of the
volatility model, forecasts two price streams:
- energy based upon a production-cost model with price set to marginal cost
in each hour, and
- compensation for capacity, which represents the additional margin
necessary to keep an economic amount of capacity in the market
PA Consulting Group uses a detailed chronological production-costing model
to simulate energy price formation in the market area of interest. From the
energy price analysis, PA Consulting Group determines the energy margin (price
minus variable cost) attributable to each generating unit in the market. These
margins, along with estimates of "going-forward costs" (fixed costs, such as
fixed operation and maintenance, property taxes, employee benefits and
incremental capital expenditures), are used in PA Consulting Group's Capacity
Market Simulation Model to predict the additional margins related to the
provision of capacity.
Compensation for capacity may take many forms. Payments could be in the
form of a capacity price arising from a capacity market, a regulated payment
fee, bilateral contracts, payments by the independent system operators for
ancillary services or in the form of prices above the marginal cost of the
price-setting plant. Regardless of the form, compensation for capacity will be
set to retain an amount of generation capability available in the market.
Ultimately, the sum of the compensation for capacity and the market price for
energy will reflect what customers are willing to pay for reliability.
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KEY ASSUMPTIONS
In developing its capacity and energy market price forecasts for the
Northeast and the PJM markets, the independent market consultant made some
assumptions related to those markets, including assumptions relating to
- demand growth
- fuel prices, and
- capacity additions
Each of these assumptions is described in detail in the independent market
consultant's report, as well as the input assumptions used in its volatility
analyses. The following discussion describes some key assumptions used by the
independent market consultant in arriving at its forecasts of capacity and
energy prices.
Demand. The PJM market peak demand is forecasted to grow at an average
annual growth rate of approximately 1.6% from 2000 through 2020.
Fuel prices. Forecasts for natural gas and oil use a consensus fuel price
forecast derived from published fuel price forecasts. Table 1 summarizes the
fuel price forecasts used in the base case for the PJM East, West and Central
regions where our facilities are located.
TABLE 1
DELIVERED FUEL PRICES IN PJM (1999 $/MMBTU)
FUEL 2000 2005 2010 2015 2020
- ---- ---- ---- ---- ---- ----
Natural Gas-PJM East........................................ 2.81 2.87 2.99 3.06 3.31
Natural Gas-PJM West........................................ 2.72 2.79 2.91 3.00 3.25
Natural Gas-PJM Central..................................... 2.77 2.83 2.95 3.03 3.28
Fuel Oil No. 2-PJM East..................................... 3.87 4.28 4.57 4.74 4.98
Fuel Oil No. 2-PJM West..................................... 3.84 4.25 4.54 4.72 4.95
Fuel Oil No. 2-PJM Central.................................. 3.82 4.24 4.53 4.70 4.93
Fuel Oil No. 6-PJM East..................................... 2.52 2.73 2.86 2.91 2.99
Fuel Oil No. 6-PJM West..................................... 2.43 2.64 2.77 2.82 2.90
Fuel Oil No. 6-PJM Central.................................. 2.41 2.62 2.75 2.80 2.88
Capacity additions. Based on assessments of the status of announced plants,
the independent market consultant has estimated operational capacity additions
of 8,147 MW in the PJM market and the Northeast Power Coordinating Council by
2003. After that time, capacity additions are based on the results of modeling
and simulation of developer's decisions. In the base case presented in the power
market report, 22,855 MW of new capacity is added in the PJM market from 2003
through 2020, and 7,529 MW is retired.
Results and Conclusions. Using the assumptions contained in its report, the
independent market consultant developed a "base case" for each region that
reflects its best assessment of future market conditions. It should be
recognized that this base case will vary to the extent the input assumptions
change, and such assumptions should be reviewed with the same rigor as the
resulting forecast. In addition to the base case, the independent market
consultant developed two sensitivities as outlined below:
- "Low Fuel Price Case," which tests the sensitivity of the market price
forecasts to lower gas and oil prices represented as a $0.50/MMBtu
reduction in the 1999 gas and oil prices with escalation remaining
unchanged (coal prices are not changed).
- "Overbuild Case," which tests the sensitivity of the market price
forecasts to an exuberance of merchant plant development as well as
continued operation of all nuclear plants. In this scenario, an
additional 12,447 MW of merchant capacity comes online by 2003, in
addition to the 8,147 MW of confirmed new merchant capacity that is
reflected in the base case.
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The all-in market price combines the energy price with the price received
by generators for other relevant generation services and energy products in the
market. The all-in price reflects the independent market consultant's estimate
of the total market price that generators will recover in PJM East, PJM West and
PJM Central. The all-in price results of the study are summarized in Figures 1,
2 and 3.
FIGURE 1
PJM EAST ESTIMATED ALL-IN PRICE FORECAST
[GRAPH]
FIGURE 2
PJM WEST ESTIMATED ALL-IN PRICE FORECAST
[GRAPH]
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FIGURE 3
PJM CENTRAL ESTIMATED ALL-IN PRICE FORECAST
[GRAPH]
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The dispatch curve below represents the projections by the independent
market consultant of the annual average marginal dispatch cost of our facilities
for the year 2000 as compared to the other generators in the PJM market. The
curve portrays the diversity of our portfolio.
DISPATCH CURVE
PJM MARKET
2000
[DISPATCH CURVE PJM MARKET 2000 GRAPH]
CONCLUSIONS
Power markets throughout the United States are presently undergoing
fundamental change. Market structures are changing to support the introduction
of a more competitive environment in the power generation industry. Power pools
are being replaced by independent system operators with both system operations
and market operations functions. Through the creation of the new market
institutions, participants intend to create efficient power markets where buyers
and sellers of generation services will be able to transact business with
greater speed.
In this new environment the nature of electricity pricing, and consequently
revenue generation, is shifting away from administered regulation and toward
market mechanisms driven by competition. The expected increase in price
volatility and related risks associated with these new markets presents both
tremendous upside and downside potential for some generators. In response to
these changes, many vertically integrated utilities are reexamining their
business model and adjusting their generation asset portfolios. A select group
of these utilities have adopted a diverse approach in assembling generation
asset portfolios that take advantage of market opportunities. These portfolios
are being assembled through utility mergers, new construction and through the
acquisition of assets divested from producers partially or completely exiting
the generation business. These portfolios, like our portfolio, offer decreased
risk, as they portray fuel and unit diversity.
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RISK FACTORS
In addition to the information contained elsewhere in this prospectus, you
should carefully consider the following risk factors in evaluating an investment
in the exchange certificates.
RISK FACTORS RELATING TO OUR BUSINESS
Our revenues and results of operations will be subject to market risks that
are beyond our control.
We expect to sell capacity, energy and ancillary services from our
facilities into the PJM spot market or other competitive power markets or on a
bilateral contract basis. We are not guaranteed any rate of return on our
capital investments through mandated rates, and our revenues and results of
operations are likely to depend, in large part, upon prevailing market prices
for energy, capacity and ancillary services in the PJM market and other
competitive markets. These market prices may fluctuate substantially over
relatively short periods of time. In addition, the ISOs that oversee these
markets may impose price limitations and other mechanisms to address some of the
volatility in these markets. All these factors could have an adverse impact on
our revenues and results of operations.
The following factors may influence the market prices for energy, capacity
and ancillary services in our markets:
- factors affecting demand, including
- weather conditions
- seasonality
- possible reductions in the projected rate of growth in electricity usage
due to regional economic conditions, the implementation of conservation
programs and other factors, and
- programs that compensate customers for reducing usage during peak
periods
- factors affecting supply, including
- prevailing market prices for coal, fuel oil and natural gas and
associated transportation costs and possible disruptions and
interruptions from time to time in fuel supplies
- changes in supplies and prices of capacity, energy and ancillary
services available from current competitors or new market entrants,
including the development of new generation facilities or transmission
lines that may be able to price or deliver electricity more cheaply or
allow greater access to competitors
- transmission congestion or other limitations on transmitting power from
generators to users
- the extended operation of nuclear generating plants in the PJM control
area beyond their presently expected dates of decommissioning, and
- prevailing regulations that affect the PJM market and other competitive
markets and regulations governing the ISOs that oversee these markets
We have only a limited history of owning and operating our facilities.
Although our power generation facilities have a significant operating
history, we have recently acquired those facilities and have no prior experience
operating the facilities or any other facilities in the deregulated PJM market.
For this reason, our historical combined financial data included in this
prospectus covers only a short period of time and may not be very helpful in
predicting our future results of operations.
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Our operations involve various risks.
The operation of our power generation facilities involves various operating
risks, including possible or potential
- performance below expected levels of availability, output or efficiency
- interruptions in fuel availability or fuel transportation
- increases in fuel or fuel transportation costs
- poor quality fuel
- disruptions in the transmission of electricity
- breakdown or failure of equipment, whether due to age or otherwise, or
processes
- shortages of equipment or spare parts
- operator error
- catastrophic events like fires, earthquakes, explosions, floods or other
similar occurrences affecting power generation facilities
- labor disputes
- curtailment of operation in compliance with the PJM ISO requirements for
transmission reliability, and
- curtailment of operations due to restrictions on emissions
If one or more of the events listed above occur, the revenues generated by
our generation facilities could be reduced significantly or the costs of
operating them could be increased significantly. If such a reduction in revenues
or an increase in costs occurs, the ability of REMA or the subsidiary guarantors
to meet their obligations related to the leases may be, and payments on your
exchange certificates may be, adversely affected.
Our inability to control the decisions of the other owners of the Conemaugh
and Keystone stations restricts our operational control over, and could limit
realization of value in, those facilities.
REMA's ability to meet obligations under the leases of the Conemaugh
station and Keystone station interests, as they relate to operational issues,
will necessarily be qualified due to its inability to control the decisions of
the other owners of those facilities. Additionally, some decisions about the
acquisition of fuel and the bid pricing mechanism for power from the Conemaugh
and Keystone stations have been delegated by the co-owners to a project office.
Because REMA does not control operating decisions, including the procurement of
fuel for the Conemaugh station or the Keystone station, REMA's ability to meet
operating obligations under the leases will be limited to exercising all of its
rights, powers, elections and options available to it under the operating
agreements in a manner consistent with its obligations under the leases. We
cannot, however, assure that the decisions made by the other Conemaugh owners or
the other Keystone owners will enable REMA to comply with specific requirements
under the leases.
Our insurance coverage for the facilities may not be adequate to cover
potential liabilities and losses.
REMA is required by the lease documents to have insurance for our
facilities in amounts and against risks as are customarily maintained by
companies engaged in the same or similar operations operating in the same or
similar locations. We cannot guarantee that such insurance coverage for our
facilities will be available in the future on commercially reasonable terms or
that the insurance that we carry will be adequate to cover potential liabilities
and losses.
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Our operations and activities are subject to extensive environmental
regulation and permitting requirements and could be adversely affected by our
future inability to comply with environmental laws and requirements or changes
in environmental laws and requirements.
Our business is subject to extensive environmental regulation by federal,
state and local authorities. We are required to comply with numerous
environmental laws and regulations, and to obtain numerous governmental permits,
in operating our facilities. We may incur significant additional costs because
of our compliance with these requirements. If we fail to comply with these
requirements, we could be subject to civil or criminal liability and the
imposition of cleanup liens or fines. Existing environmental regulations could
be revised or reinterpreted, new laws and regulations could be adopted or become
applicable to us or our facilities, and future changes in environmental laws and
regulations could occur, including potential regulatory and enforcement
developments related to air emissions. If any of these events occur, our
business, operations and financial condition could be adversely affected.
We may not be able to obtain or maintain from time to time all required
environmental regulatory approvals. If there is a delay in obtaining any
required environmental regulatory approvals or if we fail to obtain and comply
with any required environmental regulatory approvals, the operation of our
facilities or the sale of electricity to third parties could be prevented or
become subject to additional costs.
We are generally responsible for all on-site liabilities associated with
the environmental condition of our facilities, regardless of when such
liabilities arose and whether they are known or unknown.
Our operations and activities are also subject to a variety of other
regulations and permitting requirements, including those relating to energy
matters, and could be adversely affected by future inability to comply with
these laws and requirements or changes in these laws and requirements.
Our business is also subject to a variety of nonenvironmental regulations
and permitting requirements, including those relating to energy matters and
safety. The same types of risks that apply to environmental regulations and
permitting requirements apply to these regulations and permitting requirements,
including risks of
- significant additional costs to comply with these regulations and
requirements
- civil or criminal liability
- changes in or reinterpretations of laws and passage of new laws and
regulations, and
- interruption of operations for failure to comply
Our ownership by Reliant Energy, RRI and REPG and our contractual arrangements
with affiliates of Reliant Energy, RRI and REPG could give rise to conflicts
of interest, and such conflicts of interest may be resolved against us.
Reliant Energy, RRI and REPG indirectly own 100% of our equity interest. If
a conflict of interest arises between Reliant Energy, RRI or REPG, as the
indirect equity owner, on the one hand, and you, effectively as our creditors,
on the other, Reliant Energy, RRI or REPG might exercise its power to control us
in a manner that would benefit it to your detriment. For example, Reliant
Energy, RRI or REPG or any of their subsidiaries could elect in the future to
compete with us, directly or indirectly, in the markets where we sell power.
REMA and its subsidiaries are parties to contracts with REPG and RES,
including contracts by which RES supplies fuel, provides fuel transportation and
other services, and sells the capacity, energy and ancillary services from our
facilities. RES also provides these kinds of energy services to other customers,
including subsidiaries of Reliant Energy and RRI. RES is not contractually
limited from performing those services and activities in a manner that would
benefit its other customers rather than us. As a result, conflicts of interest
may arise from time to time between us and other affiliates of Reliant Energy or
RRI, including RES and REPG, that provide services to us. These conflicts of
interest could be resolved against us.
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If REPG and RES terminate agreements to provide us services that are required
for our operations, we may not be able to replace those services on as
favorable terms.
RES can terminate its contract with us to provide fuel and fuel
transportation and other services and to sell the capacity, energy and ancillary
services from our facilities on six months' notice. REPG can also terminate its
contract with us to provide various support and administrative services on six
months' notice. Payments by us of fees owed to RES under the contract with RES
and of all payments under the contract with REPG are subordinated to our lease
obligations. The services provided under the contracts with RES and REPG are
required for our operations. If these contracts are terminated, we may not be
able to replace them on terms that are as favorable to us.
RISK FACTORS RELATING TO THE EXCHANGE CERTIFICATES AND THE STRUCTURE OF THE
LEASE TRANSACTIONS
Our actual results may not match our projections of future performance.
We base our financial projections on analyses and reports prepared by our
independent engineer and by our independent market consultant in August 2000 and
May 2000, respectively. The independent engineer and the independent market
consultant made numerous assumptions in preparing these analyses and reports and
relied upon forecasts prepared by others. The independent engineer and the
independent market consultant prepared the projections on the basis of
assumptions that we, the independent engineer and the independent market
consultant believed to be reasonable at the time the projections were prepared.
However, these assumptions involve inherent uncertainties about many matters,
including matters over which we have little or no control. Moreover, neither the
independent engineer nor the independent market consultant has updated their
respective reports since we offered and sold the original certificates. These
assumptions relate to, among other things, the following:
- increases in demand for electric power
- fuel supply and prices
- net capacity additions in the PJM control area, after giving effect to
projected retirements
- availability and dispatch levels for our electric generation stations
- levels of operating and maintenance expenses
- levels of overhaul and capital expenditures
- levels of expenditures for environmental matters, including expenditures
relating to conditions that existed when we acquired our facilities
- availability and price levels for air emission credits
- our having all licenses, permits and approvals required to operate our
facilities
- levels of electric power import capacity and prices
- levels of inflation
- nonoperating expenses, including property taxes, insurance and general
and administrative expenses
- transmission constraints that could affect pricing, and
- operation of our generating facilities in accordance with operations and
maintenance, major maintenance and capital budgets and standard industry
practice
The fact that we include projections in this prospectus does not mean that
we expect our actual results to match the projections. You should not place
undue reliance on the projections. If the assumptions or forecasts upon which we
base our projections prove to be incorrect, our actual results will be different
from those projected. These differences could be material. If actual results are
materially less
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than the projections, this could adversely affect our ability to make lease
payments and distributions on your exchange certificates.
Please carefully read the independent engineer's report attached as
Appendix A and the independent market consultant's report attached as Appendix
B. You should also note that our independent accountants have neither examined
nor compiled the projections included in this prospectus and do not express any
opinion or any other form of assurance about the projections.
We do not intend to provide any revised projections or analyses of the
differences between the projections and actual operating results.
If REMA were to go into bankruptcy, the leases may be repudiated and the
collateral securing our lease obligations and the subsidiary guarantees that
cover the lease obligations may not be adequate to repay all amounts owed
under the lessor notes.
The exchange certificates are not our direct obligations. If REMA were to
become a debtor in a liquidation or reorganization case under the federal
bankruptcy code, REMA, as debtor, or a bankruptcy trustee appointed for REMA,
could reject the leases as "executory" contracts. If the leases were rejected,
rental payments under the leases would terminate and leave the owner lessors
with a claim for damages for breach of the leases. In this case, while the owner
lessors could file claims for damages, the amount of any recovery on those
claims and the amount of time that would pass between the commencement of the
bankruptcy case and the receipt of any recovery cannot be determined.
Under Pennsylvania law, it is likely that the leases will be viewed as
leases of real, rather than personal, property. If the leases are rejected, the
federal bankruptcy code limits the claims of lessors under unexpired leases of
real property. If a bankruptcy court concluded that the leases are leases of
real property, damages for the rejection of a lease would be limited to the
greater of one year's rent under the lease or 15% of the remaining rent under
the lease, not to exceed three years' rent. Any claims under guarantees of these
obligations may also be subject to this limitation. These damages would be
insufficient to cover debt service on the lessor notes and the exchange
certificates. However, the leases would not be subject to these limitations if a
court determined that they constitute a financing rather than a lease
transaction. This issue has not been definitively addressed by the courts, and
resolution would depend on a bankruptcy court's analysis of the particular facts
and circumstances associated with the lease transactions. If one or more of the
leases were rejected by us or a bankruptcy trustee, the indenture trustee would
not be deprived of its liens on the collateral for the lessor notes issued by
the owner lessors or the benefit of the guarantees.
It is also possible that, if we were involved in a bankruptcy proceeding,
we could elect to cure defaults under the leases and to assume and assign the
leases. If this occurred, an entity other than us would become obligated to make
payments under the leases (and on the exchange certificates). While this
assignee would have to demonstrate its ability to perform under the assumed
leases, the assignee might not be able to satisfy our obligations under the
leases.
If a default occurs on the lessor notes, the available remedies and the value
realized on foreclosure of the collateral may not be sufficient to repay all
amounts on such lessor notes.
The lessor notes are secured by an assignment of the rights and interests
of each owner lessor in the applicable leased facilities and in the lease
documents, other than the participation agreement and tax indemnity agreement,
including the owner lessor's interest in its ground lease and its rights under
the lease of the leased facilities. This assignment covers the owner lessor's
right to receive rent payments under the lease, other than customary excepted
payments and excepted rights reserved to the owner lessor and the owner
participant. If a default occurs under the lessor notes, the proceeds of an
exercise of remedies, including foreclosure on the related collateral, might not
provide sufficient funds to repay all amounts due on the lessor notes and on the
exchange certificates.
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In addition, the leases and the other lease documents relating to the lease
transactions do not contain cross-collateralization provisions. As a result, the
indenture trustee's security interests in each of the Keystone station, the
Conemaugh station and the Shawville station and the related lease agreements are
separate and secure separate amounts. The amounts secured are, in the aggregate,
at least equal to the aggregate amounts due under the lessor notes. If the
indenture trustee exercises its right to foreclose on and sell the rights and
interests in each of these electric generating facilities and to exercise its
rights under the related lease agreements, the proceeds from the sale of the
rights and interests in each of these electric generating facilities and such
agreements would be separately applied against the amount secured by that
particular generating facility and could not be used to satisfy any deficiency
in the proceeds from the sale of the rights and interests in those other
electric generating facilities. By operation of law, any excess of sale proceeds
relating to a particular electric generating facility would be remitted to the
owner lessor that owned the particular electric generating facility, or, in the
case of Keystone and Conemaugh, an undivided interest in the facility. As a
result, the amount of sale proceeds from the foreclosure of the rights and
interests related to a particular generating facility available to the indenture
trustee for distribution to the pass through trusts might not be sufficient to
pay all principal, premium, if any, and interest due upon the lessor notes, even
though aggregate sale proceeds were sufficient for this purpose.
In addition, if REMA defaults under the leases and the indenture trustee
exercises its right to foreclose on the rights and interests in each of the
Keystone station, the Conemaugh station and the Shawville station, transferring
the required government approvals to, or obtaining new approvals by, a purchaser
or new operators of those stations may require additional governmental approvals
or proceedings, with consequent delays.
There may not be an active, liquid market in which you can sell your exchange
certificates.
Following completion of the exchange offer, the exchange certificates will
be freely tradable by most holders. Please read "The Exchange Offer -- Resales
of the Exchange Certificates." We do not intend to apply for listing of the
exchange certificates on any securities exchange or on the Nasdaq National
Market.
We have been informed by some of the initial purchasers of the original
certificates that they intend to make a market in the exchange certificates
after the completion of the exchange offer. However, the initial purchasers are
not required to make a market in the exchange certificates, and they may cease
market-making at any time without notice. We cannot assure you that an active
market for the exchange certificates will develop. Even if a market for the
exchange certificates does develop, you may not be able to resell the exchange
certificates for an extended period of time, if at all. As a result, you may not
be able to liquidate your investment quickly or to liquidate it at an attractive
price. In addition, lenders may not readily accept the exchange certificates as
collateral for loans.
We intend to suspend reporting under the Exchange Act as soon as we are able
to do so.
Upon completion of the exchange offer, we will be subject to the reporting
requirements of the Exchange Act. However, we currently intend to suspend our
Exchange Act reporting obligations as soon as we are permitted to do so under
applicable law. Under current rules, we may be required to file such reports for
only one year after the registration statement is declared effective if we have
fewer than 300 holders of record of the exchange certificates. If we have more
than 300 holders of record of the exchange certificates at January 1, 2002, we
will suspend our reporting obligations at the beginning of the first year in
which we have fewer than 300 holders of record of the exchange certificates. If
we suspend our reporting obligations, the exchange certificates will continue to
be freely transferable by you if you are not an affiliate of ours, but we will
no longer prepare and file the reports and other information required by the
Exchange Act. You might not view this suspension favorably, and it might become
more difficult to sell the exchange certificates or to sell them at prices that
you consider favorable. The participation agreements provide that if we are not
subject to Exchange Act reporting requirements, we will provide the pass through
trustee and the holders of the exchange certificates reports containing audited
consolidated financial statements on an annual basis and unaudited consolidated
financial statements on a quarterly basis for the first three quarters of each
year.
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Our future access to capital could be limited.
We will need to make substantial expenditures in the future to, among other
things, maintain the performance of our facilities, given their age, and comply
with environmental laws and regulations. Our direct and indirect parent
companies, including Reliant Energy, Reliant Resources, Inc. and REPG, are not
generally obligated to provide, and may decide not to provide, any funds to us
in the future. Our only other source of funding will be internally generated
cash flow from our operations and proceeds from the issuance of securities or
the incurrence of other indebtedness, including working capital indebtedness in
the future. The lease documents limit our ability to issue securities and incur
indebtedness. We may not be successful in obtaining sufficient additional
capital in the future to enable us to fund all our future capital and other
requirements.
The subsidiary guarantees of our lease obligations could be voidable.
Under the federal bankruptcy law and comparable provisions of state
fraudulent transfer laws, the guarantee of REMA's lease obligations by each
subsidiary guarantor, and any guarantee subsequently issued by a parent of REMA
in accordance with the lease documents, could be voided, or claims under the
guarantees could be subordinated to all other debts of that guarantor. This
could occur if, among other things, the guarantor, at the time it incurred the
indebtedness evidenced by its guarantee,
- received less than fair consideration or reasonably equivalent value for
the guarantee
- was insolvent or rendered insolvent by reason of the issuance of the
guarantee
- was engaged in a business or transaction for which its remaining assets
constituted unreasonably small capital, or
- intended to incur, or believed that it would incur, debts beyond its
ability to pay such debts as they mature
In addition, any payment by a guarantor under its guarantee could be voided
and required to be returned to the guarantor or to a fund for the benefit of the
creditors of the guarantor. Furthermore, secured creditors of the guarantor may
rank higher in priority of payment to any claim under the guarantee. REMA's
subsidiaries' liabilities under their guarantees, and the liabilities of its
parent under any subsequently issued guarantee, are contractually limited to the
maximum amount they could pay without the guarantees being deemed to be
fraudulent transfers. This limitation may not be effective, and, if it were
effective, may limit the guarantees to amounts that are not sufficient to pay
REMA's lease obligations in full. In addition, if REMA becomes unable to pay all
of its obligations, litigation might be required to determine the amounts
payable under these contractual limitations, resulting in delays in payment
under the guarantees.
REMA may assign the leases and its interest in the leased facilities or
replace the facilities that are subject to the leases.
Subject to restrictions in the lease documents, REMA may assign, in whole
or in part, the leases and its interest in the leased facilities. Following any
such assignment, an entity other than REMA will become obligated to make
payments under the leases. While any assignee must satisfy net worth and other
requirements under the lease documents and the exchange certificates must attain
a rating requirement immediately after giving effect to the assumption, these
requirements do not guarantee that any such assignee would be able to satisfy
the obligations of REMA under the leases.
REMA is also entitled, again subject to restrictions under the lease
documents, to swap the leased undivided interest in the Keystone station for an
additional undivided interest that REMA might acquire in the future in the
Conemaugh station or, alternatively, swap the leased undivided interest in the
Conemaugh station for an additional undivided interest that REMA might acquire
in the Keystone station. Such a swap would decrease the diversity of the sources
of revenue for payment on the lessor notes and
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result in greater exposure to risks affecting revenues and results of operations
of the individual leased facilities.
Reliant Energy plans to cease to be our ultimate parent company.
Reliant Energy may dispose of its interest in REPG, our indirect parent,
without any requirement for REMA to repay the lessor notes. In July 2000,
Reliant Energy announced its intention to divide itself into two publicly traded
companies in order to separate its unregulated businesses from its regulated
businesses. RRI, which will be the parent company of the unregulated businesses,
is in the process of offering up to 20% of its common stock in an initial public
offering. Within twelve months of the completion of that offering, Reliant
Energy intends to distribute RRI's remaining stock to its shareholders. Until
Reliant Energy completes the distribution of RRI's common stock, RRI will
continue to be a subsidiary of Reliant Energy. After this distribution, we would
cease to be an indirect subsidiary of Reliant Energy. We cannot assure that the
initial public offering and the distribution will be completed.
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USE OF PROCEEDS
We will not receive any cash proceeds from the issuance of the exchange
certificates offered in the exchange offer. In consideration for issuing the
exchange certificates as contemplated in this prospectus, we will receive in
exchange original certificates in like principal amount.
The original certificates surrendered in exchange for exchange certificates
will be retired and canceled and will not be reissued. The issuance of the
exchange certificates will not result in a change in our lease rental
obligations.
THE EXCHANGE OFFER
PURPOSE OF THE EXCHANGE OFFER
When the original certificates were sold, we entered into an exchange and
registration rights agreement. Under this agreement, we agreed to
- file with the SEC a registration statement for an offer to exchange the
exchange certificates for original certificates
- use our reasonable commercial efforts to cause the registration statement
to become effective and to consummate the exchange offer on or before May
21, 2001
- keep the exchange offer open for acceptance for a period of not less than
30 days or longer as required by applicable law; and
- accept for exchange all original certificates duly tendered and not
validly withdrawn in the exchange offer in accordance with the terms of
the exchange offer and letter of transmittal
In addition, there are circumstances where we are required to use our
reasonable commercial efforts to file a shelf registration statement for resales
of the original certificates.
As soon as practicable after the registration statement for the exchange
offer is declared effective, we intend to offer the holders of original
certificates who are not prohibited by any law or policy of the SEC from
participating in the exchange offer the opportunity to exchange their original
certificates for exchange certificates.
Under the exchange and registration rights agreement, we also agreed to pay
additional interest at a rate of 0.50% per annum on the lessor notes if we
failed to complete the exchange offer within 270 days after the date we issued
the original certificates. Any additional interest will be payable on the
original certificates on the regular interest payment dates. We filed a copy of
the exchange and registration rights agreement as an exhibit to the registration
statement of which this prospectus is a part. The exchange offer being made by
this prospectus is intended to satisfy our contractual obligations under the
exchange and registration rights agreement.
RESALES OF THE EXCHANGE CERTIFICATES
Based on interpretations by the staff of the SEC in no-action letters
issued to third parties in unrelated transactions, we believe that the exchange
certificates may be offered for resale, resold and otherwise transferred by you
without compliance with the registration and prospectus delivery requirements of
the Securities Act if:
- you acquire any exchange certificate in the ordinary course your business
- you do not intend to participate in the distribution of the exchange
certificates
- you are not a broker-dealer who purchased original certificates directly
from us for resale under Rule 144A or any other available exemption under
the Securities Act, and
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- you are not our affiliate within the meaning of Rule 405 under the
Securities Act
The SEC, however, has not considered the exchange offer for the exchange
certificates in the context of a no action letter.
If you tender your original certificates in the exchange offer with the
intention of participating in any manner in a distribution of the exchange
certificates, you:
- cannot rely on such interpretations by the SEC staff, and
- must comply with the registration and prospectus delivery requirements of
the Securities Act, or rely upon an available exemption from those
requirements, in connection with any offer for resale, resale or other
transfer of the exchange certificates
Unless an exemption from registration is otherwise available, the resale by
any certificateholder intending to distribute exchange certificates should be
covered by an effective registration statement under the Securities Act
containing the selling certificateholder's information required by Item 507 or
Item 508, as applicable, of Regulation S-K under the Securities Act. This
prospectus may be used for an offer to resell, resale or other retransfer of
exchange certificates only as specifically described in this prospectus. Only
those broker-dealers that acquired the original certificates as a result of
market-making activities or other trading activities may participate in the
exchange offer. Each broker-dealer that receives exchange certificates for its
own account in exchange for original certificates, where the broker dealer
acquired such original certificates 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 such exchange certificates. Please read the
section captioned "Plan of Distribution" for more details regarding the transfer
of exchange certificates.
TERMS OF THE EXCHANGE OFFER
Upon the terms and subject to the conditions in this prospectus and in the
accompanying letter of transmittal, we will accept for exchange original
certificates that you properly tender prior to the expiration date and do not
withdraw in accordance with the procedures described below. We will issue $1,000
principal amount of exchange certificates in exchange for each $1,000 principal
amount of original certificates surrendered under the exchange offer. Original
certificates may be tendered only in integral multiples of $1,000.
The exchange offer is not conditioned upon the tender for exchange of any
minimum aggregate principal amount of original certificates.
The original certificates were originally sold on August 24, 2000 in an
offering that was exempt from the registration requirements of the Securities
Act. As of January 31, 2001, $210,000,000 aggregate principal amount of Series A
original certificates, $297,850,000 aggregate principal amount of Series B
original certificates and $220,000,000 aggregate principal amount of Series C
original certificates were outstanding. This prospectus and the letter of
transmittal are being sent to all registered holders of the original
certificates.
Holders of original certificates do not have any appraisal or dissenters'
rights in connection with the exchange offer. We intend to conduct the exchange
offer in accordance with the provisions of the exchange and registration rights
agreement, the applicable requirements of the Securities Act and the Exchange
Act and the rules and regulations of the SEC.
Original certificates that are not tendered for exchange in the exchange
offer:
- will remain outstanding
- will continue to accrue interest, and
- will be entitled to the rights and benefits that holders have under the
pass through trust agreement relating to the certificates
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We will be deemed to have accepted for exchange properly tendered original
certificates when we have given oral or written notice of the acceptance to the
exchange agent and complied with the applicable provisions of the exchange and
registration rights agreement. The exchange agent will act as agent for you for
the purposes of receiving the exchange certificates from us.
If you tender original certificates in connection with the exchange offer,
you will not be required to pay brokerage commissions or fees or, subject to the
instructions in the letter of transmittal, transfer taxes relating to the
exchange of original certificates. We will pay all charges and expenses, other
than some applicable taxes described below, in connection with the exchange
offer. It is important that you read the "-- Fees And Expenses" section for more
details regarding fees and expenses incurred in the exchange offer.
We will return or credit to an account maintained with DTC any original
certificates that we do not accept for exchange for any reason without expense
to you as promptly as practicable after the expiration or termination of the
applicable exchange offer.
WE MAKE NO RECOMMENDATION TO YOU AS TO WHETHER YOU SHOULD TENDER OR REFRAIN
FROM TENDERING ALL OR ANY PORTION OF YOUR ORIGINAL CERTIFICATES UNDER THE
EXCHANGE OFFER. IN ADDITION, NO ONE HAS BEEN AUTHORIZED TO MAKE THIS
RECOMMENDATION. YOU MUST MAKE YOUR OWN DECISION WHETHER TO TENDER UNDER THE
EXCHANGE OFFER AND, IF SO, THE AGGREGATE AMOUNT OF ORIGINAL CERTIFICATES TO
TENDER. YOU SHOULD MAKE YOUR DECISION ONLY AFTER READING THIS PROSPECTUS AND THE
LETTER OF TRANSMITTAL AND CONSULTING WITH YOUR ADVISORS.
EXPIRATION DATE
The exchange offer will expire at 5:00 p.m., New York City time, on March
16, 2001 unless in our sole discretion we extend it.
EXTENSIONS; DELAY IN ACCEPTANCE; TERMINATION OR AMENDMENT
We expressly reserve the right, at any time or at various times, to extend
the period of time during which the exchange offer will remain open. We may
delay acceptance for exchange of any original certificates by giving oral or
written notice of the extension to the exchange agent and by timely public
announcement. During any such extensions, all original certificates you have
previously tendered will remain subject to the exchange offer, and we may accept
them for exchange.
To extend the exchange offer, we will notify the exchange agent orally or
in writing of any extension. We also will make a public announcement of the
extension no later than 9:00 a.m., New York City time, on the next business day
after the previously scheduled expiration date.
If any of the conditions described below under "-- Conditions to the
Exchange Offer" have not been satisfied relating to the exchange offer for
original certificates, we reserve the right, in our sole discretion:
- to delay accepting for exchange any original certificates
- to extend the exchange offer, or
- to terminate the exchange offer
We will give oral or written notice of such delay, extension or termination to
the exchange agent. Subject to the terms of the exchange and registration rights
agreement, we also reserve the right to amend the terms of the exchange offer in
any manner.
Any such delay in acceptance, extension, termination or amendment will be
followed as promptly as practicable by oral or written notice thereof to the
registered holders of original certificates. If we amend the exchange offer in a
manner that we determine to constitute a material change, we will promptly
disclose that amendment in a manner reasonably calculated to inform the holders
of such amendment. We will distribute the supplement to the registered holders
of the original certificates. Depending upon the
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significance of the amendment and the manner of disclosure to the registered
holders, we will extend the exchange offer if the exchange offer would otherwise
expire during such period.
We will have no obligation to publish, advertise or otherwise communicate
any delay in acceptance, extension, termination or amendment of the exchange
offer, other than by making a timely release. We may also publicly communicate
these matters in any other appropriate manner that we may choose.
CONDITIONS TO THE EXCHANGE OFFER
Despite any other term of the exchange offer, we will not be required to
accept for exchange, or exchange any exchange certificates for, any original
certificates, and we may terminate the exchange offer before accepting any
original certificates for exchange, if in our reasonable judgment:
- the exchange offer, or the making of any exchange by a holder of original
certificates, would violate applicable law or any applicable
interpretation of the SEC staff, or
- any action or proceeding has been instituted or threatened in any court
or by or before any governmental agency relating to the exchange offer,
or
- any law, statute, rule or regulation has been adopted or enacted that can
reasonably be expected to impair our ability to proceed with the exchange
offer
In addition, we will not be obligated to accept for exchange your original
certificates if you have not made to us:
- the representations described under "-- Procedures for Tendering" and
"Plan of Distribution," and
- such other representations as may be reasonably necessary under
applicable SEC rules, regulations or interpretations to make available to
us an appropriate form for registering the original certificates under
the Securities Act
We expressly reserve the right to amend or terminate the exchange offer,
and to reject for exchange any original certificates not previously accepted for
exchange in the exchange offer, if any of the conditions to the exchange offer
specified above occurs. We will give oral or written notice of any extension,
amendment, non-acceptance or termination to you as promptly as practicable.
These conditions are for our sole benefit, and we may assert them or waive
them in whole or in part at any time or at various times in our sole discretion.
Our failure at any time to exercise any of these rights will not mean that we
have waived our rights. Each right will be deemed an ongoing right that we may
assert at any time or at various times.
PROCEDURES FOR TENDERING
How to Tender Generally
Because the original certificates are held through DTC, only a DTC
participant listed on a DTC securities position listing for the original
certificates may tender such original certificates in the exchange offer. If you
hold original certificates and are a DTC participant, to tender in the exchange
offer, you must comply with the automated tender program procedures of DTC
described below.
If you beneficially own original certificates that are held through a
broker, dealer, commercial bank, trust company or other nominee or custodian,
and you wish to tender those original certificates, you should contact such
person or nominee as soon as possible and instruct such person or nominee to
tender on your behalf.
To be effective, a tender must be made prior to the expiration date. To
complete a tender through DTC's automated tender offer program, the exchange
agent must receive, prior to the expiration date, a timely confirmation of
book-entry transfer of such original certificates into the exchange agent's
account at DTC according to the procedure of book-entry transfer described below
and a properly transmitted agent's
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message. Delivery of documents to DTC in accordance with their respective
procedures will NOT constitute delivery to the exchange agent.
If you tender under the exchange offer and that tender is not withdrawn
prior to the expiration date and our acceptance of that tender, then you will
have agreed with us in accordance with the terms and subject to the conditions
described in this prospectus and in the letter of transmittal.
If you tender less than all of your original certificates, you should fill
in the amount of original certificates you are tendering in the appropriate box
on the letter of transmittal or, in the case of a book-entry transfer, so
indicate in an agent's message if you have not delivered a letter of
transmittal. The entire amount of original certificates delivered to the
exchange agent will be deemed to have been tendered unless otherwise indicated.
THE METHOD OF DELIVERY OF THE LETTER OF TRANSMITTAL AND ALL OTHER REQUIRED
DOCUMENTS OR TRANSMITTAL OF AN AGENT'S MESSAGE, AS DESCRIBED BELOW UNDER
"-- TENDERING THROUGH DTC'S AUTOMATED TENDER OFFER PROGRAM," IS AT YOUR ELECTION
AND RISK, AND DELIVERY WILL BE DEEMED MADE ONLY WHEN ACTUALLY RECEIVED BY THE
EXCHANGE AGENT. RATHER THAN MAIL THE LETTER OF TRANSMITTAL OR OTHER REQUIRED
DOCUMENTS, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN
ALL CASES, YOU SHOULD ALLOW SUFFICIENT TIME TO ASSURE DELIVERY TO THE EXCHANGE
AGENT BEFORE THE EXPIRATION DATE. YOU SHOULD NOT SEND ANY LETTER OF TRANSMITTAL
TO US. YOU MAY REQUEST YOUR BROKER, DEALER, COMMERCIAL BANK, TRUST COMPANY OR
NOMINEE TO EFFECT THESE TRANSACTIONS FOR YOU.
Signatures and Signature Guarantees
Signatures on a letter of transmittal or a notice of withdrawal described
in "Withdrawal of Tenders" below must be guaranteed by an eligible institution
unless the original certificates are tendered:
- by a registered holder who has not completed the box entitled "Special
Issuance Instructions" or "Special Delivery Instructions" in the letter
of transmittal, or
- for the account of an eligible institution
An eligible institution is 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 Exchange Act, that is a member of one of the recognized
signature guarantee programs identified in the letter of transmittal.
When Endorsements or Bond Powers Are Needed
If a person other than the registered holder of any original certificates
signs the letter of transmittal, the original certificates must be endorsed or
accompanied by a properly completed bond power. The registered holder must sign
the bond power as the registered holder's name appears on the original
certificates. An eligible institution must guarantee that signature.
If the letter of transmittal or any original certificates or bond powers
are signed by trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, those persons should so indicate when signing. Unless we waive this
requirement, they also must submit evidence satisfactory to us of their
authority to deliver the letter of transmittal.
Tendering Through DTC's Automated Tender Offer Program
We understand that the exchange agent will make a request promptly after
the date of this prospectus to establish an account for the original
certificates at DTC for the purpose of facilitating the exchange offer. Any
financial institution that is a participant in DTC's system may use DTC's
automated tender offer program to tender through book-entry delivery of original
certificates into the exchange agent's account at DTC. Accordingly, participants
in the program may, instead of physically completing and
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signing the letter of transmittal and delivering it to the exchange agent,
transmit their acceptance of the exchange offer electronically. The exchange for
tendered original certificates will only be made after
- a timely confirmation of a book-entry transfer of the original
certificates into the exchange agent's account, and
- timely receipt by the exchange agent of an agent's message
An "agent's message" is a message transmitted by DTC to and received by the
exchange agent and forming part of the book-entry confirmation, stating that:
- DTC has received an express acknowledgment from a participant in DTC's
automated tender offer program that is tendering original certificates
that are the subject of such book-entry confirmation
- the participant has received and agrees to be bound by the terms of the
letter of transmittal or, in the case of an agent's message relating to
guaranteed delivery, the participant has received and agrees to be bound
by the applicable notice of guaranteed delivery, and
- we may enforce the agreement against such participant
Delivery of an agent's message will also constitute an acknowledgment from the
tendering DTC participant that the representations contained in the letter of
transmittal and described on page 41 under "-- Your Representations to Us."
Determinations Under the Exchange Offer
We will determine in our sole discretion all questions as to the form of
documents, validity, eligibility, time of receipt, acceptance of tendered
original certificates and withdrawal of tendered original certificates. Our
determination will be final and binding. We reserve the absolute right, in our
sole and absolute discretion, to reject any original certificates that we
determine are not properly tendered or any tendered original certificates our
acceptance of which, in the opinion of our counsel, would be unlawful. We also
reserve the absolute right, so long as applicable law allows, to waive any
defects, irregularities or conditions of the exchange offer as to particular
tendered original certificates. Our interpretation of the terms and conditions
of the exchange offer, including the letter of transmittal and the instructions
relating to it, will be final and binding on all parties.
Unless waived, any defects or irregularities in connection with tenders of
original certificates must be cured within such time as we determine. Neither
we, the exchange agent nor any other person will be under any duty to give
notification of defects or irregularities relating to tenders of original
certificates, nor will we or those persons incur any liability for failure to
give such notification. Tenders of original certificates will not be deemed made
until such defects or irregularities have been cured or waived. Any original
certificates received by the exchange agent that are not properly tendered and
as to which the defects or irregularities have not been cured or waived will be
returned to you, unless otherwise provided in the letter of transmittal, as soon
as practicable following the expiration date.
When We Will Issue Exchange Certificates
In all cases, we will issue exchange certificates for original certificates
that we have accepted for exchange in the exchange offer only after the exchange
agent timely receives:
- a timely book-entry confirmation of such original certificates into the
exchange agent's account at DTC, and
- a properly completed and duly executed letter of transmittal and all
other required documents or a properly transmitted agent's message
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Return of Original Certificates Not Accepted or Exchanged
If we do not accept any tendered original certificates for exchange for any
reason described in the terms and conditions of the exchange offer or if
original certificates are submitted for a greater principal amount than you
desire to exchange, we will return the unaccepted or non-exchanged original
certificates without expense to you. In the case of original certificates
tendered by book-entry transfer into the exchange agent's account at DTC
according to the procedures described above under "-- Tendering Through DTC's
Automated Tender Offer Program," such non-exchanged original certificates will
be credited to an account maintained with DTC. These actions will occur as
promptly as practicable after the expiration or termination of the exchange
offer.
Your Representations to Us
By signing or agreeing to be bound by the letter of transmittal, you will
represent to us that, among other things:
- any exchange certificates you receive will be acquired in the ordinary
course of your business
- you are not our "affiliate," as defined in Rule 405 under the Securities
Act or, if you are our affiliate, that you will comply with the
applicable registration and prospectus delivery requirements of the
Securities Act to the extent applicable
- if you are not a broker-dealer, you are not engaged in and do not intend
to engage in the distribution of the exchange certificates
- if you are a broker-dealer that will receive exchange certificates for
your own account in exchange for original certificates that you acquired
as a result of market-making or other trading activities, you will
deliver a prospectus in connection with any resale of such exchange
certificates
- you have full power and authority to tender, exchange, sell, assign and
transfer the tendered original certificates
- we will acquire good, marketable and unencumbered title to the tendered
original certificates free and clear of all liens, restrictions, charges
and encumbrances, and
- the original certificates tendered for exchange are not subject to any
adverse claims or proxies
GUARANTEED DELIVERY PROCEDURES
If you wish to tender original certificates but they are not immediately
available or if you cannot deliver your original certificates, the letter of
transmittal or any other required documents to the exchange agent or comply with
the applicable procedures under DTC's automated tender offer program prior to
the expiration date, you may tender if:
- the tender is made by or through an eligible institution
- prior to the expiration date, the exchange agent receives from the
eligible institution a properly completed and duly executed notice of
guaranteed delivery substantially in the form accompanying the letter of
transmittal by facsimile transmission, mail or hand delivery
- stating your name and address, the registration number or numbers of
your original certificates and the principal amount of original
certificates tendered
- stating that the tender is being made thereby, and
- guaranteeing that, within three New York Stock Exchange trading days
after the expiration date, the letter of transmittal or facsimile
thereof or agent's message in lieu thereof, together with the original
certificates or a book-entry confirmation, and any other documents
required by the letter of transmittal will be deposited by the eligible
guarantor institution with the exchange agent, and
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- the exchange agent receives such properly completed and executed letter
of transmittal or facsimile or agent's message, as well as all tendered
original certificates in proper form for transfer or book-entry
confirmation, and all other documents required by the letter of
transmittal, within three New York Stock Exchange trading days
Upon request to the exchange agent, the exchange agent will send a notice
of guaranteed delivery to you if you wish to tender your original certificates
according to the guaranteed delivery procedures described above.
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, you may withdraw your
tender of original certificates at any time prior to 5:00 p.m., New York City
time, on the expiration date.
For a withdrawal to be effective:
- the exchange agent must receive a written notice of withdrawal at any of
its addresses listed under the caption "Prospectus Summary -- The
Exchange Agent," or
- the withdrawing holder must comply with the appropriate procedures of
DTC's automated tender offer program
Any notice of withdrawal must:
- specify the name of the person who tendered the original certificates to
be withdrawn
- identify the original certificates to be withdrawn, including the
registration number or numbers and the principal amount of such original
certificates
- be signed by the person who tendered the original certificates in the
same manner as the original signature on the letter of transmittal used
to deposit those original certificates, or be accompanied by documents of
transfer sufficient to permit the trustee to register the transfer into
the name of the person withdrawing the tender, and
- specify the name in which such original certificates are to be
registered, if different from that of the person who tendered the
original certificates
If original certificates have been tendered under the procedure for
book-entry transfer described above, any notice of withdrawal must specify the
name and number of the account at DTC to be credited with the withdrawn original
certificates and otherwise comply with the procedures of DTC.
We will determine all questions as to the validity, form, eligibility and
time of receipt of notice of withdrawal, and our determination will be final and
binding on all parties. We will deem any original certificates so withdrawn not
to have been validly tendered for exchange for purposes of the exchange offer.
Any original certificates that you tender for exchange but that are not
exchanged for any reason will be returned to you without cost. In the case of
original certificates tendered by book-entry transfer into the exchange agent's
account at DTC according to the procedures described above, such original
certificates will be credited to an account maintained with DTC for the original
certificates. This return or crediting will take place as soon as practicable
after withdrawal, rejection of tender or termination of the exchange offer. You
may retender properly withdrawn original certificates by following one of the
procedures described under "-- Procedures for Tendering" above at any time on or
prior to the expiration date.
PAYMENTS AND DISTRIBUTIONS OF INTEREST
For each original certificate of yours that we accept for exchange, you
will receive an exchange certificate in a like amount. You will be entitled to
receive a pro rata share of all scheduled interest
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payments on the lessor notes received by the pass through trustee for the trust
in which you own an interest. The pass through trustee will receive payments of
interest on the unpaid principal amount of the lessor notes on January 2 and
July 2 of each year at the rates indicated under "Description of the Exchange
Certificates -- Payments and Distributions." If the exchange offer is
consummated prior to July 2, 2001, as we expect, the pass through trustee will
first pay a pro rata share of scheduled interest payments on the lessor notes
beginning on July 2, 2001.
FEES AND EXPENSES
We will bear the expenses of soliciting tenders of the original
certificates. We will make the solicitation primarily by mail and through the
facilities of DTC. We may decide to make additional solicitations personally or
by telephone or other means through our officers, agents, employees or
affiliates.
We have not retained any dealer-manager in connection with the exchange
offer, and we will not make any payments to brokers, dealers or others
soliciting acceptances of the exchange offer. We will pay the exchange agent and
pass through trustee reasonable and customary fees for services and will
reimburse for reasonable out-of-pocket expenses in connection with the exchange
offer. We may also pay brokerage houses and other custodians, nominees and
fiduciaries the reasonable out-of-pocket expenses they incur in forwarding
copies of this prospectus and related documents to the beneficial owners of
original certificates and in handling or forwarding tenders for exchange.
We will pay the cash expenses to be incurred in connection with the
exchange offer. They include:
- SEC registration fees
- fees and expenses of the exchange agent and pass through trustee
- accounting and legal fees and printing costs, and
- related fees and expenses
TRANSFER TAXES
If you tender your original certificates for exchange, you will not be
required to pay any transfer taxes. We will pay all transfer taxes, if any,
applicable to the exchange of original certificates in the exchange offer. You
will, however, be required to pay any transfer taxes, whether imposed on the
registered holder or any other person, if:
- you want us to deliver exchange certificates to any person other than the
registered holder of the original certificates tendered
- you want the pass through trusts to issue the exchange certificates in
the name of any person other than the registered holder of the original
certificates tendered
- tendered original certificates are registered in the name of any person
other than the person signing the letter of transmittal, or
- a transfer tax is imposed for any reason other than the exchange of
original certificates in the exchange offer
If you do not submit satisfactory evidence of payment of any transfer taxes
payable by you, the amount of such transfer taxes will be billed directly to
you. The exchange agent will retain possession of exchange certificates in an
amount equal to the amount of the transfer taxes due until it receives payment
of the taxes.
CONSEQUENCES OF EXCHANGING OR FAILING TO EXCHANGE ORIGINAL CERTIFICATES
If you do not exchange your original certificates for exchange certificates
in the exchange offer, you will remain subject to the restrictions on transfer
of the original certificates. In general, you may not offer
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or sell the original certificates unless either they are registered under the
Securities Act or the offer or sale is exempt from or not subject to
registration under the Securities Act and applicable state securities laws.
Except as required by the exchange and registration rights agreement, we do not
intend to register resales of the original certificates under the Securities
Act.
The tender of original certificates in the exchange offer will reduce the
principal amount of the original certificates outstanding. Due to the
corresponding reduction in liquidity, this may have an adverse effect upon, and
increase the volatility of, the market price of any original certificates that
you continue to hold.
Furthermore, any broker-dealer that acquired any of its outstanding bonds
directly from us:
- may not rely on the applicable interpretation of the staff of the SEC's
position contained in Exxon Capital Holdings Corp., SEC no-action letter
(April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter (June
5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1983),
and
- must also be named as a selling certificateholder in connection with the
registration and prospectus delivery requirements of the Securities Act
relating to any resale transaction. Please read "Plan of Distribution."
In addition, to comply with state securities laws, the exchange
certificates may not be offered or sold in any state unless they have been
registered or qualified for sale in the state or an exemption from registration
or qualification is available and is complied with. The offer and sale of the
exchange certificates to "qualified institutional buyers", as defined under Rule
144A of the Securities Act, is generally exempt from registration or
qualification under the state securities laws. We currently do not intend to
register or qualify the sale of the exchange certificates in any state where an
exemption from registration or qualification is required and not available.
OTHER
Participation in the exchange offer is voluntary, and you should carefully
consider whether to accept. You are urged to consult your financial and tax
advisors in making your own decision on what action to take.
We may in the future seek to acquire any untendered original certificates
in open market or privately negotiated transactions, through subsequent exchange
offers or otherwise. We have no present plans to acquire any original
certificates that are not tendered in the exchange offer or to file a
registration statement to permit resales of any untendered original
certificates.
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CAPITALIZATION
The following table sets forth our actual consolidated capitalization as of
September 30, 2000 (in thousands).
SUBORDINATED NOTES:
Subordinated note payable to affiliate(3)................... $ 961,550
MEMBER'S EQUITY............................................. $ 209,102
TOTAL SUBORDINATED NOTES AND MEMBER'S EQUITY...... $1,170,652(1)(2)
- ---------------
(1) Excludes the lease obligations of REMA because such obligations are treated
as operating lease payments for financial reporting purposes. Future minimum
rent obligations under the leases are estimated to be $259.3 million for
2001 (of which $150.9 million was paid in January 2001), $136.5 million for
2002, $76.5 million for 2003, $84.5 million for 2004 and a total of $1,262.3
million for the remaining term of the leases (as of September 30, 2000).
(2) Excludes the $120 million subordinated working capital facility described
under "Outstanding Indebtedness -- Subordinated Working Capital Facility"
and the required maintenance of $50 million of cash in restricted deposits
by REMA at September 30, 2000 and through January 2, 2001. For a description
of additional subordinated debt we issued in early 2001, see "Outstanding
Indebtedness -- Other Intercompany Debt."
(3) These outstanding notes payable to an affiliate are subordinated to the
lease obligations of REMA.
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SELECTED HISTORICAL FINANCIAL DATA
We present in the following table the selected historical combined
financial data for REMA, the subsidiary guarantors and affiliated entities
involved in the development of electric generating facilities. You should note
the following special considerations relating to the financial data presented
below.
- REMA and its two subsidiaries that hold facilities located in New Jersey
and Maryland were formed in mid 1999 as wholly owned indirect
subsidiaries of Sithe Energies for the purpose of acquiring fossil
fuel-fired electricity generating plants located in the PJM control area
from operating subsidiaries of GPU, Inc. The operating history of these
companies began on November 24, 1999, when the acquisition from the GPU
subsidiaries was completed.
- We were acquired in May 2000 from Sithe Energies and one of its
subsidiaries for an aggregate purchase price of approximately $2.1
billion.
- Before our being acquired from Sithe Energies and one of its
subsidiaries, REMA was named Sithe Pennsylvania Holdings, LLC.
- After completion of our acquisition, REMA was renamed Reliant Energy
Mid-Atlantic Power Holdings, LLC and REMA acquired all of the ownership
interests in the subsidiary guarantors that it did not already own.
- In August 2000, REMA sold its interests in the Keystone, Conemaugh and
Shawville stations for $1.0 billion, used the proceeds to repay
indebtedness owed to affiliates and to return capital and entered into
long-term leases for such interests.
- As of September 30, 2000, substantially all of our capitalization
consists of approximately $209 million of equity and approximately $962
million of debt owed to a subsidiary of REPG that is subordinated to the
lease obligations of REMA.
- The financial information below includes results from affiliated entities
that we no longer own and that are involved in the development of
electric generating facilities. We include the results of these entities
in our historical financial statements because, during a portion of the
historical periods discussed, they were under common control with us or
owned by us. However, we exclude the results from these entities from May
12, 2000. We believe that the amounts involved for these entities that
are included in the historical results discussed below are not material.
We have derived the selected historical financial data presented below from
our audited and unaudited historical combined and consolidated financial
statements included elsewhere in this prospectus. The information presented
below should be read in conjunction with the section of this offering circular
captioned "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and our audited and unaudited historical combined and
consolidated financial statements and the accompanying notes included elsewhere
in this prospectus.
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PERIOD FROM PERIOD FROM PERIOD FROM MAY
NOVEMBER 24, 1999 TO JANUARY 1, 2000 TO 12, 2000 TO
DECEMBER 31, 1999 MAY 11, 2000 SEPTEMBER 30, 2000
(FORMER REMA) (FORMER REMA) (CURRENT REMA)(1)
-------------------- ------------------ ------------------
(IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenues.................................... $ 29,526 $166,490 $365,322
Fuel, operations and maintenance costs and
facilities lease expense.................. 18,584 94,000 109,390
Depreciation and amortization............... 4,842 19,538 25,627
Administrative and general expenses......... 1,584 13,101 12,137
Project development expenses................ 1,606 -- --
Interest expense to affiliates, net......... 12,588 46,538 51,482
Income tax expense.......................... -- -- 68,828
Net (loss) income........................... (9,678) (6,687) 97,858
- ---------------
(1)See Note 3(a) to our interim condensed combined and consolidated financial
statements for a discussion of adjustments to amounts previously recorded in
connection with the REMA acquisition purchase price allocation.
PERIOD FROM PERIOD FROM PERIOD FROM MAY
NOVEMBER 24, 1999 TO JANUARY 1, 2000 TO 12, 2000 TO
DECEMBER 31, 1999 MAY 11, 2000 SEPTEMBER 30, 2000
(FORMER REMA) (FORMER REMA) (CURRENT REMA)
-------------------- ------------------ ------------------
(IN THOUSANDS)
OTHER DATA (FOR THE PERIOD):
EBITDA(1)................................... $ 7,752 $ 59,389 $243,795
Capital expenditures........................ 4,421 -- 9,949
Ratio of earnings to fixed charges(2)....... -- -- 4.1x
- ---------------
(1) EBITDA is calculated as net (loss) income plus interest expense, income
taxes, depreciation and amortization. Although it is not a U.S. GAAP-based
measure of liquidity or performance, EBITDA is presented because it is a
widely accepted indicator of funds available to service debt or other
obligations. We believe that EBITDA, while providing useful information,
should not be considered in isolation or as a substitute for other measures
of operating performance, or as an alternative to cash flow as a measure of
liquidity. EBITDA amounts that we present in this prospectus may not
necessarily be comparable to similarly titled disclosures by other
companies.
(2) Fixed charges exceed earnings by $9.7 million for the period from November
24, 1999 to December 31, 1999 and $6.7 million for the period from January
1, 2000 to May 11, 2000. Interest owed to affiliated entities was the
largest component of fixed charges for these periods. During these periods,
debt owed to affiliated entities represented almost all of our
capitalization.
AS OF AS OF
DECEMBER 31, 1999 SEPTEMBER 30, 2000(1)
----------------- ---------------------
(IN THOUSANDS)
BALANCE SHEET DATA (AT THE END OF PERIOD):
Property, plant and equipment, net........................ $1,286,319 $ 920,380
Total assets.............................................. 1,705,900 1,387,494
Long-term liabilities..................................... 31,060 1,022,745
Total liabilities......................................... 1,660,969 1,178,392
Member's and shareholder's equity......................... 44,931 209,102
- ---------------
(1)See Note 3(a) to our interim condensed combined and consolidated financial
statements for a discussion of adjustments to amounts previously recorded in
connection with the REMA acquisition purchase price allocation.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion and analysis, which contains forward-looking
statements, should be read with the combined and consolidated financial
statements and notes of REMA and related companies (including the subsidiary
guarantors and the affiliated entities that develop electric generating
facilities) contained elsewhere in this prospectus. We base these statements on
our current plans and expectations, and the statements involve risks and
uncertainties that could cause actual future activities and results of
operations to be materially different from those included in the forward-looking
statements. We describe a number of risk factors that could cause actual results
to differ from those included in the forward-looking statements below under
"Risk Factors" beginning at page 27.
REMA is a Delaware limited liability company that owns, directly or through
its affiliates and subsidiaries, electric generation facilities in Pennsylvania,
New Jersey and Maryland. REMA is an indirect wholly owned subsidiary of REPG.
You should note the following special considerations relating to the
discussion of historical results below.
- REMA and its two subsidiaries that hold facilities located in New Jersey
and Maryland were formed in mid 1999 as wholly owned indirect
subsidiaries of Sithe Energies for the purpose of acquiring fossil
fuel-fired electricity generating plants located in the PJM control area
from operating subsidiaries of GPU, Inc. The operating history of these
three companies began on November 24, 1999, when the acquisition from the
GPU subsidiaries was completed.
- We were acquired in May 2000 from Sithe Energies and one of its
subsidiaries for an aggregate purchase price of approximately $2.1
billion.
- Before our being acquired from Sithe Energies and one of its
subsidiaries, REMA was named Sithe Pennsylvania Holdings, LLC.
- After completion of our acquisition from Sithe Energies and a subsidiary
of Sithe Energies, REMA was renamed Reliant Energy Mid-Atlantic Power
Holdings LLC and REMA acquired all of the ownership interests in the
subsidiary guarantors that it did not already own.
- In August 2000, REMA sold its interest in the Keystone, Conemaugh and
Shawville stations for $1.0 billion, used the proceeds to repay
indebtedness owed to affiliates and to pay a dividend and entered into
long-term leases for such interests.
- As of September 30, 2000, substantially all of our capitalization
consists of approximately $209 million of equity and approximately $962
million of debt owed to a subsidiary of REPG that is subordinated to the
lease obligations of REMA.
- The financial information below includes results from affiliated entities
that we no longer own and that are involved in the development of
electric generating facilities. We include the results of these entities
in our historical financial statements because, during a portion of the
historical periods discussed, they were under common control with us or
owned by us. However, we exclude the results from these entities from May
12, 2000. We believe that the amounts involved for these entities that
are included in the historical results discussed below are not material.
Before November 24, 1999, our facilities were operated on a fully
integrated basis in a utility holding company system with other assets and
operations. The facilities were operated in a different manner and under
different regulatory and market environments than those that currently exist or
that we expect to exist in the future. Accordingly, we do not believe that
historical financial information for our facilities is available for periods
before November 24, 1999 that would be meaningful or indicative of our future
results. As a result, this Management's Discussion and Analysis of Financial
Condition and Results of Operations reflects the operation of these facilities
since November 24, 1999, but excludes a discussion of, or comparison to prior
periods.
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Until the end of May 2002, we expect to sell a portion of our capacity
under transition power sales contracts entered into with affiliates of GPU, Inc.
at the time of the November 1999 acquisition. During the term of the transition
power sales contracts, we will derive revenues from sales of capacity under the
contracts, as well as sales into the PJM market of capacity and energy not
required to meet the terms of the contract, sales of ancillary services and
sales through bilateral contracts with power marketers and load serving entities
within the PJM market and the surrounding markets.
RESULTS OF OPERATIONS -- 1999 (FORMER REMA)
Results of operations of REMA, its subsidiaries and affiliated entities
that own, operate and develop electric generating facilities are discussed below
for the period from November 24, 1999 through December 31, 1999.
Revenues
Revenues for the period were $29.5 million. Revenues primarily consisted of
$16.5 million of energy revenue, $11.7 million of capacity revenue and $1.3
million of other revenue.
Operating Costs
Operating costs of $18.6 million consisted of expenses for fuel purchases
and facility operations and maintenance. Fuel expense of $10.8 million included
$10.4 million for coal and $0.4 million for fuel oil and natural gas. Plant
operations and maintenance expense was $7.8 million, which included labor and
benefits costs of $4.4 million, maintenance parts, supplies and services of $2.7
million and other expenses totaling $0.7 million.
Depreciation and Amortization
Depreciation and amortization expenses were $4.8 million. Depreciation
expense amounted to $4.1 million and primarily related to the November 1999
acquisition costs of the facilities, which are being depreciated over
approximately 30 years. Amortization expense amounted to $0.7 million and
related to amortization of goodwill and air emissions credits.
Administrative and General Expenses
General and administrative expenses were $3.2 million and included costs
for outside legal and other contract services, expenses related to office
administration, costs for employee benefits incurred, and project development
expenses of approximately $1.6 million.
Interest Expense
Interest expense, net was $12.6 million related to notes payable to
affiliated entities. The weighted average interest rate on these notes was
7.644%. The aggregate principal amount of the notes was approximately $1.6
billion as of December 31, 1999.
RESULTS OF OPERATIONS -- PERIOD FROM JANUARY 1, 2000 TO MAY 11, 2000 (FORMER
REMA)
Results of operations of REMA, its subsidiaries and affiliated entities
that own, operate and develop electric generating facilities are discussed below
for the period from January 1, 2000 to May 11, 2000.
Revenues
Revenues for the period were $166.5 million. Revenues primarily consisted
of $116.5 million of energy revenue, $40.7 million of capacity revenue and $9.3
million of other revenue.
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Operating Costs
Operating costs of $94.0 million consisted of expenses for fuel purchases
and facility operations and maintenance. Fuel expense of $53.6 million included
$47.4 million for coal and $6.2 million for fuel oil and natural gas. Facility
operations and maintenance expense was $40.4 million, which included labor and
benefits of $15.3 million, maintenance parts, supplies and services of $19.6
million and property taxes and other expenses totaling $5.5 million.
Depreciation and Amortization
Depreciation and amortization expenses aggregated $19.5 million.
Depreciation expense amounted to $15.4 million and primarily related to the
acquisition costs of the facilities. Amortization expense amounted to $4.1
million and related to amortization of goodwill and air emissions credits.
Administrative and General Expenses
General and administrative expenses were $13.1 million and included costs
for outside legal and other contract services, expenses related to office
administration, and costs for employee benefits incurred.
Interest Expense
Interest expense, net aggregated $46.5 million, related to the notes
payable to an affiliated entity. The weighted average interest rate on these
notes was 8.23%, and the weighted average principal amount of the notes was
approximately $1.6 billion during the period.
RESULTS OF OPERATIONS -- PERIOD FROM MAY 12, 2000 TO SEPTEMBER 30, 2000 (CURRENT
REMA)
Results of operations of REMA and its subsidiaries that own, lease and
operate electric generating facilities are discussed below for the period from
May 12, 2000 to September 30, 2000.
Revenues
Revenues for the period were $365.3 million. Revenues primarily consisted
of $292.7 million of energy revenue, $65.7 million of capacity revenue and $6.9
million of other revenue.
Operating Costs
Operating costs of $109.4 million consisted of expenses for fuel purchases
and facility operations and maintenance. Fuel expense of $70.0 million included
$53.2 million for coal and $16.8 million for fuel oil and natural gas. Facility
operations and maintenance expense was $39.4 million, which included labor and
benefits of $22.0 million, maintenance parts, supplies and services of $8.0
million, $6.2 million for facilities lease expense and property taxes and other
expenses totaling $3.2 million.
Depreciation and Amortization
Depreciation and amortization expenses aggregated $25.6 million.
Depreciation expense amounted to $21.7 million and primarily related to the
acquisition costs of the facilities. Amortization expense amounted to $3.9
million and related to amortization of goodwill and air emissions credits.
Administrative and General Expenses
General and administrative expenses were $12.1 million and included costs
for outside legal and other contract services, expenses related to office
administration, and costs for employee benefits incurred.
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Interest Expense
Interest expense, net aggregated $51.5 million, related to the notes
payable to an affiliated entity. The weighted average interest rate on these
notes was 9.4%, and the weighted average principal amount of the notes was
approximately $1.5 billion during the period.
Income Tax Expense
Income tax expense was $68.8 million for the period. REMA calculates its
income tax provision on a separate return basis under a tax sharing agreement
with Reliant Energy. Our current federal and state income taxes are payable to
or receivable from Reliant Energy. During the period, REMA's effective tax rate
of 41% was greater than the 35% federal statutory rate principally because of
state income taxes and nondeductible goodwill amortization.
LIQUIDITY AND CAPITAL RESOURCES
Our capital requirements consist primarily of
- expenditures to maintain the operation of our existing facilities,
including expenditures for repairs, replacement and refurbishment of
equipment and environmental compliance, and
- working capital related to the seasonal nature of our business
To maintain the availability of our generation facilities in the long term,
we intend to implement standard overhaul cycles for major equipment. We have
established a budget to maintain existing equipment and to replace or repair
equipment to sustain availability. In the budget, we have attempted to identify
major capital expenditures in advance. We believe that our budgeted amounts will
be sufficient to implement required capital expenditures through 2026, and the
independent engineer confirmed as of the date of its report that, in its
opinion, our budget is sufficient for this period. We have budgeted in excess of
$152.4 million for capital expenditures during the period 2000 through 2004,
primarily related to environmental compliance, and in excess of $444 million for
capital expenditures during the period 2000 through 2026, including over $441
million for environmental compliance. The environmental expenditures include the
installation of nitrogen oxides or NOx control technology at the Conemaugh,
Keystone, Shawville and Portland stations, intake screens at the Warren,
Sayreville and Titus stations, and the resolution of a consent order for water
discharge at the Conemaugh station. The financial projections provide for
capital expenditures to be funded from cash flow.
Our budget for capital expenditures could be considerably increased by
changes in environmental requirements. In addition, our capital expenditures
budget might increase if we determine to upgrade any of our facilities.
REMA has entered into a $30 million senior working capital facility with an
affiliate and a subordinated working capital facility with an affiliate in the
initial amount of $120 million. The subordinated facility is designed to provide
funds to REMA from time to time if our pro forma coverage ratio declines below
specified levels. Please read "Outstanding Indebtedness -- Subordinated Working
Capital Facility." The lease documents also permit us to incur additional
borrowings as described under "Description of the Exchange
Certificates -- Covenants -- Limitations on Incurrence of Indebtedness." We
expect that funds from our operations, borrowings under our working capital
facilities and other borrowings permitted by the lease documents from time to
time will be sufficient for our cash needs. Please read "Outstanding
Indebtedness -- Working Capital Note" and " -- Subordinated Working Capital
Facility" for more information on the senior working capital facility and the
subordinated working capital facility.
SEASONALITY OF OUR BUSINESS
Our revenues are seasonal and are affected by unusual weather conditions.
Short-term prices for capacity, energy and ancillary services in the PJM market
are particularly impacted by weather conditions.
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Peak demand for electricity typically occurs during the summer months, caused by
increased use of air-conditioning. Cooler than normal summer temperatures may
lead to reduced use of air-conditioners. This reduces short-term demand for
capacity, energy and ancillary services and may lead to a reduction in wholesale
prices.
YEAR 2000 COMPLIANCE AND STATUS
At November 24, 1999, the date we acquired our generating assets from GPU,
all significant year 2000 plans had been completed. We closely monitored the
year 2000 date change and experienced normal operations during that time.
As of the date of this prospectus, we are not aware of any material year
2000-related problems experienced by our information technology or
non-information technology systems. Also, we have not been informed by any of
our material customers, suppliers or our other key business partners that any
such parties experienced any material year 2000-related problems. It is
possible, however, that we or our key business partners will experience year
2000-related problems in the future. If such problems do occur, they might have
a material adverse effect on our results of operations, liquidity or business
prospects.
NEW ACCOUNTING ISSUES
Effective January 1, 2001, REMA is required to adopt Statement of Financial
Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended (SFAS No. 133), which establishes accounting and
reporting standards for derivative instruments, including some specified hedging
instruments embedded in other contracts and for hedging activities. This
statement requires that derivatives be recognized at fair value in the balance
sheet and that changes in fair value be recognized either currently in earnings
or deferred as a component of other comprehensive income, depending on the
intended use of the derivative, its resulting designation and its effectiveness.
In addition, in June 2000, the Financial Accounting Standards Board issued an
amendment that narrows the applicability of the pronouncement to some purchase
and sales contracts and allows hedge accounting for some other specific hedging
relationships. Adoption of SFAS No. 133 will result in no cumulative after-tax
change in net income and a cumulative after-tax increase to other comprehensive
income of approximately $2 million in the first quarter of 2001. The adoption
will also impact assets and liabilities recorded on the balance sheet.
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101), was
issued by the SEC on December 3, 1999. SAB No. 101 summarizes some of the SEC
staff's views in applying generally accepted accounting principles to revenue
recognition in financial statements. REMA's financial statements reflect the
accounting principles provided in SAB No. 101.
USE OF DERIVATIVES AND MARKET RISK
Our floating-rate obligation that previously existed under the demand notes
payable to an affiliated entity exposed us to the risk of increased interest
expense if short-term interest rates increased. However, following REPG's
acquisition of us in May 2000, the demand notes payable were amended to convert
the floating interest rate to a fixed rate. Please read "Outstanding
Indebtedness -- Notes to Affiliated Entities."
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REMA, REPG, RES, RERC AND RELIANT ENERGY
REMA
REMA is a Delaware limited liability company that owns or leases directly
all of its Pennsylvania generating facilities, including its leased interests in
the Conemaugh, Keystone and Shawville stations.
REMA has four wholly owned subsidiaries. Two of these, Reliant Energy New
Jersey Holdings, LLC and Reliant Energy Maryland Holdings, LLC, own our
facilities that are located in New Jersey and Maryland, respectively. Reliant
Energy Northeast Management Company, or Reliant Energy Management, serves as
operator of the Conemaugh and Keystone stations, for the co-owners of these
generating stations. Reliant Energy Mid-Atlantic Power Services, Inc. serves as
a common paymaster for our employees. All four subsidiaries have guaranteed
REMA's lease obligations.
REMA is a direct wholly owned subsidiary of Reliant Energy Northeast
Generation, Inc., which is a direct wholly owned subsidiary of Reliant Energy
Northeast Holdings, Inc. Reliant Energy Northeast Holdings, Inc. is a direct
wholly owned subsidiary of REPG, which is, in turn, a direct wholly owned
subsidiary of RRI. RRI is, in turn, a direct wholly owned subsidiary of Reliant
Energy.
The mailing address of our principal executive offices is 1111 Louisiana,
Houston, Texas 77002. Our telephone number at that address is (713) 207-3200.
REPG
REPG, our indirect parent, provides services to us in support of the
operation of our facilities. These services are provided on a full cost recovery
basis, and our payment obligations to REPG are subordinated to REMA's lease
obligations. REPG is a wholly owned subsidiary of RRI and is part of the Reliant
Energy Wholesale Group, or REWG. REWG includes the operations of REPG (other
than N.V. UNA) and the energy marketing and trading operations of RES. REPG
participates in independent non-utility power markets through the acquisition of
existing power plants and the development of new power plants. REPG's business
strategy is to develop a commercial generation portfolio in key regions to
support REWG's electric and natural gas trading and marketing operations. In
1999, REPG and its subsidiaries generated approximately 6.1 million MWH of
electricity.
REPG or its subsidiaries (other than REMA and its subsidiaries) own
- fifteen electric generating units at five sites (3,800 MW in the
aggregate) located in southern California
- fourteen electric generating units (3,476 MW in the aggregate) located in
the Netherlands (N.V. UNA)
- the 619 MW Indian River generating station located near Titusville,
Florida
- a 50% interest in the Sabine Cogeneration Project, a 100 MW gas-fired
cogeneration plant located in Orange, Texas
- a 50% interest in the El Dorado Project, a 490 MW gas-fired merchant
plant located near Boulder City, Nevada
- the Desert Basin Project, a 563 MW gas-fired merchant plant being
constructed near Casa Grande, Arizona
- the Shelby County Project, a 344 MW gas-fired merchant plant being
constructed near Shelbyville, Illinois with 255 MW operational as of
January 1, 2001
- the Channelview Project, a 779 MW gas-fired merchant plant being
constructed near Channelview, Texas, and
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- the Aurora Project, a 873 MW gas-fired peaking generating station being
constructed in Aurora, Illinois
In addition, REPG has entered into an agreement to acquire the 153 MW
Sunrise generating station located near Las Vegas, Nevada from Nevada Power
Company, together with Nevada Power's rights under a power purchase agreement
covering 222 MW of generation capacity from an adjacent facility. REPG has
advised us that it expects the acquisition to close in June 2001.
REPG has begun construction of an additional plant to be located in Osceola
County Florida with a capacity of approximately 460 MW.
RES
RES markets the capacity, energy and ancillary services from our generating
facilities, procures or arranges procurement of our fuel supplies (other than
for the Keystone and Conemaugh stations) and emissions credits. Our obligation
to pay fees to RES for these services is subordinated to REMA's lease
obligations. Please read "Description of Principal Transaction Documents -- Key
Contracts With Affiliated Entities -- Procurement and Marketing Agreement." RES
buys, sells and trades natural gas, electric power, crude oil and refined
products, and derivatives. In addition, it offers physical and financial
wholesale energy marketing products and services to a variety of customers.
These customers include natural gas distribution companies, electric utilities,
municipalities, cooperatives, power generators, marketers, aggregators and large
volume industrial customers. RES supplies or arranges supply of fuel to REPG's
generating plants and sells capacity, electric energy and ancillary services
from REPG's plants. RES's trading and marketing activities include, but are not
limited to:
- Natural Gas. RES purchases natural gas from a variety of suppliers under
daily, monthly, variable-load, base-load and term contracts that include
either market-sensitive or fixed-pricing provisions. It sells natural gas
under sales agreements that have varying terms and conditions, most of
which are intended to match seasonal and other changes in demand. RES's
natural gas marketing activities include contracting to buy natural gas
from suppliers at various points of receipt, aggregating natural gas
supplies and arranging for their transportation, negotiating the sale of
natural gas, and matching natural gas receipts and deliveries based on
volumes required by customers. In 1999, RES sold an average of 5.0
billion cubic feet of natural gas per day.
Additionally, RES, from time to time, arranges for the transportation of
the natural gas it markets. Transportation arrangements are made with
affiliated and nonaffiliated interstate and intrastate pipelines through
a variety of means, including short-term and long-term firm and
interruptible agreements.
RES also enters into various short-term and long-term firm and
interruptible agreements for natural gas storage to offer peak delivery
services to satisfy winter heating and summer electric generating
demands. These services are also intended to provide an additional level
of performance security and backup services to customers.
- Electric Power. RES sells electric power primarily to electric utilities,
municipalities and cooperatives and other marketing companies. RES sold
over 112 million MWH and 65 million MWH of electric power in 1999 and
1998, respectively. RES supplies natural gas to, and purchases
electricity for resale from, non-rate regulated power plants in
deregulated markets, including generating plants currently owned or to be
developed, acquired or operated by REPG or its subsidiaries.
- Crude Oil. RES also buys and sells crude oil and other hydrocarbon
products.
- Environmental Credits. RES buys and sells air emissions credits.
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RERC
Reliant Energy Resources Corp., or RERC, is a wholly owned subsidiary of
Reliant Energy. RERC conducts its operations primarily in the natural gas
industry through the following principal business segments:
- Natural Gas Distribution, which includes the gas utility operations of
its three natural gas distribution divisions and includes non-rate
regulated retail gas businesses. RERC forms the nation's third largest
natural gas distribution operation in terms of customers served.
- Pipelines and Gathering, which provides interstate gas transportation and
related services through over 8,200 miles of transmission lines and six
natural gas storage facilities located across the south-central United
States and includes natural gas gathering operations.
RELIANT ENERGY
Reliant Energy is a diversified international energy services company that
provides energy and energy services in North America and Western Europe through
the following principal business segments:
- Electric Operations, which includes Reliant Energy HL&P, Reliant Energy's
regulated electric utility division, but excludes the non-utility
ownership and operation of electric generating facilities. Reliant Energy
HL&P provides electricity to approximately 1.7 million customers in a
5,000-square-mile area on the Texas Gulf Coast, which includes the City
of Houston, and represents one of the nation's largest electric utilities
in terms of MWH sales.
- Wholesale Energy, known as REWG, which includes the operations of REPG
other than N.V. UNA. REPG owns and operates electric generating
facilities such as ours. REWG also includes the energy marketing and
trading operations of RES.
- Reliant Energy Europe, which includes N.V. UNA, a Dutch power generation
company effectively acquired by REPG during 1999, and includes the
European energy marketing and trading operations. UNA is one of the
Netherlands' four largest generating companies.
- Natural Gas Distribution, which includes the gas utility operations of
RERC. Currently operated through three separate natural gas distribution
divisions, this gas distribution company forms the nation's third largest
natural gas distribution operations in terms of customers served, and
includes the non-rate regulated retail gas businesses.
- Pipelines and Gathering, which provides interstate gas transportation and
related services through over 8,200 miles of transmission lines and six
natural gas storage facilities located across the south-central United
States, and includes natural gas gathering operations.
As of September 30, 2000, Reliant Energy had total assets of $28.6 billion
and total shareholders' equity of $5.8 billion. Reliant Energy's consolidated
revenues aggregated $15.3 billion for 1999 and $19.5 billion for the nine months
ended September 30, 2000. Please visit the SEC's Web site at http://www.sec.gov
for more information about Reliant Energy.
Recent Developments
In December 2000, the Texas Public Utility Commission approved Reliant
Energy's amended business separation plan under which Reliant Energy would
divide into two publicly traded companies to separate its unregulated businesses
from its regulated businesses. RRI, which will be the parent company of the
unregulated businesses, is in the process of offering up to 20% of its common
stock in an initial public offering. Within twelve months of the completion of
that offering, Reliant Energy intends to distribute RRI's remaining stock to its
shareholders. Until Reliant Energy completes the distribution of RRI's common
stock, RRI will continue to be a subsidiary of Reliant Energy. We cannot assure
that the initial public offering and the distribution will be completed.
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RRI currently owns Reliant Energy's:
- domestic unregulated power generation and energy trading and marketing
operations, which are conducted through REPG and RES, respectively
- European power generation and energy trading and marketing operations,
and
- unregulated retail electric operations, communications business,
eBusiness group and venture capital operations
The business separation plan contemplates that RRI will not initially own
Reliant Energy's regulated company's Texas electric generating assets but will
have an option to acquire an 80% interest in a company that will own those
assets in 2004.
Under the business separation plan, Reliant Energy would restructure its
regulated operations into a holding company structure in which a new corporate
entity would be formed as the parent with Reliant Energy and its regulated
businesses as subsidiaries. The regulated company is expected to own Reliant
Energy's
- electric transmission and distribution operations, its natural gas
distribution businesses and, initially, its regulated electric generating
assets in Texas, and
- U.S. interstate pipelines and gas gathering operations
The initial public offering and ultimate distribution of the stock of RRI
are subject to the development of definitive separation terms, further corporate
approvals, market and other conditions, and government actions, including
receipt of a favorable Internal Revenue Service ruling that the distribution of
stock would be tax-free to Reliant Energy and its shareholders for U.S. federal
income tax purposes, as applicable. Aspects of the restructuring of Reliant
Energy's regulated businesses would be subject to the approval of Reliant
Energy's shareholders and approvals from the SEC under the Public Utility
Holding Company Act and from the Nuclear Regulatory Commission. The initial
public offering of RRI, the full separation of Reliant Energy's unregulated and
regulated businesses and the ultimate restructuring of Reliant Energy's
regulated businesses may not be completed as described or within the time
periods outlined above.
We expect that, after giving effect to the business separation plan
described above, REMA will continue to be an indirect wholly owned subsidiary of
REPG, which is a subsidiary of RRI.
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OUR BUSINESS
INDUSTRY OVERVIEW
The United States electric power industry includes investor-owned,
cooperative, municipal, state and federal utilities, as well as nonutility power
generating companies. Historically, electricity was generated, distributed and
sold by regulated, vertically integrated utilities with exclusive franchises to
provide electric services to retail customers, usually within a given state, in
contiguous areas outside the state, or both. This industry structure, however,
is being fundamentally transformed as a result of federal and state legislative
and regulatory changes. Over the last several years, many vertically integrated
utilities have restructured, including divesting their generation assets and
transferring control over their transmission system to regional transmission
operators. This restructuring is being undertaken in some cases to comply with
state laws opening retail markets to competition and in other cases to adapt to
increased wholesale competition from new merchant generators. The increasingly
competitive environment is also resulting in significant industry consolidation
and the growth of national and regional wholesale power generation companies.
Current trends indicate the emergence of a relatively small number of generating
companies with national power marketing operations backed by generation assets
in key geographic regions.
Among the key regulatory changes that have prompted industry change was the
issuance by the Federal Energy Regulatory Commission, or FERC, of Order No. 888.
This order, issued in April 1996, required transmission-owning public utilities
to offer "open-access" transmission service on a comparable, nondiscriminatory
basis. This means that such companies must offer transmission service to other
utilities or electricity providers, including merchant plants and power
marketers, at the same price and on the same terms as the utilities provide
themselves for their own transactions. On December 20, 1999, the FERC followed
up Order No. 888 with the issuance of Order No. 2000, which is designed to spur
all public utilities into transferring control over their transmission systems
either to regional transmission organizations or to independent transmission
companies. Order No. 2000 provides a further impetus to the formation of large
regional entities that will control multiple transmission systems across large
geographic regions, such as have already been established in California, New
England, the PJM control area, New York, the Electric Reliability Council of
Texas, and are in development in parts of the Midwest. Where established, an ISO
controls the transmission system and is responsible for scheduling transmission
transactions and for the planning and reliability of the bulk transmission
system under its control. These ISOs also administer some types of power and
energy markets, including those for ancillary services necessary to maintain
reliability.
THE PJM MARKET AND PJM ISO
All of our facilities are located within the PJM control area. According to
the PJM Web site (www.pjm.com), the PJM control area is currently the largest
centrally dispatched electric control area in North America and the third
largest in the world. The PJM control area includes over 540 generating units
with pooled generating capacity of over 56,000 MW. The PJM control area
represents 8.7% of the United States population and encompasses New Jersey,
Maryland, Delaware, most of Pennsylvania, a small portion of Virginia and the
District of Columbia.
By 1998, the PJM market had been restructured as a competitive,
nondiscriminatory market in response to the FERC's open-access rules. A
combination of coal, oil and gas-fired units sets the market-clearing price in
the PJM market. The PJM ISO operates the spot energy market and determines the
market-clearing price for each hour based on bids submitted by participating
generators. These generators indicate the minimum prices they are willing to
accept to dispatch power at various incremental generation levels. A
transmission charge based on the location of the energy purchaser is added to
the energy price if the transmission system becomes constrained. The PJM ISO
also administers a day-ahead installed capacity market and a monthly installed
capacity market for each and any of the 12 months following the month in which
the market is conducted. Each installed capacity market has a single
market-clearing price for each day during which the market is in operation.
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We expect the PJM market to continue to evolve in the future. This
evolution may include further deregulation of utility operations, changing rules
and regulations and changing market participants.
KEY INDUSTRY CONCEPTS
Power generation facilities can generally be categorized by their variable
cost to produce electricity, which determines the order in which they are
utilized to meet fluctuations in electricity demand. Base-load facilities are
those that typically have low variable costs and provide power at all times.
Base-load facilities are used to satisfy the base level of demand for power, or
load, that is not dependent upon time of day or weather. Peaking facilities have
the highest variable cost to generate electricity and typically are used only
during periods of highest demand for power. Intermediate facilities have cost
and usage characteristics in between those of base-load and peaking facilities.
The various tiers of base-load, intermediate and peaking facilities serving a
particular region are often referred to as the supply curve or dispatch curve
for that region. Power generation facilities can also be categorized as
cogeneration facilities. Cogeneration is the combined production of steam and
electricity in a generation facility. Cogeneration facilities typically operate
at higher thermal efficiency than other forms of fossil-fuel-fired generation
facilities.
The U.S. electricity transmission infrastructure is divided into eleven
geographic areas commonly referred to as reliability councils. In general, power
moves reasonably freely within any given reliability council. However, physical
and regulatory constraints frequently limit transfers between reliability
councils and occasionally limit transfers within reliability councils. As a
result, each reliability council, or portion of a reliability council, generally
constitutes a separate market for power. The average amount by which power
generating capacity exceeds peak demand in a given reliability council is
commonly referred to as the reserve margin for that reliability council.
Power transmission facilities in some of these reliability councils are
controlled by regional transmission organizations. A regional transmission
organization, or RTO, is an organization approved by the FERC to control the
bulk power transmission facilities in a specific region and to assure reliable
transmission operations and nondiscriminatory access to the transmission grid.
The two principal RTO models are the not-for-profit independent system operator,
or ISO, and the for-profit independent transmission company, or transco. To meet
the FERC's RTO criteria, both types of organizations must be independent from
market participants and must assume responsibility for regional transmission
planning, managing transmission congestion and providing the ancillary services
needed for transmission operations.
OUR PLAN AND STRATEGY
Our indirect parent, REPG, intends to capitalize, directly or indirectly
through affiliated entities, on deregulated and deregulating energy markets by
- establishing a significant market presence in key geographic areas,
including the mid-Atlantic region and PJM control area, and
- providing in those areas a variety of energy commodities and services,
including
- electric power generation capacity, energy and ancillary services
- wholesale energy trading and marketing, and
- retail energy marketing
We complement REPG's strategy through our presence in the PJM market and by
providing in that market electric power generation capacity, energy and
ancillary services. Our strategy is to combine our facilities and operational
expertise with the marketing and other commercial expertise of our affiliates to
- maintain the competitive position of our low-cost, base-load, coal-fired
facilities
- optimize maintenance schedules of our facilities to maximize their
availability to supply capacity, energy and ancillary services during
periods of peak demand and high prices
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- use peaking and intermediate units to supply capacity, energy and
ancillary services during periods of peak demand and high prices
- maintain an appropriate mix of both spot market sales and term sales
under bilateral contracts, and
- manage fuel procurement strategies, including seeking efficiencies in
fuel purchasing, fuel switching and hedging
COMPETITIVE STRENGTHS
We believe that we have a number of competitive strengths.
- We have contracted with our affiliate RES to obtain power marketing and
fuel procurement services for most of our facilities. We believe these
services will improve our financial performance. Transactions that
obligate us to deliver capacity, energy or ancillary services will be
backed by our ability to deliver such products from our facilities.
- Our facilities should allow us to remain competitive in the PJM market
since they include low-cost, base-load coal-fired facilities that operate
at low marginal costs relative to other thermal facilities. In
particular, the coal-fired units at the Keystone, Conemaugh and Shawville
stations are among the first thermal units in the dispatch merit order
within the PJM market.
- Our coal-fired facilities are located near supplies of coal, helping to
reduce our fuel transportation costs.
- Our facilities can supply different types of energy-related products and
services to the PJM market, including energy, capacity and ancillary
services, can use different fuel sources and include base-load, peaking
and intermediate generation.
- Our peaking facilities are located near load centers and can provide
capacity, energy and ancillary services to such load centers when prices
are high.
- We employ personnel who have significant operating experience with our
generating facilities.
- Through transition power purchase agreements, we will sell a portion of
the capacity from our facilities at fixed prices through May 2002.
- Our generating facilities have access to multiple markets in and around
the mid-Atlantic region.
Power Marketing and Fuel Procurement Agreement with RES
We have contracted with RES to manage our fuel purchasing and to market the
output from our facilities. Transactions that obligate us to deliver capacity,
energy or ancillary services will be backed by our ability to deliver such
products. All revenues from sales of capacity, energy and ancillary services,
net of transmission costs and power marketing fees, will flow to us. We do not
intend to enter into speculative transactions for capacity, energy or ancillary
services.
Under our agreement with RES, we expect that RES will be able to use its
trading and marketing expertise and experience, including its experience in the
wholesale market in the PJM control area, to maximize our net operating revenues
from sales of energy, capacity and ancillary services from our facilities. We
believe that the diversity of our facilities, which includes a significant
amount of peaking as well as base-load capacity, combined with RES's marketing
expertise, will provide for a more stable cash flow pattern than less
diversified trading portfolios or isolated assets. We expect these transactions
to occur both in the spot market, as dictated by the PJM ISO's bidding and merit
order dispatch system, and in bilateral contracts with wholesale buyers.
We believe that the scale of our facilities and the commercialization that
we achieve through our contractual arrangement with RES will bring advantages at
a time when the deregulated PJM market is still developing. Because of the
significant operational and management experience of REWG in
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deregulated and deregulating markets, including California and Texas, we believe
RES can help us to maximize our net operating revenues.
Market Presence and Strategic Location
Our facilities currently comprise 4,262 MW, or approximately 7%, of the
generating capacity in the PJM control area, which has pooled generating
capacity of over 56,000 MW.
Our generating facilities are located within the PJM control area, a
rapidly deregulating region. According to the PJM Web site (www.pjm.com), the
PJM control area is the largest centrally dispatched electric control area in
North America. The PJM market is well established and among the most developed
domestic markets as a result of its fully functioning ISO. The PJM ISO
facilitates market liquidity for power generators. The PJM ISO also provides
access to surrounding regional systems that are also rapidly deregulating,
including the East Central Area Reliability Council, the New York Power Pool and
the Virginia-Carolina region of the Southeastern Electric Reliability Council.
Low-Cost Producer
We believe that to compete successfully in the PJM market and other
deregulated electric power markets, power generators must achieve and maintain
low-cost, highly reliable and flexible production. Our facilities include
low-cost, base-load, coal-fired units that are located near sources of fuel
supply, which helps control fuel transportation costs and minimizes risks of
disruption. We also believe that opportunities may exist to operate our
facilities even more efficiently than they have been operated in the past. For
example, we believe that reductions in costs may be achieved through economies
of scale in purchasing, inventory management and maintenance support.
Priority Dispatch of Baseload Facilities
The PJM ISO manages the spot energy market in the PJM control area and
determines the market-clearing price for energy based on bids submitted by
participating generators. A bid to supply generation consists of an incremental
energy bid curve composed of start up costs, no load costs and operating costs
and represents the minimum price a bidder will accept to dispatch power at a
particular generation level. Based on historical information published by the
PJM ISO, our base-load coal-fired units have dispatch costs that are among the
lowest for thermal units in the PJM market. Please read the report of our
independent market consultant attached as Appendix B to this prospectus.
Dispatch and Fuel Diversity and Flexibility
We believe that the diversification of our facilities in terms of fuel (49%
coal, 50% gas/oil and 1% hydro, based on average net capacity), technology,
location and ability to service load through base, intermediate and peaking
generating capacity makes our facilities more able to respond to a variety of
market conditions. Of the total net MW capacity of our facilities, we estimate
that our base-load capability represents approximately 40%, while intermediate
peaking and full peaking units capacity represent approximately 29% and
approximately 31%, respectively, of our capacity. A majority of our peaking
units are located near load centers, providing ready access to markets. We
believe that this dispatch and fuel diversity and flexibility, together with the
marketing services we will obtain from our power marketing affiliate RES, will
provide a more stable cash flow pattern over time and allow us to use our
peaking units to obtain higher prices during periods of peak demand.
Diversification among fuels used by our individual units permits us to change
units and, in some cases, fuel sources if one fuel becomes relatively more
expensive than another that can be used. The range of plant types allows us to
optimize delivery of power.
We also intend to coordinate maintenance schedules for our facilities so
that they are available to supply capacity, energy and ancillary services during
periods of peak demand.
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OUR GENERATING FACILITIES
REMA owns a 100% ownership interest in each of its electric generating
stations except for the Conemaugh, Keystone and Shawville stations, which REMA
leases from owner lessors. In the case of the Keystone station and the Conemaugh
station, the owner lessor owns and REMA leases undivided ownership interests of
16.67% and 16.45%, respectively. For more detailed information regarding our
facilities, please read the independent engineer's report attached as Appendix A
to this prospectus.
OUR GENERATING FACILITIES
The table below lists and describes briefly our electric power generating
facilities.
DISPATCH PRIMARY
FACILITY/LOCATION CAPACITY(1) TYPE FUEL TYPE
- ----------------- ----------- ------------- ---------------------
FACILITIES LEASED UNDER
THE LEASE TRANSACTIONS
CONEMAUGH/New Florence, PA.......... 281(2) Base-load Coal
KEYSTONE/Shelocta, PA............... 285(3) Base-load Coal
SHAWVILLE/Shawville, PA............. 613 Base-load Coal
FACILITIES WE OWN
GILBERT/Holland Township, NJ........ 614 Intermediate/ Natural gas/Oil
Peaking
GLEN GARDNER/Lebanon Township, NJ... 184 Peaking Natural gas/Oil
PORTLAND/Portland, PA............... 585 Base-load/ Coal/Oil
Intermediate/
Peaking
SAYREVILLE/Sayreville, NJ........... 449 Peaking Natural gas/Oil
SEWARD/Seward, PA(4)................ 196 Base-load/ Coal
Intermediate
TITUS/Reading, PA................... 281 Intermediate/ Coal/Oil
Peaking
WARREN/Warren, PA................... 150 Intermediate/ Coal/Oil/Natural gas
Peaking
WERNER/South Amboy, NJ.............. 252 Peaking Oil
OTHER FACILITIES(5)................. 372 Peaking Oil/Natural gas/Hydro
-----
TOTAL............................... 4,262
- ---------------
(1) Annual average net capacity in MW.
(2) An owner lessor owns and REMA leases a 16.45% undivided interest in the
Conemaugh station, which has total capacity of 1,711 MW.
(3) An owner lessor owns and REMA leases a 16.67% undivided interest in the
Keystone station, which has total capacity of 1,711 MW.
(4)We currently expect to sell our Seward station to an affiliate. The sales
transaction will be made under terms permitted by the lease documents. See
"-- Our Other Facilities -- "Seward Station" below.
(5) Other facilities include an aggregate of ten facilities, nine located in
Pennsylvania (Blossburg; Hamilton; Hunterstown; Mountain; Orrtanna; Piney;
Shawnee; Tolna; and Wayne) and one located in Maryland (Deep Creek).
The Leased Facilities
Conemaugh Station. The Conemaugh station is located near New Florence,
Pennsylvania on a 2,539-acre site along the Conemaugh River. The Conemaugh
station operates as a base-load plant that consists
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of two coal-fired steam turbine generator units with an average net station
capacity of 1,711 MW, as well as two 1.25 MW diesel generators and four 2.75 MW
emergency diesel generators. REMA's interest equals 281 MW. The two 850 MW net
steam turbine units were commissioned in 1970 and 1971, respectively. The
Conemaugh station also includes two cooling towers to provide primary plant
cooling.
The Conemaugh station is well positioned within the PJM control area. Its
base-load, coal-fired capacity at the western terminus of the PJM control area
provides the opportunity to sell energy to other systems outside of the PJM
control area. The Conemaugh station's location on the main line of the Norfolk
Southern Railroad facilitates current and future deliveries of coal and other
supplies. Both natural gas and coal are readily available to the site.
There are eight other co-owners of undivided interests in the Conemaugh
station.
Keystone Station. The Keystone station is located in Plumcreek Township,
Armstrong County, Pennsylvania on a 1,459-acre site that also includes a
3,346-acre reservoir located near the site. The Keystone station operates as a
base-load plant that consists of two 850 MW coal-fired units and four 2.75 MW
emergency diesel generators. REMA's interest equals 285 MW. The coal-fired units
began commercial operation in 1967 and 1968, respectively. The Keystone station
also includes four cooling towers to provide primary plant cooling.
Like the Conemaugh station, the Keystone station is well positioned within
the PJM control area, with a base-load, coal-fired capacity at the western
terminus of the PJM control area that provides the opportunity to sell energy to
other systems outside of the PJM control area. The Keystone station provides
electrical interconnection to markets to the north, south and west of the PJM
control area. Both natural gas and coal are readily available to the site. In
addition, the Keystone dam and lake can provide adequate water for cooling and
process needs.
There are six other co-owners of undivided interests in the Keystone
station.
Shawville Station. The Shawville station is located in Bradford Township,
Clearfield County, Pennsylvania on a 947-acre site along the Susquehanna River.
The Shawville station operates as a base-load plant that consists of four
coal-fired steam turbine generator units and three diesel generators, for an
average capacity of 613 MW. The Susquehanna River provides process water to the
plant.
The Shawville station consists of two sets of sister units. Units 1 and 2
were installed in 1954 and 1955 with average capacities of 125 MW and 128 MW,
respectively. Units 3 and 4 were installed in 1960, each with an average
capacity of 177 MW. Shawville also operates three diesel generators, Units 5, 6
and 7, that are rated at 2 MW each.
Our Other Facilities
Blossburg Station. The Blossburg station is located in Blossburg,
Pennsylvania on a 2.85-acre site. The Blossburg station operates as a natural
gas-fired peaking plant with one simple cycle combustion turbine that has an
average capacity of 25 MW. The Blossburg station is unmanned and is remotely
operated from the Portland station.
Deep Creek Station. The Deep Creek station is located on Deep Creek Lake in
Garrett County, Maryland on a 467-acre site and operates as a peaking plant that
contains a dam and reservoir, a water conduit system and a powerhouse. The
powerhouse includes two hydro turbine generators with an average total capacity
of 18 MW.
Gilbert Station. The Gilbert station is located in Holland Township,
Hunterdon County, New Jersey on a 232-acre site adjacent to the Delaware River.
The Gilbert station operates as a natural gas/oil-fired intermediate/peaking
plant that consists of one combined cycle steam turbine, four combined cycle
combustion turbines and five simple cycle combustion turbines, for an average
total capacity of 614 MW.
Glen Gardner Station. The Glen Gardner station is located in Glen Gardner,
Lebanon Township, Hunterdon County, New Jersey on a five-acre site. The Glen
Gardner station operates as a natural gas/oil-
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fired peaking plant that contains eight simple cycle combustion turbines with an
average total capacity of 184 MW. The site is equipped for remote operation from
the Gilbert station control room.
Hamilton Station. The Hamilton station is located in Hamilton Township,
southwest of Harrisburg, Pennsylvania, on a 40-acre site. Its oil-fired single
combustion turbine unit has an average capacity of 23 MW and operates primarily
for peaking service. The Hamilton station is an unmanned site that is remotely
dispatched from Reading, Pennsylvania and maintained by the mobile maintenance
crew based at the Hunterstown station.
Hunterstown Station. The Hunterstown station is located in Straban,
Pennsylvania on a 257-acre site. The Hunterstown station operates as a natural
gas/oil-fired peaking plant that includes three combustion turbines with an
average total capacity of 71 MW. The Hunterstown station is unmanned and is
operated from our operational headquarters located at Johnstown, Pennsylvania.
The mobile maintenance crew based at Hunterstown maintains the site.
Mountain Station. The Mountain station is located in Middleton,
Pennsylvania on an 88-acre site. The Mountain station operates as a natural
gas/oil-fired peaking plant that includes two combustion turbines with an
average total capacity of 47 MW. The Mountain station is unmanned and is
operated from our operational headquarters located at Johnstown, Pennsylvania.
The mobile maintenance crew based at Hunterstown maintains the site.
Orrtanna Station. The Orrtanna station is located in Highland Township,
southwest of Harrisburg, Pennsylvania, on a 10-acre site. The site operates one
combustion turbine with an average capacity of 23 MW. The Orrtanna station
operates as an oil-fired peak-load station. The Orrtanna station is unmanned and
is operated from our operational headquarters located at Johnstown,
Pennsylvania. The mobile maintenance crew based at Hunterstown maintains the
site.
Piney Station. The Piney hydroelectric station is a hydro peaking plant
located in Piney Township, Pennsylvania on the Clarion River and includes a
watershed area of 939 acres. The powerhouse includes three hydro turbine
generators with an average total capacity of 29 MW.
Portland Station. The Portland station is located in Portland, Pennsylvania
on a 190-acre site along the Delaware River. The Portland station operates as a
coal-fired base-load/intermediate/peaking plant that consists of two steam
turbine generators and three combustion turbines with an average total capacity
of 585 MW.
Sayreville Station. The Sayreville station is located in Sayreville,
Middlesex County, New Jersey on a 67-acre site on the bank of the Raritan River.
The Sayreville station operates as a natural gas/oil-fired peaking/intermediate
plant that consists of two steam turbine generator units and four simple cycle
combustion turbines for an average total capacity of 449 MW.
Seward Station. The Seward station is located in Seward, Pennsylvania on a
298-acre site adjacent to the Conemaugh River. The Seward station operates as a
coal-fired base-load/intermediate plant that has two operating steam turbine
generator units with an average total capacity of 196 MW. The Seward station
also includes a 158-acre parcel of land within one-half mile of the station.
We currently expect to sell our Seward station to an affiliate. The terms
of the sale will comply with the provisions of the lease documents. We cannot
assure you that such a sale will take place, or if it does, when it will take
place. Following any such sale, we expect the affiliate to undertake and fund a
significant upgrade of the station.
Shawnee Station. The Shawnee station is located in Shawnee, Pennsylvania on
an 83-acre site. The Shawnee station operates as an oil-fired peaking plant that
consists of one combustion turbine with an average capacity of 23 MW. The
Shawnee station is unmanned and is operated and maintained from the Portland
station.
Titus Station. The Titus station is located in Reading, Pennsylvania on a
33-acre site with 244 acres of adjoining property on the Schuylkill River. The
Titus station operates as a coal-fired base-load/peaking
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plant that consists of three coal-fired steam turbine generator units and two
simple cycle combustion turbines for an average total capacity of 281 MW.
Tolna Station. The Tolna station is located in Hopewell Township, south of
Harrisburg, Pennsylvania, on a 136-acre site. The Tolna station operates as an
oil-fired peaking plant that consists of two simple cycle combustion turbines
with an average total capacity of 47 MW. The Tolna station is unmanned and is
remotely operated from our operational headquarters located at Johnstown,
Pennsylvania. The mobile maintenance crew based at Hunterstown maintains the
site.
Warren Station. The Warren station is located one mile west of Warren,
Pennsylvania on a 103-acre site that also includes a 67-acre plot three miles
from the station. The Warren station operates as a coal/ natural gas/oil-fired
intermediate/peaking plant that consists of two steam turbine generators and a
dual-fuel combustion turbine for an average total capacity of 150 MW.
Wayne Station. The Wayne station is located in Wayne Township, Pennsylvania
on a 159-acre site. The Wayne station operates as an oil-fired peaking plant
that consists of one simple cycle combustion turbine with an average capacity of
66 MW. The Wayne station is unmanned and is remotely operated from our
operational headquarters located at Johnstown, Pennsylvania.
Werner Station. The Werner station is located in South Amboy, Middlesex
County, New Jersey on a 28-acre site on the south bank of the Raritan River. The
Werner station operates as an oil-fired peaking plant that consists of four
simple cycle combustion turbines with an average total capacity of 252 MW. The
Sayreville station control room controls the Werner station remotely.
COMPETITION
We compete in the PJM market on the basis of price, operating
characteristics of our generating facilities and the availability of our
facilities to supply capacity, energy and ancillary services to the market when
needed. We compete in the PJM market primarily with six other major power
generators. A number of additional generation facilities are being developed in
the PJM control area, and these facilities will increase competition in the PJM
market over time. Additional facilities are also being planned for the PJM
control area and could be developed in the future.
EMPLOYEES
As of October 1, 2000, we had 1,078 employees. Of that number, 940 were
involved in operating and maintaining our generating facilities. Substantially
all of the operating employees were involved in the operation of our facilities
before they were acquired by Sithe Energies from affiliates of GPU, Inc.
Furthermore, 385 employees were involved in the operation and support of the
Keystone and Conemaugh stations. All of the facilities are staffed by a
combination of union and nonunion employees. All union employees are covered by
current labor agreements with the relevant unions, and those agreements have
varying expiration dates ranging from April 30, 2001 to May 14, 2002. To date,
we have not experienced any grievances that we expect to result in a material
adverse effect on us.
LEGAL PROCEEDINGS
REMA and its subsidiaries are parties to various legal proceedings that
arise from time to time in the ordinary course of business. While we cannot
predict the outcome of these proceedings, we do not expect these matters to have
a material adverse effect on our financial position, operations or cash flows.
Please read "Regulation -- Environmental Regulatory Matters" for a description
of various environmental matters and proceedings that affect us.
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REGULATION
ENERGY REGULATORY MATTERS
Federal Energy Regulation
Federal Power Act. Under the Federal Power Act, the Federal Energy
Regulatory Commission, or FERC, has the exclusive rate-making jurisdiction over
wholesale sales of electricity and the transmission of electricity in interstate
commerce by "public utilities." Public utilities that are subject to the FERC's
jurisdiction must file rates with the FERC applicable to their wholesale sales
or transmission of electricity. REMA and its subsidiaries that own generating
facilities, Reliant Energy New Jersey Holdings, LLC and Reliant Energy Maryland
Holdings, LLC, sell power at wholesale and are public utilities under the
Federal Power Act. In July 1999 and August 1999, the FERC accepted for filing
rate schedules for the sale of energy and capacity at wholesale at market-based
rates filed by the predecessors of REMA and those two subsidiaries. The FERC
also granted the predecessor companies waivers of many of the accounting,
recordkeeping and reporting requirements that are imposed on public utilities
with cost-based rate schedules. In October 1999, the FERC accepted for filing
rate schedules for the sale of some ancillary services at market-based rates
filed by such companies. On March 1, 2000, predecessors of REMA and its two
subsidiaries that own generating facilities jointly filed with the FERC a
notification of the planned acquisition by REPG and the resulting affiliation
with Reliant Energy, as well as revised rate schedules reflecting such changes.
The FERC accepted the revised rate schedules for filing on April 3, 2000,
effective March 2, 2000.
The FERC's orders accepting the market-based rate schedules, as is
customary with market-based rate schedules, reserved the right to revoke our
market-based rate authority if the FERC subsequently determines that REMA or any
of its affiliates possess excessive market power. If the FERC were to revoke our
market-based rate authority, we would have to file, and obtain the FERC's
acceptance of, cost-based rate schedules. In addition, the loss of market-based
rate authority would subject us to the accounting, recordkeeping and reporting
requirements that the FERC imposes on public utilities with cost-based rate
schedules.
Public Utility Holding Company Act. The Public Utility Holding Company Act
of 1935, or PUHCA, subjects to regulation as a registered holding company any
corporation, partnership or other entity or organized group that owns, controls
or has power to vote 10% or more of the outstanding voting securities of a
"public utility company" or a company that is a "holding company" of a public
utility company, unless an exemption is established or an order is issued by the
SEC declaring such company not to be a holding company. Registered holding
companies under PUHCA are generally required to limit their operations to a
single integrated utility system and to other operations functionally related to
the operation of the utility system. In addition, under PUHCA, a public utility
company that is a subsidiary of a registered holding company must comply with
various financial and organizational regulations, including approval by the SEC
of many of its financing transactions. 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 and selling electric energy at wholesale may be exempted from PUHCA
regulation as an "exempt wholesale generator," or EWG. Sithe Pennsylvania
Holdings, LLC, Sithe Maryland Holdings, LLC and Sithe New Jersey Holdings, LLC,
the predecessors of REMA, Reliant Energy Maryland Holdings, LLC and Reliant
Energy New Jersey Holdings, LLC, received from the FERC determinations of EWG
status in 1999. Following both the restructuring by which Reliant Energy
Maryland Holdings, LLC and Reliant Energy New Jersey Holdings, LLC became
subsidiaries of REMA and the lease transaction, FERC reaffirmed the continued
EWG status of REMA and its subsidiaries in an order issued in October 2000.
If, after having received this determination, there is a "material change"
in facts that might affect our continued eligibility for EWG status, within 60
days of this material change we must
- file with the FERC a written explanation of why the material change does
not affect our EWG status
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- file with the FERC a new application for EWG status, or
- notify the FERC that we no longer wish to maintain EWG status
On January 22, 2001, REMA and some of the other companies that hold or
lease individual interests in the Keystone station and in the Conemaugh station
and that are also EWGs filed with FERC separate applications for a
redetermination of their status as EWGs in connection with a transaction related
to a new fuel supply for the Keystone station and other lease and real property
activities related to the plant sites. The interest owners in the Keystone
station have agreed to lease to SynFuel Co. land and the use of some facilities
and to provide SynFuel Co. coal, which SynFuel Co. will then convert to
synthetic fuel for use at the Keystone station. Because REMA's participation in
these fuel arrangements and in other leasing activities relating to mineral
rights and agricultural and recreational uses of the property sites are
incidental to its primary business of selling electricity at wholesale, we
believe that these arrangements should be consistent with REMA's continued EWG
status.
If we lost our EWG status, we would have to restructure our organization
or, with Reliant Energy and its other subsidiaries, risk being subjected to
regulation under PUHCA.
State Regulation
In Pennsylvania, our generation facilities are not subject to rate
regulation by the Pennsylvania Public Utility Commission because, under the
Pennsylvania Electricity Generation Customer Choice and Competition Act, the
generation of electricity is no longer regulated as a utility function. Under
this statutory scheme, affiliates of GPU transferred their generation facilities
located in Pennsylvania to Sithe Energies and its affiliates through a
transaction approved by the Pennsylvania Public Utility Commission in June 1999.
Similarly, our New Jersey generation facilities are not subject to rate
regulation by the New Jersey Board of Public Utilities because, under the New
Jersey Electric Discount and Energy Competition Act, New Jersey has determined
that electric generation service in New Jersey is a competitive service that is
no longer subject to regulation. As in Pennsylvania, our New Jersey generation
facilities became unregulated when they were transferred by GPU affiliates to
Sithe Energies and its affiliates in a transaction approved by the New Jersey
Board, and the facilities continue to be unregulated. Under the New Jersey act,
however, the Board may re-regulate the provision of electric generation service
in the event the Board concludes that sufficient competition is no longer
present.
Lease Transactions Filings and Approvals
In connection with the lease transactions, we and the appropriate financial
participants in the lease transactions have obtained assurances and necessary
approvals from the FERC. These include
- the owner lessors obtaining EWG status
- confirmation that the owner lessors, the owner participant(s) and the
lenders are not public utilities under Part II or III of the Federal
Power Act
- approval by the FERC of the corporate reorganization by which REMA's
subsidiaries holding generating facilities in Maryland and New Jersey
became subsidiaries of REMA, and
- approval of the sale of FERC-jurisdictional facilities by REMA to, and
their leaseback from, the owner lessors
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ENVIRONMENTAL
General Environmental Issues
We are subject to a number of federal, state and local requirements
relating to:
- the protection of the environment, and
- the safety and health of personnel and the public.
These requirements relate to a broad range of our activities, including:
- the discharge of pollutants into the air and water,
- the identification, generation, storage, handling, transportation,
disposal, record keeping, labeling, reporting of, and emergency response
in connection with hazardous and toxic materials (and wastes, including
asbestos) associated with our operations,
- noise emissions from our facilities, and
- safety and health standards, practices and procedures that apply to the
workplace and to operation of our facilities.
In order to comply with these requirements, we may need to spend substantial
amounts and devote other resources from time to time to:
- construct or acquire new equipment,
- acquire permits and/or marketable allowances or other emission credits
for facility operations,
- modify or replace existing and proposed equipment, and
- clean up or decommission waste disposal areas, fuel storage and
management facilities and other locations and facilities, including coal
mine refuse piles and generation facilities.
We have included in our projections over $441 million for capital expenditures
between 2000 and 2026 for environmental compliance. If we do not comply with
environmental requirements that apply to our operations, regulatory agencies
could seek to impose on us civil, administrative and/or criminal liabilities as
well as seek to curtail our operations. Under some statutes, private parties
could also seek to impose civil fines or liabilities for property damage,
personal injury and possibly other costs.
Air Emissions. Our facilities are subject to the Federal Clean Air Act and
many state laws and regulations relating to air pollution. These laws and
regulations cover, among other pollutants, those contributing to the formation
of ground-level ozone, carbon monoxide, sulfur dioxide, or "SO(2)" and
particulate matter. As a general matter, our facilities emit these pollutants at
levels within regulatory requirements. Fossil fuel-fired electric utility plants
are usually major sources of air pollutants, and are therefore subject to
substantial regulation and enforcement oversight by the applicable governmental
agencies.
Pollutants Contributing to Ozone. Substantially all of our facilities burn
fossil fuels, primarily coal, oil or natural gas, to produce electricity. The
combustion of fossil fuels produces nitrogen oxides, or "NO(x)," which can react
chemically with organic and other compounds present in the lower portion of the
atmosphere to form ozone. Ozone in the lower portion of the atmosphere,
ground-level ozone, is considered by government health and environmental
protection agencies to be a human health hazard, which has prompted both the
federal and state governments to adopt stringent air emission requirements for
fossil fuel-fired generating stations. These requirements are designed to reduce
emissions that contribute to ozone formation, with particular emphasis on NO(x).
Carbon Dioxide. In November 1998, the United States became a signatory to
the Kyoto Protocol to the United Nations Framework Convention on Climate Change.
The Kyoto Protocol calls for developed
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nations to reduce their emissions of greenhouse gases, which are believed to
contribute to global climate change. Carbon dioxide, which is a major byproduct
of the combustion of fossil fuel, is considered to be a greenhouse gas. The
Kyoto Protocol, however, will not become enforceable law in the United States
unless and until the U.S. Senate ratifies it. If the U.S. Senate ultimately
ratifies the Kyoto Protocol and greenhouse gas emission reduction requirements
are implemented, the resulting limitations on power plant carbon dioxide
emissions could have a material adverse impact on all fossil fuel-fired
facilities, including our facilities.
Particulates. The U.S. Environmental Protection Agency, or EPA, issued a
new and more stringent national ambient air quality standard, or NAAQS, in July
1997 for fine particulate matter. Under the time schedule announced by the EPA
when the new standard for fine particulates was adopted, geographical areas that
were nonattainment areas for the standard were to be designated in 2002, and
control measures for significant sources of fine particulate emissions were to
be identified in 2005. On May 14, 1999, however, the U.S. Court of Appeals for
the District of Columbia Circuit vacated and remanded the fine particulate
standard to the EPA for further justification. As a result, there is no
presently enforceable standard for fine particulates, and we do not know what
impact, if any, future revision to this standard may have on our facilities. If
an ambient air quality standard for fine particulates is promulgated, further
NO(x) and SO(2) reductions may be required for those of our facilities located
in areas where sampling indicates the ambient air does not comply with the final
standards that are adopted.
Solid Wastes. All our facilities operate in states that have been
authorized to administer the federal Resource Conservation and Recovery Act, or
RCRA, which regulates the management and disposal of hazardous wastes. These
states also regulate, through their own state programs, the management and
proper disposal of non-hazardous waste and recycled materials. We have
significantly reduced our overall waste disposal amount through various
pollution prevention and waste minimization programs.
Water Issues. The federal Clean Water Act generally prohibits the
discharge of any pollutants, including heat, into any body of surface water,
except in compliance with a discharge permit issued by a state environmental
regulatory agency or the EPA. All of our facilities that are required to have
such permits either have them or have timely applied for extensions of expired
permits and are lawfully operating under the prior permit.
The EPA has issued for public comment proposed rules that would impose
uniform, minimum technology requirements on new cooling water intake structures.
Similar rules for existing intake structures are expected to be prepared in the
summer of 2001. It is not known at this time what requirements the final rules
for existing intake structures will impose and whether our existing intake
structures will require modification as a result of such requirements.
In July 2000, the EPA issued final rules for the implementation of the
total maximum daily load, or TMDL, program of the Clean Water Act. The goal of
the TMDL rules is to establish, over the next 15 years, the maximum amounts of
various pollutants that can be discharged into waterways while keeping those
waterways in compliance with water quality standards. The establishment of TMDL
values may eventually result in more stringent discharge limits in each
facility's wastewater discharge permit. Such limits may require our facilities
to install additional wastewater treatment, modify operational practices or
implement other wastewater control measures. Certain members of Congress have
expressed to the EPA concern about the TMDL program with respect to such issues
as the scientific validity of data used to establish TMDLs as well as the costs
to implement the program.
Specific Environmental Issues Affecting Our Plants
Liability for Preexisting Conditions. Under the purchase agreement between
Sithe Energies and REPG, REPG agreed, with a few exceptions, to:
- assume liability for, and provide indemnification against, remediation
and other consequences of the presence, handling, storage or release of
hazardous and toxic materials on any of the sites of our
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electric generating stations or at off-site locations to the extent
resulting from events on or after November 24, 1999.
- any noncompliance by Sithe Energies with environmental requirements, in
each case whether arising or relating to events occurring prior to, on or
after the date of the acquisition from Sithe Energies, except as noted,
and
- assume similar indemnification obligations of Sithe Energies owed to the
prior owners of the facilities.
We are not currently aware of any environmental condition at any of our
Mid-Atlantic region facilities that we expect to have a material adverse effect
on our financial position, results of operations or cash flows.
Nitrogen Oxides. A multistate memorandum of understanding dealing with the
control of NO(x) air emissions from major emission sources has been signed by
the Ozone Transport Commission states primarily in the Mid-Atlantic and
Northeastern states. The memorandum of understanding and underlying state laws
establish a regional three-phase plan for reducing NO(x) emissions from electric
generating units and large industrial boilers within the ozone transport region,
or OTR. Implementation of Phase 1 was the installation of reasonably available
control technology, or RACT no later than May 31, 1995. This was successfully
completed. Phase 2 commenced in 1999 and will continue through 2002. Phase 3
will begin in 2003. The rules implementing Phase 2 and 3:
- establish NO(x) budgets, or emissions caps during the ozone season of May
through September,
- establish methodology to allocate the allowances to affected sources
within the budget, and
- require an affected source to account for ozone season NO(x) emissions
through the surrender of NO(x) allowances.
The number of NO(x) allowances available to each facility under the annual
budget decreases as the program progresses, which effectively forces an overall
reduction in NO(x) emissions. We currently have been allocated sufficient NO(x)
allowances to meet the Phase 2 emission reduction targets. During Phase 3, we
will receive fewer allowances under a reduced NO(x) budget. We currently
anticipate capital expenditures of approximately $64 million through 2002 to
meet the Phase 3 budget levels for our facilities. We also anticipate that the
consortium of owners of the Conemaugh and Keystone stations will elect to
install additional NO(x) controls on one or more of the boilers at these
stations during the next few years to maintain compliance with these facilities'
budget allocations. We will be responsible for the cost of any capital
expenditures at Conemaugh and Keystone in proportion to our lessor's ownership
percentage through a NO(x) cap and trade system, similar to that described below
for SO(2). We may purchase NO(x) allowances in addition to those that are
allocated to our facilities in order to minimize the total cost of compliance.
We also believe that recent installations of additional boiler operational
control systems at our Keystone and Conemaugh stations and future installations
at the Portland and Shawville stations will further enhance our ability to
control NO(x) emissions.
Pennsylvania and New Jersey state regulations implement both the Phase 2
and 3 emission reductions through a NO(x) cap and trade system, similar to that
described below for SO(2). Under regulatory systems of this type, we may
purchase NO(x) allowances from other sources in the area in addition to those
that are allocated to our facilities, instead of installing NO(x) emission
control systems at our facilities. Depending on the market conditions, the
purchase of extra allowances for a portion of our NO(x) budget requirements may
minimize the total cost of compliance. Our current NO(x) compliance strategy
relies primarily on emission reduction projects, but does incorporate some
allowance purchases for a small fraction of our expected NO(x) allowance
requirements.
Separate and apart from the requirements described above, the EPA has
initiated several regulatory and enforcement efforts that are intended to impose
limitations on major NO(x) sources located in the eastern United States and the
Midwest in order to reduce the formation and regional transport of ozone. Such
regulatory efforts include the EPA's Section 126 rule and the NO(x) SIP Call,
both of which would
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establish a federal NO(x) emissions cap-and-trade program that would apply to
some existing utilities and large industrial sources located in 12 states whose
emissions the EPA has determined contribute to air quality problems in
"downwind" states (generally in the northeast corner of the United States). The
Pennsylvania regulations in 25 PA, Chapter 145 and New Jersey regulations under
N.J.A.C. 7:27-31 will satisfy the NO(x) emission goals specified in those
regulatory efforts.
The EPA also has been conducting a nationwide enforcement investigation
regarding the historical compliance of coal-fueled electric generating stations
with various permitting requirements of the Clean Air Act. Specifically, the EPA
and the U.S. Department of Justice have recently initiated formal enforcement
actions and enforcement litigation against several other utility companies that
operate coal-fueled utility stations, alleging that these companies modified
their plants (sometimes more than 20 years ago) without proper preconstruction
permit authority. The Conemaugh station responded to a formal information
request by the EPA in June 1998 related to this EPA enforcement initiative.
Subsequently, the Shawville and Keystone stations responded to similar, but more
detailed, requests. We have received an additional letter dated January 10, 2001
from the Environmental Protection Agency requesting information related to work
activities conducted at the Seward, Portland and Titus stations. Any litigation,
if pursued successfully by the EPA against any of these three stations, could
result in the imposition of substantial penalties and could accelerate the
timing of emission reduction expenditures currently contemplated for the
facilities. If fines and penalties connected to such litigation are imposed on
our facilities, affiliates of GPU will be responsible for such fines and
penalties but GPU will not be responsible for emission reduction expenditures
necessary to correct any historical non-compliance.
Sulfur Dioxide. The Clean Air Act acid rain provisions require substantial
reductions in SO(2) emissions. Implementation of the acid rain provisions is
achieved through a total cap on SO(2) emissions from affected units and an
allocation of marketable SO(2) allowances to each affected unit. Operators of
electric generating units that emit SO(2) in excess of their allocations can buy
additional allowances from other affected sources. We currently project the
number of SO(2) allowances allocated to our Mid-Atlantic facilities will be less
than projected SO(2) emissions through 2026. Whether we will have an excess or
deficit of SO(2) allowances for any given year will depend, in part, on the
capacity utilization of each of the facilities. We currently intend to comply
with acid rain SO(2) requirements by purchasing additional allowances to make up
any deficit from our allowance allocation. However, depending on the extent of
any allowance deficits, the price and the availability of allowances and other
factors, we will consider changing to low-sulfur coal or other emission control
technologies to maintain compliance.
A number of our coal-fired stations have also had to address concerns
raised by the state and federal environmental agencies regarding impacts on the
ambient air quality caused by the facility's SO(2) emissions, and specifically
impacts on modeled compliance with the NAAQS for SO(2).
The Keystone, Conemaugh and Seward stations are located in the proximity of
the Chestnut and Laurel Ridges. To address concerns expressed by the EPA and the
Pennsylvania Department of Environmental Protection, or PaDEP, about the ambient
air quality for SO(2) in this area, a prior owner of those stations conducted
air quality modeling studies for these three stations to assess compliance with
the NAAQS for SO(2). Based on these studies, more stringent SO(2) emission
limits were placed on these three stations, and the stations currently comply
with these limits. Based on similar SO(2) NAAQS modeling studies for the
Portland, Warren and Shawville stations, the PaDEP imposed more stringent SO(2)
emissions limits at the Warren station. The results of the studies show that the
Portland and Shawville stations do not require revised SO(2) emission limits to
demonstrate attainment of the SO(2) NAAQS. Finally, results of a similar SO(2)
NAAQS modeling study for the Titus station suggest that SO(2) emissions
reductions or increased vent gas dispersion may be necessary to maintain modeled
NAAQS compliance. Final resolution of the Titus SO(2) modeling study could
result in the construction of a new emissions stack to increase vent gas
dispersion within the next two or three years, which may cost an estimated $5
million to $7 million. These amounts have been included in the financial
projections of the independent engineer.
Visibility Impairment Rules. The EPA has promulgated regulations relating
to reduction in the impairment of visibility resulting from man-made pollution.
The primary target of these regulations would
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be SO(2), NO(x), and hydrogen chloride air emissions from stationary sources.
The regulations have been challenged in court, and the ultimate impact of these
regulations on our facilities is uncertain. Even under the existing regulations,
there would be no impact on our facilities until 2012 and beyond.
Mercury. The EPA is currently considering whether it will regulate steam
electric generating plants under Title III of the Clean Air Act, which addresses
emissions of hazardous air pollutants from specific industrial categories. Power
plants are a source of mercury air emissions. If the EPA decides to regulate the
electric power industry under Title III of the Clean Air Act, it will likely
establish emission control standards for mercury, as well as, potentially, other
hazardous air pollutants. The standards likely would not be imposed on affected
sources until 2010 or later. The applicable control level is uncertain, as is
the cost of these potential future rules.
Asbestos and Lead-based Paint. Many of our facilities are more than 40
years old, and as a result contain significant amounts of asbestos insulation,
other asbestos containing materials, as well as lead-based paint. Existing state
and federal rules require the proper management and disposal of these
potentially toxic materials. We have developed a management plan that includes
proper maintenance of existing non-friable asbestos installations, and removal
and abatement of asbestos containing materials where necessary because of
maintenance, repairs, replacement or damage to the asbestos itself. We have
planned for the proper management, abatement and disposal of asbestos and
lead-based paint at our facilities in our financial planning.
Clean Water Act. The PaDEP is currently evaluating the existing thermal
load on the stream that receives the Shawville cooling water discharge. This
evaluation may result in a reduced temperature limit in the wastewater discharge
permit for the Shawville cooling water discharge. Depending on the final limits
established, installation of a cooling tower that would cost approximately $10
million may be required. This amount has been included in the financial
projections of the independent engineer.
Solid Wastes. Several of our facilities are subject to regulations in
Pennsylvania governing ash disposal sites. These regulations require, among
other things, the development of a groundwater assessment plan if groundwater
monitoring indicates degradation of water quality. A groundwater assessment must
evaluate the cause and determine the need for abatement measures. Groundwater
assessments have been developed for several of our ash disposal sites.
Specifically, the Titus station ash disposal site was upgraded in 1991 and meets
many of the Pennsylvania lined facility requirements. Nevertheless, groundwater
degradation has been identified at that site. In 1996, an abatement plan was
filed with the PaDEP in conjunction with the Titus ash disposal site
repermitting application. The plan states that any contaminated groundwater will
be appropriately abated until the landfill is closed, which is expected to occur
in 2008 or 2009. Prior to the projected landfill closure, procedures will be
implemented to evaluate the groundwater condition at the site and determine if
additional remediation is required. Similarly, the Portland station ash disposal
site requires significant modifications under a state permit issued in December
1998 that requires a synthetic liner and a leachate collection and treatment
system. These modifications are nearing completion. In general, we expect to
develop and expand existing ash disposal sites as well as close other ash
disposal sites at various facilities during the lives of those facilities. These
activities may include various remedial activities to address actual or
threatened impacts on groundwater from prior disposal activities or other
technical construction requirements imposed by the applicable regulatory agency.
The associated expenditures have been included in the financial projections of
the independent engineer.
Other residual waste compliance requirements in Pennsylvania apply to waste
water treatment processes including the use of storage impoundments, which
eventually will also require groundwater monitoring systems, and potential
assessments of the impact, if any, on groundwater. Groundwater abatement may be
necessary at locations where pollution problems are identified. The removal of
all the residual waste, sometimes called clean closure, has been completed at
some of our impoundments to eliminate the need for future monitoring and
abatement requirements. Wastewater storage impoundments must implement
groundwater monitoring plans. The PaDEP has approved the monitoring plans for
the
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Keystone and Conemaugh stations. Implementation of those plans has begun. The
plans for the Shawville, Titus and Portland stations are awaiting PaDEP
approval.
Hazardous Substances/Site Remediation. Under federal environmental
monitoring requirements, an affiliate of GPU, as prior owner of our Seward
station, reported to the PaDEP that contaminants from coal mine refuse piles
were identified in stormwater runoff at the property where the station is
situated. That affiliate of GPU signed a modified consent order, effective
December 1996, and an amendment, in December 1998, that established a schedule
for submitting a plan for long-term remediation, based on future operating
scenarios. We estimate that the remediation on the Seward station property will
range from $6 million to $10 million. These amounts have been included in the
financial projections and anticipated environmental expenditures for the Seward
station of the independent engineer. We base this cost estimate on continuing
discussions with the PaDEP about the method of remediation, the extent of
remediation required and available cleanup technologies. Under the acquisition
agreements by which Sithe Energies purchased our facilities from affiliates of
GPU, a GPU affiliate has agreed to retain responsibility for up to $6 million of
environmental liabilities arising as a result of or in connection with the
investigation or remediation of hazardous substances disposed, released or
stored prior to November 24, 1999 in connection with the coal refuse site at the
Seward station. We will be responsible for any amounts in excess of that $6
million. In August 2000 we signed a modified consent order that committed us to
complete the remediation work no later than November 2004. On-site work has
commenced in accordance with the modified order.
We are generally responsible for the liabilities associated with site
contamination at our facilities, with the exception of the first $6 million to
remediate the coal mine refuse pile at the Seward station and all costs
associated with the remediation of asbestos contamination identified at an
office building. An affiliate of GPU, Inc. retained liabilities associated with
the disposal of hazardous substances to off-site locations prior to November 24,
1999. In that regard, the presence of hazardous substances at the generating
facilities could expose us to potential liabilities associated with the cleanup
of contaminated soil and groundwater under federal or state Superfund statutes.
Under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended, or CERCLA or Superfund, owners and operators
of facilities from which there has been a release or threatened release of
hazardous substances, together with those who have transported or arranged for
the disposal of those substances, are liable for:
- the costs of responding to that release or threatened release, and
- the restoration of natural resources damaged by any such release.
The liability imposed by the statute is both strict and, under almost all
circumstances, joint and several. Any such liabilities could have a material
adverse effect on us. We are not aware of any liabilities that we are
responsible for under CERCLA that would have a material adverse effect on us,
our financial position, results of operations or cash flows.
We are also responsible for remediation costs under the New Jersey
Industrial Site Recovery Act, or ISRA, relating to our facilities located in New
Jersey. Under ISRA, owners and operators of industrial properties are
responsible for performing all necessary remediation at the facility prior to
closing, or undertaking actions that ensure that the property will be remediated
after the closing. In connection with the acquisition of our facilities from
Sithe Energies, we have agreed to take responsibility for any costs under ISRA
relating to the New Jersey properties, which include the Gilbert, Sayreville,
Glen Gardner and Werner stations. We estimate that the costs to fulfill our
obligations under ISRA will be approximately $5 to $10 million. Provision has
been made in the financial projections of the independent engineer for these
costs. However, these remedial activities are still in the early investigative
stage. Following further investigation the scope of the necessary remedial work
could increase, and we could, as a result, incur significantly greater costs.
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MANAGEMENT
ABOUT OUR MANAGEMENT COMMITTEE AND EXECUTIVE OFFICERS
REMA is a sole-member limited liability company, whose affairs are managed
through a management committee.
The members (and their ages) of REMA's management committee, and the
directors of or the members of the management committees of the subsidiary
guarantors, are Joe Bob Perkins (40) and David G. Tees (56).
Joe Bob Perkins has served as Executive Vice President of RRI since
September 2000 and as Executive Vice President and Group President, Wholesale
Businesses, of RRI since January 2001. He served as President and Chief
Operating Officer of REWG and of REPG since 1998. In 1998, Mr. Perkins served as
President and Chief Operating Officer of REPG. Between 1996 and 1998, Mr.
Perkins served as Vice President -- Corporate Planning and Development of
Reliant Energy. Before joining Reliant Energy, Mr. Perkins served as Vice
President of Business Development and Corporate Secretary of Coral Energy
Resources, L.P. and Vice President and General Manager of Coral Power, L.L.C.
Between 1994 and 1995, he was Director of Business Development for Tejas Gas
Corporation.
David G. Tees has served as Senior Vice President of Generation Operations
for REWG since 1998. During 1997 and 1998, Mr. Tees served as Vice President of
Operations for HI Power Generation Group. Between 1986 and 1997, Mr. Tees served
as Vice President of Energy Production for Houston Lighting & Power Company. Mr.
Tees joined Houston Lighting & Power Company in 1966 and worked in various
positions in the power department until 1986.
We list below REMA's executive officers and its subsidiary guarantors'
executive officers, with their respective positions.
NAME AGE POSITION
- ---- --- --------
John H. Stout........................................ 51 Vice President and General Manager
W. Paul Ruwe, Jr. ................................... 49 Vice President
Joseph J. Wagner, Jr. ............................... 51 Vice President
James E. Hammelman................................... 43 Treasurer
Lloyd A. Whittington................................. 45 Assistant Treasurer
Michael L. Jines..................................... 42 Secretary
Rufus S. Scott....................................... 56 Assistant Secretary
We describe below the principal occupations and business activities of our
executive officers for the past five years in addition to their positions
described above.
John H. Stout has served as Vice President, California Asset
Commercialization of REPG and as Vice President and General Manager of Reliant
Energy California Holdings since 1999. In 1998, Mr. Stout served as General
Manager, California Acquisitions for REPG. During 1996 and 1997, Mr. Stout
served as Managing Director, Power Origination for Noram Energy Services, Inc.
Before 1996, Mr. Stout held the position of General Manager, Energy Control for
Houston Lighting & Power Company.
W. Paul Ruwe, Jr. has served as Vice President, Mid-Atlantic/Eastern Plant
Operations of REWG since May 2000. In 1999 and 2000, Mr. Ruwe served as Vice
President of Unregulated Plant Operations of REWG. Before joining Reliant
Energy, Mr. Ruwe served as a Senior Consultant for Muse, Stancil & Co. between
1997 and 1999. Between 1990 and 1997, Mr. Ruwe served in various Asset
Management and Business Development positions at Destec Energy, Inc.
Joseph J. Wagner, Jr. became Vice President of REMA in July 2000. He
previously served as Director of Operations of REMA since May 2000 and as Vice
President of Operations of Sithe Mid-Atlantic Power Services, Inc. from November
1999 to May 2000. Between 1991 and November 1999, he served as the Director of
the Keystone Generating Station of GPU Generation, Inc.
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James E. Hammelman has served as Treasurer of REPG since March 1999. Before
joining REPG in December 1998, from 1996 to 1998, Mr. Hammelman served as Vice
President and Treasurer of Tractebel Power, Inc. with primary responsibility for
corporate and structured finance. Before 1996, Mr. Hammelman was employed by
Conoco Inc. as Director, Downstream Projects with a focus on project finance.
Lloyd A. Whittington has served as Assistant Treasurer of REPG since 1999
and as Manager, Treasury Operations of Reliant Energy since 1998. Before 1998,
Mr. Whittington served in various capacities in the customer service
organization of Entergy Corp. as well as Director, Shareholder Services of Gulf
States Utilities Co. before the merger with Entergy Corp.
Michael L. Jines has served as Vice President and General Counsel, REWG
since 1998. Before that time, Mr. Jines served in various positions in the
Reliant Energy Law Department. Since 1992, Mr. Jines has been responsible for
the legal services required to support both the domestic and international power
development activities of Reliant Energy and its subsidiaries. Mr. Jines has
been employed by Reliant Energy since 1984.
Rufus S. Scott has served as Vice President, Deputy General Counsel and
Assistant Corporate Secretary of Reliant Energy since 1995. In 1985, Mr. Scott
joined the company as a managing attorney and was named associate general
counsel the same year. Before 1985, Mr. Scott worked at Phillips Petroleum Co.
and at the law firm of Baker Botts L.L.P.
COMPENSATION OF MANAGEMENT
REPG pays directly the salaries of our management listed above. A portion
of those salaries will effectively be paid by REMA through the support services
agreement with REPG. This support services agreement is described under "Related
Party Arrangements."
All members of our management are eligible to participate in employee
benefit plans and arrangements sponsored by Reliant Energy for its similarly
situated employees, including its pension plan, savings plan, long-term
incentive compensation plan, annual incentive compensation plan, health and
welfare plans and other plans that may be established in the future.
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RELATED PARTY ARRANGEMENTS
REMA's sole member is Reliant Energy Northeast Generation, Inc., which owns
all of REMA's equity interest. Reliant Energy Northeast Generation, Inc. is a
100% directly owned subsidiary of Reliant Energy Northeast Holdings, Inc., which
is a 100% directly owned subsidiary of REPG. REPG is a 100% directly owned
subsidiary of RRI, which is a 100% directly owned subsidiary of Reliant Energy.
PROCUREMENT AND MARKETING AGREEMENT
REMA and each of its subsidiaries owning generating facilities are parties
to a procurement and marketing agreement with RES, a 100% directly owned
subsidiary of RRI, under which RES is entitled to procurement and power
marketing fees. Under that agreement, RES
- procures coal, fuel oil and emissions allowances on our behalf at a pass
through price
- procures gas on our behalf at a pass through price or for an index price
plus costs of delivery depending on when and how the gas is procured, and
- markets power and surplus gas, fuel oil and emissions allowances on our
behalf
Please read "Description of Principal Transaction Documents -- Key
Contracts With Affiliated Entities -- Procurement and Marketing Agreement."
We do not, and RES will not, procure coal, natural gas or limestone for the
Keystone station or the Conemaugh station or submit the bid price to the PJM ISO
for dispatch of power from those stations. Please read "Description of Principal
Transaction Documents -- Acquired Contracts -- Contracts and Commitments
Regarding Keystone and Conemaugh Stations -- Fuel Procurement and Dispatch
Arrangement for Keystone and Conemaugh Stations."
SUPPORT SERVICES AGREEMENT
We are a party to a support services agreement with REPG under which REPG
will, on an as-requested basis and at cost, provide or procure from third
parties services in support of our business in areas such as human resources,
accounting, finance, treasury, tax, office administration, information
technology, engineering, construction management, environmental, legal and
safety. REPG has agreed to provide these services only to the extent it or its
affiliates provide these services for its or its subsidiaries' generating
assets. Please read "Description of Principal Transaction Documents -- Key
Contracts With Affiliated Entities -- Support Services Agreement."
NOTES TO AFFILIATED ENTITIES
As of September 30, 2000, we had an aggregate of approximately $962 million
outstanding in subordinated indebtedness owed to an affiliate of Reliant Energy.
For a description of additional subordinated debt we issued in early 2001, see
" -- Other Intercompany Debt." Payments under this indebtedness are subordinated
to REMA's lease obligations as described under "Outstanding
Indebtedness -- Notes to Affiliated Entities" and may be made only to the extent
permitted under the covenant described in "Description of the Exchange
Certificates -- Covenants -- Limitations on Restricted Payments and Restricted
Investments" beginning on page 89.
WORKING CAPITAL NOTE
REMA has executed a two-year revolving note with Reliant Energy Northeast
Holdings, Inc. under which we may borrow, and Reliant Energy Northeast Holdings,
Inc. is committed to lend, up to $30 million from time to time for working
capital needs. Borrowings under the note will be unsecured and will rank equal
in priority with REMA's lease obligations. REMA may replace this note with a
working capital facility from an unaffiliated lender.
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SUBORDINATED WORKING CAPITAL FACILITY
REMA has entered into an irrevocably committed subordinated working capital
facility with Reliant Energy Northeast Holdings, Inc., or RENH. RENH will fund
REMA's drawings under this facility through borrowings or equity contributions
irrevocably committed to RENH by RERC or another entity rated at least Baa2 by
Moody's and BBB by Standard & Poor's. REMA may borrow under this facility to pay
operating expenditures, senior indebtedness and rent, but excluding capital
expenditures and subordinated indebtedness. In addition, RENH must make advances
to REMA and REMA must obtain such advances under such facility up to the maximum
available commitment under such facility from time to time if our pro forma
coverage ratio does not equal or exceed 1.1 to 1.0, measured at the time rent
under the leases is due. Subject to the maximum available commitment, drawings
will be made in amounts necessary to permit us to achieve a pro forma coverage
ratio of at least 1.1 to 1.0. Initially the amount available under each of the
subordinated working capital facility and the related RENH facility was $120
million, declining to $0 in 2011. Presently, there are no borrowings outstanding
under this facility. Please read "Outstanding Indebtedness -- Subordinated
Working Capital Facility."
OTHER INTERCOMPANY DEBT
REMA has also borrowed from Reliant Energy Northeast Holdings, Inc.
approximately $83 million. The borrowing will mature on January 1, 2029, bears
interest at a fixed rate of 9.4% and is unsecured. Repayment of the borrowing
will be subordinated to REMA's lease obligations as required by the lease
documents and as described above under "-- Notes to Affiliated Entities."
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DESCRIPTION OF PRINCIPAL TRANSACTION DOCUMENTS
ACQUISITION AGREEMENT WITH SITHE ENERGIES
General
REPG, as buyer, and Reliant Energy, as guarantor, entered into a purchase
agreement dated as of February 19, 2000 with Sithe Energies and one of its
subsidiaries, Sithe Northeast Generating Company, Inc., to purchase (1) all of
the equity interests in REMA and affiliated companies that are now its
subsidiaries and (2) demand notes aggregating approximately $1.6 billion that we
owed to the Sithe Energies subsidiary. REPG assigned its right to purchase the
equity interests and notes to two of its subsidiaries, Reliant Energy Northeast
Generation, Inc., which is our immediate parent company, and Reliant Energy
Northeast Holdings, Inc.
Purchase Price
The purchase price for the acquisition was $2.1 billion, subject to
adjustment for various items, including
- changes in net working capital of REMA and the other acquired companies
- capital expenditures relating to our facilities, and
- development costs and other expenditures approved by REPG and made by
REMA and the other acquired companies
We expect that all purchase price adjustments will be finalized during the first
quarter of 2001.
Assets
Under the purchase agreement, as assigned by REPG, Reliant Energy Northeast
Generation, Inc. acquired us. After the acquisition, REMA acquired the companies
that own the facilities located in New Jersey (1,499 MW) and Maryland (18 MW),
and those companies became its subsidiaries. REMA owns directly or leases all of
the Pennsylvania facilities (2,745 MW). In total, the acquisition covered 21
facilities.
ACQUIRED CONTRACTS
Contracts and Commitments Regarding Keystone and Conemaugh Stations
Owners' Agreements. The owners of each of the Conemaugh station and the
Keystone station have entered into separate owners' agreements that specify that
the stations are owned as tenants-in-common and that each owner's entitlement to
energy and capacity from the respective station is in accordance with such
owner's applicable ownership percentage in the station. The owners' agreements
also provide that each owner bears loss and liability for bodily injury, death
or damage arising out of the ownership or operation of the applicable station in
accordance with its respective ownership interests in such station.
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The co-owners of the Conemaugh station and their percentage ownership
interests are as follows:
PERCENTAGE
CO-OWNERS INTERESTS
- --------- ----------
Atlantic City Electric Company........................... 3.83%
Constellation Power Source Generation, Inc. ............. 10.56
Conectiv Delmarva Generation, Inc. ...................... 3.72
PECO Energy Company...................................... 20.72
PPL Montour, LLC and Allegheny Energy Supply
Conemaugh, LLC......................................... 9.72*
PPL Montour, LLC......................................... 11.39
PSEG Fossil LLC.......................................... 22.50
Conemaugh Lessor Genco LLC............................... 16.45**
UGI Development Company.................................. 1.11
------
Total.......................................... 100.00%
- ---------------
*This interest is held as tenants in common of the undivided interest.
** This interest is leased by REMA.
Atlantic City Electric Company and Conectiv Delmarva Generation, Inc. have
announced that they are selling their respective interests in the Conemaugh
station to NRG Energy, Inc.
The co-owners of the Keystone station and their percentage ownership
interests are as follows:
PERCENTAGE
CO-OWNERS INTERESTS
- --------- ----------
Atlantic City Electric Company............................ 2.47%
Constellation Power Source Generation, Inc. .............. 20.99
Conectiv Delmarva Generation, Inc......................... 3.70
PECO Energy Company....................................... 20.99
PPL Montour, LLC.......................................... 12.34
PSEG Fossil LLC........................................... 22.84
Keystone Lessor Genco LLC................................. 16.67*
------
Total........................................... 100.00%
- ---------------
* This interest is leased by REMA.
Atlantic City Electric Company and Conectiv Delmarva Generation, Inc. have
announced that they have entered into definitive agreements to sell their
interests in the Keystone station to NRG Energy, Inc.
Operating Agreements. The Keystone and Conemaugh stations are operated
under operating agreements that we describe below.
REMA operates and manages the Conemaugh station and the Keystone station on
behalf of the co-owners under separate ownership and operating agreements
through REMA's wholly owned subsidiary, Reliant Energy Management. The ownership
and operating agreements for the Conemaugh station and the Keystone station have
substantially the same material terms. Reliant Energy Management was the
operator of both the Conemaugh station and the Keystone station under a
different name when we were owned by Sithe Energies. We maintain this management
structure. Reliant Energy Management continues to operate the Conemaugh station
and the Keystone station under the original ownership and operating agreements.
The Conemaugh operating agreement was entered into as of December 1, 1965,
and the Keystone operating agreement was entered into as of December 1, 1967.
Generally, the operating agreements require Reliant Energy Management to
maintain and operate the Conemaugh station and the Keystone station in
accordance with "good utility practice" and operating plans developed and
updated annually by Reliant
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Energy Management and the co-owners and approved by the co-owners. The operating
agreements also specify other operating duties, including, among others,
- management of personnel, fuel supply and real estate matters
- purchase of material and services
- keeping the applicable station in "safe and efficient operating
condition"
- protecting property by taking action approved by the applicable owners
- performing other agreed services if requested by the applicable owners,
and
- performing accounting and billing functions
Generally, the co-owners of each station make all decisions concerning the
station by unanimous consent. If the owners cannot agree and the matter is
likely to impede any operation of either station, a decision of all except one
of the applicable owners or the owners of applicable ownership interests of at
least 75% will decide the matter. Matters arising in connection with the
operation and maintenance of each station that are not covered in the operating
agreements are the responsibility of the applicable owners and not Reliant
Energy Management.
Reliant Energy Management operates and maintains each station at cost and
without profit. Reliant Energy Management's liability for any damages is limited
to any insurance proceeds it receives; otherwise, the applicable owners are
liable proportionately to their ownership interest. Reliant Energy Management is
required by the operating agreements to maintain statutory workers'
compensation, for which it is reimbursed at cost. The owners of each station
must provide comprehensive public liability and hazard and property insurance,
which must cover physical loss and damage to each station, except for Reliant
Energy Management's property.
The term of each operating agreement extends each year for an additional
year. Each operating agreement permits the owners of each station to terminate
the respective operating agreement on any December 31 upon three years' prior
notice. The owners of the Conemaugh station and owners of the Keystone station
have elected to terminate the respective operating agreements effective as of
December 31, 2002 and have not yet decided on replacement operating agreements.
Fuel Procurement and Dispatch Arrangement for Keystone and Conemaugh Stations
Neither RES nor we procure coal, natural gas or limestone for the Keystone
and Conemaugh stations. Instead, the co-owners of those stations rely on a team
of personnel, known as Key-Con Fuels, to procure those commodities under spot,
short-term and long-term contracts as agent for the co-owners. Under that
arrangement, the co-owners, including REMA, take direct title to the commodities
procured by Key-Con Fuels. The personnel in Key-Con Fuels currently are on the
payroll of Reliant Energy Management, as operator of the Keystone and Conemaugh
stations, but take direction only from the Keystone-Conemaugh owners committee.
Key-Con Fuels prepares, on an annual basis, a coal supply plan for the
review and approval of the Keystone-Conemaugh owners committee. Key-Con Fuels
currently has the following base amounts of coal under short-term and long-term
contracts for the Keystone and Conemaugh stations:
YEAR KEYSTONE CONEMAUGH
- ---- -------- ---------
(MILLION TONS)
2001.................................... 4.573 4.703
2002.................................... 4.436 2.223
2003.................................... 4.755 1.581
2004.................................... 3.820 0.707
2005.................................... 2.800 0.000
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Neither RES nor we submit the bid price to the PJM ISO for energy produced
by the Keystone and Conemaugh stations. Instead, the co-owners of those stations
rely on a team of personnel, known as the Keystone-Conemaugh Projects Office, to
submit that bid price. The personnel in the Keystone-Conemaugh Projects Office
currently are on the payroll of Reliant Energy Management, as operator of the
Keystone and Conemaugh stations, but take direction only from the
Keystone-Conemaugh owners committee. Reliant Energy Management, as operator of
the Keystone and Conemaugh stations, submits to the PJM ISO the technical data
regarding availability and other factors required by the PJM ISO. If the PJM ISO
dispatches the Keystone and Conemaugh stations, each co-owner has the right to
market its share of the energy produced by those stations. Each co-owner can
sell that energy into the PJM system, sell or trade that energy under bilateral
arrangements or use that energy. RES markets our share of that energy on our
behalf under the procurement and marketing agreement.
Each co-owner has the right to market its share of the capacity of the
Keystone and Conemaugh stations. RES markets our share of that capacity on our
behalf under the procurement and marketing agreement.
Interconnection Agreements
Before our acquisition from Sithe Energies and one of its subsidiaries,
REMA and each of its subsidiaries owning generating facilities entered into five
interconnection agreements that establish the requirements, terms and conditions
for the interconnection of their existing electric generating facilities to the
interconnection providers' transmission system and for the provision by the
interconnection provider of building, revenue metering and other local services
to those facilities. Unless terminated earlier in accordance with its terms,
each interconnection agreement remains in effect until the earlier of a mutually
agreeable termination date or, insofar as it relates to a particular facility,
the retirement date for that facility. With specified exceptions, we are not
responsible for the costs of providing interconnection service to our facilities
or for the costs of providing building services. We are, however, responsible
for the costs of providing revenue metering services and, in some cases, for the
costs of other local services.
The interconnection provider has rights under the interconnection
agreements to discontinue interconnection service or curtail energy delivery if,
in its reasonable judgment, the operation of one or more of our facilities would
have a material adverse impact on the quality of its service or would interfere
with the safe and reliable operation of the transmission system. In addition,
either party may take reasonable and necessary action if, in the good faith
judgment of that party, there exists an emergency that endangers or might
endanger life or property. Neither we nor the interconnection provider is liable
under the interconnection agreements for interruptions or damages resulting from
electrical transients, unless caused by gross negligence or willful misconduct.
We are required under the interconnection agreements to comply with the
requests, orders and directives of the interconnection provider to the extent
they are
- issued under good utility practice and, in the case of the Keystone and
Conemaugh stations only, applicable law and regulation
- not unduly discriminatory, and
- otherwise in accordance with applicable tariffs
Transition Power Purchase Agreements
Before our acquisition from Sithe Energies and one of its subsidiaries,
REMA and each of its subsidiaries owning generating facilities, Sithe Energies
and Sithe Power Marketing executed three transition power purchase agreements
with affiliates of GPU, Inc., each dated November 24, 1999. We have acquired the
rights and obligations of Sithe Energies and Sithe Power Marketing under these
agreements.
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Under the transition power purchase agreements, we and each of the GPU
affiliates have an option agreement for the purchase and sale of electric
generating capacity, but not energy or ancillary services. We have a "put
option" whereby GPU is obligated to accept and purchase capacity from us up to
the maximum put capacity. GPU has a "call option" whereby we are required to
provide and sell capacity to GPU up to the maximum call capacity. Three months
before each contract year end, we must choose whether to exercise the put option
for the following contract year under each of the agreements. Then, the
affiliates of GPU must decide whether to exercise the call option in respect of
any capacity for which we have not exercised our put option.
The maximum put capacity for each contract year equals GPU's forecast of
the amount of installed capacity that it will need to satisfy its installed
capacity obligations during that contract year minus the installed capacity
available to GPU from other specified sources. The maximum call capacity for
each contract year equals the maximum put capacity minus the amount of installed
capacity for which we exercise our put option for that contract year. The
transition power purchase agreements provide some flexibility to permit us to
provide installed capacity to meet our obligations from sources other than our
existing facilities.
The term of the transition power purchase agreements began November 24,
1999 and will end on May 31, 2002 (or, if the PJM planning year changes, the
last day of the PJM planning year ending in 2002). There is no provision for
unilateral extension or early termination. A schedule of put and call prices is
included and is common to all three agreements. The prices, in dollars per
MW-day, and assumed revenues under these agreements, are described in the
independent engineer's report included as Appendix A to this prospectus. In the
first quarter of 2000, we exercised the put option described above for the
twelve-month period ending May 31, 2001. The effect of our exercise of this put
option is reflected in the financial projections included in the independent
engineer's report.
KEY CONTRACTS WITH AFFILIATED ENTITIES
Procurement and Marketing Agreement
REMA and its subsidiaries owning generating facilities are parties to a
procurement and marketing agreement with RES. Under that agreement, RES procures
gas, coal, fuel oil and emissions allowances for our facilities and markets
power from our facilities by arranging contracts with commodity suppliers and
power purchasers. We may be directly responsible to those commodity suppliers
and power purchasers to the extent RES executes contracts as our agent. We do
not, and RES will not, procure coal, gas or limestone for the Keystone station
or the Conemaugh station or submit the bid price to the PJM ISO for dispatch of
power from those stations.
Commodity Procurement. RES procures gas, coal, fuel oil and emissions
allowances pursuant to the following terms:
- Gas. RES procures gas on our behalf (1) at a pass through price in the
case of gas procured as part of a forward package, later than day-ahead
or under an existing or replacement contract with a local gas
distribution company or (2) for an index price plus costs of delivery in
any other case. RES also assists us in remarketing surplus gas upon
reasonable request. We incur a gas procurement fee payable to RES of
$0.07 per mmBtu of gas consumed (escalated for inflation) on a monthly
basis for its gas procurement services.
- Coal. RES procures coal on our behalf at a pass through price. We incur a
coal procurement fee payable to RES of $500,000 per year (escalated for
inflation) on a monthly basis for its coal procurement services allocated
by facility on the basis of installed capacity beginning from when RES
assumes the coal procurement responsibilities.
- Fuel Oil. RES procures fuel oil on our behalf at a pass through price.
RES also assists us in remarketing surplus fuel oil upon reasonable
request. We incur a fuel oil procurement fee payable to RES of $0.07 per
mmBtu of fuel oil consumed (escalated for inflation) on a monthly basis
for its fuel oil procurement services.
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- Emissions Allowances. RES procures emissions allowances on our behalf at
a pass through price. RES also assists us in remarketing surplus
emissions allowances upon reasonable request. We incur an emissions
allowance procurement fee payable to RES of $350,000 per year (escalated
for inflation) on a monthly basis for its emissions allowance procurement
services allocated by facility on the basis of installed capacity.
Power Marketing. RES markets our power and passes through to us the actual
net proceeds received from power sales. These power marketing services include
administration of the transition power purchase agreements with GPU for their
remaining terms. RES maintains a separate trading book for the power marketing
transactions relating to our facilities. We reimburse RES for its costs and, in
addition, we incur a power marketing fee payable to RES of $3,500,000 per year
(escalated for inflation) on a monthly basis for its power marketing services
allocated by facility on the basis of installed capacity.
Payment. We pay the fees that we owe to RES under the procurement and
marketing agreement only when and to the extent permitted under the covenant
described in "Description of the Exchange
Certificates -- Covenants -- Limitations on Restricted Payments and Restricted
Investments" beginning on page 89 with unpaid fees accumulated with interest
until payment is permitted.
Commodity Procurement and Power Marketing Guidelines. We have established
commodity procurement and power marketing guidelines for RES that specify
limitations on the terms of a commodity supply or power marketing arrangement
that cannot be exceeded without our prior approval. These limitations could
relate to, among other things,
- pricing
- payment terms
- hedging
- duration, and
- quantity of commodity or power
Transactions that obligate us to deliver capacity, energy or ancillary services
will be based upon our ability to deliver capacity, energy or ancillary services
from our facilities. We do not intend to enter into those transactions for
purely speculative purposes.
Operations and Dispatch. RES has control over the dispatch of our
facilities, other than the Keystone and Conemaugh stations, subject to technical
limitations. We have control over scheduled outages of our facilities, other
than the Keystone and Conemaugh stations, and we intend to schedule those
outages in cooperation with RES.
Term. The procurement and marketing agreement has a 30-year term. We or RES
can terminate the agreement in whole or in respect of a particular service at
our convenience without any payment or liability upon six months' prior notice.
In addition, we or RES can terminate the agreement in respect of any or all
services in the event of default (following specified notice and cure periods).
In particular, we can terminate the agreement in whole or in part upon three
months' prior notice if, during any rolling 12-month period, the average gross
sales price for power sales arranged by RES on our behalf is less than 85% of
the average gross sales price for other comparable power sales arranged by RES
in the PJM control area. Our sole remedy for nonperformance, inadequate
performance or faulty performance by RES, except in the case of fraud or
intentional tort by RES, is termination.
Support Services Agreement
Scope. We are party to a support services agreement with REPG under which
REPG will, on an as-requested basis, provide or procure from third parties
services in support of our business. REPG has agreed
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to provide or procure these services only to the extent it or its affiliates
provide these services for its or its subsidiaries' generating assets. These
services may include
- accounting services, including the preparation of management reports,
internal auditing services and the procurement of audits
- office administration
- information technology and data processing services
- human resource services and benefit planning and administration
- preparation and submission of various legal and governmental filings and
procuring and maintaining governmental approvals and permits
- legal services
- tax planning and preparation of administrative tax reports and returns
- risk management services and procurement of insurance
- cash management, treasury and finance services
- purchasing of materials, supplies and equipment
- construction management and engineering services
- safety and environmental services, and
- other services of this general administrative nature
REPG may provide these services directly or, in its sole discretion, may
arrange contracts with other service providers. We may be directly responsible
to these other service providers to the extent REPG executes contracts as our
agent. We currently estimate that the total amount owing to REPG and other
service providers under the support service agreement will be approximately $7
million per year, escalated for inflation.
Payment. We compensate REPG for its costs but only when and to the extent
permitted under the covenant described in "Description of the Exchange
Certificates -- Covenants -- Limitations on Restricted Payments and Restricted
Investments" beginning on page 89 with unpaid costs accumulated with interest
until payment is permitted. Payments we may be required to make to other service
providers directly under contracts executed by REPG as our agent, however, will
not be restricted by the covenant referenced in the immediately preceding
sentence.
Warranty and Limitation of Liability. REPG has agreed to perform, or cause
other service providers to perform, the services with the same degree of care as
REPG customarily exercises in respect of its and its subsidiaries' electric
generating facilities and in material compliance with all applicable laws.
REPG's legal liability, however, will not exceed the compensation paid to REPG
for its services.
Term. The support services agreement has a 30-year term. We or REPG can
terminate the agreement in whole or in respect of a particular service at our
convenience without any payment or liability upon six months' prior notice. In
addition, we or REPG can terminate the agreement in respect of any or all
services in the event of default (following specified notice and cure periods).
Our sole remedy for nonperformance, inadequate performance or faulty performance
by REPG, except in the case of fraud or intentional tort by REPG, is
termination.
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DESCRIPTION OF THE EXCHANGE CERTIFICATES
We summarize below selected provisions relating to the exchange
certificates. The various documents relating to the lease transactions,
including the leases, the participation agreements, the lease indentures, the
lessor notes, the pass through trust agreements, the facility site leases, the
facility site subleases, the subsidiary guarantees, any other applicable
guarantees, the letters of credit and the lease pledge agreements, which we
refer to herein as the "lease documents," all contain provisions that affect the
exchange certificates. Because some of the documents described in this section
use terms with assigned meanings, we have described what those terms mean in
"-- Special terms" below.
GENERAL
An aggregate of $851 million principal amount of original certificates were
issued through three separate pass through trusts and three separate pass
through trust agreements with Bankers Trust Company acting as trustee under each
trust. As of January 31, 2001, an aggregate of $727,850,000 principal amount of
original certificates were outstanding.
The exchange certificates will be issued in fully registered form without
coupons. Each exchange certificate will represent a fractional, undivided
interest in the related pass through trust. The property of each pass through
trust consists solely of the lessor notes held in such pass through trust, plus
all monies that have been or will be paid on those lessor notes. Each exchange
certificate will represent a pro rata share of the outstanding principal amount
of the lessor notes held in the related pass through trust. The exchange
certificates will be issued in minimum denominations of $100,000 or integral
multiples of $1,000 in excess of $100,000.
If you acquire a beneficial interest in the exchange certificates, you will
not receive a definitive certificate representing your interest, except as set
forth below under "-- Book-Entry, Delivery and Form." Unless and until
definitive certificates are issued,
- all actions that otherwise would be taken by you and other registered
holders of exchange certificates will be taken by The Depository Trust
Company, or DTC, acting upon instructions from DTC participants, and
- all distributions, notices and communications that otherwise would be
made to you and other registered certificate holders will be made to DTC
or its nominee for distribution to you in accordance with DTC procedures
We qualify all the descriptions below that relate to actions by or
distributions, notices and communications to registered certificateholders by
this general reference relating to beneficial ownership through DTC. Please read
"-- Book-Entry, Delivery and Form." You should consult with each bank or broker
through which you hold a beneficial interest in an exchange certificate for
information on how you will receive notices and payments related to your
exchange certificates.
LIMITATION ON LIABILITY
The exchange certificates represent interests in the pass through trusts
and do not represent an interest in or obligation of us, the pass through
trustee, the owner participants or the managers of the owner lessors or any of
their affiliates. The pass through trustee will make distributions solely from
the trust property. By accepting an exchange certificate, you agree that you
will receive distributions solely from the trust property, and you will not look
to any other source for distributions on the exchange certificates. The exchange
certificates may be prepaid if the related lessor notes are redeemed, prepaid or
purchased. Please read "Description of Lease Documents -- The Lessor
Notes -- Redemption of Lessor Notes" and "-- Owner Lessors' Right to Purchase
the Lessor Notes."
The lessor notes are not obligations of, and are not guaranteed by, us, the
owner participants or the managers of the owner lessors or any of their
affiliates. The managers of the owner lessors, the owner
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participants and the indenture trustees, and their affiliates, will not be
personally liable to you, and the managers of the owner lessors and owner
participants will not be liable to the indenture trustees for any amounts
related to the lessor notes, except as provided in the applicable lease
indenture. The indenture trustee will make all payments of principal, premium
and interest on the lessor notes only from the collateral or the income and
proceeds it receives from the collateral, which will include scheduled periodic
rent REMA will pay.
PAYMENTS AND DISTRIBUTIONS
The pass through trustee will pay each certificateholder a pro rata share
of all scheduled principal and interest payments on the lessor notes received by
the pass through trustee. The pass through trustee will distribute scheduled
payments on the scheduled distribution dates of January 2 and July 2 of each
year. The lessor notes may be prepaid in whole or in part under some
circumstances. Please read "Description of Lease Documents -- Redemption of
Lessor Notes."
Interest. The pass through trustee will receive payments of interest on the
unpaid principal amount of the lessor notes on each January 2 and July 2 of each
year at 8.554% per annum for the lessor notes payable to holders of the Series A
exchange certificates, 9.237% per annum for the lessor notes payable to holders
of the Series B exchange certificates and 9.681% per annum for the lessor notes
payable to the holders of the Series C exchange certificates, calculated on the
basis of a 360-day year of 12 30-day months.
Scheduled Principal. The initial principal amounts of the lessor notes
payable to holders of the certificates were as follows:
Series A.............................................. $210,000,000
Series B.............................................. $421,000,000
Series C.............................................. $220,000,000
Scheduled principal payments on the lessor notes (which have been rounded
to the nearest dollar), and resulting distributions on the exchange
certificates, are as follows:
SERIES A
CONEMAUGH STATION KEYSTONE STATION SHAWVILLE STATION EXCHANGE
SERIES A SERIES A SERIES A PASS THROUGH
SCHEDULED DISTRIBUTION DATES LESSOR NOTES LESSOR NOTES LESSOR NOTES CERTIFICATES
---------------------------- ------------------ ---------------- ----------------- -------------
July 2, 2001........................... $ 1,554,640 $ 0 $ 50,313,360 $ 51,868,000
January 2, 2002........................ 24,811,000 0 0 24,811,000
July 2, 2002........................... 16,360,025 34,328,000 1,664,975 52,353,000
July 2, 2003........................... 0 0 22,720,000 22,720,000
July 2, 2004........................... 2,274,335 0 30,301,665 32,576,000
July 2, 2005........................... 5,000,000 15,672,000 5,000,000 25,672,000
----------- ----------- ------------ ------------
Total.............................. $50,000,000 $50,000,000 $110,000,000 $210,000,000
=========== =========== ============ ============
SERIES B
CONEMAUGH STATION KEYSTONE STATION SHAWVILLE STATION EXCHANGE
SERIES B SERIES B SERIES B PASS THROUGH
SCHEDULED DISTRIBUTION DATES LESSOR NOTES LESSOR NOTES LESSOR NOTES CERTIFICATES
---------------------------- ------------------ ---------------- ----------------- -------------
July 2, 2001........................... 0 9,719,554 11,500,446 21,220,000
July 2, 2006........................... 10,825,126 5,574,874 0 16,400,000
July 2, 2007........................... 0 18,850,000 0 18,850,000
July 2, 2008........................... 18,040,000 0 0 18,040,000
July 2, 2009........................... 20,420,000 0 0 20,420,000
July 2, 2010........................... 12,070,000 0 0 12,070,000
July 2, 2011........................... 16,617,367 7,442,633 0 24,060,000
July 2, 2012........................... 19,410,000 0 0 19,410,000
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SERIES B
CONEMAUGH STATION KEYSTONE STATION SHAWVILLE STATION EXCHANGE
SERIES B SERIES B SERIES B PASS THROUGH
SCHEDULED DISTRIBUTION DATES LESSOR NOTES LESSOR NOTES LESSOR NOTES CERTIFICATES
---------------------------- ------------------ ---------------- ----------------- -------------
July 2, 2013........................... 0 29,170,000 0 29,170,000
July 2, 2014........................... 0 15,984,910 14,595,090 30,580,000
July 2, 2015........................... 0 0 26,260,000 26,260,000
July 2, 2016........................... 0 0 34,130,000 34,130,000
July 2, 2017........................... 0 0 27,240,000 27,240,000
----------- ----------- ------------ ------------
Total.............................. $97,382,493 $86,741,971 $113,725,536 $297,850,000
=========== =========== ============ ============
SERIES C
CONEMAUGH STATION KEYSTONE STATION SHAWVILLE STATION EXCHANGE
SERIES C SERIES C SERIES C PASS THROUGH
SCHEDULED DISTRIBUTION DATES LESSOR NOTES LESSOR NOTES LESSOR NOTES CERTIFICATES
---------------------------- ------------------ ---------------- ----------------- -------------
July 2, 2018......................... $ 31,553,000 $ 0 $ 0 $ 31,553,000
July 2, 2019......................... 44,917,000 0 0 44,917,000
July 2, 2020......................... 0 36,960,000 0 36,960,000
July 2, 2021......................... 26,184,000 0 0 26,184,000
July 2, 2022......................... 1,308,833 27,210,167 0 28,519,000
July 2, 2023......................... 0 24,367,000 0 24,367,000
July 2, 2024......................... 0 10,000,000 0 10,000,000
July 2, 2025......................... 0 10,000,000 0 10,000,000
July 2, 2026......................... 0 7,500,000 0 7,500,000
------------ ------------ --- ------------
Total............................ $103,962,833 $116,037,167 $ 0 $220,000,000
============ ============ === ============
Special Payments. The pass through trustee will pay each certificateholder
of its pass through trust a pro rata share of:
(1) all payments of principal, premium, if any, and interest received
by the pass through trustee because of a partial or full redemption of the
lessor notes held by the trustee, including as a result of the optional or
mandatory redemption of those lessor notes;
(2) amounts received by the pass through trustee following a default
under the lessor notes held by the trustee upon exercise of remedies under
the lease indenture, including payments received from the sale of lessor
notes held by the pass through trustee; and
(3) any payment received by the pass through trustee five or more
business days after the scheduled distribution date.
We refer to these amounts as special payments. The pass through trustee
will establish and maintain, on behalf of and for the benefit of the
certificateholders, one or more non-interest bearing accounts, each a special
payments account, for the deposit of special payments. Under each pass through
trust agreement, the pass through trustee must immediately deposit in the
special payment account any special payments received.
General. On each scheduled distribution date, and on each of the following
five days, the pass through trustee will distribute to certificateholders of
record all scheduled payments that it receives before 2:00 p.m. New York time,
subject to exceptions. If the pass through trustee receives a scheduled payment
after such five-day period, the pass through trustee will treat it as a special
payment and distribute it as described below.
If the special payment results from the redemption of lessor notes, the
pass through trustee will distribute the special payment on the date the
redemption is scheduled to occur under the terms of the applicable lease
indenture. The pass through trustee will distribute any other special payment to
certificateholders of record on the second day of the next month after which the
pass through trustee has received the special payment and given notice as
required under the pass through trust agreement. We
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refer to these dates as the special distribution dates. The pass through trustee
must give 20 days' notice to the certificateholders of any special payments
resulting from a redemption. Please read "-- Events of Default and Remedies" and
"Description of Lease Documents -- Redemption of Lessor Notes." The pass through
trustee will mail notice of each special payment to the certificateholders of
record and, if requested, to certificateowners stating
- the special distribution date and record date
- the amount of the special payment per $1,000 of face amount of exchange
certificates and the amount of the special payment that constitutes
principal, premium, if any, and interest
- the reason for the special payment, and
- if the special distribution date is the same as a regular distribution
date, the total amount to be distributed on such date per $1,000 of face
amount of exchange certificates
The record date for each distribution of a scheduled payment or a special
payment on a special distribution date will be the 15th day preceding the
applicable distribution date. The pass through trustee will distribute any
payment received after 2:00 p.m., New York time on any scheduled or special
distribution date on the next business day.
While DTC holds exchange certificates on your behalf, the pass through
trustee will make distributions by wire transfer in immediately available funds
to an account maintained by DTC. If DTC does not hold exchange certificates on
your behalf and you hold them directly, the pass through trustee will make such
wire transfers to you only if you
- hold exchange certificates in an aggregate amount greater than $10
million, or
- hold exchange certificates in an aggregate amount greater than $1 million
and request that such distributions be made by wire transfer
Otherwise, the pass through trustee will make distributions by check mailed
to you at your address as it appears on the register. The pass through trustee
will mail notice of the final distribution by each pass through trust (at
maturity, redemption or otherwise) to the certificateholders of record no
earlier than 60 days and no later than 30 days before the final distribution.
The notice will specify the date set for the final distribution, the amount of
the distribution and the office or agency of the pass through trustee at which
exchange certificates must be surrendered. The pass through trustee will make
the final distribution for each pass through trust only upon surrender of the
exchange certificates by a certificateholder specified in the notice of the
final distribution. Please read "-- Termination of the Pass Through Trusts."
If any regular or special distribution date is not a business day,
distributions scheduled on that date will be made on the next business day
without any additional interest.
SAME-DAY SETTLEMENT AND PAYMENT
Because the exchange certificates will trade in DTC's same-day funds
settlement system until maturity, DTC will require that secondary market trading
activity in the exchange certificates settle in immediately available funds. We
do not know what effect this requirement will have on trading activity in the
exchange certificates.
STATEMENTS TO CERTIFICATEHOLDERS
On each scheduled distribution date, the pass through trustee will provide
to certificateholders of record a statement, indicating the amount of principal,
premium, if any, and interest represented by that distribution per $1,000 face
amount of exchange certificate.
Within a reasonable time after the end of each calendar year, the pass
through trustee will furnish to each person who at any time during such calendar
year was a certificateholder of record and, upon request,
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to each certificate owner, a statement summarizing all payments made on the
exchange certificates during the year to that person. The pass through trustee
will also furnish certificateholders of record and certificate owners with some
other items requested for the preparation of federal income tax returns. The
pass through trustee will prepare the report and such other items on the basis
of information supplied by the DTC participants and the certificate owners.
The pass through trustee will notify certificateholders of all events of
default under the pass through trust agreements known to the pass through
trustee within 90 days after the occurrence of each such default. The pass
through trustee may withhold any such notice, except a notice of a payment
default on any lessor note, if it determines in good faith that it is in the
interests of the certificateholders and the certificate owners.
As long as any certificates remain outstanding, REMA must furnish to the
pass through trustee
- unaudited quarterly financial statements within 60 days following the end
of each of its first three fiscal quarters during each fiscal year
- audited annual financial statements within 120 days following the end of
its fiscal year
- notice of some material events within 20 days after their occurrence, and
- at any time that the certificates are subject to the Trust Indenture Act
of 1939, or TIA, an annual statement about whether REMA has fulfilled its
covenants and obligations under the pass through trust agreements
The pass through trustee will, upon request, furnish all such information
directly to certificateholders and certificate owners.
RANKING
REMA's obligations under the leases and the other lease documents are
REMA's senior obligations secured by a pledge of REMA's equity ownership in the
subsidiary guarantors and otherwise ranking at least equal in right of payment
with REMA's other unsecured and unsubordinated indebtedness.
VOTING OF LESSOR NOTES
The pass through trustee has the right under the lease indentures to vote
and give waivers for the lessor notes under some circumstances. The holders of a
majority in interest of the certificates may direct the exercise of any power
conferred on the pass through trustee including any right as holder of the
lessor notes. Each pass through trust agreement provides for the circumstances
in which the pass through trustee may act for the certificateholders. The pass
through trustee, as the holder of the lessor notes, will direct any action or
vote for or against any proposal in proportion to the face amount of
certificates taking that action or voting for or against that proposal.
COVENANTS
So long as the certificates are outstanding, REMA will be subject to the
following principal covenants under the lease documents relating to each lease
transaction:
Limitations on Incurrence of Indebtedness. REMA will not
- incur any indebtedness other than intercompany loans, permitted
indebtedness and affiliate subordinated indebtedness
- permit any subsidiary guarantor to incur any indebtedness other than
- guarantees of the leases
- any guarantee of permitted indebtedness, excluding subordinated
indebtedness
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- intercompany loans
- affiliate subordinated indebtedness, and
- IRB indebtedness, and
- permit any unrestricted subsidiary to incur any indebtedness other than
nonrecourse indebtedness
For purposes of this covenant, the term "incur", when used in relation to
indebtedness, means to create, incur, issue, assume, guarantee, permit to exist
or otherwise become directly or indirectly liable for that indebtedness.
Limitations on Restricted Payments and Restricted Investments. Unless the
parent guarantee described below has been delivered, REMA will not, and will not
permit any subsidiary guarantor to, make any restricted payments unless, at the
time of such restricted payment
- no significant lease default or lease event of default has occurred or
will occur as a result of the restricted payment
- the aggregate amount of credit support described under "Credit Support"
below equals the greater of (1) the next six months' scheduled rental
payments under the leases or (2) 50% of the scheduled rental payments due
in the next 12 months under the leases.
- the fixed charge coverage ratio for the most recently ended four full
fiscal quarters, or such shorter period commencing on the closing date
and ending on the last day of the most recent fiscal quarter, is at least
- 1.7 to 1.0
- 1.6 to 1.0 if, as of the last day of the most recently completed fiscal
quarter, REMA and the subsidiary guarantors are parties, as sellers, to
power sales contracts for the sale of energy, capacity and ancillary
services at prices established by a formula, index or other price risk
management methodology not based on spot market prices having a
remaining term from such date of calculation of at least two years that
are then in full force and effect and not in default in any material
respect, referred to as permitted contracts, and covering, in the
aggregate, at least 40% of the projected total consolidated operating
revenue of REMA and the subsidiary guarantors for the 24-month period
following such date, or
- 1.4 to 1.0 if, as of the last day of the most recently completed fiscal
quarter, REMA and the subsidiary guarantors are parties, as sellers, to
permitted contracts covering, in the aggregate, at least 50% of the
projected total consolidated operating revenue of REMA and the
subsidiary guarantors for the 24-month period following such date
- the projected fixed charge coverage ratio (determined on a pro forma
basis after giving effect to such restricted payment) measured for the
next succeeding eight fiscal quarters (taken as two periods of four
quarters and determined as of the beginning of the quarter during which
the determination is made) is at least
- 1.7 to 1.0
- 1.6 to 1.0 if, as of the last day of the most recently completed fiscal
quarter, REMA and the subsidiary guarantors are parties, as sellers, to
permitted contracts covering, in the aggregate, at least 40% of the
projected total consolidated operating revenue of REMA and the
subsidiary guarantors for the 24-month period following such date, or
- 1.4 to 1.0 if, as of the last day of the most recently completed fiscal
quarter, REMA and the subsidiary guarantors are parties, as sellers, to
permitted contracts covering, in the aggregate, at least 50% of the
projected total consolidated operating revenue of REMA and the
subsidiary guarantors for the 24-month period following such date, and
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- we deliver an officer's certificate to the pass through trustee
certifying about the matters in the above bullet points
For purposes of this limitation, "restricted payments" includes
- any declaration or payment of any dividend or making of any other payment
or distributions on REMA's outstanding equity interests, whether in cash,
property, securities or obligations other than additional equity
interests of the same type
- any other payments or distributions on account of payments of interest
on, or the setting apart of money for a sinking or other analogous fund
for, or the purchase, redemption, retirement or other acquisition of, any
outstanding equity interest in REMA or a subsidiary guarantor or of any
warrants, options or other rights to acquire any such equity interest
- any payments to any person, such as "phantom stock" payments, where the
amount is calculated based upon the fair market or equity value of REMA
or any of the subsidiary guarantors
- any payment on any affiliate subordinated indebtedness or permitted
subordinated indebtedness or any payment to purchase, redeem, defease or
otherwise acquire or retire for value any affiliated subordinated
indebtedness or permitted subordinated indebtedness
- any payment to REPG under the support services agreement and any payment
of fees to RES under the procurement and marketing agreement, and
- any restricted investment
Restricted payments exclude
- distributions or payments the subsidiary guarantors make to REMA
- distributions REMA makes of distributions or payments or other returns of
capital it receives, directly or indirectly, from an unrestricted
subsidiary
- distributions of the proceeds of the sale of the leased facilities, or
- repurchase or redemption of any of REMA's equity interest or subordinated
indebtedness solely in exchange for, or out of the net cash proceeds
from, the issuance or sale of equity interests in REMA or subordinated
indebtedness that it issues or incurs expressly for that purpose
The limitation on restricted payments will be suspended if any direct or
indirect domestic parent company, referred to as the parent guarantor, delivers
to the lease indenture trustees an unconditional guarantee of the lease
obligations, referred to as the parent guarantee. A parent guarantor must have,
as one of its principal businesses, the wholesale generation of electricity in
the United States. The delivery of a parent guarantee must be accompanied by an
opinion of counsel as to the validity and enforceability of such parent
guarantee. In order for the suspension of the restricted payment covenant
through the delivery of the parent guarantee to be effective, at the time such
guarantee is delivered
- the long-term unsecured senior debt of this parent guarantor must be
rated at least BBB by Standard & Poor's and Baa2 by Moody's
- the sum of such parent guarantor's common shareholders' equity and the
amount of affiliate subordinated indebtedness owed by it to affiliates
(other than its subsidiaries, REMA or REMA's subsidiaries) must be at
least $2 billion, and
- after giving effect to such parent guarantee and the suspension of such
covenant, each of Standard & Poor's and Moody's must confirm its then
current rating on the exchange certificates. Upon any assignment of
REMA's lease obligations described under the caption "Description of
Lease Documents -- The Leases -- Lease Assignment," this parent guarantee
of such lease obligations will terminate.
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The guarantee may also serve as qualifying credit support so long as the
long-term unsecured senior debt of the parent guarantor is rated at least BBB by
Standard & Poor's and Baa2 by Moody's.
The limitation on restricted payments will be reinstated in full and the
guarantee will no longer be considered qualifying credit support if
- customary bankruptcy events occur to the parent guarantor, or
- more than $50 million, escalated annually according to the consumer price
index, of the parent guarantor's indebtedness is accelerated
Limitation on Liens. REMA will not, and will not permit any of the
subsidiary guarantors to, create, incur, assume or otherwise cause or permit to
exist liens on its properties or assets or the subsidiary guarantors' properties
or assets. Exceptions to this limitation include
- liens in existence on the closing date, including those arising under the
lease documents
- liens by REMA to any of the subsidiary guarantors or by any of the
subsidiary guarantors to REMA or to any other subsidiary guarantor
- liens arising by reason of court judgments, decrees or orders that are
being contested in good faith and are appropriately bonded or reserved
against
- liens arising from taxes, duties or other governmental charges that are
not yet delinquent or are being contested in good faith or that could not
reasonably be expected to have a material adverse effect, as that term is
defined under "-- Special terms" beginning on page 96
- liens securing payment of worker's compensation or other insurance
- liens arising by operation of law (1) in favor of carriers, warehousemen,
landlords, mechanics, materialmen, laborers or employees incurred in the
ordinary course of business for sums that are not yet delinquent or are
being contested in good faith or (2) under any governmental approval
issued by any governmental authority required for our operation of
hydroelectric generation facilities
- liens in favor of contractors, mechanics, materialmen and suppliers
incurred in the ordinary course of business for sums that are not yet
delinquent or are being contested in good faith
- liens arising from easements, rights-of-way, zoning and similar covenants
and restrictions or similar encumbrances or title defects that do not in
the aggregate materially interfere with the ordinary course of business
of REMA or the subsidiary guarantors taken as a whole
- liens not permitted by the lease documents arising through the owner
lessor or owner participant or their affiliates
- liens consisting of, or under, operating agreements or other similar
arrangements for any property used by or useful to us not securing
indebtedness for borrowed money that could not reasonably be expected to
result in a material adverse effect
- purchase money liens that cover only the property being acquired
- liens on accounts receivable to secure indebtedness under a working
capital facility up to a maximum of $30 million, escalated annually
according to the consumer price index
- liens on property of the obligor securing or related to IRB indebtedness
- liens on equity interests in unrestricted subsidiaries
- some types of liens existing on assets at the time they are acquired or
at the time we acquire any business entity that owns such assets, if such
liens were not incurred, extended or renewed in contemplation of its
acquisition
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- other liens securing REMA's permitted indebtedness not in excess of 3% of
our consolidated net tangible assets, or
- extensions, renewals or refundings of permitted liens provided no
significant lease default or event of default would exist
Limitations on Merger, Consolidation or Sale of Substantially All
Assets. REMA will not, and will not permit any subsidiary guarantor to, directly
or indirectly
- consolidate or merge with or into any other person, or
- sell, transfer or otherwise dispose of all or substantially all of its
properties or assets to any person or persons in one or a series of
transactions
If, after giving effect to any of the items listed immediately below, no
significant lease default or lease event of default has occurred and is
continuing, then
- any subsidiary guarantor may merge into REMA in a transaction in which
REMA is the surviving entity
- any subsidiary guarantor may merge with another subsidiary guarantor
- any subsidiary guarantor may sell, transfer, lease or otherwise dispose
of its assets to REMA or another subsidiary guarantor, and
- REMA may consolidate or merge with, or sell substantially all its
properties to, any other person that is a corporation, limited liability
company or partnership if
- the surviving entity, if other than REMA, is organized under the laws of
the United States, any state or the District of Columbia and the
surviving entity, if other than REMA, assumes all of REMA's obligations
under the lease documents
- REMA provides to the pass through trustees, the indenture trustees, the
owner lessors and the owner participants an officer's certificate and a
legal opinion addressing customary matters in connection with the merger
or consolidation
- if the entity with whom REMA has consolidated or merged has any
indebtedness after giving effect to such consolidation or merger, REMA
would have been permitted to incur such indebtedness under the covenant
described under the caption "-- Limitations on Incurrence of
Indebtedness" at the time of such consolidation or merger after giving
effect to such consolidation or merger, and
- the owner participant receives assurances about adverse tax consequences
However, we may not consummate such transaction unless, after giving effect to
such transaction, Moody's and Standard & Poor's confirm the then current ratings
of the exchange certificates. In addition, the surviving entity in such
transaction must be rated at least BBB- by Standard & Poor's and Baa3 by Moody's
unless the owner participants consent to the transaction. These ratings
requirements do not apply to a consolidation or merger in which REMA is the
surviving entity.
Limitations on Sale of Assets. REMA will not, and will not permit any
subsidiary guarantor to, sell, transfer, lease or otherwise dispose of any
assets other than
- transfers of assets (including equity or indebtedness interests) among
REMA and any of the subsidiary guarantors
- sales of inventory, including fuel, products or obsolete items and other
similar dispositions and sales of energy, capacity and ancillary services
in the ordinary course of business
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- sales of assets required to be made under any change in law, regulation
or any imposition by the FERC or any other governmental entity
- sales or other dispositions of equity or indebtedness interests in
unrestricted subsidiaries
- restricted payments or restricted investments made in cash or cash
equivalents permitted under the covenant described under "Limitations on
Restricted Payments and Restricted Investments" above
- sales or other dispositions of assets not in excess of 3% of our
consolidated net tangible assets in any fiscal year, if such sales or
other dispositions do not, in the aggregate since August 24, 2000, exceed
10% of REMA's consolidated net tangible assets as of the beginning of
REMA's most recently ended full fiscal quarter. For purposes of this 10%
limitation, any such asset sales or transfers will be disregarded if
- the proceeds of the sale are invested in permitted businesses of REMA
and the subsidiary guarantors in the PJM market
- the proceeds of the sale are used by REMA or the subsidiary guarantors
to repay existing unsubordinated indebtedness of REMA or the subsidiary
guarantors
- the consideration received is retained by REMA or the subsidiary
guarantors, or
- such transfers are permitted by any other exception under this
limitation
- sales or other dispositions of the Hunterstown development site to
Reliant Energy Hunterstown LLC and the Portland development site to
Reliant Energy Portland LLC
- any transaction permitted under the covenants described under
"-- Limitations on Merger, Consolidation or Sale of Substantially All
Assets" beginning on page 92 or "Description of Lease Documents -- The
Leases -- Right to Exchange Leasehold Interest" below
- sales or dispositions of property that we certify are no longer used or
useful in the business of REMA or any of the subsidiary guarantors and
the disposal of which will not have a material adverse effect, and
- any other sale or disposition of assets if, after giving effect to such
events, Moody's and Standard & Poor's confirm their ratings of the
exchange certificates in effect immediately before such sale or other
disposition
However, notwithstanding these exceptions, REMA and the subsidiary
guarantors may not sell, transfer or otherwise dispose of any equity interest or
intercompany loan in any subsidiary guarantor unless
- such sale or other disposition is of all, but not less than all, of the
equity and indebtedness of such subsidiary guarantor, and any other
investments therein, held by REMA and the other subsidiary guarantors,
and
- any investment in REMA and the other subsidiary guarantors to be held by
such subsidiary guarantor after such sale or other disposition is
permitted to be held by an entity other than a subsidiary guarantor
Further, without the consent of the applicable owner lessor and owner
participant, REMA will not transfer any interest in the leased facilities, the
site lease and sublease, or the facility interests except as expressly permitted
by the lease documents.
Designation of Unrestricted Subsidiaries. At the time REMA acquires or
creates any direct or indirect subsidiary, it may designate such subsidiary as
an unrestricted subsidiary if such designation would not cause a lease default
or lease event of default, including under "-- Limitations on Restricted
Payments and Restricted Investments." Any subsidiary that it does not designate
as an unrestricted subsidiary when acquired or created will become a subsidiary
guarantor and will guarantee REMA's lease obligations. REMA may not designate a
subsidiary as an "unrestricted subsidiary" unless such subsidiary
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- has no indebtedness other than nonrecourse debt
- is not party to any arrangement with REMA or any subsidiary guarantor
unless the terms of such arrangement are no less favorable to REMA or
such subsidiary guarantor than those that could be obtained from persons
who are not REMA's affiliates, and
- is a person to which neither REMA nor any of the subsidiary guarantors
owe any indebtedness, other than a pledge of its or a subsidiary
guarantor's equity interest in such subsidiary and loans to such
subsidiary
If any unrestricted subsidiary fails to meet the requirements of an
unrestricted subsidiary, it will cease to be an unrestricted subsidiary under
the lease indentures, and REMA will deem any indebtedness of such subsidiary as
incurred by the subsidiary guarantors as of such date. If such indebtedness is
not permitted to be incurred as of such date under the covenant described under
"-- Limitations on Incurrence of Indebtedness," REMA will be in default of such
covenant.
REMA may at any time designate an unrestricted subsidiary to be a
subsidiary guarantor if any indebtedness of such subsidiary is permitted to be
incurred under the covenant described under "-- Limitations on Incurrence of
Indebtedness" and no significant lease default or lease event of default would
be created by such designation. Any such designation will be deemed to be an
incurrence of indebtedness by a subsidiary guarantor of any indebtedness of such
unrestricted subsidiary.
Limitations on Business Activities. REMA will not, and will not permit any
of the subsidiary guarantors to, engage in any business other than the
generation and sale of energy, capacity and ancillary services from nonnuclear
generation assets in the United States, and all activities related or incidental
to this business.
Limitations on Transactions With Affiliates. REMA will not, and will not
permit any of the subsidiary guarantors to
- sell, lease, transfer or otherwise dispose of any of its properties or
assets to an affiliate
- purchase any property or assets from an affiliate, or
- enter into or make or amend any contract, agreement, understanding, loan,
advance or guarantee with, to or for the benefit of an affiliate
unless such transaction or series of transactions is on terms that are no less
favorable to REMA or such subsidiary guarantor than would be available in a
comparable transaction with an unrelated third party. This covenant will not
apply to existing transactions, to transactions among REMA and the subsidiary
guarantors or to transactions with any affiliates expressly permitted by the
lease documents.
Limitations on Contingent Obligations. REMA will not, and will not permit
any of the subsidiary guarantors to, incur contingent obligations for the
obligations or liabilities of any other person other than
- contingent obligations of the subsidiary guarantors under the lease
documents
- guarantees of REMA's permitted indebtedness, excluding permitted
subordinated indebtedness
- contingent obligations incurred by endorsement of instruments in the
ordinary course of business
- contingent obligations of any subsidiary guarantor, other than
indebtedness
- contingent obligations under performance or payment guarantees and
indemnity and contribution agreements or similar arrangements, other than
for indebtedness, that REMA enters into in the ordinary course of
business and not for purely speculative purposes, which are related to
- procurement by RES or other persons of fuel or emissions allowances
directly related to facilities owned or leased by REMA or the subsidiary
guarantors, and
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- sales by RES or other persons of energy, capacity and ancillary services
from the facilities owned or leased by REMA or the subsidiary
guarantors, or
- contingent obligations arising under law
Maintenance of Existence and Properties. REMA will, and will cause each
subsidiary guarantor to,
- preserve, renew and keep in full force and effect its legal existence
- preserve, renew and keep in full force and effect the rights,
governmental approvals, privileges and franchises material to the conduct
of its business
- keep and maintain all property material to the conduct of its business in
good working order and condition, force majeure and ordinary wear and
tear excepted, and
- operate and maintain its property and assets in good condition, repair
and working order and in all material respects
- in compliance with all applicable laws, rules and regulations of any
governmental body having jurisdiction, unless such noncompliance could
not reasonably be expected to result in a material adverse effect,
subject to force majeure and ordinary wear and tear, and
- in accordance with prudent industry practice
These covenants do not prohibit any merger, consolidation, liquidation,
dissolution or other transaction permitted under the lease documents.
Maintenance of Tax Status. REMA will not, and will cause each subsidiary
guarantor not to, voluntarily take any action to cause it or any subsidiary
guarantor to be subject to taxation as a separate entity for federal income tax
purposes.
Compliance With Laws and Contractual Obligations. REMA will, and will cause
each of its subsidiaries to, comply with all laws, rules, regulations and orders
of any governmental authority, and all contractual obligations applicable to it
or its property, except where the failure to do so, individually or in the
aggregate, could not reasonably be expected to result in a material adverse
effect.
Insurance. REMA will maintain, and will cause each subsidiary guarantor to
maintain, with financially sound and reputable insurers, insurance for their
respective properties and business against such liabilities, casualties, risks
and contingencies and in such types and amounts as is maintained by persons
engaged in our businesses.
Limitations on Restrictive Agreements. REMA will not, and will not permit
any subsidiary guarantor to, subject to some exceptions, directly or indirectly,
enter into or permit to exist or become effective any consensual restriction on
the ability of any subsidiary guarantor to
- make restricted payments on any equity interests of such subsidiary
guarantor, or pay any indebtedness, held by or owed to REMA or any other
subsidiary guarantors
- make loans or advances to, or other investments in, REMA or any other
subsidiary guarantor
- transfer any of its assets to REMA or any other subsidiary guarantor, or
- create or assume any lien upon the properties, revenues or assets of REMA
or any subsidiary guarantor, whether owned at the time of the closing of
the lease transactions or acquired after that time, except for such liens
or restrictions existing under the lease documents
Credit Support. So long as the certificates are outstanding, REMA will
- maintain for the benefit of the owner lessor qualifying credit support
with an available amount equal to, for each lease, the greater of (1) the
periodic lease rent scheduled to be paid under such lease in the next six
months and (2) 50% of the periodic lease rent scheduled to be paid under
such
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lease in the next twelve months, and with a stated expiration date not
earlier than one year after the date of issuance of such qualifying
credit support.
- extend or replace any qualifying credit support at least 30 days before
its expiration date if such qualifying credit support expires before the
maturity date of the exchange certificates
- within 60 days of receiving knowledge of a credit support issuer's
failing to meet the credit criteria in the definition of "qualifying
credit support" in "-- Special terms" below, replace such qualifying
credit support with a replacement qualifying credit support issued by a
credit support issuer meeting such credit criteria, and
- within 90 days after a qualifying credit support is drawn upon by a lease
indenture trustee to pay scheduled rent or termination value, reinstate
the availability under the drawn qualifying credit support or provide new
qualifying credit support in the required amount
REMA currently meets its obligation to provide credit support through three
separate letters of credit provided by a commercial bank totalling approximately
$120.0 million.
Information Requirements. We will furnish to the pass through trustees and
the lease indenture trustees the following information:
- our audited annual consolidated financial statements and, if unrestricted
subsidiaries exceed specified financial thresholds, additional financial
statements
- our unaudited consolidated financial statements for each of the first
three fiscal quarters of our fiscal year and, if unrestricted
subsidiaries exceed specified financial thresholds, additional financial
statements
- an annual officer's certificate stating whether any significant lease
default or lease event of default exists and, if existing, describing the
significant lease default or lease event of default and stating the
remedial actions we propose to take, and
- prompt, written notice of any significant lease default or lease event of
default and other specified events
Each pass through trustee will, upon request, furnish all such information
directly to you and to prospective purchasers of exchange certificates
designated by the selling certificateholders or certificate owners. You may
request to receive such information for subsequent financial reporting periods
on an ongoing basis. REMA will furnish our audited and unaudited consolidated
financial statements described above upon request.
Non-discrimination Among Leases. REMA will pay scheduled rent and
termination value for each lease, pro rata under all leases, without preference
to any lease.
Special terms. We define below various terms that we use in the description
of covenants.
"affiliate subordinated indebtedness" means unsecured indebtedness of a
subsidiary guarantor that is
- issued to, and at all times after such issuance held by, us or any of
our affiliates, and
- expressly subordinated to the obligations of the subsidiary guarantors
under the leases, subsidiary guarantees and the other lease documents.
We have described these subordination provisions under the caption
"Outstanding Indebtedness -- Notes to Affiliated Entities."
"cash flow available for fixed charges" for any period means
- consolidated EBITDA for such period, minus
- capital expenditures made by REMA and the subsidiary guarantors during
such period other than capital expenditures financed with
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- subordinated indebtedness
- contributions to the equity of REMA
- permitted indebtedness described in the first bullet point of the
definition of permitted indebtedness
- IRB indebtedness, or
- consolidated EBITDA for an earlier period to the extent
- the amount of consolidated EBITDA was specifically reserved during
the earlier period for the capital expenditure, and
- the capital expenditure was at that time treated as being made during
an earlier period for purposes of this definition
"consolidated EBITDA" for any period means the sum of
- consolidated net income before interest and taxes, excluding any
distributions from or income of unrestricted subsidiaries, during such
period, plus
- lease rent expenses determined under generally accepted accounting
principles, or GAAP, to the extent such expenses reduce net income and
to the extent the payments related to such lease are included in clause
(2) under the definition of "fixed charge coverage ratio" below, plus
- all provisions for depreciation and amortization made by REMA and the
subsidiary guarantors during such period, plus
- expenses under the support services agreement and fees under the
procurement and marketing agreement during such period to the extent
such expenses and fees reduce net income and to the extent not paid
during such period in accordance with the terms of their subordination,
plus
- any other noncash charges and reserves of REMA and the subsidiary
guarantors made during such period to the extent they reduce net income,
minus
- any noncash charges and reserves of REMA and the subsidiary guarantors
released during such period to the extent they increase net income,
minus
- to the extent recognized in determining such net income, nonrecurring
gains, extraordinary gains or the cumulative positive effect of changes
in accounting principles, for such period, plus
- to the extent recognized in determining such net income, nonrecurring
losses, extraordinary losses or the cumulative negative effect of
changes in accounting principles, for such period
We will determine all amounts used to calculate consolidated EBITDA on a
consolidated basis in accordance with GAAP.
"consolidated net tangible assets" means, at any date of determination,
- the total net assets of REMA and the subsidiary guarantors determined in
accordance with GAAP, excluding, however, from the determination of
total net assets
- goodwill, organizational expenses, research and product development
expenses, intellectual property and similar intangibles,
- all deferred charges or unamortized debt discount and expenses,
- all reserves carried and not deducted from assets,
- cash held in sinking or other analogous funds established for the
purpose of payments in respect of equity interests or indebtedness,
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- any write-up in the book value of assets resulting from their
revaluation after the closing date, and
- any items not included in the bullet points above which are treated by
GAAP as intangibles, plus
- the aggregate purchase price of the leased facilities paid by the owner
lessors, plus
- the aggregate net book value of all asset sales or dispositions made by
REMA or the subsidiary guarantors since August 24, 2000 to the extent
that the proceeds thereof or other consideration received therefor are
not invested in our respective permitted businesses and are not retained
by us
"fixed charge coverage ratio" as defined in the lease documents, means, for
any period on a consolidated basis for REMA and the subsidiary guarantors but
excluding unrestricted subsidiaries, the ratio of
(1) cash flow available for fixed charges for such period, to
(2) the aggregate amount of scheduled rent payable under the leases plus
the aggregate of principal, interest and fees payable on all other
indebtedness, other than intercompany loans and subordinated
indebtedness and principal payments under a working capital facility if
such amounts remain available to be drawn under the working capital
facility or are refinanced under a replacement working capital
facility, plus payments to be made under any interest rate hedging
agreements minus payments to be received under any interest rate
hedging agreements for such period
"indebtedness" of any person means
- all indebtedness for borrowed money
- all obligations evidenced by bonds, debentures, notes or other similar
instruments
- all obligations to pay the deferred purchase price of property or
services, other than trade payables and accrued liabilities arising in
the ordinary course of business
- all indebtedness incurred under any conditional sale or other title
retention agreement for property acquired by such person
- all lease obligations
- all obligations, contingent or otherwise, under acceptance, letter of
credit or similar facilities securing indebtedness
- all unconditional obligations to purchase, redeem, retire, defease or
otherwise acquire for value any capital stock or other equity interests
or any warrants, rights or options to acquire such capital stock or
other equity interests at any time before July 2, 2027
- all indebtedness of any other person of the type referred to in the
preceding bullet points guaranteed by such person or for which such
person must otherwise (including under any keepwell, makewell or similar
arrangement) become directly or indirectly liable, and
- all third-party indebtedness of the type referred to in the preceding
bullet points secured by any lien or security interest on property owned
by the person whose indebtedness is being measured, even though such
person has not assumed or become liable for the payment of such
third-party indebtedness. The amount of such obligation will be deemed
to be the lesser of the net book value of such property or the amount of
the obligation so secured.
"intercompany loans" means loans to REMA or any subsidiary guarantor by
REMA or any subsidiary guarantor. REMA or the subsidiary guarantor must continue
to hold such indebtedness at all times.
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"IRB indebtedness" means indebtedness in an aggregate principal amount of
up to $100 million escalated annually by the consumer price index
- for pollution control revenue bonds, industrial revenue bonds or similar
instruments, and
- that, if the obligor is a subsidiary guarantor, provides a material
economic benefit to REMA and the subsidiary guarantors taken as a whole
that REMA cannot otherwise obtain without incurring material costs or
significant delays
To be IRB indebtedness, at the time the indebtedness is incurred, each of
Moody's and Standard & Poor's must confirm its then current rating on the
exchange certificates.
"lease obligations" means
- indebtedness for lease obligations that are required to be capitalized
for financial reporting purposes
- nonrecourse indebtedness of the lessor in noncapital leases or, if such
amount is indeterminable, the present value of rent obligations of the
lessee under such lease, and
- the principal amount of financial obligations under any synthetic lease,
tax retention operating lease, off-balance sheet loan or similar
off-balance sheet financing product, where such transaction is
considered borrowed money indebtedness for tax purposes but is
classified as an operating lease under generally accepted accounting
principles
"material adverse effect" means a material adverse effect on
- our business, assets, results of operations or financial condition,
taken as a whole
- our ability to perform our obligations under the lease documents
- the validity or enforceability of the lease documents, the liens granted
under the lease documents or the material rights and remedies provided
by the lease documents, or
- the leased facilities
"nonrecourse indebtedness" means indebtedness of an unrestricted subsidiary
- for which neither REMA nor any subsidiary guarantor
- provides credit support that constitutes indebtedness
- is directly or indirectly liable as a subsidiary guarantor, or
otherwise, that constitutes indebtedness, other than solely as a
result of recourse to stock of an unrestricted subsidiary as permitted
under the last bullet point under this definition of "nonrecourse
indebtedness," or
- is the lender, unless the indebtedness constitutes an investment under
the sixth and seventh bullet points of the definition of "restricted
investment" or a restricted investment permitted under "-- Limitations
on Restricted Payments and Restricted Investments"
- that, if in default, would not
- permit, upon notice, lapse of time or both, any holder of any other
indebtedness of REMA or any of the subsidiary guarantors to declare a
default on the other indebtedness
- cause the payment of the other indebtedness to be accelerated or
payable before its stated maturity, or
- provide such holder the right to take enforcement action against an
unrestricted subsidiary, and
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- that is issued or incurred under a written agreement or instrument that
expressly provides that the lenders will not have any recourse to the
stock or assets of REMA or any subsidiary guarantor, other than stock of
an unrestricted subsidiary, for payment of such indebtedness
"permitted indebtedness" means any of the following items of indebtedness:
- indebtedness, if, at the time such indebtedness is incurred
- each of Moody's and Standard & Poor's confirms its then current rating
on the exchange certificates
- no significant lease default or a lease event of default has occurred
and is continuing unless the proceeds from the indebtedness are used to
cure the significant lease default or lease event of default.
"Significant lease default," when used in this prospectus, means a
default under any of the leases based on nonpayment, bankruptcy,
violation of the covenants described below or acceleration of
indebtedness. We have described the applicable covenants for this bullet
point under
- "-- Limitations on Incurrence of Indebtedness"
- "-- Limitations on Restricted Payments and Restricted Investments"
- "-- Limitations on Merger, Consolidation or Sale of Substantially All
Assets"
- "-- Limitations on Sale of Assets," and
- (to the extent relating to liens in respect of borrowed money)
"-- Limitation on Liens" and
- we deliver an officer's certificate to the pass through trustee
certifying as to the above bullet points
- indebtedness for letters of credit, surety bonds or performance bonds or
guarantees issued in the ordinary course of business
- unsecured indebtedness that is expressly subordinated to REMA's lease
obligations and the other lease documents. Payments on this indebtedness
will be restricted by the covenant described in "Description of the
Exchange Certificates -- Covenants -- Limitations on Restricted Payments
and Restricted Investments" and subordinated as described in "Outstanding
Indebtedness -- Notes to Affiliated Entities."
- additional indebtedness that does not exceed the greater of, at any time
outstanding, (1) the sum of the amount of the required credit support at
such time and $50 million and (2) $125 million. These amounts will be
escalated annually based upon the consumer price index, or
- indebtedness represented by hedging agreements entered into in the
ordinary course of business and not for purely speculative purposes
"pro forma coverage ratio", as defined in the lease documents, means a
projection of the fixed charge coverage ratio over the period for the six months
(or, initially, the period from August 24, 2000) ending on any periodic rent
payment date commencing January 2, 2001, applying the same methodology as the
computation of the projected fixed charge coverage ratio
"projected fixed charge coverage ratio" means a projection of the fixed
charge coverage ratio over a specified period. REMA will prepare the projected
fixed charge coverage ratio based upon assumptions consistent in all material
respects with the applicable contracts to which REMA or any of the subsidiary
guarantors are a party, historical operating results and REMA's good faith
projections of our future revenues and operating expenses. REMA will prepare
those projections from time to time based on the then-existing or reasonably
expected regulatory and market environments in the markets in which we are
operating our facilities and upon the assumption that no early redemption or
prepayment of the lessor
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notes will be made before the stated maturity of such lessor notes, unless such
projection is prepared for the purpose of incurring indebtedness specifically
for the purpose of such redemption or payment.
"qualifying credit support" means
- uncollateralized irrevocable stand-by letters of credit or surety bonds
with the applicable owner lessor as their beneficiaries and assigned to
the applicable lease indenture trustee, if (1) the bank or surety issuing
such letter of credit or surety bond has a long term unsecured debt
rating of at least A- by Standard & Poor's and A3 by Moody's, and (2) in
the case of surety bonds, each of Standard & Poor's and Moody's confirms
its then current rating on the certificates before the first use of the
surety bonds, or
- an unconditional guarantee by REPG or any affiliate of REPG, other than
REMA or any subsidiary of REMA, provided that the long term unsecured
debt of such guarantor is rated at least BBB by Standard & Poor's and
Baa2 by Moody's
"restricted investment" means any investment other than
- investments in REMA or subsidiary guarantors
- various types of cash equivalents
- any investment by REMA or any subsidiary guarantor in a person, if as a
result of such investment such person becomes a subsidiary guarantor or
is merged, consolidated or amalgamated with or into, or transfers or
conveys substantially all of its assets to, or is liquidated into, REMA
or a subsidiary guarantor
- acquisitions of assets solely in exchange for the issuance of REMA's
equity securities
- hedging arrangements entered into in the ordinary course of business and
not for purely speculative purposes
- investments from proceeds of equity contributions or subordinated
indebtedness that REMA incurs specifically to make those investments
- up to $10 million (escalated for inflation) in other investments by REMA
and the subsidiary guarantors
- investments outstanding at the closing
- investments in persons operating and administering the operations of the
Conemaugh and Keystone stations, and
- several other investments that are expressly permitted by the lease
documents
EVENTS OF DEFAULT AND REMEDIES
An event of default under the pass through trust agreements means the
occurrence and continuance of an event of default under any lease indenture. For
a description of lease indenture event of defaults, please read "Description of
Lease Documents -- The Lessor Notes -- Lease Indenture Events of Default" below.
Subject to the rights of the owner lessor, owner participant and their
affiliates, if a lease indenture event of default occurs and is continuing, the
applicable indenture trustee may exercise the rights and remedies available to
it under the lease indenture and applicable law. These rights and remedies
include the right to, and upon instructions from a majority in interest of the
certificateholders the indenture trustee must, declare the unpaid principal,
with accrued interest and premium, if any, of the lessor notes to be immediately
due and payable. In the case of a lease indenture event of default constituting
a bankruptcy event, such principal and interest will automatically become due
and payable. The indenture trustee's rights and remedies include, if a lease
event of default under the related lease occurs and is continuing, the
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remedies of the applicable owner lessor under the lease, described below under
"The Lease Documents -- The Leases -- Consequences of Lease Events of Default."
The indenture trustee may take possession of the collateral described below
under "Description of Lease Documents -- The Lessor Notes -- Security" and
exercise all remedies available to a secured party under applicable law and
exclude the owner lessor and the owner participant from the exercise of such
remedies. If the indenture trustee sells the applicable leased facilities and
facility site sublease as its remedy, such sale will be free and clear of any
rights of the owner lessor and the owner participant other than the right to
redeem provided by law. The indenture trustee may not exercise any remedies
under the lease indenture that affect REMA's rights under the lease unless a
lease event of default has occurred and is continuing.
If a lease indenture event of default occurs arising out of a lease event
of default, the indenture trustee may not exercise any remedy under the
applicable lease indenture that could divest the owner lessor of its ownership
interest in the leased facilities under the lease unless the indenture trustee
is exercising its remedies under the lease to dispossess REMA of the applicable
leased facilities. If the indenture trustee is stayed or otherwise prevented by
operation of law from exercising such remedies, the indenture trustee will not
divest the owner lessor of its interest in such assets until the earlier of
- six months after such stay or other preventing circumstance began, or
- the date the applicable leased facilities are repossessed under the
related lease
If a lease event of default occurs because an owner lessor fails to pay the
equity portion only of periodic rent, the indenture trustee may not exercise
remedies under the applicable lease indenture for six months unless the owner
lessor or owner participant consents to the indenture trustee declaring a lease
event of default under the related lease.
If a lease indenture event of default occurs because a change of control
accelerates the lessor notes, a change of control premium will be payable, equal
to 1% of the principal amount of the lessor notes.
MODIFICATION OF THE PASS THROUGH TRUST AGREEMENTS
REMA may enter into a supplemental trust agreement for the following
reasons without the consent of any certificateholders:
- to evidence that another person is succeeding REMA and assuming its
obligations under the pass through trust agreements
- to add to or modify REMA's covenants for the protection of the
certificateholders
- to cure any ambiguous or correct any defective or inconsistent provisions
of a pass through trust agreement or supplemental trust agreement if such
action does not adversely affect the interests of the certificateholders
- to surrender any right or power conferred in a pass through trust
agreement on REMA
- to correct or amplify the description of trust property or the conveyance
of such property to the pass through trustee
- to evidence and provide for a successor pass through trustee
- to modify, eliminate or add provisions required or permitted by the Trust
Indenture Act of 1939, or TIA, for a qualified indenture
- to modify, amend or supplement any provision in a pass through trust
agreement to reflect the assumption and substitution of any lessor note
by REMA under the terms of the lease indenture
- to add, eliminate or change any provision of a pass through trust
agreement that does not adversely affect the interests of the
certificateholders
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If REMA obtains the consent of the applicable owner lessor and the
certificateholders who represent a majority in interest in a pass through trust,
it may add, change or delete any provisions to the pass through trust agreements
or modify any rights and obligations of the certificateholders. However, REMA
may not, unless it obtains the consent of each certificateholder that is
affected,
- reduce the amount of, or delay the timing of, payments to the applicable
pass through trustee on the lessor notes or distributions on any exchange
certificate
- change any date of payment on any exchange certificate or the place of
payment
- make distributions payable in currency other than that provided for in
the exchange certificates
- impair the right of any certificateholder to bring suit to enforce any
payment that is due
- permit the disposition of any lessor note held in the related pass
through trust
- permit the creation of a lien on the related pass through trust property
- deprive any certificateholder of the benefit of ownership of the lessor
notes held in the related pass through trust or the lien of the related
lease indenture, except as provided in the pass through trust agreements
- reduce the percentage of the aggregate fractional undivided interest of
the related pass through trust that is required to approve any
supplemental trust agreement or reduce the percentage required for any
waiver, or
- cause the related pass through trust to become taxable as an
"association" or to fail to qualify as a fixed investment trust for
federal income tax purposes
MODIFICATION OF INDENTURE
Each indenture trustee may, without the consent of the holders of the
lessor notes, enter into any indenture or supplemental indentures or execute any
amendment, modification, supplement, waiver or consent to any other lease
document related to such indenture
- to evidence that another person is succeeding as manager of the owner
lessor, that a co-manager is being appointed, that a separate or
co-trustee is being appointed or that the indenture trustee is being
removed and/or succeeded and to define the rights, powers, duties and
obligations conferred upon any such manager or co-manager, trustee or
trustees or co-trustees
- to correct, confirm or amplify the description of any property at any
time subject to the lien of such lease indenture, or to convey, transfer,
assign, mortgage or pledge any property to or with such indenture trustee
- to evidence the creation and issuance of any additional lessor notes
related to the lease indenture and to establish the form or terms of such
lessor notes
- to correct ambiguous or incorrect provisions of, or to add to or modify
any other provisions and agreements in, such lease indenture or any other
lease document related to the lease indenture, if it will not, in the
judgment of such indenture trustee, materially adversely affect the
interests of the holders of such lessor notes
- to grant to such indenture trustee for the benefit of the holders of such
lessor notes any additional rights, remedies, powers, authority or
security that may be lawfully granted and that are not contrary or
inconsistent with such lease indenture
- to add to or modify the covenants or agreements that REMA or the
applicable owner lessor must observe that are not contrary to such lease
indenture
- to add lease indenture events of default for the benefit of the holders
of such lessor notes
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- to surrender any right or power of the applicable owner lessor provided
that such owner lessor has given its consent
- to effect REMA's assumption of any or all of the lessor notes as
described elsewhere in this prospectus, if REMA's obligations under the
related lease and the related participation agreement, if still
applicable following termination of the relevant lease, will continue in
full force and effect for the benefit of the indenture trustees and the
holders of the lessor notes
- to comply with SEC requirements or any exchange on which the exchange
certificates are listed or any regulatory body
- to modify, eliminate or add provisions to any lease documents to the
extent necessary to qualify or continue the qualification of the lease
indenture or the pass through trust agreements under the TIA or similar
federal statute enacted after the closing date and to add to the lease
indenture other provisions expressly permitted by the TIA
- to effect the assumption of the lessor notes by the owner participant in
accordance with the participation agreement
- to amend the schedules to the leases in connection with some rent
adjustments, and
- to otherwise amend, modify or supplement, or provide a waiver of or
consent relating to, such lease indenture or any other lease document
related to the lease indenture provided that the indenture trustee may
only enter into such supplemental indenture, amendment, modification,
supplement, waiver or consent if, in its judgment, it does not materially
adversely affect the interests of the holders of such lessor notes. The
indenture trustee may not make any amendment, modification, supplement,
waiver or consent that modifies some covenants in the participation
agreements and the provisions of the participation agreements relating to
assignment of the leases without the consent of the holders of a majority
in interest of the lessor notes, other than modifications having no
adverse effect on the interests of the holders of such lessor notes.
The indenture trustee, upon the written direction of the majority in
interest of the holders of the lessor notes, will execute an amendment to add
to, change or eliminate provisions as specified in such directions, provided
that the indenture trustee may not enter into any supplement to or amendment of
such lease indenture or the related assigned lease documents, or any waiver or
modification of or consent to the terms of such supplement or amendment, without
the consent of the holders representing 100% of the outstanding principal amount
of such lessor notes, that
- reduces the percentage of holders of such lessor notes required to take
or approve any action under the lease indenture
- changes the amount or the timing of any payment on such lessor note or
changes the rate or manner of calculation of interest payable on any such
lessor note
- alters or modifies the payment provisions relating to the manner of
payment or order of priorities for distributions under the lease
indenture as between the holders of such lessor notes and the related
owner lessor
- reduces the amount of periodic rent or termination value below the amount
sufficient to pay the aggregate principal of and interest on all such
lessor notes or extends the time for payment of such periodic rent or
termination value, except as expressly provided in the related lease, or
changes any of the circumstances under which periodic rent or termination
value is payable, or
- consents to any assignment of the related lease if REMA will be released
from its obligation to pay periodic rent and termination value, except as
expressly provided in this prospectus, or otherwise releases REMA from
its obligations to pay periodic rent or termination value or changes the
absolute and unconditional character of such obligations
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TERMINATION OF THE PASS THROUGH TRUSTS
REMA's obligations and those of the pass through trustee created by the
pass through trust agreements will terminate when the pass through trustee
distributes to the certificateholders all amounts required by the pass through
trust agreements and disposes of all property held in the pass through trusts.
The pass through trustee will mail to each certificateholder notice of the
termination of the related pass through trust, the amount of the proposed final
payment and the proposed date on which it will distribute such final payment.
The pass through trustee will distribute the final distribution to each
certificateholder when such certificateholder surrenders its exchange
certificates at the office or agency of the pass through trustee specified in
the notice of termination.
THE PASS THROUGH TRUSTEE
Bankers Trust Company acts as the pass through trustee for each pass
through trust. The pass through trustee may hold exchange certificates in its
own name.
The pass through trustee may resign as pass through trustee for any or all
of the pass through trusts at any time. If the pass through trustee resigns,
REMA will appoint a successor pass through trustee. If the pass through trustee
ceases to be eligible to continue as the pass through trustee under the pass
through trust agreements or becomes insolvent, REMA may remove the pass through
trustee, or any certificateholder who has held an exchange certificate for at
least six months may, on behalf of himself and all others similarly situated,
petition any court of competent jurisdiction for the removal of such pass
through trustee and the appointment of a successor pass through trustee. Any
resignation or removal of the pass through trustee and appointment of a
successor pass through trustee will not become effective until acceptance of the
appointment by the successor pass through trustee.
REMA will pay the pass through trustee's fees and expenses. REMA will
indemnify the pass through trustee for any loss, liability or expense related to
the pass through trust, and for any tax related to the pass through trust,
incurred without the gross negligence, willful misconduct of, or noncompliance
or breach by, the pass through trustee, except for any tax attributable to the
pass through trustee's compensation for serving as the pass through trustee.
BOOK-ENTRY, DELIVERY AND FORM
We will arrange for the pass through trusts to issue exchange certificates
in exchange for original certificates currently represented by one or more fully
registered global certificates. The exchange certificates will be represented by
one or more fully registered global certificates, and will be deposited upon
issuance with DTC or a nominee of DTC.
The pass through trusts will issue exchange certificates in certificated
form in exchange for original certificates, which were issued originally in
certificated form.
Book-Entry Procedures for the Global Certificates. We have provided the
following descriptions of the operations and procedures of DTC, Euroclear and
Clearstream, Luxembourg solely as a matter of convenience. These operations and
procedures are solely within the control of the settlement systems and are
subject to change by them from time to time. None of REMA, the initial
purchasers or the pass through trustee takes any responsibility for these
operations or procedures, and you are urged to contact the relevant system or
its participants directly to discuss these matters.
DTC has advised us as follows:
- DTC is a limited purpose trust company organized under the laws of the
State of New York, a "banking organization" within the meaning of the New
York Banking Law, a member of the Federal Reserve System, a "clearing
corporation" within the meaning of the Uniform Commercial Code, as
amended, and a "clearing agency" registered pursuant to Section 17A of
the Exchange Act
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- DTC holds securities that its participants deposit with DTC and
facilitates the settlement among participants of securities transactions,
such as transfers and pledges, in deposited securities through electronic
book-entry changes in participants' accounts, thereby eliminating the
need for physical movements of securities certificates
- Direct participants include securities brokers and dealers (including the
initial purchasers), banks and trust companies, clearing corporations and
some other organizations
- Indirect access to the DTC system is also available to others such as
securities brokers and dealers and banks and trust companies that clear
through or maintain a custodial relationship with a direct participant,
either directly or indirectly. Investors who are not participants may
beneficially own securities held by or on behalf of DTC only through
participants or indirect participants, and
- The rules applicable to DTC and its participants are on file with the SEC
We expect that under the procedures established by DTC
- upon deposit of each global certificate with DTC or its custodian, DTC
will credit on its internal system the accounts of direct participants
designated by the initial purchasers with portions of the face amount of
the global certificate, and
- ownership of the exchange certificates will be shown on, and the transfer
of ownership thereof will be effected only through, records maintained by
DTC for interests of direct participants and the records of direct and
indirect participants for the interests of persons other than
participants
The laws of some jurisdictions may require that purchasers of securities
take physical delivery of such securities in definitive form. Accordingly, the
ability to transfer interests in the exchange certificates represented by a
global certificate to such persons may be limited. In addition, because DTC can
act only on behalf of its participants, who in turn act on behalf of persons who
hold interests through participants, the ability of a person having an interest
in exchange certificates represented by a global certificate to pledge or
transfer such interest to persons or entities that do not participate in DTC's
system, or otherwise to take actions in respect of such interest, may be
affected by the lack of a physical definitive security for such interest.
So long as DTC or its nominee is the registered owner of a global
certificate, DTC or such nominee, as the case may be, will be considered the
sole owner or holder of the exchange certificates represented by the global
certificate for all purposes under the pass through trust agreements. Except as
provided below, you will not
- be entitled to have exchange certificates represented by such global
certificate registered in your name
- receive or be entitled to receive physical delivery of certificated
exchange certificates, and
- be considered the owners or holders of the exchange certificates under
the pass through trust for any purpose, including the giving of any
direction, instruction or approval to the pass through trustee
Accordingly, you must rely on the procedures of DTC. If you are not a
participant or an indirect participant in DTC, you must rely on the procedures
of the participant through which you own your interest to exercise any rights of
a holder of exchange certificates under the pass through trust agreement, or
such global certificate.
We understand that under existing industry practice, if we request any
action of holders of exchange certificates, or you desire to take any action
that DTC, as the holder of the global certificate, is entitled to take, DTC
would authorize the participants to take such action and the participants would
authorize holders owning through such participants to take such action or would
otherwise act upon the instruction of such holders.
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Neither REMA nor the pass through trustee will have any responsibility or
liability for any aspect of the records relating to or payments made on account
of exchange certificates by DTC, or for maintaining, supervising or reviewing
any records of DTC relating to such exchange certificates.
The pass through trustee will make payments on the exchange certificates
represented by a global certificate to DTC or its nominee, as the case may be,
as the registered holder of the global certificate. Under the terms of the pass
through trust agreements, REMA and the pass through trustee may treat the
persons in whose names the exchange certificates, including the global
certificates, are registered as the owners for the purpose of receiving payments
and for any and all other purposes whatsoever. Accordingly, neither REMA nor the
pass through trustee has or will have any responsibility or liability for the
payment of such amounts to owners of beneficial interests in a global
certificate, including principal, premium, if any, liquidated damages, if any,
and interest. We expect that DTC or its nominee, upon receipt of any payment on
the exchange certificates represented by a global certificate, will credit
participants' accounts with payments in amounts proportionate to their
respective beneficial interests in the global certificate as shown in the
records of DTC or its nominee. We also expect that payments by participants to
owners of beneficial interests in the global certificate held through such
participants will be governed by standing instructions and customary practice as
is now the case with securities held for the accounts of customers registered in
the names of nominees for such customers. The participants will be responsible
for those payments.
Transfers between participants in DTC will be effected in accordance with
DTC's procedures and will be settled in same-day funds.
Cross-market transfers between the participants in DTC, on the one hand,
and Euroclear or Clearstream, Luxembourg participants, on the other hand, will
be effected through DTC in accordance with DTC's rules on behalf of Euroclear or
Clearstream, Luxembourg, as the case may be. However, such cross-market
transactions will require delivery of instructions to Euroclear or Clearstream,
Luxembourg, as the case may be, by the counterparty in such system in accordance
with the rules and procedures and within the established deadlines (Brussels
time) of such system. Euroclear or Clearstream, Luxembourg, as the case may be,
will, if the transaction meets its settlement requirements, deliver instructions
to its respective depositary to take action to effect final settlement on its
behalf by delivering or receiving interests in the global certificates in DTC,
and making or receiving payment in accordance with normal procedures for
same-day funds settlement applicable to DTC. Euroclear participants and
Clearstream, Luxembourg participants may not deliver instructions directly to
the depositories for Euroclear or Clearstream, Luxembourg.
Because of time zone differences, the securities account of a Euroclear or
Clearstream, Luxembourg participant purchasing an interest in a global
certificate from a participant in DTC will be credited, and any such crediting
will be reported to the relevant Euroclear or Clearstream, Luxembourg
participant, during the securities settlement processing day (which must be a
business day for Euroclear and Clearstream, Luxembourg) immediately following
the settlement date of DTC. Cash received in Euroclear or Clearstream,
Luxembourg as a result of sales of an interest in a global security by or
through a Euroclear or Clearstream, Luxembourg participant to a participant in
DTC will be received with value on the settlement date of DTC but will be
available in the relevant Euroclear or Clearstream, Luxembourg cash account only
as of the business day for Euroclear or Clearstream, Luxembourg following DTC's
settlement date.
Although DTC, Euroclear and Clearstream, Luxembourg have agreed to the
foregoing procedures to facilitate transfers of interests in the global
certificates among participants in DTC, Euroclear and Clearstream, Luxembourg,
they are under no obligation to perform or to continue to perform such
procedures. Such procedures may be discontinued at any time. Neither REMA nor
the pass through trustee will have any responsibility for the performance by
DTC, Euroclear or Clearstream, Luxembourg or their respective participants or
indirect participants of their respective obligations under the rules and
procedures governing their operations.
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Certificated Exchange Certificates. REMA will issue certificated exchange
certificates to each person that DTC identifies as the beneficial owner of the
exchange certificates represented by the global certificates upon surrender by
DTC of the global certificates if
- DTC is no longer willing or able to act as a depositary for the global
certificates, or DTC ceases to be registered as a clearing agency under
the Exchange Act, and a successor depositary is not appointed within 90
days of such notice or cessation
- REMA determines not to have the exchange certificates represented by a
global certificate, or
- upon the occurrence of other events as provided in the pass through trust
agreement.
Upon any such issuance, the pass through trustee is required to register
such certificated exchange certificates in the name of such person or persons
(or the nominee of any thereof) and cause the same to be delivered to such
person(s).
Neither REMA nor the pass through trustee will be liable for any delay by
DTC, its nominee or any direct participant or indirect participant in
identifying the beneficial owners of the related exchange certificates. Each
such person may conclusively rely on, and will be protected in relying on,
instructions from DTC or its nominee for all purposes, including the
registration and delivery, and the respective principal amounts, of the exchange
certificates to be issued.
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DESCRIPTION OF LEASE DOCUMENTS
THE LESSOR NOTES
General. The lessor notes were issued in three series under each lease
indenture between the applicable owner lessor and Bankers Trust Company, as
indenture trustee.
Each owner lessor leased facility interests consisting of a generating
facility or undivided interest in a generating facility to REMA under the
related lease. REMA must pay rent and other amounts to each owner lessor
sufficient to pay the principal, premium and interest on the related lessor
notes. Such payments do not have to be sufficient to pay principal and interest
that are payable upon a lease indenture event of default not caused by a lease
event of default or any premium payable by the applicable owner participant or
the owner lessor because such owner participant or owner lessor purchases or
redeems the lessor notes. The lessor notes are not REMA's obligations, and
neither REMA nor the subsidiary guarantors have guaranteed the lessor notes, but
REMA may assume the obligations of the applicable owner lessor under the lessor
notes as described elsewhere in this prospectus. The indenture trustee will pay
to the applicable owner lessor all payments in excess of the amounts required to
make payments on the applicable lessor notes, and such owner lessor will
distribute such payments to the applicable owner participant. As a result, these
payments will not be available to be distributed to the certificateholders,
except in some cases when a lease indenture event of default occurs. REMA's
rental obligations under the leases and the other lease documents are its
general obligations.
Security. The lessor notes issued by an owner lessor are secured by a
first-priority security interest on behalf of the indenture trustee in the owner
lessor's rights and interests in the applicable collateral:
- the relevant leased facility interest
- the applicable lease, facility site lease, facility site sublease, and
the other lease documents (excluding the tax indemnity agreement and the
participation agreement) to which such owner lessor is a party or under
which it has rights, including the right to receive payments of periodic
rent under the lease (other than the excepted payments and insurance
proceeds payable solely to such owner lessor under liability insurance
REMA maintains under such lease), and
- the subsidiary guarantees, the lease pledge agreements and the credit
support
So long as no lease indenture event of default has occurred and is
continuing, the applicable owner lessor may exercise all of its rights under the
lease documents, with some exceptions (including amendments, waivers,
modifications and consents under specified provisions of some of such lease
documents). The owner lessors' rights, however, will exclude the right to
receive payments of rent and some other amounts due under the leases, which
payments will be made directly to the applicable indenture trustee. The
assignment by each owner lessor to the applicable indenture trustee of its
rights under the related lease and other lease documents also will exclude some
rights of such owner lessor, including rights relating to indemnification by
REMA for various matters and insurance proceeds payable solely to such owner
lessor under liability insurance maintained by REMA under such lease. For a
description of various other rights of the owner lessors, please read "-- The
Leases -- Lease Events of Default."
Funds, if any, held from time to time by the indenture trustee under the
lease indentures will be invested by the indenture trustee, at the direction and
at the risk and expense of each owner lessor, in cash equivalents.
Limitation of Liability. The lessor notes are not obligations of, or
guaranteed by REMA, the owner participants (and their direct or indirect parent,
referred to as their owners), the owner lessors' manager or their affiliates.
None of the owner lessors, the owner participants, the owner lessor's manager or
their affiliates will be personally liable to any holder of a lessor note for
any amounts payable under any lessor notes. All payments of principal of,
premium, if any, and interest on the lessor notes (other than payments made in
connection with an optional redemption or purchase by the applicable owner
lessor or owner
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participant) will be made only from the assets subject to the lien of the
related lease indenture or the income and proceeds received by the indenture
trustee from such assets (including rent payable by REMA under the related
lease).
Redemption of Lessor Notes
The lessor notes are redeemable under the circumstances described below.
The pass through trustee will make distributions to the certificateholders on
the date and in the amount paid in that redemption.
Mandatory Redemption with Make Whole Premium. An owner lessor will redeem
all lessor notes relating to a facility interest, in whole but not in part, if
REMA terminates a lease of the applicable facility interest before its
expiration. Such termination must be made upon six months notice following
REMA's determination that such facility interest is
- economically or technologically obsolete other than as a result of
- a change in law, regulation or tariff of general application, or
- any governmental entity having or claiming jurisdiction over us or the
leased facility imposing any conditions or requirements upon the
continued effectiveness or renewal of any license or permit required for
the operation or ownership of that facility
- surplus to REMA's needs, or
- no longer useful in REMA's trade or business for any reason
REMA may not terminate a lease for the above reasons before August 24, 2006
without the consent of the applicable owner lessor. Before REMA terminates a
lease, it will deliver to the indenture trustee and the pass through trustee an
officer's certificate stating the basis on which it is terminating the lease.
The pass through trustee will furnish the officer's certificate to the
certificateholders upon request.
Any redemption of lessor notes under this provision will be made at the
principal amount of the lessor notes, together with all accrued and unpaid
interest to the redemption date, plus a make whole premium.
For purposes of this provision, the term "make whole premium" means, for
any lessor note being redeemed, an amount equal to the discounted present value
of all principal and interest payments scheduled to become due after the date of
the redemption of the lessor note, less the outstanding principal amount of that
lessor note. The make whole premium may not be less than zero. The discounted
present value will be calculated using a discount rate equal to the sum of
- the yield to maturity on the U.S. Treasury security with an average life
equal to the remaining average life of such lessor note and trading in
the secondary market at the price closest to par, and
- 50 basis points
If there is not a U.S. Treasury security with an average life equal to the
remaining average life of such lessor note, the discount rate will be calculated
using a yield to maturity calculated on a straight-line basis (rounding to the
nearest calendar month) from the yields to maturity for the two U.S. Treasury
securities with average lives most closely corresponding to the remaining life
of the lessor note and trading in the secondary market at the price closest to
par.
Mandatory Redemption Without Make Whole Premium. An owner lessor will
redeem all lessor notes relating to a facility interest, in whole but not in
part, at the principal amount of the lessor notes, together with all accrued and
unpaid interest to the redemption date, but without any premium, if REMA
terminates a lease of any facility interest
- because an event of loss (as defined under "-- The Leases -- Events of
Loss" below) has occurred. If the event of loss results from a regulatory
event of loss, REMA may assume the applicable lessor
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notes and purchase the owner lessor's interest in the affected facility
interest, in which event the lessor notes will not be redeemed.
- upon six months notice after August 24, 2006 and so long as there is no
lease event of default, if REMA determines in good faith that such
facility interest has become economically or technologically obsolete as
a result of
- a change in law, regulation or tariff of general application, or
- any governmental entity imposing any conditions or requirements upon the
availability, continued effectiveness or renewal of any license or
permit required for the operation or ownership of such facility interest
that makes such facility interest economically or technologically
obsolete
- because a change in law makes it illegal for REMA to continue such lease
or to make payments under the lease, and REMA cannot restructure the
applicable lease documents and the lease transactions to comply with such
change in law, unless it assumes the applicable lessor notes and
purchases the owner lessor's interest in the affected facility, in which
event the lessor notes will not be redeemed, or
- because each of the following conditions exists:
- one or more events outside our control give rise or could reasonably be
expected to give rise to indemnity obligations by REMA under the lease
documents
- REMA can avoid its indemnity obligations in whole or in part if it
terminates the lease and the owner lessor sells the leased facilities,
and
- the present value of the avoided indemnity obligation payments exceeds
3% of the original purchase price of such facility interest
No such redemption will occur if the indemnitee waives its right to the
indemnification payment or the owner participant arranges for the payment
thereof such that the indemnity obligations do not exceed such 3% threshold
or if REMA assumes the lessor notes and purchases the applicable owner
lessor's interest in the facility interest.
A "regulatory event of loss" will occur if elected by the applicable owner
participant and only if any of the following conditions arises that can be cured
by the termination of the related lease and transfer of the related leased
facilities to REMA:
- any governmental authority regulates the rate of return on the applicable
owner participant's (or its owner) or owner lessor's interest in the
applicable facility interest, any lease document or the applicable lease,
or
- any governmental authority otherwise regulates such owner participant (or
its owner), or the applicable owner lessor, as a public utility in a way
that, in the reasonable opinion of such owner participant, is burdensome
and in each case such regulation arises because the owner lessor or owner
participant is participating in the transaction contemplated by the lease
documents and not because of
- other investments, loans or other business activities of the owner
participant or its affiliates in respect of equipment or facilities
similar in nature to the leased facilities or in any other electrical,
steam, cogeneration or other energy or utility related equipment or the
general business or other activities of the owner participant or its
affiliates or the nature of any of their properties, or
- a failure of the owner participant to perform routine, administrative or
ministerial actions if the performance of those actions would not subject
the owner participant or any affiliate to any material adverse
consequence in the reasonable opinion of the owner participant acting in
good faith
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REMA will cooperate with the applicable owner lessor and owner participant
to take reasonable measures to alleviate the source or consequence of any
regulation constituting a regulatory event of loss if taking those measures does
not result in any adverse consequences to the applicable owner lessor or owner
participant (or affiliate).
Optional Redemption. The lessor notes may be redeemed, in whole or in part,
at the principal amount of the lessor notes, together with all accrued and
unpaid interest to the date of redemption, plus a make whole premium.
Assumption of Lessor Notes by REMA. So long as no significant lease default
or lease event of default has occurred and is continuing, REMA may assume the
lessor notes on a full recourse basis and acquire the facility interests of the
relevant owner lessor if it terminates a lease (1) as a result of a regulatory
event of loss as described above under "Mandatory Redemption Without Make Whole
Premium" or (2) in connection with a burdensome event described below under
"-- The Leases -- Termination for Burdensome Events." As a condition to such
assumption, the lease indenture trustee must have received an opinion of counsel
stating, among other things, that
- the assumption agreement and the applicable lessor notes constitute
REMA's legal, valid and binding obligations, subject to some exceptions,
and specified tax assurances, and
- the lien of the lease indenture will continue to be a first-priority
perfected lien on the collateral
In addition, the lessor notes may only be assumed if, after the assumption,
Standard & Poor's and Moody's confirm the then-existing credit rating of the
exchange certificates after giving effect to such assumption.
Assumption by the Owner Participant. While a lease indenture event of
default resulting from a lease event of default continues, but before any sale
by the lease indenture trustee of any of the collateral, the applicable owner
participant has the right, but not the obligation, to assume, on a recourse
basis as joint obligor, all but not less than all of the obligations of the
owner lessor under the lessor notes.
This right to assume is subject to several conditions including, among
others, that:
- the owner participant is then a direct or indirect, wholly owned
subsidiary of PSEG Resources Inc., which is currently a subsidiary of
Public Service Enterprise Group
- no lease indenture event of default exists other than the then-existing
lease events of default
- after giving effect to such assumption, the lien of the lease indenture
remains a valid and perfected lien on the collateral
- the owner participant, the owner lessor and the lease indenture trustee
will amend the lease indenture to give effect to such assumption, to
delete any cross-default to REMA or the subsidiary guarantors and to add
a cross-default to the assumption agreement
- the owner participant has cured all monetary defaults and, after giving
effect to the assumption and such payment, no lease indenture event of
default is continuing, and
- such assumption will not result in a downgrade of the then existing
credit ratings of the exchange certificates and Standard & Poor's and
Moody's have confirmed that after such assumption, the exchange
certificates will be rated at least BBB+ by Standard & Poor's and Baa1 by
Moody's.
Payments to the Lease Indenture Trustee. So long as the lessor notes are
outstanding, REMA will make all payments of periodic rent and termination values
under the leases directly to the lease indenture trustee. The lease indenture
trustee will pay to the pass through trustee all amounts then due on the lessor
notes, and the pass through trustee will distribute such amounts to the
certificateholders.
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Lease Indenture Events of Default. Each of the following is a lease
indenture event of default:
- a lease event of default, as defined under "-- The Leases" below, under
the applicable lease, except for
- customary excepted payments reserved to the applicable owner lessor,
owner participant and other participants in the transaction, and
- REMA's failure to maintain required insurance so long as the insurance
it actually maintains constitutes prudent industry practice
- a payment default by the owner lessor under the applicable lease
indenture related to the payment of principal or interest due on the
lessor notes that continues unremedied for five business days
- failure of
- the applicable owner lessor to perform any of its covenants in such
lease indenture
- the applicable owner lessor or owner participant to perform any of its
covenants under the applicable lease documents, or
- the applicable owner participant's guarantor to perform any material
covenant under such owner participant's parent guarantee,
and the failure is not remedied within 30 days after written notice of
such failure. If such failure can be remedied, the cure period will be
extended for up to 180 days so long as such party diligently pursues such
remedy and such failure is reasonably capable of being remedied within
such period
- any representation or warranty made by the owner participant, the owner
lessor or the owner lessor's manager in the applicable lease document or
in any officer's certificate delivered under such lease document or by
the owner participant's parent in its parent guarantee proves to have
been incorrect as of the date made in any material respect and the
representation or warranty continues to be material and is unremedied for
30 days after receipt by such party of written notice. If the condition
can be remedied, the cure period will be extended for up to an additional
120 days, so long as such party diligently pursues such remedy and such
condition is reasonably capable of being remedied within such period, and
- customary events of bankruptcy and insolvency, whether voluntary or
involuntary, of the owner lessor, the owner participant or the owner
participant's guarantor, provided the related guaranty is still required
to be in effect. Any involuntary event must continue 60 days after it
begins in order to be a lease indenture event of default.
Owner Lessors' Right to Purchase the Lessor Notes. Each owner lessor may
purchase all, but not less than all, the lessor notes outstanding under the
applicable lease indenture to which it is a party at a price equal to the
outstanding principal amount of such lessor notes, together with accrued and
unpaid interest to the date of purchase and all outstanding fees and expenses
owed to or incurred by the applicable indenture trustee, if
- any of the following occur:
- a lease indenture event of default, which also constitutes a lease event
of default, has occurred and continues for at least 90 days, and the
indenture trustee does not accelerate the lessor notes or exercise any
remedy under the related lease to dispossess REMA of the leased assets
- a lease indenture event of default occurs and continues and, as a
result, the indenture trustee accelerates or, a majority in interest of
certificateholders directs the indenture trustee to accelerate, the
lessor notes, and the indenture trustee has not rescinded such
acceleration, or
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- within the last 30 days the indenture trustee has provided REMA and the
applicable owner participant written notice that it intends, within not
less than 30 days, to dispossess REMA of the leased assets under the
lease because a lease indenture event of default that also constitutes a
lease event of default has occurred and is continuing
- no lease indenture event of default has occurred and is continuing under
such lease indenture other than any such event of default that is solely
the result of a lease event of default occurring, and
- the applicable owner lessor has notified the indenture trustee in writing
that it intends to purchase its lessor notes
THE LEASES
Term and Rent. The basic term under each lease commenced on August 24, 2000
and will continue for the following approximate periods for each facility
interest lease:
- 33.75 years for the Conemaugh station facility interest
- 33.75 years for the Keystone station facility interest, and
- 26.25 years for the Shawville station facility interest
REMA may renew each lease for one or more renewal lease terms. We refer to
the basic lease term plus all renewal lease terms for such lease as the "lease
term" for such lease.
Rent payable under each lease will consist of periodic rent payable for the
basic lease term and renewal rent payable for any renewal lease term. We refer
collectively to these rent payment obligations as "rent."
REMA will pay periodic rent under each lease on each January 2 and July 2
during each lease's basic lease term.
Use and Maintenance. REMA will or, in the case of the Conemaugh and
Keystone stations will exercise all its rights under the owners agreements, to
maintain the facility interests, in good condition, repair and working order and
in all material respects
- in accordance with prudent industry practice
- in compliance with all applicable laws, rules and regulations of any
governmental body, unless such noncompliance could not reasonably be
expected to result in a material adverse effect or involve any (1) danger
of foreclosure or other loss or imposition of a lien on any facility
interests or the impairment of its use, operation or maintenance in any
material respect, (2) risk of criminal liability to the owner participant
and other participants in the transaction, the owner lessor, the owner
manager, the lease indenture trustee or pass through trustee or any of
their affiliates or (3) material risk of any such person incurring any
material adverse effect, and
- in accordance with the terms of all insurance policies REMA is required
to maintain under the leases
REMA will make all necessary repairs, renewals, replacements, betterments
and improvements to the facility interests as in its reasonable judgment may be
necessary to operate the facility interests in accordance with the lease
documents. For the leases of the Conemaugh station facility interest and the
Keystone station facility interest, however, REMA will exercise all rights,
power, elections and options available to it under the owners agreements.
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In the ordinary course of maintenance, service, repair or testing, REMA or
the operator of its facilities, at no cost to the applicable owner lessor, may
remove any components of the applicable facility if REMA
- replaces such components with replacement components that are free and
clear of all liens (other than permitted liens) and in as good an
operating condition as that of the components replaced assuming the
components replaced were maintained in accordance with the applicable
lease, and
- performs such replacement in a manner that does not diminish the then
current value, residual value, utility or remaining useful life of the
applicable facility by more than a de minimis amount
REMA may not, however, remove any part, component or portion of the
facilities without replacing it if such removal or replacement would diminish
the value, utility or remaining useful life of such facility interests or
facilities by more than a de minimis amount.
Modifications to the Leased Facilities. REMA may, subject to the owners
agreements related to the Conemaugh and Keystone stations, at its own expense,
make additions, modifications, alterations and improvements to the facilities
that it considers desirable in the proper conduct of its business. REMA will or,
in the case of the Conemaugh and Keystone stations, will exercise all its rights
under the owners agreements to, make all modifications required by any
applicable law, rule or regulation, subject to contest. REMA cannot make any
optional modifications that diminish the current value, residual value,
remaining useful life or utility of the facilities by more than a de minimis
amount.
Modifications that can be removed without causing damage to the facilities,
except for severable modifications that are required modifications or that are
financed through the related lease, will remain REMA's property. All required
modifications, non-severable modifications and modifications that are financed
through the related lease will automatically become the property of the
applicable owner lessor and subject to the applicable lease upon being attached
to the facility.
If REMA elects to finance modifications to the facilities through a lease,
the applicable owner participant may finance such modifications in whole or in
part with additional equity. REMA will not be obligated to accept, and the owner
participant will not be obligated to provide, any such equity financing. At
REMA's request, the applicable owner lessor will, however, agree to cooperate
with REMA to finance such modifications, and will, at REMA's request, be
obligated to finance such nonseverable modifications and modifications required
by law through the issuance of additional lessor notes, which will rank equally
with the then outstanding lessor notes under the applicable lease indenture if
various conditions are met, including the following:
- the additional debt has a final maturity date no later than the later of
- the final maturity of the then-existing exchange certificates related to
the lessor notes issued under such lease indenture, and
- the date that is two years before the last day of the basic lease term
and will be fully repaid out of the additional periodic rent as adjusted
under the lease
- appropriate adjustments to periodic rent and termination value
(determined without regard to any tax benefits associated with such
improvements, unless the applicable owner participant is financing the
equity) are made to protect the applicable owner participant's expected
return
- no significant lease default or lease event of default under the
applicable lease has occurred and is continuing unless the modifications
to be constructed with such financing will cure such significant lease
default or lease event of default and such modifications will be made in
compliance with the lease documents, and
- such financing is for an amount not less than $20 million, and not
greater than 100% of the costs of the modifications being financed. The
aggregate balance of all lessor notes for such facility interest
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may not exceed 87% of the projected fair market value of such facility
interest, taking into account such modifications
Notwithstanding the preceding, REMA may, subject to its ability to incur
additional indebtedness and the limitation on liens below, fund modifications to
any leased facility other than through the respective lease.
Liens. REMA will not, directly or indirectly, create, incur, assume or
permit to exist any liens or other encumbrances on the facility interest,
facility site, components of the facility or its interest in the related lease
or any lease document, except for permitted liens.
Each owner lessor will not, directly or indirectly, create, incur, assume
or permit to exist any lien or encumbrance on its respective facility, facility
interest, facility site or lease that arises as a result of
- claims against such owner lessor or its manager that are not related to
or are in violation of any lease document or the transactions
contemplated by any lease document
- any act or omission of such owner lessor or its manager or any of their
respective affiliates that is in breach of any covenant or agreement of
such owner lessor in the lease documents
- taxes imposed upon such owner lessor or its manager or any of their
respective affiliates for which REMA has not indemnified it under the
lease documents
- claims against or affecting such owner lessor, its manager or any of
their respective affiliates arising out of the voluntary or involuntary
transfer by such person of any portion of its interest in the applicable
owner lessor or the facility or facility interest, other than under the
lease documents
Insurance. REMA will, at its cost and expense, maintain insurance including
- all risk property insurance customarily carried by prudent operators of
coal-fired electric generating facilities of comparable size and risk to
the applicable facility and in an amount equal to REMA's portion of the
maximum probable loss of the applicable facility, and
- general liability insurance, automobile liability insurance, sudden and
accidental pollution liability coverage and contractual liability
coverage insuring against claims for bodily injury and property damage to
third parties arising out of the ownership, operation, maintenance,
condition and use of the facilities and the facility sites
Lease Assignment. REMA may assign its interest in all (but not less than
all) of the leases, leased assets and the other lease documents to an entity
meeting the criteria described below if
- Moody's and Standard & Poor's both confirm that the assignment will not
result in a downgrade of the then-existing credit rating of the exchange
certificates, and
- the exchange certificates are rated at least Baa2 by Moody's and BBB by
Standard & Poor's
REMA may assign its interest in the Keystone station or the Conemaugh
station and in the leases and lease documents relating to the Keystone station
or the Conemaugh station to an entity described below if
- concurrently with such assignment, the then-existing exchange
certificates are exchanged for new classes of exchange certificates,
representing (1) an undivided interest in lessor notes relating to the
assigned lease and (2) an undivided interest in lessor notes relating to
the non-assigned lease, and
- Moody's and Standard & Poor's both confirm that such assignment will
result in a credit rating for the classes of the new exchange
certificates representing the assigned interests and the non-assigned
interests at least one level above the then-existing credit rating of the
existing exchange certificates, and such credit ratings are at least as
high as the initial ratings by each of Standard & Poor's and Moody's of
the exchange certificates
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Any assignment described above must be to a person or entity that
- has, or a party that guarantees its obligations under the lease documents
assigned to it has, credit ratings from Standard & Poor's and Moody's
equal to or higher than BBB and Baa2, respectively
- unless the owner participant gives its consent, has, or a party that
guarantees its obligations under the lease documents assigned to it has,
a tangible net worth of at least $750 million after giving effect to such
assignment, and
- to the extent the assignor is the operator of the facilities, is an
experienced operator of coal-fired electric generating facilities, or its
operating obligations under the applicable leases are guaranteed by or
contracted to such an operator
Upon the transferee's assumption of REMA's obligations under the leases and
the corresponding lease documents, neither REMA nor the subsidiary guarantors
will have any further liability or obligation related to the assigned interests,
except any liability and obligation relating to the period before such
assignment.
Any assignment described in this section must comply with some additional
conditions including, among others:
- receipt of an opinion of counsel stating that all regulatory approvals
necessary for such assignment have been obtained
- after giving effect to such assignment, no lease event of default or
significant lease default has occurred and is continuing and no other
default has occurred and is continuing as a result of such assignment
- the assignment will not result in a regulatory event of loss
- the assignee is not involved in material litigation with the owner
participants or their affiliates, unless the affected owner participant
has provided its prior written consent, and
- REMA will pay, on an after-tax basis, all reasonable documented
out-of-pocket expenses of the applicable owner lessor, owner participant,
lease indenture trustee and the pass through trustee in connection with
such assignment
Subleases. REMA may sublease its leasehold interest in any of the leased
facilities without consent, subject to some conditions, including, among others,
that
- the total annual rent payments payable under the sublease must be at
least equal to 80% of the total annual rent payments under the respective
lease, and
- the present value of all scheduled rent payments under the sublease,
together with any payment made at the closing of the sublease, must be at
least equal to 90% of the present value of the periodic rents payable
under the respective leases (in each case discounted at an incremental
borrowing rate in accordance with Financial Accounting Standards Board
Statement 13, Accounting for Leases)
REMA must obtain the consent of the applicable owner lessor, owner participant,
lease indenture trustee and pass through trustee unless
- the sublessee
- is a solvent entity not subject to bankruptcy proceedings
- is not involved in material litigation with the applicable owner
participant or any affiliate, and
- is an experienced, reputable operator of coal-fired electric
generating facilities, or its operating and maintenance obligations
under the sublease are guaranteed by or are contracted to be performed
by such an operator
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- the sublease does not extend beyond the scheduled expiration of the term
of the applicable lease, the sublease may be terminated if the lease
terminates early and the sublease is expressly subject and subordinate
to the lease
- all terms and conditions of the applicable lease and the other lease
documents remain in effect, and REMA remains fully and primarily liable
for its obligations under the lease documents
- no lease event of default or significant lease default has occurred and
is continuing and no other default has occurred as a result of such
sublease
- the sublease prohibits further assignment or subletting, and
- the sublease requires the sublessee to operate and maintain the
facility, or undivided interest, or cause the same to be operated and
maintained, in a manner consistent with the applicable lease
Right to Exchange Leasehold Interest. REMA may, no more than once, exchange
- its interest in its lease of undivided interests in the Keystone station
for a lease of additional undivided interests in the Conemaugh station,
or
- its interest in its lease of undivided interests in the Conemaugh station
for a lease of additional undivided interests in the Keystone station
with the consent of the owner participant. This consent will not be unreasonably
withheld or delayed. The owner lessor, the indenture trustee, the pass through
trustee and the owner participant will execute any documents and take such other
action as REMA may reasonably request in connection with any such exchange.
Conditions to such exchange include, among others, that
- Moody's and Standard & Poor's confirm that the exchange will not result
in a downgrade of the then current rating on the exchange certificates,
and the exchange certificates are rated at least BBB by Standard & Poor's
and Baa3 by Moody's
- REMA has acquired the undivided interests in the facility being exchanged
- all other governmental authorizations necessary to consummate the
exchange are reasonably satisfactory in form and substance to the owner
participant, its owner, the pass through trustee and REMA and are in full
force and effect, other than those which the failure to obtain or
maintain would not reasonably be expected to have a material adverse
effect, and
- each owner participant and its owner has received an appraisal and a tax
opinion in form and substance satisfactory to the owner participant, and
the property substituted in the exchange has no less than the current
value, residual value, utility and remaining useful life of the
applicable undivided interest being exchanged
Termination for Burdensome Events. REMA may terminate any lease and
purchase the applicable facility interest on the termination date it specifies
in a notice delivered within a year after it learns of the following
circumstances
- as a result of a change in law, it becomes illegal for REMA to continue
that lease or make payments under the lease, and it cannot restructure
the transactions contemplated by the lease documents to comply with such
change in law to the reasonable satisfaction of the parties to the lease
documents including the indenture trustee and the pass through trustee,
or
- each of the following conditions exists:
- one or more events outside our control give rise or we reasonably expect
could give rise to indemnity obligations by REMA under the lease
documents
- REMA can avoid its indemnity obligations in whole or in part if it
terminates the lease and the owner lessor sells the leased facilities,
and
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- the present value of the avoided indemnity obligation payments exceeds
3% of the original purchase price of such facility interest
REMA will not be able to terminate a lease if the indemnitee waives its right to
the indemnification payment or the owner participant arranges for the payment
such that they do not exceed such 3% threshold. If REMA gives notice to an owner
lessor that it intends to terminate the lease, the owner lessor may, at its
option, retain the facility interest and its rights in the facility site
interest. REMA may, at its option, make an offer to purchase such interests from
the owner lessor for an amount at least equal to the termination value. If the
owner lessor sells such interests to REMA, REMA will pay the owner lessor the
amount of its offer, plus
- unpaid amounts due under the lease, and
- reasonable costs and expenses of the owner lessor, the owner participant,
the lease indenture trustee and the pass through trustee
If the owner lessor rejects REMA's offer or elects to retain such
interests, REMA will pay the amounts in the two bullet points above. If the
owner lessor receives no offer from REMA and does not elect to retain such
interests, the lease will continue and will remain in effect.
If REMA terminates a lease under the circumstances described above and
purchases the applicable facility interest and facility site interest, REMA will
have the right to assume the applicable lessor notes if no significant lease
default or lease event of default has occurred and is continuing, subject to the
satisfaction of some other conditions. In such event, REMA's obligation to pay
the purchase price will be satisfied to the extent REMA assumes the outstanding
principal amount of and accrued interest on the lessor notes. No termination of
a lease under the circumstances described above will be effective, regardless of
whether the owner lessor elects to sell or retain the facility interest in
connection with such termination, unless and until
- REMA assumes the related lessor notes in accordance with the provisions
of the lease indenture, or
- the owner lessor pays all outstanding principal and accrued interest on
such lessor notes and all other amounts due under the lease indenture on
the proposed date of termination
Termination for Obsolescence. If REMA gives at least six months' prior
notice to the applicable owner lessor, indenture trustee and the pass through
trustee and such notice contains a certification by its management committee (or
other governing body), REMA may terminate the applicable lease at any time on or
after August 24, 2006 if
- no lease event of default has occurred and is continuing
- the applicable facility interest is economically or technologically
obsolete as a result of
- a change in law, regulation or tariff of general application, or
- any governmental entity imposing any conditions or requirements upon the
continued effectiveness or renewal of any license or permit required for
the operation or ownership of such facility interest, or
- the applicable facility interest is otherwise economically or
technologically obsolete, or the facility interest is surplus to REMA's
needs or no longer useful in its trade or business, as it determines in
good faith, including as a result of
- a change in the markets for the wholesale purchase and/or sale of
energy, or
- any material abrogation of power purchase agreements
If REMA terminates a lease early, it will, as the nonexclusive agent for
the applicable owner lessor, use commercially reasonable efforts to obtain bids
for and sell such owner lessor's interest on the
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termination of the lease. All proceeds of such sale will be for the account of
the owner lessor but will be paid directly to the indenture trustee. The
purchaser of such interests may not be REMA, any of its affiliates or any third
party with whom it or one of its affiliates has an arrangement to use or operate
the facilities to generate power for REMA's benefit or the benefit of its
affiliates after the termination of the lease. On the termination date, REMA
will pay such owner lessor the amount by which the applicable termination value
exceeds the sale price of such interest, plus
- if REMA terminates the lease under the third bullet point above, the
scheduled redemption premium arising from a redemption of the lessor
notes
- unpaid amounts due under the lease, and
- reasonable costs and expenses of the owner lessor, the owner participant,
the lease indenture trustee and the pass through trustee
Under some circumstances under which the lessor notes are redeemed for any
of the above reasons, the owner lessor is permitted to retain its interest in
the appropriate facility.
Events of Loss. Each of the following events constitutes an event of loss
under each lease:
(1) the loss of the facility or use of the facility due to destruction
or damage that is beyond economic repair or that renders the facility
permanently unfit for normal use
(2) any damage to the facility that results in an insurance settlement
for the total loss or an agreed constructive or a compromised total loss of
the facility
(3) seizure, condemnation, confiscation or taking of, or requisition
of title to the facility, or use of the facility, by any governmental
authority if all permitted appeals have been exhausted. Appeals during the
occurrence of some lease events of default require the consent of the
applicable owner participant's owner. No appeals must extend beyond the
earlier of the date that is
- one year after the loss of such title, or
- 36 months before the end of the basic lease term or any renewal lease
term then in effect or elected by us
Such requisition will include a requisition of use but not of title
only if such requisition of use continues beyond the basic lease term or
any renewal term then in effect or elected, and
(4) a regulatory event of loss (as defined in "Description of Lease
Documents -- Redemption of Lessor Notes -- Mandatory Redemption Without
Make Whole Premium" above) has occurred if REMA and the applicable owner
participant, or any affiliate, and owner lessor have agreed to cooperate
and to take reasonable measures to alleviate the source or consequence of
any regulation constituting a regulatory event of loss and there are no
adverse consequences to the applicable owner lessor or owner participant or
any affiliate as a result of such cooperation or the taking of reasonable
measures
If an event of loss described in (1) or (2) above occurs, REMA may elect to
rebuild and restore the facility, subject to some specified conditions.
If REMA elects not to rebuild the facility following the occurrence of an
event of loss described in (1) or (2) above, or any other event of loss occurs,
it must terminate the lease and pay the owner lessor
- the applicable termination value
- unpaid amounts due under the lease, and
- reasonable costs and expenses of the owner lessor, the owner participant
and its owner, the lease indenture trustee and the pass through trustee
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When REMA terminates the lease, all of the owner lessor's right, title and
interest in the facility interest will be transferred to REMA.
If a regulatory event of loss occurs and REMA assumes the applicable lessor
notes in accordance with the provisions of the lease indenture, its obligation
to pay the applicable termination value will be reduced by the outstanding
principal amount of the lessor notes it assumes so long as no significant lease
default or lease event of default has occurred and is continuing and all other
conditions required for its assumption of the lessor notes are satisfied.
REMA may rebuild or restore the facilities only if there is no lease event
of default continuing and it satisfies the following conditions, among others:
- REMA delivers a reasonably acceptable report of an independent engineer
stating that it is technologically feasible and economically viable to
rebuild and restore the affected facility and that such rebuilding or
restoring can be completed at least 36 months before the end of the basic
lease term or 12 months before the expiration of any renewal lease term
- REMA delivers a reasonably acceptable appraisal of an independent
appraiser stating that after it rebuilds or restores the affected
facility, the affected facility interest will have at least the same
value, residual value, utility and useful life as such facility interest
had immediately before the event of loss and such facility interest will
not become "limited use" property for federal income tax purposes
- REMA demonstrates that it possesses adequate financial resources, from
insurance proceeds or otherwise, to rebuild or restore the affected
facility
- REMA delivers a certificate stating that it reasonably believes that it
will have sufficient funds to continue to pay periodic rent and renewal
rent while it rebuilds and restores the affected facility, and
- REMA begins rebuilding or restoring the affected facility as soon as
practicable after it notifies the owner lessor, the indenture trustee and
the pass through trustee of its intent and, in any event, within 24
months after the event that caused the event of loss
Lease Events of Default. Each of the following is a lease event of default:
(1) REMA fails to pay periodic rent, renewal rent or termination value
when due, and such failure continues, after application of the proceeds of
any credit support, unremedied for five business days
(2) REMA fails to make any other payment under the lease documents,
other than excepted payments unless the applicable owner participant has
declared a default on such excepted payments, within 30 days after it
receives written notice of such default from the applicable owner
participant, owner lessor, lease indenture trustee or the pass through
trustee
(3) REMA fails to maintain insurance in the amounts and on the terms
required by such lease
(4) REMA or any subsidiary guarantor fails to perform any covenant or
agreement set forth in the applicable participation agreement or lease
indenture or the pass through trust agreements or in any other lease
document (other than any covenant referred to in (1), (2), (3), (6), (7),
(13) or (14) of this section or its covenants in the tax indemnity
agreement), in any material respect, and it does not remedy such failure
within 30 days after it receives written notice of such failure from the
applicable owner participant, owner lessor, lease indenture trustee or the
pass through trustee. If REMA cannot remedy such condition within 30 days,
it may extend the period to remedy such condition up to an additional 180
days if it diligently pursues a remedy and it is reasonably capable of
remedying such condition within the additional 180 days and the
continuation of such failure during this extension would not have a
material adverse effect. REMA's failure to operate and maintain the leased
assets as provided in the second bullet point under "Use and Maintenance"
above will not
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constitute an event of default if it prosecutes in good faith a test,
challenge, appeal or proceeding of such failure that does not involve any
- danger of foreclosure, sale, forfeiture or loss of, any part of the
leased assets or the impairment of the use, operation or maintenance
of the leased facilities in any material respect, or
- risk of any criminal liability being asserted against the owner
lessor, owner participant (or its owner) or their affiliates or a
material risk of material adverse effect being incurred by the
applicable owner participant (or its owners) or owner lessor (or its
owners), the indenture trustee or the pass through trustee, including
being subject to regulation as a public utility under applicable law
Additionally, REMA's failure to operate and maintain the leased assets in
accordance with the above referenced second bullet point of "Use and
Maintenance" will not constitute an event of default if
- such failure to comply cannot be immediately remedied
- REMA is taking all reasonable action to remedy such noncompliance,
and
- such noncompliance does not involve any danger or risk described in
the two bullet points of the previous paragraph
Such noncompliance, or such test, challenge or appeal or proceeding to
review may not extend beyond the date 36 months before the scheduled expiration
of the lease term for each facility.
(5) any representation or warranty of REMA or any of the subsidiary
guarantors in the lease documents (other than some tax representations) was
incorrect in any material respect when made, and REMA or the subsidiary
guarantor does not remedy such condition within 30 days after REMA or the
subsidiary guarantor receives written notice of such condition. If REMA, or
the subsidiary guarantor, cannot remedy such condition within 30 days, REMA
may extend the period to remedy such condition up to an additional 120 days
if REMA or the subsidiary guarantor diligently pursue a remedy and REMA or
the subsidiary guarantor is reasonably capable of remedying such condition
within the additional 120 days and the continuation of such condition
during such extension would not have a material adverse effect.
(6) REMA fails to perform or observe, in any material respect, any of
the covenants described under the following subsections under "Description
of the Exchange Certificates -- Covenants":
- Limitations on Incurrence of Indebtedness
- Limitations on Restricted Payments and Restricted Investments
- Limitations on Merger, Consolidation or Sale of Substantially All
Assets
- Limitations on Sale of Assets
- Insurance
- Limitation on Liens, or
- Limitations on Contingent Obligations
and REMA does not remedy such failure within 30 days
(7) REMA fails to comply with the restriction on assignment under
"-- Lease Assignment" or fails to comply with the covenant described under
"-- Right to Exchange Leasehold Interest"
(8) any lien on a material portion of the trust indenture estate in
favor of the indenture trustee ceases to be enforceable and of the same
effect and priority as was purported to be created by the lease documents
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(9) customary bankruptcy events of default occur to REMA or any of the
subsidiary guarantors that are significant subsidiaries (as defined in Rule
1-02 of Regulation S-X under the Securities Act of 1933)
(10) a judgment or decree is entered against REMA or any of the
subsidiary guarantors for $50 million or more, and such liability has not
been paid or is not fully covered by insurance, and such judgment or decree
is not vacated, discharged, stayed or bonded pending appeal within 30 days
(11) more than $50 million of REMA or the subsidiary guarantor's
indebtedness is accelerated
(12) a change of control occurs
(13) REMA fails to perform its obligation under the covenant described
under "Description of the Exchange Certificates -- Covenants -- Credit
Support" to replace or reinstate the credit support or otherwise fails to
comply with such covenant, and
(14) any of REMA, RENH, RERC or any other person party to the
subordinated working capital facility described under "Outstanding
Indebtedness -- Subordinated Working Capital Facility" or the related RENH
facility fails to perform its obligations thereunder in any material
respect and such failure continues for 30 days or such subordinated working
capital facility or the RENH facility is terminated or modified in any
material respect or otherwise fails to be in full force and effect in all
material respects (other than in accordance with its terms) and is not
reinstated within 30 days thereafter
"Change of control" means the consummation of any transaction or series of
related transactions that will result in any person or group, in each case as
defined in the Exchange Act, other than
- REMA's parent, Reliant Energy, or any of its successors into which
Reliant Energy has consolidated or merged or any person to which Reliant
Energy has transferred all or substantially all of its assets
- any person who becomes a beneficial owner, directly or indirectly, of
more than 50% of the voting power of Reliant Energy or any other person
described in the first bullet point above, or
- any direct or indirect subsidiary of Reliant Energy, or any other person
described in the two bullet points above,
becoming the beneficial owner, directly or indirectly, of more than 50% of
REMA's voting power, or acquiring, by contract or otherwise, the power to direct
or cause the direction of its management or policies. A change of control will
not be deemed to have occurred if Moody's and Standard & Poor's confirm that the
then-existing ratings of the exchange certificates will not be lowered as a
result of any of these events.
If any of the events described in the definition of "change of control"
occurs, but such event is not deemed a change of control because Moody's and
Standard & Poor's confirm that the then-existing ratings of the exchange
certificates will not be lowered as a result of such event, REMA will amend the
definition of "Reliant Energy" in the leases to mean the entity or entities
Moody's and Standard & Poor's relied upon in confirming the then-existing
ratings of the exchange certificates.
In addition, if
- any person becomes a beneficial owner, directly or indirectly, of more
than 50% of the voting power of Reliant Energy
- Reliant Energy merges into or consolidates with another entity and
Reliant Energy is not the surviving entity, or
- Reliant Energy transfers all or substantially all of its assets to
another person,
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the definition of "Reliant Energy" in the leases will be amended to refer to the
person so acquiring more than 50% of the voting power of Reliant Energy, such
surviving entity or such transferee, as applicable.
In addition, for purposes of the change of control provision, the test for
a change of control will cease to refer to Reliant Energy and will instead refer
to the entity that satisfies the first bullet point below, if
- the unsecured, senior long-term debt of REPG, or of any person that
directly or indirectly owns beneficially 100% of the voting stock of REPG
(other than Reliant Energy), is rated at least Baa2 by Moody's and BBB by
Standard & Poor's
- the common equity of REPG or of the person that directly or indirectly
owns beneficially 100% of the voting stock of REPG (other than Reliant
Energy) is listed for trading on a national securities exchange or quoted
on an automated quotation system of a registered securities association
- RES and each other subsidiary of Reliant Energy that is a party to a
procurement and marketing agreement or a support services agreement with
us is or becomes a direct or indirect wholly owned subsidiary of REPG or
such person, and
- REPG or such person beneficially owns, directly or indirectly, 100% of
the voting stock of REMA
Consequences of Lease Events of Default. Subject to the assignment of
rights to the indenture trustee, upon the occurrence and continuance of any
lease event of default, the applicable owner lessor may declare the lease to be
in default. Except as provided below, such owner lessor may at any time after
such declaration or after a bankruptcy default, so long as REMA has not cured
all outstanding lease events of default, exercise one or more of the remedies
set forth in such lease, including
- seeking specific performance of REMA's obligations under such lease by
appropriate court actions, either at law or equity, or recover damages
for breach thereof
- terminating such lease, at which time REMA will be required to return
possession of the owner lessor's interest in the leased facilities to
such owner lessor, and REMA's right to the possession and use of such
interest under the lease will cease and terminate, but REMA will remain
liable as provided in such lease
- selling the applicable interest in the leased facilities at public or
private sale, free and clear of REMA's rights
- holding, keeping idle or leasing to others the applicable interest in the
leased facilities, free and clear of REMA's rights under such lease, or
- exercising its rights under the credit support and applying the proceeds
of such exercise against REMA's lease obligations.
Subject to the assignment of rights to the indenture trustee, upon the
occurrence and continuance of any lease event of default and so long as the
applicable owner lessor has not sold its interest in the leased facilities, such
owner lessor may terminate the applicable lease and require REMA to pay any
accrued and unpaid rent due before such termination date, any other amounts due
and payable under the applicable lease documents, plus
(1) an amount equal to the excess, if any, of the applicable
termination value over the fair market sales value of its interest in the
leased facilities, as of such termination date,
(2) an amount equal to the excess, if any, of the applicable
termination value over the present value of the fair market rental value of
its interest in the leased facilities, as of such termination date, or
(3) an amount equal to the applicable termination value.
Upon payment of the termination value described in clause (3) and all other
accrued and unpaid rent by REMA, such owner lessor will transfer to REMA its
interest in the leased facilities. If the owner lessor elects to sell its
interest in the leased facilities, it may require REMA to pay any accrued and
unpaid rent
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due before such sale, any other amounts due and payable under the applicable
lease documents, plus an amount equal to the excess, if any, of the applicable
termination value over the net proceeds of the sale of its interest in the
leased facilities. The amounts payable under the immediately preceding sentences
would be sufficient to pay the principal, premium, if any, and interest due on
the applicable lessor notes.
Owner Lessor's Right to Perform. If REMA fails to make any payment other
than periodic rent or to perform or comply with any other obligations under a
lease, at any time within ten business days of receiving notice of such failure,
the applicable owner lessor or owner participant may make such payment or
perform or comply with such obligation. If REMA fails to make any payment of
periodic rent when due, and such failure is not the fourth consecutive failure
or the eighth cumulative failure, the applicable owner lessor may, at any time
within ten business days of receiving notice of such failure, pay to the
indenture trustee an amount equal to the principal and interest of the
applicable lessor notes then due together with any past due interest, and such
payment will cure any lease indenture event of default that would have otherwise
arisen.
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OUTSTANDING INDEBTEDNESS
NOTES TO AFFILIATED ENTITIES
When we were acquired from Sithe Energies and one of its subsidiaries, REMA
and its subsidiaries owning facilities in New Jersey and Maryland owed to the
Sithe Energies subsidiary indebtedness aggregating $1.575 billion. At the
closing of the acquisition, Reliant Energy Northeast Holdings, Inc., a direct
wholly owned subsidiary of REPG, purchased the notes evidencing this
indebtedness.
As of September 30, 2000, approximately $962 million of this indebtedness
remained outstanding. This indebtedness
- bears interest at a fixed rate of 9.4% per annum
- matures on January 1, 2029, and
- is unsecured
In addition, the indebtedness is subordinated to the obligation of REMA to
make payments under the leases and other senior obligations. REMA may make
payments on the amended note only to the extent permitted under the covenant
described in "Description of the Exchange Certificates -- Covenants --
Limitations on Restricted Payments and Restricted Investments" beginning on page
89. In particular, no payment on the indebtedness may be made unless (1) full
payment of all senior obligations then due and payable has been made, and (2)
immediately after giving effect to such payment, no significant lease default or
lease event of default exists.
Upon any payment or distribution of assets of REMA of any kind or
character, whether in cash, property or securities, to creditors upon any
dissolution or winding up or total or partial liquidation or reorganization of
REMA, whether voluntary or involuntary or in bankruptcy, insolvency,
receivership or other proceedings, then all amounts due or to become due under
the senior obligations of REMA must first be paid in full before the holder of
the indebtedness is entitled to payment or to receive any distribution of assets
of REMA. So long as any senior obligations are outstanding, the holder of the
indebtedness will not commence, or join with any creditor in commencing, or
causing REMA to commence, any bankruptcy, insolvency, receivership or other
proceeding seeking a dissolution, winding up, liquidation or reorganization of
REMA.
The holder of the indebtedness may not accelerate payment of, or institute
any proceedings to enforce, the note so long as any senior obligations are
outstanding.
For purposes of these subordination provisions, the term "senior
obligations" means
- rent obligations of REMA under the lease agreements
- all obligations of REMA under any application, reimbursement agreement,
indemnity or other agreement or undertaking for any letter of credit or
surety bond providing credit support for lease rental obligations, and
- all obligations of REMA under any unsubordinated indebtedness permitted
to be incurred by the lease documents
WORKING CAPITAL NOTE
REMA has executed a two-year revolving note with Reliant Energy Northeast
Holdings, Inc. under which REMA may borrow up to $30 million during that
two-year period for working capital needs. REPG is committed to lend to Reliant
Energy Northeast Holdings, Inc. any amounts Reliant Energy Northeast Holdings,
Inc. is required to lend to REMA. Borrowings under REMA's note to Reliant Energy
Northeast Holdings, Inc.
- bear interest at a rate per annum equal to the sum of (1) the weighted
average interest rate for commercial paper issued by Houston Industries
Finance Co., LP for the preceding month and (2) 15 basis points (0.15%)
- are unsecured
- rank equal in priority with REMA's obligations to make rental payments
under the leases, and
- may be repaid and, subject to the conditions to borrowing provided in the
note, reborrowed
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The working capital note provides for defaults in the case of various
bankruptcy and insolvency events and non-payment of principal or interest.
OTHER INTERCOMPANY DEBT
REMA has borrowed from Reliant Energy Northeast Holdings, Inc.
approximately $83 million. The borrowing will mature on January 1, 2029, bears
interest at a fixed rate of 9.4% and is unsecured. Repayment of the borrowing
will be subordinated to REMA's lease obligations as required by the lease
documents and as described above under "-- Notes to Affiliated Entities."
CREDIT SUPPORT -- LETTER OF CREDIT
We have entered into reimbursement agreements with a letter of credit
issuer satisfying the credit criteria set forth in the definition of "qualifying
credit support" in "Description of the Exchange
Certificates -- Covenants -- Special terms" above. REMA initially has provided
three separate irrevocable standby letters of credit from a commercial bank in
the aggregate amount of approximately $120 million as credit support, as
described under "Description of the Exchange Certificates -- Covenants -- Credit
Support."
REMA's obligation to repay amounts drawn under each letter of credit is
unsecured and ranks equal to its obligations under the leases, except to the
extent that REMA's lease obligations are secured. REMA's obligation to repay
amounts drawn under each letter of credit is guaranteed by the subsidiary
guarantors on an equal basis with their guarantees of the obligations under the
leases.
SUBORDINATED WORKING CAPITAL FACILITY
REMA has entered into an irrevocably committed subordinated working capital
facility with RENH. The amount available under the subordinated working capital
facility is as follows:
- from August 24, 2000 through January 1, 2007 -- $120 Million
- from January 2, 2007 through January 1, 2008 -- $96 million
- from January 2, 2008 through January 1, 2009 -- $72 million
- from January 2, 2009 through January 1, 2010 -- $48 million
- from January 2, 2010 through January 1, 2011 -- $24 million
RENH will fund REMA's drawings under this facility through borrowings or
equity contributions irrevocably committed to RENH by RERC or another entity
rated at least Baa2 by Moody's and BBB by Standard & Poor's. REMA may borrow
under this facility in amounts necessary to achieve a pro forma coverage ratio
of at least 1.1 to 1.0 to pay operating expenses, senior indebtedness and rent,
but excluding capital expenditures and subordinated indebtedness. In addition,
RENH must make advances to REMA under such facility from time to time up to the
maximum available commitment under such facility if our pro forma coverage ratio
does not equal or exceed 1.1 to 1.0, measured at the time rent under the leases
is due. Subject to the maximum available commitment, drawings will be made in
amounts necessary to permit us to achieve a pro forma coverage ratio of 1.1 to
1.0.
The commitments of RERC or such other entity, as the case may be, and RENH
will expire at the earliest of
- January 2, 2011
- such time as Moody's and Standard & Poor's reaffirm the original ratings
on the exchange certificates after giving effect to termination of the
subordinated working capital facility, or
- such time as any entity having a rating of at least Baa2 by Moody's and
BBB by Standard & Poor's guarantees REMA's obligations under the leases
Borrowings under the subordinated working capital facility with RENH
- are unsecured
- are subordinated to REMA's obligations to make rental payments under the
leases
- will be repaid only to the extent permitted under the covenant described
in "Description of the Exchange Certificates -- Covenants -- Limitations
on Restricted Payments and Restricted Investments" beginning on page 89.
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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES
In the opinion of Baker Botts L.L.P., our counsel, the following are the
material United States federal income tax consequences to U.S. holders and
non-U.S. holders of exchanging original certificates for exchange certificates
and owning and disposing of exchange certificates. As used in this discussion,
the term "U.S. holder" means any person or entity who, for U.S. federal income
tax purposes,
- is a beneficial owner of an exchange certificate, and
- is
- a citizen or resident of the United States
- a corporation or other entity created or organized in or under the laws
of the United States or any political subdivision of the United States
- an estate, the income of which is includible in gross income for U.S.
income tax purposes regardless of its source, or
- a trust in which
- a court in the United States is able to exercise primary supervision
over the administration of the trust, and
- one or more United States persons have the authority to control all
substantial decisions of the trust
The term "non-U.S. holder" means a holder that is not a U.S. holder.
This summary is based on
- the Internal Revenue Code of 1986, or the Code
- Treasury regulations (including proposed regulations and temporary
regulations) promulgated thereunder
- Internal Revenue Service rulings
- Internal Revenue Service official pronouncements, and
- judicial decisions
All of these authorities are subject to change at any time, with or without
retroactive effect. This discussion also generally assumes that each holder
holds the exchange certificates as capital assets, as defined in Section 1221 of
the Code, and that any amounts received by a non-U.S. holder on the exchange
certificates are not effectively connected with the conduct by such non-U.S.
holder of a trade or business in the United States. This discussion does not
purport to cover all aspects of U.S. federal income taxation that might be
relevant to you because of your personal investment or tax circumstances or
status. In addition, it does not discuss the U.S. federal income tax
consequences that may be applicable to you because you are subject to special
treatment under the U.S. federal income tax laws as
- a financial institution
- an insurance company
- a dealer in securities or currencies
- a tax-exempt organization
- a person holding exchange certificates that are a hedge against, or that
are hedged against, currency risk or that are part of a straddle, wash
sale, constructive sale or conversion transaction
- a person whose functional currency is not the U.S. dollar, or
- a U.S. expatriate
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Moreover, this discussion addresses neither alternative minimum tax consequences
nor the effect of any applicable state, local or foreign tax.
THIS SUMMARY PROVIDES GENERAL INFORMATION AND DOES NOT PURPORT TO ADDRESS
ALL OF THE TAX CONSEQUENCES THAT MAY BE APPLICABLE TO YOU. YOU ARE URGED TO
CONSULT YOUR OWN TAX ADVISOR ABOUT THE PARTICULAR UNITED STATES FEDERAL, STATE
AND LOCAL, AND OTHER, TAX CONSEQUENCES OF THE EXCHANGE OFFER AND THE
ACQUISITION, OWNERSHIP AND DISPOSITION OF THE EXCHANGE CERTIFICATES.
EXCHANGE OFFER
The exchange of the original certificates for the exchange certificates in
the exchange offer will not constitute a taxable transaction for U.S. federal
income tax purposes. Rather, the exchange certificates received by any U.S.
Holder or Non-U.S. Holder will be treated as a continuation of the holder's
investment in the original certificates. As a result, there will be no material
U.S. federal income tax consequences to a U.S. Holder or Non-U.S. Holder
exchanging the original certificates for the exchange certificates in the
exchange offer.
Some material U.S. federal income tax consequences to U.S. Holders and
Non-U.S. Holders of owning and disposing of the certificates are described below
under "Classification of Pass Through Trusts."
CLASSIFICATION OF PASS THROUGH TRUSTS
Assuming each pass through trust is operated in accordance with the terms
of the applicable pass through trust agreement, Baker Botts L.L.P. is of the
opinion that the trust will not be classified as an association taxable as a
corporation for federal income tax purposes, but rather should be classified as
a fixed investment trust that is further classified as a grantor trust for U.S.
federal income tax purposes. Further, in such counsel's opinion, if a pass
through trust were determined not to constitute a fixed investment trust, it
would be classified as a partnership for U.S. federal income tax purposes and
would not be classified as a publicly traded partnership (taxable as a
corporation for U.S. federal income tax purposes) if at least 90% of the trust's
gross income for each taxable year of its existence consisted of "qualifying
income" for federal income tax purposes. Qualifying income generally includes,
among other things, interest income and gain from the sale or disposition of
capital assets held for the production of interest income. In this regard, Baker
Botts L.L.P. believes that the interest derived by each pass through trust from
the lessor notes and any gain derived by each pass through trust from the sale
or other disposition of the lessor notes will constitute qualifying income and,
therefore, that the pass through trusts should meet the 90% test.
The following discussion of U.S. federal income tax consequences assumes
that (1) each pass through trust is properly classified as a fixed investment
trust for federal income tax purposes and (2) the pass through trust is not also
classified as being engaged in a U.S. trade or business. If, however, a pass
through trust were classified as a partnership, and not as a publicly traded
partnership taxable as a corporation, for U.S. federal income tax purposes, the
consequences described below would generally apply, except that
- income or loss on the assets held by the pass through trust would be
calculated at the pass through trust level, and a holder of an exchange
certificate would be required to report its share of the items of income
and deduction of the pass through trust on its tax return for its taxable
year within which the pass through trust's taxable year ends
- the holder of the exchange certificate would be required to report income
or loss on the exchange certificates on an accrual basis even if the
holder otherwise uses the cash method of accounting, and
- the bond premium and market discount rules discussed below would not
apply
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U.S. HOLDERS
Payments of Interest
For U.S. federal income tax purposes, if you are a U.S. holder, you will be
treated as if you directly owned your pro rata share of the lessor notes held by
each pass through trust. As a result, interest on the underlying lessor notes
will be taxable to you, as a U.S. holder, at the time that it is accrued or
(actually or constructively) received, depending upon your method of accounting
for U.S. federal income tax purposes. This assumes that the exchange
certificates are issued for their face amount. If a partial acceleration of
principal on the exchange certificates were to occur based on an acceleration of
principal on the lessor notes, it is possible that the special rules relating to
the accrual of original issue discount set forth in Section 1272(a)(6) of the
Code will apply to the exchange certificates.
Fees and Expenses
You will be entitled to deduct, consistent with your method of accounting,
your pro rata share of the fees and expenses paid or incurred by each pass
through trust as provided in Section 162 or 212 of the Code. Although we
anticipate that these fees and expenses will be borne by parties other than the
holders of exchange certificates, it is possible that these fees and expenses
would be treated as constructively received by the pass through trust, in which
event you would be required to include in income and would be entitled to deduct
your pro rata share of these fees and expenses. If you are an individual, an
estate or a trust, the deduction for your share of such fees or expenses will be
allowed only to the extent that all of your miscellaneous deductions, including
your share of such fees and expenses, exceed 2% of your adjusted gross income.
In addition, if you are an individual, any such deduction will be subject to
additional rules that limit the amount of your otherwise allowable itemized
deductions under generally applicable provisions of the Code.
Disposition of the Exchange Certificates
Upon the sale, exchange, redemption, retirement or other disposition of an
exchange certificate, you generally will recognize capital gain or loss equal to
the difference between the amount realized on the sale or exchange, not
including any amounts attributable to accrued and unpaid interest, and your
adjusted basis in the exchange certificate for U.S. federal income tax purposes.
Such gains or losses will be long term if the exchange certificates have been
held by you for more than one year. An exception to this general treatment will
apply if you must recognize ordinary income under the market discount rules. In
addition, the portion of the amount realized on a sale or an exchange that is
attributable to accrued and unpaid interest will be taxable as ordinary income.
Generally, if you are an individual, your long-term capital gains will be
eligible for reduced rates of U.S. federal income tax. Your tax basis in an
exchange certificate generally will equal the cost of the original certificate
or exchange certificate to you,
- increased by the amount of market discount, if any, previously taken into
income by you and, in some cases, original issue discount, or
- decreased by any amortized bond premium and any payments other than
payments of interest made on the exchange certificate (and on the
corresponding original certificate if it was also held by you), if so
elected
Rules similar to these rules will apply to any sale or exchange of a lessor note
by the pass through trust.
NON-U.S. HOLDERS
Payments of Interest
If you are a non-U.S. holder, generally you will not be subject to U.S.
federal income tax by withholding on interest on an exchange certificate under
the portfolio interest exception if
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(1) you fulfill the certification requirements set forth in applicable
Treasury regulations
(2) you do not actually or constructively own 10% or more of the total
combined voting power of all classes of stock entitled to vote of any of
the owner participants or REMA
(3) you are not a controlled foreign corporation related, directly or
indirectly, to any of the owner participants or REMA within the meaning of
Section 864(d)(4) of the Code
(4) you are not a bank receiving interest on an extension of credit
made pursuant to a loan agreement entered into in the ordinary course of
business, and
(5) the interest is not effectively connected with the conduct of a
trade or business by you in the United States
To fulfill the certification requirements and qualify for the exemption
from withholding, the last U.S. person within the meaning of Section 7701(a)(30)
of the Code in the chain of payment before payment to you, referred to in this
section as the "withholding agent", must have received in the year in which such
a payment occurs, or in either of the two preceding years, a statement that
- is signed by you under penalties of perjury
- certifies that you are not a U.S. holder, and
- provides your name and address
The statement may be made on Internal Revenue Service Form W-8BEN, or a
successor form, or a substantially similar substitute form, and you must inform
the withholding agent of any change in the information on the statement within
30 days of the change. If you hold an exchange certificate through a securities
clearing organization or another financial institution permitted to provide the
necessary statement, the organization or institution may provide a signed
statement to the withholding agent. However, in that case, the signed statement
must be accompanied by a copy of a Form W-8BEN, or a successor form, or a
substantially similar substitute form provided by you to the organization or
institution holding the exchange certificate on your behalf.
New regulations would provide alternative methods for satisfying the
certification requirements described above. These new regulations also would
require, in the case of exchange certificates held by a foreign partnership,
that
- the certification described above be provided by the partners rather than
by the foreign partnership, and
- the partnership provide some information, including a United States
taxpayer identification number
A look-through rule would apply in the case of tiered partnerships. These new
regulations will generally apply to payments made after December 31, 2000.
If you cannot satisfy the requirements of the portfolio interest exception
set forth in clauses (1) through (5) above, payments of interest, including
original issue discount, made to you generally will be subject to a 30%
withholding tax. This rate would be lower if an applicable income tax treaty
between the United States and a foreign country applied and provided for a lower
rate. The withholding tax will apply unless you provide the withholding agent
with a properly executed
- Internal Revenue Service Form W-8BEN, or a successor form, claiming an
exemption from, or a reduction in the rate of, withholding tax under the
benefit of a tax treaty, or
- Internal Revenue Service Form W-8ECI, or a successor form, stating that
the interest is effectively connected with the conduct of a trade or
business by you in the United States. In this case, you will be subject
to U.S. tax on the interest in the same manner as if you were a U.S.
person.
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Gain on Disposition of the Exchange Certificates
Subject to the discussion of backup withholding below, generally any amount
that constitutes a capital gain to you upon retirement or disposition of an
exchange certificate will not be subject to U.S. federal income taxation unless
- if you are an individual, you are present in the United States for a
period or periods aggregating 183 days or more during the taxable year of
the disposition, in which case you may be taxed as a U.S. holder in any
event, or
- the gain is effectively connected with the conduct of a trade or business
by you in the United States
INFORMATION REPORTING AND BACKUP WITHHOLDING
If you are not an exempt recipient, interest and payments of proceeds from
the disposition of exchange certificates may be subject to information reporting
and backup withholding at a rate of 31%. Generally, individuals are not exempt
recipients, but corporations and some other entities generally are exempt
recipients. If you are a U.S. holder, you generally will be subject to backup
withholding at a rate of 31% unless
- you supply an accurate taxpayer identification number, as well as some
other information, or
- you otherwise establish, in the manner prescribed by law, an exemption
from backup withholding
Backup withholding and information reporting do not apply to payments of
interest and payments of proceeds from the disposition of exchange certificates
made to non-U.S. holders if the certification described under "Non-U.S.
Holders -- Payments of Interest" is received, provided that the withholding
agent does not have actual knowledge that the holder is a U.S. person.
If you sell an exchange certificate to or through a U.S. office of a
broker, the broker must withhold at a rate of 31% of the payment and report the
sale to the Internal Revenue Service unless the holder certifies under penalties
of perjury that it is a non-U.S. person, or otherwise establishes an exemption.
If you sell an exchange certificate through the non-U.S. office of a non-U.S.
broker, backup withholding and information reporting will not apply. However,
unless the broker has documentary evidence in its records that the holder is a
non-U.S. person and some other conditions are met, or the holder otherwise
establishes an exemption, if you sell an exchange certificate through a non-U.S.
office of a broker, information reporting (but not backup withholding) will
apply if the broker is
- a controlled foreign corporation within the meaning of Section 957(a) of
the Code
- a foreign person, 50% or more of whose gross income from all sources for
the three-year period ending with the close of its taxable year preceding
the payment, or for the part of the period that the foreign broker has
been in existence, was effectively connected with the conduct of a trade
or business within the United States, or
- under the new regulations that apply to payments made after December 31,
2000, a foreign partnership if the foreign partnership is engaged in a
trade or business in the United States or if 50% or more of its income or
capital interests are held by U.S. persons
Under Treasury regulations, both backup withholding and information
reporting would apply to the proceeds from dispositions if the broker has actual
knowledge that the payee is a U.S. holder.
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Generally, any amounts withheld under the backup withholding rules from a
payment to you would be allowed as a refund or credit against your U.S. federal
income tax. You should consult your tax advisor regarding
- the application of information reporting and backup withholding in your
particular situation
- the availability of an exemption from withholding, and
- the procedures for obtaining any such exemption
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ERISA CONSIDERATIONS
If you intend to use plan assets to purchase exchange certificates, you
should consult with your counsel about the potential consequences of such an
investment under the fiduciary responsibility provisions of the Employee
Retirement Income Security Act of 1974, or ERISA, and the prohibited transaction
provisions of ERISA and the Code.
ERISA and the Code impose some restrictions on
- employee benefit plans that are subject to ERISA and/or the Code
- other retirement plans and arrangements, including individual retirement
accounts and annuities, that are subject to ERISA and/or the Code
- persons who are fiduciaries of such plans, and
- entities that hold plan assets, such as bank common investment funds and
insurance company general and separate accounts
If you exercise discretionary authority or control over the management or
assets of an ERISA plan, you are considered a fiduciary of the plan under ERISA.
Under ERISA's general fiduciary standards, before investing in the exchange
certificates, a plan fiduciary should determine whether
- the governing plan instruments permit such an investment, and
- the investment is appropriate for the plan in view of its overall
investment policy and the composition and diversification of its
portfolio, taking into account the limited liquidity of the exchange
certificates
Other provisions of ERISA and the Code prohibit specified types of
transactions involving the assets of a plan and persons who have specified
relationships to the plan. As a result, if you are a plan fiduciary, you should
also consider whether an investment in the exchange certificates might
constitute or give rise to a prohibited transaction under ERISA or the Code for
which no exemption is available.
An investment in exchange certificates by benefit plan investors or with
plan assets might cause the assets of the related pass through trust to be
deemed to constitute plan assets. If the assets of a pass through trust are
considered to be plan assets, the operation of the pass through trust might give
rise to nonexempt prohibited transactions under ERISA and/or the Code. In
addition, if you are the fiduciary of a plan subject to ERISA, you might be
deemed to have engaged in an improper delegation to the pass through trustee of
your investment management responsibilities over those assets of the pass
through trust deemed to be plan assets.
Neither ERISA nor the Code defines the term "plan assets." Pursuant to
Section 2510.3-101 of the United States Department of Labor regulations, the
plan's assets, in general, include both the equity interest and an undivided
interest in each of the underlying assets of the entity when
- a plan acquires an equity interest in an entity, such as a pass through
trust
- such interest does not represent a "publicly offered security" or a
security issued by an investment company registered under the Investment
Company Act of 1940, and
- it is not established either that the entity is an "operating company" or
that equity participation in the entity by benefit plan investors is not
"significant"
In general, an "equity interest" is defined under the Department of Labor,
or DOL, regulation as any interest in an entity other than an instrument that is
treated as indebtedness under applicable local law and that has no substantial
equity features. We believe that the exchange certificates will be treated as
equity interests in the pass through trusts under the DOL regulation. In
addition, we believe it is possible that, during the term of the exchange
certificates, equity participation in the pass through trust by benefit plan
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investors will be "significant" and that the assets of the pass through trust
will, therefore, be considered "plan assets." Under the DOL regulation, an
investment in exchange certificates by a plan subject to ERISA during any period
that the assets of the pass through trust are treated as plan assets would be
considered to be an investment in the corresponding lessor note and any other
assets of a pass through trust and an ongoing loan to the owner lessor for
purposes of the fiduciary responsibility provisions of ERISA and the prohibited
transaction provisions of ERISA and the Code. As a result, if assets of a pass
through trust are considered plan assets, investment in exchange certificates by
a plan or plans subject to ERISA or the Code could result in prohibited
transactions or impermissible delegations of authority.
In addition, the acquisition of exchange certificates by a plan subject to
ERISA or the Code could be a prohibited transaction whether or not the assets of
a pass through trust are considered plan assets if, for example, any of the
initial purchasers, a pass through trustee, we or any of their respective
affiliates are parties in interest or disqualified persons related to the
investing plan.
A prohibited transaction could be treated as exempt under ERISA and the
Code if the exchange certificates are acquired under one or more "class
exemptions" issued by the DOL, such as
- PTCE 84-14 (an exemption for some transactions determined by an
independent qualified professional asset manager)
- PTCE 91-38 (an exemption for some transactions involving bank collective
investment funds)
- PTCE 90-1 (an exemption for some transactions involving insurance company
pooled separate accounts)
- PTCE 95-60 (an exemption for some transactions involving insurance
company general accounts), or
- PTCE 96-23 (an exemption for some transactions determined by a qualified
in-house asset manager)
IF YOU ARE A FIDUCIARY OF A PLAN SUBJECT TO ERISA OR THE CODE CONSIDERING
AN INVESTMENT IN THE EXCHANGE CERTIFICATES, YOU MUST CONSIDER WHETHER THE
ACQUISITION OR THE CONTINUED HOLDING OF THE EXCHANGE CERTIFICATES MIGHT
CONSTITUTE OR GIVE RISE TO A NONEXEMPT PROHIBITED TRANSACTION. IF YOU PURCHASE
OR ACQUIRE EXCHANGE CERTIFICATES OR AN INTEREST IN THE EXCHANGE CERTIFICATES,
YOU WILL BE DEEMED BY SUCH PURCHASE OR ACQUISITION TO HAVE REPRESENTED AND
WARRANTED THAT EITHER
- NO PLAN ASSETS SUBJECT TO ERISA OR THE CODE HAVE BEEN USED TO PURCHASE
SUCH EXCHANGE CERTIFICATES OR AN INTEREST THEREIN, OR
- THE PURCHASE AND HOLDING OF SUCH EXCHANGE CERTIFICATES ARE EXEMPT FROM
THE PROHIBITED TRANSACTION RESTRICTIONS OF ERISA AND THE CODE UNDER ONE
OR MORE PROHIBITED TRANSACTION CLASS EXEMPTIONS
IF YOU ARE A FIDUCIARY OF PLAN ASSETS SUBJECT TO ERISA OR THE CODE AND ARE
CONSIDERING THE PURCHASE OF EXCHANGE CERTIFICATES, YOU SHOULD CONSULT YOUR TAX
AND/OR LEGAL ADVISORS REGARDING
- UNDER WHAT CIRCUMSTANCES THE ASSETS OF A PASS THROUGH TRUST WOULD BE
CONSIDERED PLAN ASSETS
- THE AVAILABILITY, IF ANY, OF EXEMPTIVE RELIEF FROM ANY POTENTIAL
TRANSACTION, AND
- OTHER FIDUCIARY ISSUES AND THEIR POTENTIAL CONSEQUENCES
Governmental plans and some church plans, while generally not subject to
the fiduciary responsibility provisions or the prohibited transaction provisions
of ERISA or the Code, may nevertheless be subject to state or other federal laws
that are substantially similar to the foregoing provisions of ERISA and the
Code. Fiduciaries of those plans should consult with their counsel before
purchasing an exchange certificate.
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PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC in no action letters
issued to third parties, we believe that you may transfer exchange certificates
issued in the exchange offer in exchange for the original certificates if:
- you acquire the exchange certificates in the ordinary course of your
business, and
- you are not engaged in, and do not intend to engage in, and have no
arrangement or understanding with any person to participate in, a
distribution of exchange certificates
We believe that you may not transfer exchange certificates issued in the
exchange offer in exchange for the original certificates if you are:
- our "affiliate" within the meaning of Rule 405 under the Securities Act
- a broker-dealer that acquired original certificates directly from us, or
- a broker-dealer that acquired original certificates as a result of
market-making activities or other trading activities without compliance
with the registration and prospectus delivery provisions of the
Securities Act
If you wish to exchange your original certificates for exchange
certificates in the exchange offer, you will be required to make representations
to us as described in "The Exchange Offer -- Procedures for Tendering -- Your
Representations to Us" of this prospectus and in the letter of transmittal.
Each broker-dealer that receives exchange certificates for its own account
under the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of such exchange certificates. Broker-dealers may use
this prospectus for resales of exchange certificates received in exchange for
original certificates where such original certificates were acquired as a result
of market-making activities or other trading activities. We have agreed that,
for a period of 90 days after the expiration date, we will make this prospectus
available to any broker-dealer for use in connection with any such resale. In
addition, until May 15, 2001, all dealers effecting transactions in the exchange
certificates may be required to deliver a prospectus.
We will not receive any proceeds from any sale of exchange certificates by
broker-dealers. Broker-dealers may sell exchange certificates received for their
own account under the exchange offer in transactions:
- in the over-the-counter market
- in negotiated transactions
- through the writing of options on the exchange certificates, or
- a combination of such methods of resale
The prices at which these sales occur may be:
- at market prices prevailing at the time of resale
- at prices related to such prevailing market prices, or
- at negotiated prices
Broker-dealers may make any such resale directly to purchasers or to or through
brokers or dealers who may receive compensation in the form of commissions or
concessions from any such broker-dealer or the purchasers of any such exchange
certificates. Any broker-dealer that resells exchange certificates that it
received for its own account under the exchange offer and any broker or dealer
that participates in a distribution of such exchange certificates may be deemed
to be an "underwriter" within the meaning of
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the Securities Act. Any profit on any such resale of exchange certificates and
any commission or concessions received by any such persons may be deemed to be
underwriting compensation under the Securities Act. The letter of transmittal
states that, by acknowledging that it will deliver and by delivering a
prospectus, a broker-dealer will not admit that it is an "underwriter" within
the meaning of the Securities Act.
For a period of 90 days after the expiration date we will promptly send
additional copies of this prospectus and any amendment or supplement to this
prospectus to any broker-dealer that requests such documents in the letter of
transmittal. We have agreed to pay all expenses incident to the exchange offer
other than commissions or concessions of any broker-dealers and will indemnify
the holders of the certificates (including any broker-dealers) against some
liabilities, including liabilities under the Securities Act. Each holder must
pay all underwriting discounts and commissions and transfer taxes, if any,
relating to the sale or disposition of such holder's certificates under a shelf
registration statement.
LEGAL MATTERS
Baker Botts L.L.P., our counsel, will issue opinions about various legal
matters relating to the exchange certificates.
EXPERTS
The combined financial statements of REMA and the consolidated financial
statements of RENJ as of December 31, 1999 and for the period from November 24,
1999 through December 31, 1999 included in this prospectus have been audited by
Deloitte & Touche LLP, independent auditors, as stated in their reports
appearing herein and elsewhere in the registration statement, and have been so
included in reliance upon the reports of such firm given upon their authority as
experts in accounting and auditing.
INDEPENDENT ENGINEER
S&W Consultants, a division of Stone & Webster, Inc. and referred to in
this paragraph as Stone & Webster, has prepared the independent engineer's
report, dated August 4, 2000, which is included as Appendix A to this
prospectus. You should read the independent engineer's report in its entirety
for information about our facilities and the related subjects discussed in the
report. We have included the independent engineer's report in this prospectus in
reliance upon the conclusions in such report of Stone & Webster and upon that
firm's experience in the review of the design and operation of electric
generation facilities. The detailed independent engineer's report is available
upon request from the lead book manager.
S&W Consultants is the successor to some of the rights, obligations and
business activities of Stone & Webster Management Consultants, Inc. pursuant to
that company's bankruptcy proceedings and the sale of those rights, obligations
and business activities approved by the bankruptcy court.
INDEPENDENT MARKET CONSULTANT
PA Consulting Group, formerly PHB Hagler Bailly, Inc., has prepared the
independent market expert's report dated May 5, 2000, and we have included this
report as Appendix B to this prospectus. You should read the market report in
its entirety for information about the electricity market and the related
subjects discussed in, and the assumptions and qualifications stated in, the
report.
137
142
INDEX TO FINANCIAL STATEMENTS
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
AUDITED COMBINED FINANCIAL STATEMENTS
Independent Auditors' Report................................ F-3
Statement of Combined Operations for the Period from
November 24, 1999 to December 31, 1999.................... F-4
Combined Balance Sheet as of December 31, 1999.............. F-5
Statement of Combined Cash Flows for the Period from
November 24, 1999 to December 31, 1999.................... F-6
Statement of Combined Member's and Shareholder's Equity for
the Period from November 24, 1999 to December 31, 1999.... F-7
Notes to Combined Financial Statements...................... F-8
UNAUDITED INTERIM CONDENSED COMBINED AND CONSOLIDATED
FINANCIAL STATEMENTS
Interim Condensed Statements of Combined and Consolidated
Operations for the Periods from January 1, 2000 to May 11,
2000 and from May 12, 2000 to September 30, 2000.......... F-16
Interim Condensed Combined and Consolidated Balance Sheets
as of December 31, 1999 and September 30, 2000............ F-17
Interim Condensed Statements of Combined and Consolidated
Cash Flows for the Periods from January 1, 2000 to May 11,
2000 and from May 12, 2000 to September 30, 2000.......... F-18
Interim Condensed Statement of Combined and Consolidated
Member's and Shareholder's Equity for the Periods from
January 1, 2000 to May 11, 2000 and from May 12, 2000 to
September 30, 2000........................................ F-19
Notes to Unaudited Interim Condensed Combined and
Consolidated Financial Statements......................... F-20
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
AUDITED CONSOLIDATED FINANCIAL STATEMENTS
Independent Auditors' Report................................ F-25
Statement of Consolidated Operations for the Period from
November 24, 1999 to December 31, 1999.................... F-26
Consolidated Balance Sheet as of December 31, 1999.......... F-27
Statement of Consolidated Cash Flows for the Period from
November 24, 1999 to December 31, 1999.................... F-28
Statement of Consolidated Member's Equity for the Period
from November 24, 1999 to December 31, 1999............... F-29
Notes to Consolidated Financial Statements.................. F-30
UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
Interim Condensed Statement of Consolidated Operations for
the Periods from May 12, 2000 to September 30, 2000 and
from January 1, 2000 to May 11, 2000...................... F-35
Interim Condensed Consolidated Balance Sheets as of
September 30, 2000 and December 31, 1999.................. F-36
Interim Condensed Statement of Consolidated Cash Flows for
the Periods from May 12, 2000 to September 30, 2000 and
from January 1, 2000 to May 11, 2000...................... F-37
Interim Condensed Statement of Consolidated Member's Equity
for the Periods from May 12, 2000 to September 30, 2000
and from January 1, 2000 to May 11, 2000.................. F-38
Notes to Unaudited Interim Condensed Consolidated Financial
Statements................................................ F-39
F-1
143
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
UNAUDITED PRO FORMA CONDENSED COMBINED AND CONSOLIDATED
FINANCIAL STATEMENTS
Introduction to Unaudited Pro Forma Condensed Combined and
Consolidated Financial Statements......................... F-43
Unaudited Pro Forma Condensed Combined Statements of
Operations for the Period from November 24, 1999 to
December 31, 1999......................................... F-44
Unaudited Pro Forma Condensed Combined and Consolidated
Statement of Operations for the Nine Months Ended
September 30, 2000........................................ F-45
Notes to Unaudited Pro Forma Condensed Combined and
Consolidated Financial Statements......................... F-46
F-2
144
INDEPENDENT AUDITORS' REPORT
To the Directors, Shareholder and Member of
Reliant Energy Mid-Atlantic Power Holdings, LLC
Reliant Energy New Jersey Holdings, LLC
Reliant Energy Maryland Holdings, LLC
Reliant Energy Mid-Atlantic Power Services, Inc.
We have audited the accompanying combined balance sheet of Reliant Energy
Mid-Atlantic Power Holdings, LLC (formerly Sithe Pennsylvania Holdings, LLC)
(REMA) and related companies as of December 31, 1999, and the related combined
statements of operations, member's and shareholder's equity, and cash flows for
the period from November 24, 1999 to December 31, 1999. The combined financial
statements include the accounts of Reliant Energy Mid-Atlantic Power Holdings,
LLC and three related companies, Reliant Energy New Jersey Holdings, LLC
(formerly Sithe New Jersey Holdings, LLC), Reliant Energy Maryland Holdings, LLC
(formerly Sithe Maryland Holdings, LLC) and Reliant Energy Mid-Atlantic Power
Services, Inc. (formerly Sithe Mid-Atlantic Power Services, Inc.) These
companies are under common ownership and common management. These financial
statements are the responsibility of REMA's management. Our responsibility is to
express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such combined financial statements present fairly, in all
material respects, the combined financial position of REMA at December 31, 1999,
and the combined results of its operations and its combined cash flows for the
period from November 24, 1999 to December 31, 1999 in conformity with accounting
principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
Pittsburgh, Pennsylvania
July 12, 2000
(except for Note 8(c) to the combined financial
statements which is dated August 24, 2000)
F-3
145
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
STATEMENT OF COMBINED OPERATIONS
FOR THE PERIOD FROM NOVEMBER 24, 1999 TO DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
Revenues from Affiliate..................................... $29,526
Expenses:
Fuel, including $5.7 million from affiliate............... 10,754
Operation and maintenance................................. 7,084
Administrative and general................................ 1,584
Project development....................................... 1,606
Other taxes............................................... 746
Depreciation and amortization............................. 4,842
-------
Total Expenses.................................... 26,616
-------
Operating Income............................................ 2,910
Interest Expense to Affiliate, net.......................... 12,588
-------
Net Loss.................................................... $(9,678)
=======
See Notes to the Combined Financial Statements.
F-4
146
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
COMBINED BALANCE SHEET
DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
ASSETS
Current Assets:
Cash and cash equivalents.............................. $ 570
Fuel inventories....................................... 6,411
Material and supplies inventories...................... 52,965
Other current assets................................... 637
----------
Total current assets.............................. 60,583
Property, Plant and Equipment, net........................ 1,286,319
Other Noncurrent Assets:
Goodwill, net.......................................... 184,518
Air emissions regulatory allowances, net............... 166,791
Project development costs.............................. 7,689
----------
Total other noncurrent assets..................... 358,998
----------
Total Assets...................................... $1,705,900
==========
LIABILITIES AND MEMBER'S AND SHAREHOLDER'S EQUITY
Current Liabilities:
Accounts payable....................................... $ 10,244
Payable to affiliates.................................. 7,928
Accrued payroll........................................ 5,273
Asset purchase consideration payable................... 27,296
Demand notes payable to affiliate...................... 1,575,312
Other current liabilities.............................. 3,856
----------
Total current liabilities......................... 1,629,909
Noncurrent Liabilities:
Accrued environmental liabilities...................... 28,030
Other noncurrent liabilities........................... 3,030
----------
Total noncurrent liabilities...................... 31,060
Commitments and Contingencies (Note 5)
Member's and Shareholder's Equity:
Common stock ($.01 par value, 1,500 shares authorized,
100 shares issued and outstanding).................... --
Member's capital contributions......................... 54,609
Retained deficit....................................... (9,678)
----------
Total member's and shareholder's equity........... 44,931
----------
Total Liabilities and Member's and Shareholder's
Equity........................................... $1,705,900
==========
See Notes to the Combined Financial Statements.
F-5
147
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
STATEMENT OF COMBINED CASH FLOWS
FOR THE PERIOD FROM NOVEMBER 24, 1999 TO DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
Cash Flows from Operating Activities:
Net loss.................................................. $ (9,678)
Adjustments to reconcile net loss to net cash provided by
operations:
Depreciation and amortization expense.................. 4,842
Changes in assets and liabilities:
Fuel inventories..................................... 1,591
Material and supplies inventories.................... (181)
Other assets......................................... (421)
Accounts payable..................................... 10,244
Other current liabilities............................ (5,367)
-----------
Net cash provided by operating activities......... 1,030
-----------
Cash Flows from Investing Activities:
Acquisition of generating stations........................ (1,629,921)
Capital expenditures...................................... (4,421)
-----------
Net cash flows used in investing activities....... (1,634,342)
-----------
Cash Flows from Financing Activities:
Capital contribution...................................... 54,609
Proceeds from demand notes payable to affiliate........... 1,575,312
Net change in payables to affiliates...................... 3,961
-----------
Net cash flows provided by financing activities... 1,633,882
-----------
Net Change in Cash and Cash Equivalents..................... 570
Cash and Cash Equivalents, Beginning of Period.............. --
-----------
Cash and Cash Equivalents, End of Period.................... $ 570
===========
Supplemental Cash Flow Information:
Interest paid to affiliate................................ $ 12,588
===========
See Notes to the Combined Financial Statements.
F-6
148
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
STATEMENT OF COMBINED MEMBER'S AND SHAREHOLDER'S EQUITY
FOR THE PERIOD FROM NOVEMBER 24, 1999 TO DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
TOTAL
MEMBER'S MEMBER'S AND
COMMON CAPITAL RETAINED SHAREHOLDER'S
STOCK CONTRIBUTIONS DEFICIT EQUITY
------- ------------- -------- -------------
Balance, Beginning of Period.................... $ -- $ -- $ -- $ --
Capital contributions......................... 54,609 -- 54,609
Net loss...................................... -- -- (9,678) (9,678)
------- ------- ------- -------
Balance, End of Period.......................... $ -- $54,609 $(9,678) $44,931
======= ======= ======= =======
See Notes to the Combined Financial Statements.
F-7
149
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Reliant Energy Mid-Atlantic Power Holdings, LLC -- Reliant Energy
Mid-Atlantic Power Holdings, LLC (formerly Sithe Pennsylvania Holdings, LLC) and
related companies which include the affiliates and subsidiaries listed below
(collectively, REMA), were indirect wholly owned subsidiaries of Sithe Energies,
Inc. (Sithe) as of December 31, 1999. See Note 8. REMA acquired its generating
stations and various related assets (including the capital stock of Sithe
Mid-Atlantic Power Services, Inc.) from the operating subsidiaries of GPU, Inc.
(GPU), a utility holding company, on November 24, 1999. REMA was formed as
follows:
RELATION TO
RELIANT MID-ATLANTIC
POWER HOLDINGS AT
FORMATION DATE DECEMBER 31, 1999
-------------- --------------------
Operating Entities:
Sithe Pennsylvania Holdings, LLC December 28, 1998 N/A
Sithe New Jersey Holdings, LLC December 28, 1998 Affiliate
Sithe Maryland Holdings, LLC December 28, 1998 Affiliate
Sithe Northeast Management Company April 11, 1994 Subsidiary
Sithe Mid-Atlantic Power Services, Inc. June 11, 1999 Affiliate
Developmental Entities:
Sithe Portland, LLC March 31, 1999 Subsidiary
Sithe Hunterstown, LLC March 31, 1999 Subsidiary
Sithe Seward, LLC March 31, 1999 Subsidiary
Sithe Erie West, LLC March 31, 1999 Subsidiary
Sithe Atlantic, LLC March 31, 1999 Affiliate
Sithe Gilbert, LLC March 31, 1999 Affiliate
Sithe Titus, LLC March 31, 1999 Subsidiary
In May 2000, Sithe, through an indirect wholly owned subsidiary, sold all
of its equity interests in REMA to an indirect wholly owned subsidiary of
Reliant Energy Power Generation, Inc. (REPG). REPG is a wholly owned subsidiary
of Reliant Resources, Inc., which is in turn, a direct wholly owned subsidiary
of Reliant Energy, Incorporated (Reliant Energy). See Note 8. Following this
transaction, REMA changed its name and the names of its operating and
developmental entities. Sithe Pennsylvania Holdings, LLC was renamed Reliant
Energy Mid-Atlantic Power Holdings, LLC. In all other cases, the names were
changed such that "Sithe" was replaced with "Reliant Energy."
REMA owns interests in and operates 21 electric generation plants in
Pennsylvania, New Jersey and Maryland with an annual average net generating
capacity of approximately 4,262 megawatts (MW).
(b) Basis of Presentation and Principles of Combination -- These financial
statements present the results of operations for the period from November 24,
1999 (the date that REMA acquired the generation assets from GPU) to December
31, 1999. There are no separate financial statements available with regard to
the facilities of REMA prior to the acquisition because their operations were
fully integrated with, and their results of operations were consolidated into,
the former owners of the facilities of REMA. In addition, the electric output of
the facilities was sold based on rates set by regulatory authorities. As a
result and because electricity rates will now be set by the operation of market
forces, the historical financial data with respect to the facilities of REMA
prior to November 24, 1999 is not meaningful or indicative of REMA's future
results. REMA's results of operations in the future will depend
F-8
150
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
primarily on revenues from the sale of energy, capacity and ancillary services,
and the level of its operating expenses.
The acquisition of REMA's generating assets was recorded under the purchase
method of accounting with assets and liabilities of REMA reflected at their
estimated fair values as of the date of the purchase. On a preliminary basis,
REMA's fair value adjustments included increases in property, plant and
equipment and air emissions regulatory allowances. The allocation of the
purchase price is preliminary, since the valuation of property, plant and
equipment and air emissions regulatory allowances as well as the valuation of
material and supplies inventories and environmental reserves have not been
finalized. REMA's liabilities include $27.3 million of asset purchase
consideration payable in connection with REMA's acquisition of its generating
assets.
The combined financial statements include the accounts of REMA and related
companies including the affiliates and subsidiaries described in Note 1(a). All
significant inter-affiliate and intercompany transactions and balances are
eliminated in combination. The combination of affiliates and subsidiaries
includes all of the operations and assets acquired from GPU on November 24,
1999, which have been managed together since that acquisition date.
Investments that represent direct interests in the assets, liabilities and
operations of ventures are reported as REMA's share of each account in the
venture. See Note 2.
(c) Use of Estimates -- The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from these estimates.
(d) Revenue Recognition -- Revenue includes energy, capacity and ancillary
service sales. During 1999, REMA's power and services, excluding capacity, were
sold at market-based prices through sales to a related party and wholly owned
subsidiary of Sithe (the Sithe Affiliate) for resale. The Sithe Affiliate acted
as agent on behalf of REMA on most market-based sales. REMA's capacity was also
sold to the Sithe Affiliate at terms that mirror a transition power purchase
agreement between Sithe and GPU. The transition power purchase agreement extends
from November 24, 1999 to May 31, 2002. Sales not billed by month-end are
accrued based upon estimated energy or services delivered.
(e) Cash and Cash Equivalents -- Cash and cash equivalents are considered
to be highly liquid investments with an original maturity of three months or
less, which are cash or are readily convertible to cash.
(f) Inventories -- Inventories are comprised of materials, supplies and
fuel stock held for consumption and are stated at the lower of weighted-average
cost or market.
(g) Fair Values of Financial Instruments -- The recorded amounts for
financial instruments such as cash and cash equivalents, accounts payable and
affiliate payables approximate fair value due to the short-term nature of these
instruments.
(h) Property, Plant and Equipment -- Property, plant and equipment are
stated at cost. Depreciation is computed using the straight-line method over the
estimated useful lives commencing when assets, or major components thereof, are
either placed in service or acquired, as appropriate.
(i) Intangible Assets -- Cost in excess of fair value of net assets
acquired (goodwill) is amortized on a straight-line basis over the estimated
useful life of 40 years. Goodwill amortization expense during 1999 was $481,000.
F-9
151
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Other intangible assets consist primarily of air emissions regulatory
allowances that have already been issued to REMA and allowances that REMA
expects to be allocated during the remaining useful lives of the plants. These
intangible assets are amortized on a unit-of-production basis as utilized.
Amortization expense recognized in 1999 related to other intangible assets was
$209,000.
(j) Impairment of Long-Lived Assets -- REMA periodically compares the
carrying value of its long-lived assets, including goodwill and other intangible
assets, to the anticipated undiscounted future net cash flows from their
corresponding businesses, and no impairment is indicated at December 31, 1999.
(k) Project Development Costs -- REMA capitalizes the deposits made toward
future combustion turbine deliveries as well as the direct costs associated with
viable projects, including some third-party legal, accounting and consulting
costs. These capitalized costs are amortized over the estimated life of the
project on a straight-line basis, beginning when the project becomes
operational. Other project development costs are expensed as incurred.
(l) Income Taxes -- REMA and some of its affiliates that are limited
liability companies are not taxable for federal income tax purposes. Any taxable
earnings or losses and certain other tax attributes are reported by the member
on its income tax return. Other affiliates that are taxable corporate entities
have incurred tax and book losses but are not subject to any tax-sharing
agreements with Sithe. As such, no tax benefits have been recorded for these
entities since the tax benefits are not considered realizable. These tax
benefits and the offsetting valuation allowance are less than $1 million.
(m) Market Risk and Uncertainties -- REMA is subject to certain risks
including the supply and price of fuel, seasonal weather patterns, technological
obsolescence and the regulatory environment within the United States.
(n) Comprehensive Income -- REMA had no items of comprehensive income for
the financial statement period presented.
(o) New Accounting Pronouncements -- Effective January 1, 2001, REMA is
required to adopt Statement of Financial Accounting Standard No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS
No. 133), which establishes accounting and reporting standards for derivative
instruments, including some specified hedging instruments embedded in other
contracts and for hedging activities. This statement requires that derivatives
be recognized at fair value in the balance sheet and that changes in fair value
be recognized either currently in earnings or deferred as a component of other
comprehensive income, depending on the intended use of the derivative, its
resulting designation and its effectiveness. In addition, in June 2000, the
Financial Accounting Standards Board issued an amendment that narrows the
applicability of the pronouncement to some purchase and sales contracts and
allows hedge accounting for some other specific hedging relationships. Adoption
of SFAS No. 133 will result in no cumulative after-tax change in net income and
a cumulative after-tax increase to other comprehensive income of approximately
$2 million in the first quarter of 2001. The adoption will also impact assets
and liabilities recorded on the balance sheet.
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101), was
issued by the SEC on December 3, 1999. SAB No. 101 summarizes some of the SEC
staff's views in applying generally accepted accounting principles to revenue
recognition in financial statements. REMA's combined financial statements
reflect the accounting principles provided in SAB No. 101.
F-10
152
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
2. JOINTLY OWNED ELECTRIC GENERATION PLANTS
REMA has partial undivided interests in two jointly owned generation
stations in Pennsylvania and bears a corresponding share of the capital and
operating costs associated with the facilities. The following table summarizes
certain financial and operational information about REMA's jointly owned
coal-fired facilities as of December 31, 1999 (dollars in thousands):
CONEMAUGH STATION KEYSTONE STATION
----------------- ----------------
Ownership interest................................... 16.45% 16.67%
Company's share of capacity (MW)..................... 281 285
Net investment....................................... $257,410 $207,334
Accumulated depreciation............................. $ 537 $ 432
The Conemaugh and Keystone stations (Conemaugh and Keystone, respectively)
are each owned as a tenancy in common among their co-owners, with each owner
retaining its undivided ownership interest in the generating units and the
electrical output from those units. Reliant Energy Northeast Management Company,
a subsidiary of Reliant Energy Mid-Atlantic Power Holdings, LLC, operates and
manages Conemaugh and Keystone under separate operating agreements that the
owners of Conemaugh and Keystone have elected to terminate effective December
31, 2002. The owners of each station have not yet decided on the operating
arrangements for such station for the period beginning on January 1, 2003.
3. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following at December 31 (in
thousands):
ESTIMATED USEFUL
LIVES (YEARS) 1999
-------------------- ----------
Land................................................... -- $ 28,154
Generation plant-in-service............................ 11 to 45 1,242,166
Buildings.............................................. 30 to 32 6,045
Machinery and equipment................................ 10 13,353
----------
Total plant-in-service................................. 1,289,718
Construction work-in-progress.......................... 753
----------
Total........................................ 1,290,471
Less -- accumulated depreciation....................... (4,152)
----------
Property, plant and equipment -- net................... $1,286,319
==========
4. DEMAND NOTES PAYABLE TO AFFILIATE
In connection with Sithe's acquisition of its generating assets from GPU,
REMA executed or issued approximately $1.6 billion of demand notes payable to
Sithe Northeast Generating Company, Inc. (an indirect wholly owned subsidiary of
Sithe) due August 20, 2001. The notes bear interest at a financing rate based on
the London interbank offered rate (LIBOR) plus (a) 1.9% per annum through
November 24, 2000 and (b) 2.4% per annum thereafter. The applicable interest
rate was 7.644% at December 31, 1999. Borrowings outstanding under these
unsecured notes payable approximate fair value, as the individual borrowings
bear interest at current market rates. In connection with the acquisition of
REMA in May 2000, Sithe Northeast Generating Company, Inc. sold these notes to
an indirect wholly owned subsidiary of REPG. See Note 8.
F-11
153
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
5. COMMITMENTS AND CONTINGENCIES
(a) Environmental -- Under the agreement to acquire REMA's generating
assets from GPU, liabilities associated with ash disposal site closure and site
contamination at the acquired facilities in Pennsylvania and New Jersey prior to
plant closing were assumed, except for the first $6 million of remediation costs
at the Seward Station. GPU retained liabilities associated with the disposal of
hazardous substances to off-site locations prior to November 24, 1999. REMA has
recorded its estimate of these environmental liabilities in the amount of $28.0
million as of December 31, 1999.
(b) Operating Leases -- REMA leases some equipment and vehicles under
noncancelable operating leases extending through 2004. Future minimum rentals
under lease agreements are as follows (in thousands):
2000........................................................ $371
2001........................................................ 243
2002........................................................ 143
2003........................................................ 50
2004........................................................ 12
----
Total............................................. $819
====
Rent expense incurred under operating leases aggregated approximately
$35,000 in 1999.
(c) Fuel Supply Agreements -- REMA, primarily through its ownership
interests in Conemaugh and Keystone, is a party to several long-term fuel supply
contracts that have various quantity requirements and durations. Minimum payment
obligations under these agreements that extend through 2004 are as follows (in
millions):
2000........................................................ $ 67
2001........................................................ 47
2002........................................................ 40
2003........................................................ 19
2004........................................................ 13
----
Total............................................. $186
====
(d) Other -- REMA is party to various legal proceedings that arise from
time to time in the ordinary course of business. While REMA cannot predict the
outcome of these proceedings, REMA does not expect these matters to have a
material adverse effect on REMA's financial position, operations or cash flows.
6. EMPLOYEE BENEFIT PLANS AND OTHER EMPLOYEE MATTERS
Substantially all of REMA's union employees participate in a
noncontributory pension plan (the Hourly Plan). The Hourly Plan provides
retirement benefits based on years of service and compensation. The funding
policy of REMA is to contribute amounts annually in accordance with applicable
regulations in order to achieve adequate funding of projected benefit
obligations. Sithe included REMA's union employees in its pension plan effective
November 24, 1999, and all pension liabilities associated with employee service
periods prior to that date were retained by GPU pursuant to the purchase
agreement between Sithe and GPU. Pension expense for 1999 for REMA employees was
approximately $500,000.
F-12
154
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Effective November 24, 1999, REMA participated in Sithe's savings plan (the
Savings Plan), which covered substantially all of REMA's employees. The Savings
Plan limits non-union employees' pre-tax and/or after-tax contributions to 16%
of covered compensation, not to exceed the annual contribution limits of the
Internal Revenue Code of 1986, as amended (the Code). REMA matches up to 100% of
the first 3% of each non-union employee's contributions (based on the employee's
service). REMA matches between 55% and 65% (based upon the terms of the
applicable collective bargaining agreement) of the first 4% of each union
employee's pre-tax and/or after-tax contributions (up to the annual Code
contribution limits) to the Savings Plan. Employer matching contributions for
non-union employees are subject to a vesting schedule, which entitles the
employee to a percentage of the employer matching contributions, depending on
years of service, but union employees are fully vested in their employer
matching contributions. Sithe's savings plan benefit expense for REMA employees
for 1999 was approximately $93,000.
Effective November 24, 1999, Sithe provided various health care benefits to
eligible REMA employees. Health care expense for 1999 was approximately
$400,000. These benefits were funded from the general assets of REMA as they
were incurred. All health care liabilities associated with employee service
periods prior to November 24, 1999 were retained by GPU pursuant to the purchase
agreement between Sithe and GPU. All retiree medical obligations for REMA
employees were retained by GPU pursuant to the purchase agreement between Sithe
and GPU.
Approximately 67% of REMA's employees are the subject of three collective
bargaining arrangements. Of these employees, 7%, representing 5% of REMA's total
workforce, are subject to arrangements that expire prior to December 31, 2000.
7. RELATED PARTY TRANSACTIONS
In 1999, REMA sold most of the electric power generated by its facilities
to the Sithe Affiliate. REMA also purchased fuel for its generating plants
(other than coal for Keystone and Conemaugh) from the Sithe Affiliate. In
connection with the acquisition of REMA in May 2000, REMA now markets its power
through and purchases fuel from Reliant Energy Services, Inc., an affiliate of
REPG.
8. SUBSEQUENT EVENT
(a) Acquisition by REPG
In February 2000, REPG reached a definitive agreement to purchase the
equity of REMA and the $1.6 billion of pre-existing affiliate debt from Sithe
for an aggregate purchase price of $2.1 billion, subject to adjustments.
Included within this purchase transaction were transition power purchase
agreements, including the capacity transition contract with GPU described in
Note 1(d). The transaction was completed in May 2000. The acquisition was
accounted for as a purchase and the purchase price allocations were pushed down
to REMA.
(b) Restructuring
In July 2000, Reliant Energy Mid-Atlantic Power Holdings, LLC acquired the
ownership interests in the following affiliates, which are included in these
combined financial statements:
Reliant Energy New Jersey Holdings, LLC
Reliant Energy Maryland Holdings, LLC
Reliant Energy Mid-Atlantic Power Services, Inc.
F-13
155
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
These affiliates were acquired from an indirect wholly owned subsidiary of
REPG for a purchase price of $167 million, and REMA issued a note in this amount
to the subsidiary. In addition, the developmental entities listed in Note 1(a)
were distributed to Reliant Energy Mid-Atlantic Development, Inc., a wholly
owned subsidiary of REPG but not of REMA.
(c) Lease Financing
In August 2000, REMA sold to and leased back from each of three owner
lessors in separate lease transactions REMA's respective 16.45%, 16.67% and 100%
interests in the Conemaugh, Keystone and Shawville generating stations. As
lessee, REMA leases an interest in each facility from each owner lessor under a
facility lease agreement. The lease agreements contain some restrictive
covenants that restrict REMA's ability to, among other things, make dividend
distributions unless REMA satisfies various conditions. The covenant restricting
dividends would be suspended if a direct or indirect parent of REMA meeting
specified criteria guarantees the lease obligations. As consideration for the
sale of REMA's interest in each of the facilities, REMA received $1.0 billion in
cash. These proceeds were utilized to return capital of $183 million, with the
remainder used to reduce affiliate debt.
The following table sets forth REMA's obligation under these long-term
operating leases (in millions).
Inception of lease to December 31, 2000................. $ 0.9
2001.................................................... 259.3
2002.................................................... 136.5
2003.................................................... 76.5
2004.................................................... 84.5
2005 and beyond......................................... 1,262.3
--------
$1,820.0
========
The equity interests in all of the affiliates of REMA are pledged as
collateral for REMA's lease obligations. In addition, these affiliates have also
guaranteed the payments under the lease obligations. The following represents
condensed combining financial statements of REMA and its affiliates. The
affiliates included in the condensed combining financial statements presented
below are all wholly owned and constitute all of REMA's direct and indirect
affiliates (Guarantor Affiliates). The guaranties of the Guarantor Affiliates of
the lease obligations are all full, unconditional, and joint and several. There
are no significant restrictions on the Company's ability to obtain funds from
the Guarantor Affiliates.
F-14
156
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS LLC AND RELATED COMPANIES
STATEMENT OF CONDENSED COMBINING OPERATIONS
FOR THE PERIOD FROM NOVEMBER 24, 1999 TO DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
GUARANTOR
REMA AFFILIATES ELIMINATIONS COMBINED
---------- ------------ ------------ ----------
Revenues......................................... $ 25,391 $ 4,135 $ -- $ 29,526
Expenses:
Fuel and operating............................. 16,695 1,889 -- 18,584
Administrative and general..................... 385 1,199 -- 1,584
Project development............................ 1,606 -- -- 1,606
Depreciation and amortization.................. 4,177 665 -- 4,842
---------- -------- ------ ----------
Total Expenses......................... 22,863 3,753 -- 26,616
Operating Income................................. 2,528 382 -- 2,910
Interest Expense to Affiliates, net.............. 11,324 1,264 -- 12,588
---------- -------- ------ ----------
Net Loss......................................... $ (8,796) $ (882) $ -- $ (9,678)
========== ======== ====== ==========
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS LLC AND RELATED COMPANIES
CONDENSED COMBINING BALANCE SHEET
DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
GUARANTOR
REMA AFFILIATES ELIMINATIONS COMBINED
---------- ------------ ------------ ----------
Current Assets................................... $ 42,527 $ 18,056 $ -- $ 60,583
Property, Plant and Equipment, net............... 1,129,101 157,218 -- 1,286,319
Other Noncurrent Assets.......................... 323,439 35,559 -- 358,998
---------- -------- ------ ----------
Total Assets........................... $1,495,067 $210,833 $ -- $1,705,900
========== ======== ====== ==========
Demand Notes Payable to Affiliate................ $1,418,320 $156,992 $ -- $1,575,312
Other Current Liabilities........................ 33,592 21,005 -- 54,597
Noncurrent Liabilities........................... 17,001 14,059 -- 31,060
Member's and Shareholder's Equity................ 26,154 18,777 -- 44,931
---------- -------- ------ ----------
Total Liabilities and Member's and
Shareholder's Equity................. $1,495,067 $210,833 $ -- $1,705,900
========== ======== ====== ==========
***
F-15
157
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
INTERIM CONDENSED STATEMENTS OF COMBINED AND CONSOLIDATED OPERATIONS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
FOR THE PERIODS FROM
--------------------------------------
JANUARY 1, 2000 MAY 12, 2000 TO
TO MAY 11, 2000 SEPTEMBER 30, 2000
(FORMER REMA) (CURRENT REMA)
----------------- ------------------
Revenues, including $166.5 million and $133.5 million from
affiliate (for Former REMA and Current REMA,
respectively)............................................. $166,490 $365,322
Expenses:
Fuel, including $37.3 million and $14.7 million from
affiliate (for Former REMA and Current REMA,
respectively)........................................ 53,628 69,999
Operation and maintenance.............................. 40,372 33,146
Facilities lease expense............................... -- 6,245
Administrative and general............................. 13,101 12,137
Depreciation and amortization.......................... 19,538 25,627
-------- --------
Total Expenses.................................... 126,639 147,154
-------- --------
Operating Income............................................ 39,851 218,168
Interest Expense to Affiliate, net.......................... 46,538 51,482
-------- --------
Net (Loss) Income Before Taxes.............................. (6,687) 166,686
-------- --------
Income Tax Expense.......................................... -- 68,828
-------- --------
Net (Loss) Income........................................... $ (6,687) $ 97,858
======== ========
See Notes to the Interim Condensed Combined and Consolidated Financial
Statements.
F-16
158
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
INTERIM CONDENSED COMBINED AND CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
DECEMBER 31, 1999 SEPTEMBER 30, 2000
(FORMER REMA) (CURRENT REMA)
----------------- ------------------
ASSETS
Current Assets:
Cash and cash equivalents.............................. $ 570 $ 157,840
Fuel inventories....................................... 6,411 31,264
Material and supplies inventories...................... 52,965 35,859
Other current assets................................... 637 52,543
---------- ----------
Total current assets.............................. 60,583 277,506
Property, Plant and Equipment, net........................ 1,286,319 920,380
Other Noncurrent Assets:
Goodwill, net.......................................... 184,518 7,154
Air emissions regulatory allowances, net............... 166,791 157,548
Other.................................................. 7,689 24,563
Deferred income taxes, net............................. -- 343
---------- ----------
Total other noncurrent assets..................... 358,998 189,608
---------- ----------
Total Assets...................................... $1,705,900 $1,387,494
========== ==========
LIABILITIES AND MEMBER'S AND SHAREHOLDER'S EQUITY
Current Liabilities:
Accounts payable....................................... $ 10,244 $ 26,269
Payable to affiliates.................................. 7,928 109,966
Accrued payroll........................................ 5,273 14,394
Asset purchase consideration payable................... 27,296 --
Demand notes payable to affiliate...................... 1,575,312 --
Other current liabilities.............................. 3,856 5,018
---------- ----------
Total current liabilities......................... 1,629,909 155,647
Noncurrent Liabilities:
Accrued environmental liabilities...................... 28,030 36,396
Other noncurrent liabilities........................... 3,030 24,799
---------- ----------
Total noncurrent liabilities...................... 31,060 61,195
Subordinated note payable to affiliate.................... -- 961,550
Commitments and contingencies
Member's and Shareholder's Equity:
Common stock ($.01 par value, 1,500 shares authorized,
100 shares issued and outstanding)................... -- --
Member's capital contributions......................... 54,609 111,244
Retained (deficit) earnings............................ (9,678) 97,858
---------- ----------
Total member's and shareholder's equity........... 44,931 209,102
---------- ----------
Total Liabilities and Member's and Shareholder's
Equity.......................................... $1,705,900 $1,387,494
========== ==========
See Notes to the Interim Condensed Combined and Consolidated Financial
Statements.
F-17
159
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
INTERIM CONDENSED STATEMENTS OF COMBINED AND CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
FOR THE PERIODS FROM
---------------------------------------
JANUARY 1, 2000 MAY 12, 2000
TO MAY 11, 2000 TO SEPTEMBER 30, 2000
(FORMER REMA) (CURRENT REMA)
--------------- ---------------------
Cash Flows from Operating Activities:
Net (loss) income........................................ $ (6,687) $ 97,858
Adjustments to reconcile net (loss) income to net cash
(used in) provided by operations:
Depreciation and amortization expense................. 19,538 25,627
Deferred income taxes................................. -- (4,611)
Changes in assets and liabilities:
Inventories......................................... (1,107) (11,903)
Other assets........................................ (30,668) (53,603)
Accounts payable.................................... 4,114 26,269
Other current liabilities........................... 848 (2,361)
-------- -----------
Net cash (used in) provided by operating
activities..................................... (13,962) 77,276
-------- -----------
Cash Flows from Investing Activities:
Business acquisition..................................... -- (2,084,960)
Proceeds from sale-leaseback transactions................ -- 1,000,000
Proceeds from sale of development companies.............. -- 8,041
Capital expenditures..................................... -- (9,949)
-------- -----------
Net cash flows used in investing activities...... -- (1,086,868)
-------- -----------
Cash Flows from Financing Activities:
Proceeds from subordinated note payable to affiliate..... -- 1,611,550
Payments on subordinated note payable to affiliate....... -- (650,000)
Contributions from parent................................ -- 294,244
Return of capital........................................ -- (183,000)
Lease financing costs.................................... -- (24,687)
Net change in payables to affiliates..................... 14,415 119,325
-------- -----------
Net cash flows provided by financing
activities..................................... 14,415 1,167,432
-------- -----------
Net Change in Cash and Cash Equivalents.................... 453 157,840
Cash and Cash Equivalents, Beginning of Period............. 570 --
-------- -----------
Cash and Cash Equivalents, End of Period................... $ 1,023 $ 157,840
======== ===========
Supplemental Cash Flow Information:
Interest paid to affiliate............................... $ 46,519 $ --
======== ===========
See Notes to the Interim Condensed Combined and Consolidated Financial
Statements.
F-18
160
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
INTERIM CONDENSED COMBINED AND CONSOLIDATED STATEMENT OF
MEMBER'S AND SHAREHOLDER'S EQUITY
(THOUSANDS OF DOLLARS)
(UNAUDITED)
TOTAL
MEMBER'S
MEMBER'S RETAINED AND
COMMON CAPITAL EARNINGS SHAREHOLDER'S
STOCK CONTRIBUTIONS (DEFICIT) EQUITY
------ ------------- --------- -------------
Former REMA:
Balance at December 31, 1999.................... $-- $ 54,609 $ (9,678) $ 44,931
Net loss...................................... -- -- (6,687) (6,687)
--- --------- -------- ---------
Balance at May 11, 2000......................... 54,609 (16,365) 38,244
Current REMA:
Adjustments due to Acquisition:
Eliminate former REMA balances............. -- (54,609) 16,365 (38,244)
Capital contribution from Parent.............. -- 294,244 -- 294,244
Return of capital............................. (183,000) -- (183,000)
Net income.................................... -- -- 97,858 97,858
--- --------- -------- ---------
Balance at September 30, 2000................... $-- $ 111,244 $ 97,858 $ 209,102
=== ========= ======== =========
See Notes to the Interim Condensed Combined and Consolidated Financial
Statements.
F-19
161
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
NOTES TO UNAUDITED INTERIM CONDENSED COMBINED AND CONSOLIDATED
FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
These interim condensed combined and consolidated financial statements
(Interim Financial Statements) include the accounts of Reliant Energy
Mid-Atlantic Power Holdings, LLC and the affiliates and subsidiaries
(collectively, REMA) described in Note 1(a) to REMA's Annual Financial
Statements. These Interim Financial Statements are unaudited, omit certain
information included in financial statements prepared in accordance with
generally accepted accounting principles and should be read in combination with
the Annual Financial Statements of REMA for the period from November 24, 1999 to
December 31, 1999 included in this prospectus.
As described in Notes 1 and 8 to the Annual Financial Statements, REMA
(formerly Sithe Pennsylvania Holdings, LLC), together with its affiliates and
subsidiaries, were indirect wholly owned subsidiaries of Sithe Energies, Inc.
(Sithe) as of December 31, 1999. REMA acquired its generating stations and
various related assets from the operating subsidiaries of GPU, Inc. (GPU), a
utility holding company, on November 24, 1999. In May 2000, Sithe, through an
indirect wholly owned subsidiary, sold all of its equity interests in REMA to an
indirect wholly owned subsidiary of Reliant Energy Power Generation, Inc.
(REPG). Within these interim financial statements, "Current REMA" and "Former
REMA" refer to REMA, its subsidiaries and affiliated entities that develop
electric generating facilities after and before, respectively, the acquisition
from Sithe Energies and one of its subsidiaries. As a result of the
restructuring (see Note 3(b)), Current REMA financials are presented on a
consolidated basis, whereas Former REMA financials are presented on a combined
basis.
There are no separate financial statements available with regard to the
facilities of REMA, prior to the date that REMA acquired the generation assets
from GPU, because their operations were fully integrated with, and their results
of operations were consolidated into, the former owners of the facilities of
REMA. In addition, the electric output of the facilities was sold based on rates
set by regulatory authorities. As a result and because electricity rates will
now be set by the operation of market forces, the historical financial data with
respect to the facilities of REMA prior to November 24, 1999 is not meaningful
or indicative of REMA's future results. REMA's results of operations in the
future will depend primarily on revenues from the sale of energy, capacity and
other related products, and the level of its operating expenses.
Prior to the date REPG acquired REMA, the acquisition of REMA's generating
assets was recorded under the purchase method of accounting with assets and
liabilities of REMA reflected at their estimated fair values as of the date of
the purchase. On a preliminary basis, REMA's fair value adjustments included
increases in property, plant and equipment and air emissions regulatory
allowances. The allocation of the purchase price is preliminary, since the
valuation of property, plant and equipment and air emissions regulatory
allowances as well as the valuation of material and supplies inventories and
environmental reserves have not been finalized.
The Interim Financial Statements reflect all normal recurring adjustments
that are, in the opinion of management, necessary to present fairly the
financial position and results of operations. Amounts reported in the interim
condensed statement of combined and consolidated operations are not necessarily
indicative of amounts expected for a full year period due to the effects of,
among other things, seasonal variations in energy consumption and timing of
maintenance and other expenditures.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
F-20
162
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
NOTES TO UNAUDITED INTERIM CONDENSED COMBINED AND CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
Note 1 to the Annual Financial Statements describes significant accounting
policies of Former REMA, which is updated for Current REMA as follows:
(a) Revenue Recognition -- Revenue includes energy, capacity and ancillary
service sales. Current REMA's power and services, excluding capacity,
were sold at market-based prices through sales to a related party and
indirect wholly owned subsidiary of Reliant Energy, Incorporated (the
Affiliate) for resale. The Affiliate acted as agent on behalf of REMA
on most market-based sales. REMA's capacity was also sold to the
Affiliate at terms that mirror a transition power purchase agreement
between the Affiliate and GPU. The transition power purchase agreement
extends through May 31, 2002. Sales not billed by month-end are accrued
based upon estimated energy or services delivered.
(b) Intangible Assets -- Cost in excess of fair value of net assets
acquired (goodwill) is amortized on a straight-line basis over the
estimated useful life of 35 years. Air emissions regulatory allowances
are being amortized on a units-of-production basis as utilized.
(c) Income Taxes -- In connection with the acquisition, REMA entered into a
tax sharing agreement with Reliant Energy whereby REMA calculates its
income tax provision on a separate return basis. REMA's current federal
and state income taxes are payable to and receivable from Reliant
Energy.
(d)Major Maintenance Expense -- REMA expenses all repair and maintenance
costs as incurred, including planned major maintenance.
(e) New Accounting Pronouncements -- Effective January 1, 2001, REMA is
required to adopt Statement of Financial Accounting Standard No. 133,
"Accounting for Derivative Instruments and Hedging Activities", as
amended (SFAS No. 133), which establishes accounting and reporting
standards for derivative instruments, including some specified hedging
instruments embedded in other contracts and for hedging activities.
This statement requires that derivatives be recognized at fair value in
the balance sheet and that changes in fair value be recognized either
currently in earnings or deferred as a component of other comprehensive
income, depending on the intended use of the derivative, its resulting
designation and its effectiveness. In addition, in June 2000, the
Financial Accounting Standards Board issued an amendment that narrows
the applicability of the pronouncement to some purchase and sales
contracts and allows hedge accounting for some other specific hedging
relationships. Adoption of SFAS No. 133 will result in no cumulative
after-tax change in net income and a cumulative after-tax increase in
other comprehensive income of approximately $2 million in the first
quarter of 2001. The adoption will also impact assets and liabilities
recorded on the balance sheet.
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101),
was issued by the SEC on December 3, 1999. SAB No. 101 summarizes some
of the SEC staff's views in applying generally accepted accounting
principles to revenue recognition in financial statements. REMA's
combined financial statements reflect the accounting principles provided
in SAB No. 101.
2. DEMAND NOTES PAYABLE TO AFFILIATE
In connection with Sithe's acquisition of its generating assets from GPU,
REMA entered into approximately $1.6 billion of demand notes payable to Sithe
Northeast Generating Company, Inc. (an indirect wholly owned subsidiary of
Sithe) due August 20, 2001. In connection with the acquisition of REMA in May
2000, Sithe Northeast Generating Company, Inc. sold these notes to an indirect
wholly owned subsidiary of REPG. See Note 3. The original notes were
subsequently cancelled and new notes issued (New Notes), which are due January
1, 2029.
F-21
163
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
NOTES TO UNAUDITED INTERIM CONDENSED COMBINED AND CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
Prior to May 2000, the notes bore interest at a financing rate based on the
London interbank offered rate (LIBOR) plus 1.9% per annum. The New Notes accrue
interest at a fixed rate of 9.4% per annum. Borrowings outstanding under these
unsecured notes payable are deemed to approximate fair value.
3. BUSINESS ACQUISITIONS
(a) Acquisition by REPG
In February 2000, REPG reached a definitive agreement to purchase the
equity in REMA and the $1.6 billion of pre-existing affiliate debt from Sithe
for an aggregate purchase price of $2.1 billion, subject to adjustments.
Included within this purchase transaction were transition power purchase
agreements, including the capacity transition contract with GPU described in
Note 1(d) to REMA's Annual Financial Statements. The transaction was completed
in May 2000. REPG accounted for the acquisition as a purchase with assets and
liabilities of REMA reflected at their estimated fair values. On a preliminary
basis, the fair value adjustments related to the acquisition which have been
pushed down to REMA, primarily included adjustments in property, plant and
equipment, air emissions regulatory allowances, materials and supplies
inventory, environmental reserves and related deferred taxes. The air emissions
regulatory allowances of $153 million are being amortized on a
units-of-production basis as utilized. In addition, a valuation allowance for
materials and supplies inventory of $17 million was established. Subsequent to
the issuance of REMA's financial statements for the period ended September 30,
2000, management determined that its preliminary purchase price allocation for
the acquisition of REMA should be reallocated. This reallocation resulted in the
elimination of major maintenance reserves, and related reductions of goodwill
and deferred tax assets, previously recorded in connection with the acquisition
of REMA. As a result, REMA has revised its September 30, 2000 consolidated
balance sheet to reduce major maintenance reserves, goodwill and deferred tax
assets by $110 million, $66 million and $44 million, respectively. In addition,
REMA recognized an increase in deferred tax liabilities of $21 million resulting
from book/tax basis differences of recorded air emissions regulatory allowances.
Such deferred tax effects and the corresponding increase in goodwill had not
been considered in connection with REMA's previously recorded purchase price
allocation. REMA believes that the fair value allocated to property, plant and
equipment acquired in connection with its acquisition properly reflects planned
major maintenance activities. The excess of the purchase price over the fair
value of the net assets acquired of approximately $7 million was recorded as
goodwill and is being amortized over 35 years. As of September 30, 2000, REMA
has liabilities associated with six ash disposal sites and six site
investigations and environmental remediations. REMA has recorded its estimate of
these environmental liabilities in the amount of $36 million as of September 30,
2000, of which approximately $13 million will be paid over the next five years.
REMA expects to finalize the fair value adjustments, based on valuation reports
for property, plant and equipment and intangible assets that will be finalized
by May 2001 and does not anticipate additional material modifications to the
preliminary adjustments.
(b) Restructuring
In July 2000, Reliant Energy Mid-Atlantic Power Holdings, LLC acquired the
ownership interests in the following affiliates, which are included in these
combined financial statements:
Reliant Energy New Jersey Holdings, LLC
Reliant Energy Maryland Holdings, LLC
Reliant Energy Mid-Atlantic Power Services, Inc.
These affiliates were acquired from an indirect wholly owned subsidiary of
REPG for a purchase price of $167 million, which amount was borrowed from an
indirect wholly owned subsidiary of REPG. In addition, the developmental
entities listed in Note 1(a) to REMA's Annual Financial Statements were
F-22
164
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
NOTES TO UNAUDITED INTERIM CONDENSED COMBINED AND CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
sold to Reliant Energy Mid-Atlantic Development, Inc. a wholly owned subsidiary
of REPG, but not of REMA, for approximately $8 million.
Pro-forma (loss) net income for the period from November 24 through
December 31, 1999 and for the nine months ended September 30, 2000, giving
effect to the acquisition and sale leaseback (See Note 4) as if it had occurred
as of the beginning of each period, was a net loss of $10.2 million and net
income of $88.9 million, respectively.
4. LEASE FINANCING
In August 2000, REMA sold to and leased back from each of three owner
lessors in separate lease transactions REMA's respective 16.45%, 16.67% and 100%
interest in the Conemaugh, Keystone and Shawville generating stations. As a
lessee, REMA leases an interest in each facility from each owner lessor under a
facility lease agreement. The lease agreements contain some restrictive
covenants that restrict REMA's ability to, among other things, make dividend
distributions unless REMA satisfies various conditions. The covenant restricting
dividends would be suspended if a direct or indirect parent of REMA meeting
specified criteria guarantees the lease obligations. As consideration for the
sale of REMA's interest in each of the facilities; REMA received $1.0 billion in
cash. These proceeds were utilized to return capital of $183 million, with the
remainder used to reduce affiliate debt. In connection with the lease
transactions, REMA entered into working capital facilities with affiliates in
the aggregate amount of $150 million.
The following table sets forth REMA's obligation under these long-term
operating leases (in millions):
Inception of lease to December 31, 2000.................... $ 0.9
2001....................................................... 259.3
2002....................................................... 136.5
2003....................................................... 76.5
2004....................................................... 84.5
2005 and beyond............................................ 1,262.3
--------
$1,820.0
========
Operating lease expense was $0 and $6.2 million for Former REMA and Current
REMA, respectively.
The equity interests in all of the subsidiaries of REMA are pledged as
collateral for REMA's lease obligations. In addition, these subsidiaries have
also guaranteed the payments under the lease obligations. The following
represents condensed consolidating financial statements of REMA and its
subsidiaries. The subsidiaries included in the condensed consolidating financial
statements presented below are all wholly owned and constitute all of REMA's
direct and indirect subsidiaries (Guarantor Subsidiaries). The guaranties of the
Guarantor Subsidiaries of the lease obligations are all full, unconditional, and
joint and several. There are no significant restrictions on the Company's
ability to obtain funds from the Guarantor Subsidiaries.
F-23
165
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
NOTES TO UNAUDITED INTERIM CONDENSED COMBINED AND CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
(THOUSANDS OF DOLLARS)
GUARANTOR
REMA SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------
Revenues...................................... $ 426,876 $104,936 $ -- $ 531,812
Expenses:
Fuel and operating.......................... 175,882 27,508 -- 203,390
Administrative and general.................. 21,766 3,472 -- 25,238
Depreciation and amortization............... 37,599 7,566 -- 45,165
---------- -------- --------- ----------
Total Expenses...................... 235,247 38,546 -- 273,793
Operating Income.............................. 191,629 66,390 -- 258,019
Equity in Earnings of Consolidated
Subsidiaries................................ 33,315 -- (33,315) --
Interest Expense.............................. 89,244 8,776 -- 98,020
---------- -------- --------- ----------
Net Income Before Taxes....................... 135,700 57,614 (33,315) 159,999
Income Tax Expense to Affiliates, net......... 45,129 23,699 -- 68,828
---------- -------- --------- ----------
Net Income.................................... $ 90,571 $ 33,915 $ (33,315) $ 91,171
========== ======== ========= ==========
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
SEPTEMBER 30, 2000
(THOUSANDS OF DOLLARS)
GUARANTOR
REMA SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------
Current Assets................................ $ 108,964 $168,542 $ -- $ 277,506
Property, Plant and Equipment, net............ 595,009 325,371 -- 920,380
Other Noncurrent Assets....................... 556,107 14,760 (381,259) 189,608
---------- -------- --------- ----------
Total Assets........................ $1,260,080 $508,673 $(381,259) $1,387,494
========== ======== ========= ==========
Other Current Liabilities..................... $ 37,512 $118,135 $ -- $ 155,647
Noncurrent Liabilities........................ 51,917 9,278 -- 61,195
Subordinated Note Payable to Affiliate........ 961,550 -- -- 961,550
Member's Equity............................... 209,102 381,259 (381,259) 209,102
---------- -------- --------- ----------
Total Liabilities and Member's
Equity............................ $1,260,081 $508,672 $(381,259) $1,387,494
========== ======== ========= ==========
5. COMMITMENTS AND CONTINGENCIES
(a) Environmental -- Under the agreement to acquire REMA's generating
assets from GPU, liabilities associated with ash disposal site closure and site
contamination at the acquired facilities in Pennsylvania and New Jersey prior to
plant closing were assumed, except for the first $6 million of remediation costs
at the Seward station. GPU retained liabilities associated with the disposal of
hazardous substances to off-site locations prior to November 24, 1999. REMA has
recorded its estimate of these environmental liabilities in the amount of $36
million as of September 30, 2000.
(b) Legal -- REMA is a party to various legal proceedings that arise from
time to time in the ordinary course of business. While REMA cannot predict the
outcome of these proceedings, REMA does not expect these matters to have a
material adverse effect on REMA's financial position, operations or cash flows.
F-24
166
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND RELATED COMPANIES
NOTES TO UNAUDITED INTERIM CONDENSED COMBINED AND CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
6. SUBSEQUENT EVENT
(a) Reliant Resources, Inc.
Effective December 31, 2000, Reliant Energy, Incorporated consolidated all
of its unregulated operations under is wholly owned subsidiary, Reliant
Resources, Inc. (RRI). As a result of these transactions, REPG, REMA's indirect
parent, became a wholly owned subsidiary of RRI.
(b) Intercompany Note
REMA has borrowed from Reliant Energy Northeast Holdings, Inc.
approximately $83 million. The borrowing will mature on January 1, 2029, bears
interest at a fixed rate of 9.4% and is unsecured. Repayment of the borrowing
will be subordinated to REMA's lease obligations as required by the lease
documents.
* * *
F-25
167
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Member of
Reliant Energy New Jersey Holdings, LLC
We have audited the accompanying consolidated balance sheet of Reliant
Energy New Jersey Holdings, LLC (formerly Sithe New Jersey Holdings, LLC) (RENJ)
and its subsidiaries as of December 31, 1999, and the related consolidated
statements of operations, member's equity, and cash flows for the period from
November 24, 1999 to December 31, 1999. These financial statements are the
responsibility of RENJ's management. Our responsibility is to express an opinion
on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the consolidated financial position of RENJ and its
subsidiaries at December 31, 1999, and the results of their operations and their
cash flows for the period from November 24, 1999 to December 31, 1999 in
conformity with accounting principles generally accepted in the United States of
America.
DELOITTE & TOUCHE LLP
Pittsburgh, Pennsylvania
July 12, 2000
(except for Note 7(c) to the consolidated financial
statements which is dated August 24, 2000)
F-26
168
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
FOR THE PERIOD FROM NOVEMBER 24, 1999 TO DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
Revenues from Affiliate..................................... $4,017
Expenses:
Fuel from affiliate....................................... 66
Operation and maintenance................................. 1,115
Administrative and general................................ 3
Project development....................................... 614
Other taxes............................................... 134
Depreciation and amortization............................. 605
------
Total Expenses.................................... 2,537
------
Operating Income............................................ 1,480
Interest Expense to Affiliate, net.......................... 1,171
------
Net Income.................................................. $ 309
======
See Notes to the Consolidated Financial Statements.
F-27
169
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
ASSETS
Current Assets:
Material and supplies inventories...................... $ 17,649
Other current assets................................... 216
--------
Total current assets.............................. 17,865
Property, Plant and Equipment, net........................ 143,952
Other Noncurrent Assets:
Goodwill, net.......................................... 22,498
Air emissions regulatory allowances, net............... 11,000
--------
Total other noncurrent assets..................... 33,498
--------
Total Assets...................................... $195,315
========
LIABILITIES AND MEMBER'S EQUITY
Current Liabilities:
Payable to affiliates.................................. $ 15,513
Accrued payroll........................................ 385
Asset purchase consideration payable................... 1,015
Demand notes payable to affiliate...................... 145,033
Other current liabilities.............................. 872
--------
Total current liabilities......................... 162,818
Noncurrent Liabilities:
Accrued environmental liabilities...................... 11,903
Other noncurrent liabilities........................... 2,156
--------
Total noncurrent liabilities...................... 14,059
Commitments and Contingencies (Note 4)
Member's Equity:
Member's equity........................................ 18,129
Retained earnings...................................... 309
--------
Total member's equity............................. 18,438
--------
Total Liabilities and Member's Equity............. $195,315
========
See Notes to the Consolidated Financial Statements.
F-28
170
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
FOR THE PERIOD FROM NOVEMBER 24, 1999 TO DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
Cash Flows from Operating Activities:
Net income................................................ $ 309
Adjustments to reconcile net income to net cash provided
by operations:
Depreciation and amortization expense.................. 605
Changes in assets and liabilities:
Material and supplies inventories.................... 8
Other current liabilities............................ 357
---------
Net cash provided by operating activities......... 1,279
---------
Cash Flows from Investing Activities:
Acquisition of generating stations........................ (163,162)
---------
Net cash flows used in investing activities....... (163,162)
---------
Cash Flows from Financing Activities:
Capital contribution...................................... 18,129
Proceeds from demand notes payable to affiliate........... 145,033
Net change in payables to affiliates...................... (1,279)
---------
Net cash flows provided by financing activities... 161,883
---------
Net Change in Cash and Cash Equivalents..................... --
Cash and Cash Equivalents, Beginning of Period.............. --
---------
Cash and Cash Equivalents, End of Period.................... $ --
=========
Supplemental Cash Flow Information:
Interest paid to affiliate................................ $ 1,171
=========
See Notes to the Consolidated Financial Statements.
F-29
171
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF MEMBER'S EQUITY
FOR THE PERIOD FROM NOVEMBER 24, 1999 TO DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
TOTAL
MEMBER'S RETAINED MEMBER'S
EQUITY EARNINGS EQUITY
-------- -------- --------
Balance, Beginning of Period................................ $ -- $ -- $ --
Capital contributions..................................... 18,129 -- 18,129
Net income................................................ -- 309 309
------- ---- -------
Balance, End of Period...................................... $18,129 $309 $18,438
======= ==== =======
See Notes to the Consolidated Financial Statements.
F-30
172
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Reliant Energy New Jersey Holdings, LLC -- Reliant Energy New Jersey
Holdings, LLC (formed December 28, 1998 and formerly named Sithe New Jersey
Holdings, LLC), together with its subsidiaries (collectively, RENJ), were
indirect wholly owned subsidiaries of Sithe Energies, Inc. (Sithe) as of
December 31, 1999. RENJ acquired its generating stations and various related
assets from an operating subsidiary of GPU, Inc. (GPU), a utility holding
company, on November 24, 1999. Reliant Energy Mid-Atlantic Power Holdings, LLC
(formerly Sithe Pennsylvania Holdings, LLC) (REMA), an affiliate of the Company,
also acquired assets from GPU in Pennsylvania as did another affiliate in
Maryland. The operations of RENJ, REMA and the other affiliate in Maryland have
been managed together since November 24, 1999.
In May 2000, Sithe, through an indirect wholly owned subsidiary, sold all
of its equity interests in RENJ and REMA to an indirect wholly owned subsidiary
of Reliant Energy Power Generation, Inc. (REPG). REPG is a wholly owned
subsidiary of Reliant Energy, Incorporated (Reliant Energy). See note 7.
Following this transaction, RENJ changed its name such that "Sithe" was replaced
with "Reliant Energy."
RENJ owns and operates four electric generation plants in New Jersey with
an annual average net generating capacity of approximately 1,499 megawatts (MW).
(b) Basis of Presentation and Principles of Consolidation -- These
consolidated financial statements present the results of operations for the
period from November 24, 1999 (the date that RENJ acquired the generation assets
from GPU) to December 31, 1999. There are no separate financial statements
available with regard to the facilities of RENJ (prior to the acquisition)
because their operations were fully integrated with, and their results of
operations were consolidated into, the former owners of the facilities of RENJ.
In addition, the electric output of the facilities was sold based on rates set
by regulatory authorities. As a result and because electricity rates will now be
set by the operation of market forces, the historical financial data with
respect to the facilities of RENJ prior to November 24, 1999 is not meaningful
or indicative of RENJ's future results. RENJ's results of operations in the
future will depend primarily on revenues from the sale of energy, capacity and
ancillary services, and the level of its operating expenses.
The acquisition of RENJ's generating assets was recorded under the purchase
method of accounting with assets and liabilities of RENJ reflected at their
estimated fair values as of the date of the purchase. On a preliminary basis,
RENJ's fair value adjustments included increases in property, plant and
equipment and air emissions regulatory credits. The allocation of the purchase
price is preliminary, since the valuation of property, plant and equipment and
air emissions regulatory allowances as well as the valuation of material and
supplies inventories and environmental reserves have not been finalized. RENJ's
liabilities include $1.0 million of asset purchase consideration payable in
connection with RENJ's acquisition of its generating assets.
The consolidated financial statements include the accounts of RENJ and its
subsidiaries. All significant intercompany transactions and balances are
eliminated in consolidation.
(c) Use of Estimates -- The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from these estimates.
F-31
173
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(d) Revenue Recognition -- Revenue includes energy, capacity and ancillary
service sales. During 1999, RENJ's power and services, excluding capacity, were
sold at market-based prices through sales to a related party and wholly owned
subsidiary of Sithe (the Sithe Affiliate) for resale. The Sithe Affiliate acted
as agent on behalf of RENJ on most market-based sales. RENJ's capacity was also
sold to the Sithe Affiliate at terms that mirror a transition power purchase
agreement between Sithe and GPU. The transition power purchase agreement extends
from November 24, 1999 to May 31, 2002. Sales not billed by month-end are
accrued based upon estimated energy or services delivered.
(e) Cash and Cash Equivalents -- Cash and cash equivalents are considered
to be highly liquid investments with an original maturity of three months or
less, which are cash or are readily convertible to cash.
(f) Inventories -- Inventories are comprised of materials and supplies and
are stated at the lower of weighted-average cost or market.
(g) Fair Values of Financial Instruments -- The recorded amounts for
financial instruments such as affiliate payables approximate fair value due to
the short-term nature of these instruments.
(h) Property, Plant and Equipment -- Property, plant and equipment are
stated at cost. Depreciation is computed using the straight-line method over the
estimated useful lives commencing when assets, or major components thereof, are
either placed in service or acquired, as appropriate.
(i) Intangible Assets -- Cost in excess of fair value of net assets
acquired (goodwill) is amortized on a straight-line basis over the estimated
useful life of 40 years. Goodwill amortization expense during 1999 was $46,000.
Other intangible assets consist primarily of air emissions regulatory
allowances that have already been issued to RENJ and allowances that RENJ
expects to be allocated during the remaining useful lives of the plants. These
intangible assets are amortized on a unit-of-production basis as utilized.
Because no credits were utilized in 1999, no amortization expense was recognized
during the period related to other intangible assets.
(j) Impairment of Long-Lived Assets -- RENJ periodically compares the
carrying value of its long-lived assets, including goodwill and other intangible
assets, to the anticipated undiscounted future net cash flows from their
corresponding businesses, and no impairment is indicated at December 31, 1999.
(k) Project Development Costs -- RENJ capitalizes the deposits made toward
future combustion turbine deliveries as well as the direct costs associated with
viable projects, including some third-party legal, accounting and consulting
costs. These capitalized costs, once incurred, are amortized over the estimated
life of the project on a straight-line basis, beginning when the project becomes
operational. Other project development costs are expensed as incurred.
(l) Income Taxes -- RENJ and its subsidiaries are limited liability
companies that are not taxable for federal income tax purposes.
(m) Market Risk and Other Uncertainties -- RENJ is subject to certain risks
such as the supply and price of fuel, seasonal weather patterns, technological
obsolescence and the regulatory environment within the United States.
(n) Comprehensive Income -- RENJ had no items of comprehensive income for
the financial statement period presented.
(o) New Accounting Pronouncements -- Effective January 1, 2001, RENJ is
required to adopt Statement of Financial Accounting Standard No. 133,
"Accounting for Derivative Instruments and
F-32
174
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Hedging Activities," as amended (SFAS No. 133), which establishes accounting and
reporting standards for derivative instruments, including some specified hedging
instruments embedded in other contracts and for hedging activities. This
statement requires that derivatives be recognized at fair value in the balance
sheet and that changes in fair value be recognized either currently in earnings
or deferred as a component of other comprehensive income, depending on the
intended use of the derivative, its resulting designation and its effectiveness.
In addition, in June 2000, the Financial Accounting Standards Board issued an
amendment that narrows the applicability of the pronouncement to some purchase
and sales contracts and allows hedge accounting for some other specific hedging
relationships. Adoption of SFAS No. 133 will result in no cumulative after-tax
change to net income or other comprehensive income.
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101), was
issued by the SEC on December 3, 1999. SAB No. 101 summarizes some of the SEC
staff's views in applying generally accepted accounting principles to revenue
recognition in financial statements. RENJ's consolidated financial statements
reflect the accounting principles provided in SAB No. 101.
2. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following at December 31 (in
thousands):
ESTIMATED USEFUL
LIVES (YEARS) 1999
-------------------- -----------
Land.................................................. -- $ 5,280
Generation plant-in-service........................... 11 to 30 139,020
Machinery and equipment............................... 10 211
-----------
Total....................................... 144,511
Less -- accumulated depreciation...................... (559)
-----------
Property, plant and equipment -- net.................. $ 143,952
===========
3. DEMAND NOTES PAYABLE TO AFFILIATE
In connection with Sithe's acquisition of its generating assets from GPU,
RENJ executed or issued approximately $145 million of demand notes payable to
Sithe Northeast Generating Company, Inc. (an indirect wholly owned subsidiary of
Sithe) due August 20, 2001. The notes bear interest at a financing rate based on
the London interbank offered rate (LIBOR) plus (a) 1.9% per annum through
November 24, 2000 and (b) 2.4% per annum thereafter. The applicable interest
rate was 7.644% at December 31, 1999. Borrowings outstanding under these
unsecured notes payable approximate fair value, as the individual borrowings
bear interest at current market rates. In connection with the acquisition of
RENJ in May 2000, Sithe Northeast Generating Company, Inc. sold these notes to
an indirect wholly owned subsidiary of REPG. See Note 7.
4. COMMITMENTS AND CONTINGENCIES
(a) Environmental -- Under the agreement to acquire RENJ's generating
assets from GPU, liabilities associated with ash disposal site closure and site
contamination at the acquired facilities in New Jersey prior to closing were
assumed. GPU retained liabilities associated with the disposal of hazardous
substances to off-site locations prior to November 24, 1999. RENJ has recorded
its estimate of these environmental liabilities in the amount of $11.9 million
as of December 31, 1999.
F-33
175
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(b) Operating Leases -- RENJ leases some equipment and vehicles under
noncancelable operating leases extending through 2004. Future minimum rentals
under lease agreements are as follows (in thousands):
2000........................................................ $22
2001........................................................ 22
2002........................................................ 22
2003........................................................ 18
---
Total............................................. $84
===
Rent expense incurred under operating leases aggregated approximately
$4,000 in 1999.
(c) Other -- RENJ is party to various legal proceedings that arise from
time to time in the ordinary course of business. While RENJ cannot predict the
outcome of these proceedings, RENJ does not expect these matters to have a
material adverse effect on RENJ's financial position, operations or cash flows.
5. EMPLOYEE BENEFIT PLANS AND OTHER EMPLOYEE MATTERS
Substantially all of RENJ's union employees participate in a
noncontributory pension plan (the Hourly Plan). The Hourly Plan provides
retirement benefits based on years of service and compensation. The funding
policy of RENJ is to contribute amounts annually in accordance with applicable
regulations in order to achieve adequate funding of projected benefit
obligations. Sithe included RENJ's union employees in its pension plan effective
on November 24, 1999, and all pension liabilities associated with employee
service periods prior to that date were retained by GPU pursuant to the purchase
agreement between Sithe and GPU. Pension expense for 1999 for RENJ employees was
approximately $46,000.
Effective November 24, 1999, RENJ participated in Sithe's savings plan (the
Savings Plan), which covered substantially all of RENJ's employees. The Savings
Plan limits non-union employees' pre-tax and/or after-tax contributions to 16%
of covered compensation, not to exceed the annual contribution limits of the
Internal Revenue Code of 1986, as amended (the Code). RENJ matches up to 100% of
the first 3% of each non-union employee's contributions (based on the employee's
service). RENJ matches between 55% and 65% (based upon the terms of the
applicable collective bargaining agreement) of the first 4% of each union
employee's pre-tax and/or after-tax contributions (up to the annual Code
contribution limits) to the Savings Plan. Employer matching contributions for
non-union employees are subject to a vesting schedule, which entitles the
employee to a percentage of the employer matching contributions, depending on
years of service, but union employees are fully vested in their employer
matching contributions. Sithe's savings plan benefit expense for RENJ employees
for 1999 was approximately $12,000.
Effective November 24, 1999, Sithe provided various health care benefits to
eligible RENJ employees. Health care expense for 1999 was approximately $35,000.
These benefits were funded from the general assets of RENJ as they were
incurred. All health care liabilities associated with employee service periods
prior to November 24, 1999 were retained by GPU pursuant to the purchase
agreement between Sithe and GPU. All retiree medical obligations for RENJ
employees were retained by GPU pursuant to the purchase agreement between Sithe
and GPU.
Approximately 67% of RENJ's employees are the subject of a collective
bargaining arrangement. All of these union employees are subject to arrangements
that expire prior to December 31, 2000.
F-34
176
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC
(FORMERLY SITHE NEW JERSEY HOLDINGS, LLC) AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. RELATED PARTY TRANSACTIONS
In 1999, RENJ sold all of the electric power generated by its facilities to
the Sithe Affiliate. RENJ also purchased fuel for its generating plants from the
Sithe Affiliate. In connection with the acquisition of RENJ in May 2000, RENJ
now markets its power through and purchases fuel from Reliant Energy Services,
Inc., an affiliate of REPG.
7. SUBSEQUENT EVENT
(a) Acquisition by REPG
In February 2000, REPG reached a definitive agreement to purchase the
equity in and the pre-existing affiliate debt of RENJ, REMA and other affiliates
from Sithe for an aggregate purchase price of $2.1 billion, subject to
adjustments. Included within this purchase transaction were transition power
purchase agreements, including the capacity transition contract with GPU
described in Note 1(d). The transaction was completed in May 2000. The
acquisition was accounted for as a purchase and the purchase price allocations
were pushed down to RENJ.
(b) Restructuring
In July 2000, REMA acquired the equity ownership interests in RENJ as well
as other affiliates. These affiliates were acquired from an indirect wholly
owned subsidiary of REPG for an aggregate purchase price of $167 million, and
REMA issued a note in this amount to the subsidiary. In addition, certain
developmental subsidiaries, which had no assets as of December 31, 1999, were
distributed to Reliant Energy Mid-Atlantic Development, Inc., a wholly owned
subsidiary of REPG but not of RENJ.
(c) Lease Financing
In August 2000, REMA sold interests in three of its generating plants
acquired in November 1999 and leased them back from owner lessors. The equity
interests in RENJ are pledged as collateral for REMA's lease obligation. In
addition, RENJ guarantees the lease obligations.
* * *
F-35
177
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC AND SUBSIDIARIES
INTERIM CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
FOR THE PERIODS FROM
------------------------------------
JANUARY 1, 2000 MAY 12, 2000 TO
TO MAY 11, 2000 SEPTEMBER 30, 2000
(FORMER RENJ) (CURRENT RENJ)
--------------- ------------------
Revenues, including $19.4 million and $44.2 million from
affiliate (for Former RENJ and Current RENJ,
respectively).......................................... $19,370 $83,863
Expenses:
Fuel, including $3.8 million and $10.0 million from
affiliate (for Former RENJ and Current RENJ,
respectively)....................................... 3,829 10,345
Operation and maintenance.............................. 5,219 4,629
Administrative and general............................. 748 2,104
Depreciation and amortization.......................... 2,068 4,866
------- -------
Total Expenses................................. 11,864 21,944
------- -------
Operating Income......................................... 7,506 61,919
Interest Expense to Affiliate, net....................... 4,243 3,837
------- -------
Net Income Before Taxes.................................. 3,263 58,082
------- -------
Income Tax Expense....................................... -- 23,726
------- -------
Net Income............................................... $ 3,263 $34,356
======= =======
See Notes to the Interim Condensed Consolidated Financial Statements.
F-36
178
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC AND SUBSIDIARIES
INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
DECEMBER 31, 1999 SEPTEMBER 30, 2000
(FORMER REMA) (CURRENT REMA)
----------------- ------------------
ASSETS
Current Assets:
Cash and cash equivalents.............................. $ -- $ 1
Receivables from affiliates............................ -- 30,110
Inventories............................................ 17,649 23,859
Other current assets................................... 216 3
-------- --------
Total current assets.............................. 17,865 53,973
Property, Plant and Equipment, net........................ 143,952 313,468
Other Noncurrent Assets:
Goodwill, net.......................................... 22,498 --
Air emissions regulatory allowances, net............... 11,000 11,513
Deferred income taxes, net............................. -- 3,404
-------- --------
Total other noncurrent assets..................... 33,498 14,917
-------- --------
Total Assets...................................... $195,315 $382,358
======== ========
LIABILITIES AND MEMBER'S EQUITY
Current Liabilities:
Payable to affiliates.................................. $ 15,513 $ --
Accrued payroll........................................ 385 319
Asset purchase consideration payable................... 1,015 --
Demand notes payable to affiliate...................... 145,033 --
Other current liabilities.............................. 872 3,670
-------- --------
Total current liabilities......................... 162,818 3,989
Noncurrent Liabilities:
Accrued environmental liabilities...................... 11,903 9,278
Other noncurrent liabilities........................... 2,156 --
-------- --------
Total noncurrent liabilities...................... 14,059 9,278
Commitments and contingencies (Note 1)....................
Member's Equity:
Member's equity........................................ 18,129 334,735
Retained earnings...................................... 309 34,356
-------- --------
Total member's equity............................. 18,438 369,091
-------- --------
Total Liabilities and Member's Equity............. $195,315 $382,358
======== ========
See Notes to the Interim Condensed Consolidated Financial Statements.
F-37
179
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC AND SUBSIDIARIES
INTERIM CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
FOR THE PERIODS FROM
------------------------------------
JANUARY 1, 2000 MAY 12, 2000 TO
TO MAY 11, 2000 SEPTEMBER 30, 2000
(FORMER RENJ) (CURRENT RENJ)
--------------- ------------------
Cash Flows from Operating Activities:
Net income................................................ $ 3,263 $ 34,356
Adjustments to reconcile net income to net cash (used in)
provided by operations:
Depreciation and amortization expense.................. 2,068 4,866
Deferred income taxes.................................. -- 2,759
Changes in assets and liabilities:
Inventories.......................................... (2,631) (9,089)
Other assets......................................... (3,745) (3)
Other current liabilities............................ (385) (6,364)
------- ---------
Net cash (used in) provided by operating
activities...................................... (1,430) 26,525
======= =========
Cash Flows from Investing Activities:
Business acquisition...................................... -- (191,450)
Other..................................................... -- (2)
------- ---------
Net cash flows used in investing activities....... -- (191,452)
------- ---------
Cash Flows from Financing Activities:
Decrease in subordinated note payable to affiliate........ -- (143,284)
Contributions from parent................................. 334,735
Net change in payables to affiliates...................... 1,430 (26,523)
------- ---------
Net cash flows provided by financing activities... 1,430 164,928
------- ---------
Net Change in Cash and Cash Equivalents..................... -- 1
Cash and Cash Equivalents, Beginning of Period.............. -- --
------- ---------
Cash and Cash Equivalents, End of Period.................... $ -- $ 1
======= =========
Supplemental Cash Flow Information:
Interest paid to affiliate................................ $ 4,111 $ --
======= =========
See Notes to the Interim Condensed Consolidated Financial Statements.
F-38
180
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC AND SUBSIDIARIES
INTERIM CONDENSED STATEMENT OF CONSOLIDATED MEMBER'S EQUITY
(THOUSANDS OF DOLLARS)
(UNAUDITED)
TOTAL
MEMBER'S RETAINED MEMBER'S
EQUITY EARNINGS EQUITY
-------- -------- --------
Former RENJ:
Balance at December 31, 1999................................ $ 18,129 $ 309 $ 18,438
Net income................................................ -- 3,263 3,263
-------- ------- --------
Balance at May 11, 2000..................................... 18,129 3,572 21,701
-------- ------- --------
Adjustments due to Acquisition:
Eliminate Former RENJ balances............................ (18,129) (3,572) (21,701)
Capital contribution from Parent............................ 334,735 -- 334,735
Net income.................................................. -- 34,356 34,356
-------- ------- --------
Balance at September 30, 2000............................... $334,735 $34,356 $369,091
======== ======= ========
See Notes to the Interim Condensed Consolidated Financial Statements.
F-39
181
RELIANT ENERGY NEW JERSEY HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
These interim condensed consolidated financial statements (Interim
Financial Statements) include the accounts of Reliant Energy New Jersey
Holdings, LLC and its subsidiaries (collectively, RENJ). These Interim Financial
Statements are unaudited, omit certain information included in financial
statements prepared in accordance with generally accepted accounting principles
and should be read in combination with the Annual Financial Statements of RENJ
for the period from November 24, 1999 to December 31, 1999 included in this
prospectus.
As described in Notes 1 and 7 to the Annual Financial Statements, RENJ
(formerly Sithe New Jersey Holdings, LLC), together with its subsidiaries, were
indirect wholly owned subsidiaries of Sithe Energies, Inc. (Sithe) as of
December 31, 1999. RENJ acquired its generating stations and various related
assets from the operating subsidiaries of GPU, Inc. (GPU), a utility holding
company, on November 24, 1999. Reliant Energy Mid-Atlantic Power Holdings, LLC
(formerly Sithe Pennsylvania Holdings, LLC) (REMA), an affiliate of RENJ, also
acquired assets from GPU in Pennsylvania and, through another affiliate, in
Maryland. The operations of RENJ, REMA and the other affiliate in Maryland have
been managed together since November 24, 1999. In May 2000, Sithe, through an
indirect wholly owned subsidiary, sold all of its equity interests in the
Company and REMA to an indirect wholly owned subsidiary of Reliant Energy Power
Generation, Inc. (REPG). Within these Interim Financial Statements, "Current
RENJ" and "Former RENJ" refer to RENJ, its subsidiaries and affiliated entities
that develop electric generating facilities after and before, respectively, the
acquisition from Sithe Energies and one of its subsidiaries.
There are no separate financial statements available with regard to the
facilities of RENJ prior to the date that RENJ acquired the generation assets
from GPU because their operations were fully integrated with, and their results
of operations were consolidated into, the former owners of the facilities of
RENJ. In addition, the electric output of the facilities was sold based on rates
set by regulatory authorities. As a result and because electricity rates will
now be set by the operation of market forces, the historical financial data with
respect to the facilities of RENJ prior to November 24, 1999 is not meaningful
or indicative of RENJ's future results. RENJ's results of operations in the
future will depend primarily on revenues from the sale of energy, capacity and
ancillary services, and the level of its operating expenses.
Prior to the date REPG acquired RENJ, the acquisition of RENJ's generating
assets was recorded under the purchase method of accounting with assets and
liabilities of RENJ reflected at their estimated fair values as of the date of
the purchase. On a preliminary basis, RENJ's fair value adjustments included
increases in property, plant and equipment and air emissions regulatory
allowances. The allocation of the purchase price is preliminary, since the
valuation of property, plant and equipment and air emissions regulatory
allowances as well as the valuation of materials and supplies inventories and
environmental reserves have not been finalized.
The Interim Financial Statements reflect all normal recurring adjustments
that are, in the opinion of management, necessary to present fairly the
financial position and results of operations. Amounts reported in the interim
condensed statement of consolidated operations are not necessarily indicative of
amounts expected for a full year period due to the effects of, among other
things, seasonal variations in energy consumption and timing of maintenance and
other expenditures.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
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RELIANT ENERGY NEW JERSEY HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
Note 1 to the Annual Financial Statements describes significant accounting
policies of Former RENJ, which is updated for Current RENJ as follows:
(a) Revenue Recognition -- Revenue includes energy, capacity and ancillary
service sales. Current RENJ's power and services, excluding capacity,
were sold at market-based prices through sales to a related party and
indirect wholly owned subsidiary of Reliant Energy, Incorporated (the
Affiliate) for resale. The Affiliate acted as agent on behalf of RENJ
on most market-based sales. RENJ's capacity was also sold to the
Affiliate at terms that mirror a transition power purchase agreement
between Affiliate and GPU. The transition power purchase agreement
extends through May 31, 2002. Sales not billed by month-end are accrued
based upon estimated energy or services delivered.
(b) Intangible Assets -- Air emissions regulatory allowances are being
amortized on a units-of-production basis as utilized.
(c) Inventories -- Inventories are comprised of materials, supplies and
fuel stock held for consumption and are stated at the lower of
weighted-average cost or market.
(d) Income Taxes -- In connection with the acquisition, RENJ entered into a
tax sharing agreement with Reliant Energy, whereby RENJ calculates its
income tax provision on a separate return basis. RENJ's current federal
and state income taxes are payable to and receivable from Reliant
Energy.
(e)Major Maintenance Expense -- RENJ expenses all repair and maintenance
costs as incurred, including planned major maintenance.
(f) New Accounting Pronouncements -- Effective January 1, 2001, RENJ is
required to adopt Statement of Financial Accounting Standard No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as
amended (SFAS No. 133), which establishes accounting and reporting
standards for derivative instruments, including some specified hedging
instruments embedded in other contracts and for hedging activities.
This statement requires that derivatives be recognized at fair value in
the balance sheet and that changes in fair value be recognized either
currently in earnings or deferred as a component of other comprehensive
income, depending on the intended use of the derivative, its resulting
designation and its effectiveness. In addition, in June 2000, the
Financial Accounting Standards Board issued an amendment that narrows
the applicability of the pronouncement to some purchase and sales
contracts and allows hedge accounting for some other specific hedging
relationships. Adoption of SFAS No. 133 will result in no cumulative
after-tax charge to net income or other comprehensive income.
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101),
was issued by the SEC on December 3, 1999. SAB No. 101 summarizes some
of the SEC staff's views in applying generally accepted accounting
principles to revenue recognition in financial statements. RENJ's
consolidated financial statements reflect the accounting principles
provided in SAB No. 101.
2. DEMAND NOTES PAYABLE TO AFFILIATE
In connection with Sithe's acquisition of its generating assets from GPU,
RENJ entered into approximately $145 million of demand notes payable to Sithe
Northeast Generating Company, Inc. (an indirect wholly owned subsidiary of
Sithe) due August 20, 2001. In connection with the acquisition of RENJ in May
2000, Sithe Northeast Generating Company, Inc. sold these notes to an indirect
wholly owned subsidiary of REPG. See Note 3(a). The original notes were
subsequently cancelled and new notes issued (New Notes), which are due January
1, 2029.
F-41
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RELIANT ENERGY NEW JERSEY HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
Prior to May 2000, the notes bore interest at a financing rate based on the
London interbank offered rate (LIBOR) plus 1.9% per annum. The New Notes accrue
interest at a fixed rate of 9.4% per annum. There are no amounts outstanding on
these notes as of September 30, 2000.
3. BUSINESS ACQUISITIONS
(a) Acquisition by REPG
In February 2000, REPG reached a definitive agreement to purchase the
equity in and the pre-existing affiliate debt of RENJ, REMA and other affiliates
from Sithe for an aggregate purchase price of $2.1 billion, subject to
adjustments. Included within this purchase transaction were transition power
purchase agreements, including the capacity transition contract with GPU
described in Note 1(d) to RENJ's Annual Financial Statements. The transaction
was completed in May 2000. REPG accounted for the acquisition as a purchase with
assets and liabilities of RENJ reflected at their estimated fair values. On a
preliminary basis, the fair value adjustments related to the acquisitions which
have been pushed down to RENJ, primarily included adjustments in property, plant
and equipment, air emissions regulatory allowances, materials and supplies
inventory, environmental reserves and related deferred taxes. The air emissions
regulatory allowances of $12 million are being amortized on a
units-of-production basis as utilized. In addition, a valuation allowance for
materials and supplies inventory of $8 million was established. Subsequent to
the issuance of RENJ's financial statements for the period ended September 30,
2000, management determined that its preliminary purchase price allocation for
the acquisition of RENJ should be reallocated. This reallocation resulted in the
elimination of major maintenance reserves, and related reductions of goodwill
and deferred tax assets, previously recorded in connection with the acquisition
of RENJ. As a result, RENJ has revised its September 30, 2000 consolidated
balance sheet to reduce major maintenance reserves, goodwill and deferred tax
assets by $31 million, $7 million and $12 million, respectively. In addition,
RENJ recognized an increase in deferred tax liabilities of $2 million resulting
from book/tax basis differences of recorded air emissions regulatory allowances.
Such deferred tax effects and the corresponding increase in goodwill had not
been considered in connection with RENJ's previously recorded RENJ acquisition
purchase price allocation. RENJ believes that the fair value allocated to
property, plant and equipment acquired in connection with its acquisition of
RENJ properly reflects planned major maintenance activities. As of September 30,
2000, RENJ has liabilities associated with four site investigations and
environmental remediations. RENJ has recorded its estimate of these
environmental liabilities in the amount of $9 million as of September 30, 2000,
of which approximately $5 million will be paid over the next five years. RENJ
expects to finalize the fair value adjustments based on valuation reports for
property, plant and equipment and intangible assets that will be finalized by
May 2001.
(b) Restructuring
In July 2000, REMA acquired the equity ownership interests in RENJ as well
as other affiliates. These affiliates were acquired from an indirect wholly
owned subsidiary of REPG for an aggregate purchase price of $167 million, which
amounts were borrowed from an indirect wholly owned subsidiary of REPG.
4. LEASE FINANCING
In August 2000 REMA sold interests in three of its generating plants
acquired in May 2000 and leased them back from owner lessors. The equity
interests in RENJ are pledged as collateral for REMA's lease obligation. In
addition, RENJ guarantees the lease obligation.
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RELIANT ENERGY NEW JERSEY HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
5. COMMITMENTS AND CONTINGENCIES
(a) Environmental -- Under the agreement to acquire RENJ's generating
assets from GPU, liabilities associated with ash disposal site closure and site
contamination at the acquired facilities in New Jersey prior to plant closing
were assumed. GPU retained liabilities associated with the disposal of hazardous
substances to off-site locations prior to November 24, 1999. RENJ has recorded
its estimate of these environmental liabilities in the amount of $9 million as
of September 30, 2000
(b) Legal -- RENJ is a party to various legal proceedings that arise from
time to time in the ordinary course of business. While RENJ cannot predict the
outcome of these proceedings, RENJ does not expect these matters to have a
material adverse effect on RENJ's financial position, operations or cash flows.
6. SUBSEQUENT EVENT
Effective December 31, 2000, Reliant Energy, Incorporated consolidated all
of its unregulated operations under its wholly owned subsidiary, Reliant
Resources, Inc. (RRI). As a result of these transactions, REPG, RENJ's indirect
parent, became a wholly owned subsidiary of RRI.
* * *
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RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
INTRODUCTION TO UNAUDITED PRO FORMA CONDENSED
COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma condensed combined and consolidated
financial statements of REMA for the period from November 24, 1999 to December
31, 1999, and for the nine months ended September 30, 2000, have been prepared
based upon our historical combined and consolidated financial statements. The
pro forma financial statements have been prepared to describe the effects of the
following:
- the purchase from Sithe Energies and one of its subsidiaries by
subsidiaries of REPG of (a) all of the equity interests in REMA and
affiliated companies that collectively owned interests in and operated 21
electric generating facilities in Pennsylvania, New Jersey and Maryland
and (b) demand promissory notes aggregating approximately $1.6 billion
that we owed to the Sithe subsidiary (collectively, Mid-Atlantic
Acquisition), and
- the related sale and leaseback of REMA's interests in three electric
generating facilities (Sale-Leaseback)
The purchase price for the Mid-Atlantic Acquisition was approximately $2.1
billion, and the acquisition closed on May 12, 2000. The results of operations
of the entities acquired in the Mid-Atlantic Acquisition have been included in
REMA's historical results of operations subsequent to the acquisition date. The
acquisition was accounted for using the purchase method. The unaudited pro forma
condensed combined and consolidated statements of operations for the nine months
ended September 30, 2000, and the period from November 24, 1999 to December 31,
1999, give effect to the Mid-Atlantic Acquisition as if this transaction had
occurred on January 1, 2000 and November 24, 1999, respectively. Sithe acquired
these facilities through REMA, which was then named Sithe Pennsylvania Holdings,
LLC, and affiliated entities on November 24, 1999.
On a preliminary basis, REMA's purchase price allocation related to the
Mid-Atlantic Acquisition primarily included fair value adjustments in property,
plant and equipment, air emissions regulatory allowances, material and supplies
inventory, environmental reserves and related deferred taxes. REMA expects to
finalize these fair value adjustments no later than May 2001, based on valuation
reports of property, plant and equipment and intangible assets. REMA does not
anticipate any additional material modifications to the preliminary adjustments.
In August 2000, REMA completed the Sale-Leaseback, which was contemplated
in connection with the Mid-Atlantic Acquisition. The unaudited pro forma
condensed combined and consolidated statements of operations for the nine months
ended September 30, 2000, and for the period from November 24, 1999 to December
31, 1999, give effect to the Sale-Leaseback as if this transaction had been
completed on January 1, 2000, and November 24, 1999, respectively.
The unaudited pro forma condensed combined and consolidated financial
statements do not purport to present REMA's actual results of operations as if
the transactions described above had occurred on January 1, 2000 and November
24, 1999, as applicable, nor are they necessarily indicative of REMA's financial
position or results of operations that may be achieved in the future.
The unaudited condensed pro forma financial statements should be read in
conjunction with REMA's combined and consolidated financial statements and
related notes and "Management's Discussion and Analysis of Financial Condition
and Results of Operations" included elsewhere in this prospectus.
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RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
FOR THE PERIOD FROM NOVEMBER 24, 1999 TO DECEMBER 31, 1999
ACQUISITIONS
MID-ATLANTIC AND SALE-
PRE-ACQUISITION LEASEBACK PRO FORMA
ACTIVITY ADJUSTMENTS BALANCE
--------------- ------------ ---------
(THOUSANDS OF DOLLARS)
Revenues.................................................... $ 29,526 $ 29,526
Expenses:
Fuel and cost of gas sold................................. 10,754 10,754
Operation and maintenance................................. 7,830 $ 6,105(a) 13,935
Administrative and general................................ 3,190 3,190
Depreciation and amortization............................. 4,842 2,273(b) 5,742
(1,923)(a)
550(c)
-------- -------- --------
Total Expenses.................................... 26,616 7,005 33,621
-------- -------- --------
Operating Income (Loss)..................................... 2,910 (7,005) (4,095)
-------- -------- --------
Interest expense to affiliate, net........................ (12,588) (10,548)(d) (13,370)
9,766(e)
-------- -------- --------
Loss Before Income Taxes.................................... (9,678) (7,787) (17,465)
Income Tax Benefit.......................................... -- (7,300)(f) (7,300)
-------- -------- --------
Loss from Continuing Operations............................. $ (9,678) $ (487) $(10,165)
======== ======== ========
See Notes to Unaudited Pro Forma Condensed Combined and Consolidated Financial
Statements.
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RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
UNAUDITED PRO FORMA CONDENSED COMBINED AND CONSOLIDATED
STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
MID-ATLANTIC
JANUARY 1, 2000 MAY 12, 2000 TO ACQUISITION AND
TO MAY 11, 2000 SEPTEMBER 30, 2000 SALE-LEASEBACK PRO FORMA
(FORMER REMA) (CURRENT REMA) ADJUSTMENTS BALANCE
--------------- ------------------ --------------- ---------
(THOUSANDS OF DOLLARS)
Revenues............................................. $166,490 $365,322 $531,812
Expenses:
Fuel and cost of gas sold.......................... 53,628 69,999 123,627
Operation and maintenance.......................... 40,372 39,391 $ 38,220(a) 117,983
Administrative and general......................... 13,101 12,137 25,238
Depreciation and amortization...................... 19,538 25,627 8,022(b) 38,540
16,558(a)
1,911(c)
-------- -------- -------- --------
Total Expenses.............................. 126,639 147,154 31,595 305,388
-------- -------- -------- --------
Operating Income..................................... 39,851 218,168 (31,595) 226,424
-------- -------- -------- --------
Other Income (Expense):
Interest expense to affiliate, net................. (46,538) (51,482) (36,714)(d) (73,634)
61,100(e)
-------- -------- -------- --------
Income Before Income Taxes........................... (6,687) 166,686 (7,209) 152,790
Income Tax Expense (Benefit)......................... -- 68,828 (4,962)(f) 63,866
-------- -------- -------- --------
Income from Continuing Operations.................... $ (6,687) $ 97,858 $ (2,247) $ 88,924
======== ======== ======== ========
See Notes to Unaudited Pro Forma Condensed Combined and Consolidated Financial
Statements.
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RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
(FORMERLY SITHE PENNSYLVANIA HOLDINGS, LLC) AND RELATED COMPANIES
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED AND CONSOLIDATED FINANCIAL
STATEMENTS
(a) Reflects the recognition of lease expense associated with the facilities
involved in the Sale-Leaseback (see note (e) for related elimination of
interest expense) and the elimination of depreciation expense on the
interests in the three facilities involved in the Sale-Leaseback.
(b) Represents adjustments to depreciation expense based upon our preliminary
allocation of the purchase price of the Mid-Atlantic Acquisition. The
average economic life of the assets acquired is 35 years.
(c) Represents the incremental amortization expense resulting from identifiable
intangible assets with a fair value of $153 million over a 30-year
estimated life and of goodwill of $7 million over a 35-year estimated life.
Both of these items were recorded in connection with the Mid-Atlantic
Acquisition.
(d) Represents the additional interest expense on the $1.1 billion of
intercompany debt issued to finance the Mid-Atlantic Acquisition. Funds for
the acquisition were made available through loans from Reliant Energy and
$1.0 billion of these loans were subsequently converted to equity. The
annual interest rate of the intercompany debt was 9.4%.
(e) Reflects the elimination of interest expense associated with the repayment
of indebtedness with proceeds received from the Sale-Leaseback.
(f) An adjustment has been made to include the effect of income tax benefit for
the period prior to the Mid-Atlantic Acquisition and to tax effect all
other pre-tax pro forma adjustments at the applicable 42% combined
effective federal and state rate. REMA calculates its income tax provision
on a separate return basis under a tax sharing agreement with Reliant
Energy. Current federal and state income taxes are payable to or receivable
from Reliant Energy.
* * *
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APPENDIX A
INDEPENDENT ENGINEER'S REPORT
190
INDEPENDENT TECHNICAL REVIEW
FOR FINANCING
RELIANT ENERGY MID-ATLANTIC POWER
HOLDINGS, LLC
AUGUST 4, 2000
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191
LEGAL NOTICE
This document was prepared by S&W Consultants, a Division of Stone & Webster,
Inc., hereafter referred to as Stone & Webster, expressly for PSEG Resources
Inc., PSEGR Conemaugh Generation, LLC, Conemaugh Lessor Genco LLC, PSEGR
Keystone Generation, LLC, Keystone Lessor Genco LLC, PSEGR Shawville Generation,
LLC, and Shawville Lessor Genco LLC. Neither Stone & Webster nor PSEG Resources
Inc., PSEGR Conemaugh Generation, LLC, Conemaugh Lessor Genco LLC, PSEGR
Keystone Generation, LLC, Keystone Lessor Genco LLC, PSEGR Shawville Generation,
LLC, and Shawville Lessor Genco LLC nor any person acting in their behalf: (a)
makes any warranty, express or implied, with respect to the use of any
information or methods disclosed in this report; or (b) assumes any liability
with respect to the use of any information or methods disclosed in this report.
Stone & Webster's review and modeling of information relating to Reliant Energy
Mid-Atlantic Power Holdings, LLC in no way serves to transfer to Stone & Webster
responsibility for the correctness and/or accuracy of such information or
modeling results.
ELECTRONIC MAIL NOTICE
Electronic mail copies of this report are not official unless authenticated and
signed by Stone & Webster and are not to be modified in any manner without Stone
& Webster's expressed written consent.
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TABLE OF CONTENTS
1. EXECUTIVE SUMMARY.........................................................................................1-1
1.1 General.........................................................................................1-1
1.2 Scope of Services...............................................................................1-2
1.3 Plant Description...............................................................................1-2
1.4 Conclusions.....................................................................................1-5
2. PLANT TECHNICAL DESCRIPTIONS SUMMARY......................................................................2-1
2.1 Plant Description...............................................................................2-1
2.1.1 Conemaugh Station....................................................................2-1
2.1.2 Keystone Station.....................................................................2-2
2.1.3 Shawville Station....................................................................2-3
2.1.4 Portland Station.....................................................................2-5
2.1.5 Seward Station.......................................................................2-6
2.1.6 Titus Station........................................................................2-7
2.1.7 Sayreville Station...................................................................2-9
2.1.8 Warren Station......................................................................2-10
2.1.9 Gilbert Station.....................................................................2-12
2.1.10 Combustion Turbines.................................................................2-14
2.1.11 Piney Station.......................................................................2-21
2.1.12 Deep Creek Station..................................................................2-22
3. PLANT PERFORMANCE.........................................................................................3-1
3.1 Definitions.....................................................................................3-1
3.2 Projected Performance...........................................................................3-2
3.2.1 Conemaugh Station....................................................................3-2
3.2.2 Keystone Station.....................................................................3-4
3.2.3 Shawville Station....................................................................3-5
3.2.4 Seward Station.......................................................................3-6
3.2.5 Sayreville Station...................................................................3-6
3.2.6 Portland Station.....................................................................3-8
3.2.7 Titus Station.......................................................................3-10
3.2.8 Warren Station......................................................................3-12
3.2.9 Gilbert Station.....................................................................3-14
3.3 Combustion Turbines............................................................................3-15
3.3.1 Piney Station.......................................................................3-16
3.3.2 Deep Creek..........................................................................3-18
4. Plant Condition Assessment................................................................................4-1
4.1 Condition Assessment............................................................................4-1
4.1.1 Conemaugh Station....................................................................4-1
4.1.2 Keystone Station.....................................................................4-3
4.1.3 Shawville Station....................................................................4-5
4.1.4 Portland Station.....................................................................4-6
4.1.5 Seward Station.......................................................................4-8
4.1.6 Titus Station.......................................................................4-10
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4.1.7 Sayreville Station..................................................................4-12
4.1.8 Warren Station......................................................................4-14
4.1.9 Gilbert Station.....................................................................4-15
4.1.10 Combustion Turbines.................................................................4-16
4.1.11 Piney Station.......................................................................4-17
4.1.12 Deep Creek Station..................................................................4-18
4.2 Remaining Life.................................................................................4-18
5. ENVIRONMENTAL ASSESSMENT..................................................................................5-1
5.1 Air Quality.....................................................................................5-1
5.1.1 Air Permits and Emission Control Systems.............................................5-1
5.2 System-Wide Air Emissions Compliance Programs...................................................5-3
5.2.1 SO(2) Compliance Plans...............................................................5-3
5.2.2 NO(x) Compliance Plans...............................................................5-5
5.2.3 SO(2) NAAQS Compliance Issues........................................................5-8
5.3 Water/Wastewater...............................................................................5-10
5.3.1 Conemaugh...........................................................................5-10
5.3.2 Keystone............................................................................5-11
5.3.3 Shawville...........................................................................5-12
5.3.4 Portland............................................................................5-12
5.3.5 Seward..............................................................................5-13
5.3.6 Titus...............................................................................5-13
5.3.7 Sayreville..........................................................................5-14
5.3.8 Warren..............................................................................5-14
5.4 Solid Wastes...................................................................................5-15
5.4.1 Conemaugh...........................................................................5-15
5.4.2 Keystone............................................................................5-15
5.4.3 Shawville...........................................................................5-16
5.4.4 Portland............................................................................5-16
5.4.5 Seward..............................................................................5-17
5.4.6 Titus...............................................................................5-17
5.4.7 Sayreville..........................................................................5-17
5.4.8 Warren..............................................................................5-17
5.5 Site Contamination/Remediation.................................................................5-18
5.6 Combustion Turbines............................................................................5-20
5.6.1 Air Quality.........................................................................5-20
5.6.2 Water/Wastewater....................................................................5-22
5.6.3 Site Contamination Remediation......................................................5-23
5.7 Hydroelectric Stations.........................................................................5-24
5.7.1 Site Contamination/Remediation......................................................5-24
5.7.2 Operating Licenses..................................................................5-24
6. OPERATION & MAINTENANCE...................................................................................6-1
6.1 General.........................................................................................6-1
6.2 Approach........................................................................................6-1
6.3 Operation and Maintenance Review................................................................6-1
6.3.1 Conemaugh Station....................................................................6-1
6.3.2 Keystone Station.....................................................................6-3
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6.3.3 Shawville Station....................................................................6-4
6.3.4 Portland Station.....................................................................6-6
6.3.5 Seward Station.......................................................................6-8
6.3.6 Titus Station........................................................................6-9
6.3.7 Sayreville Station..................................................................6-11
6.3.8 Warren Station......................................................................6-13
6.3.9 Gilbert Station.....................................................................6-15
6.3.10 Combustion Turbines.................................................................6-16
6.3.11 Piney Station.......................................................................6-17
6.3.12 Deep Creek..........................................................................6-18
7. PROJECT Agreements........................................................................................7-1
7.1 Purchase and Sale Agreement.....................................................................7-1
7.2 Transition Power Purchase Agreements............................................................7-2
8. ASSESSMENT OF FINANCIAL PROJECTIONS.......................................................................8-1
8.1 Overview........................................................................................8-1
8.2 Principal Considerations and Assumptions........................................................8-2
8.3 Revenues........................................................................................8-3
8.4 Operating Expenses..............................................................................8-3
8.4.1 Fixed and Variable O&M Expenses......................................................8-4
8.4.2 Capital Improvements.................................................................8-5
8.4.3 Emission Compliance Costs/Revenues...................................................8-5
8.4.4 Fuel Expense.........................................................................8-7
8.5 Financing Assumptions...........................................................................8-8
8.6 Financial Projections...........................................................................8-8
8.7 Sensitivity Analyses............................................................................8-8
8.7.1 Project Sensitivities................................................................8-8
8.7.2 Hagler Bailly Sensitivities..........................................................8-9
8.7.3 Summary..............................................................................8-9
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1. EXECUTIVE SUMMARY
1.1 GENERAL
S&W Consultants, a Division of Stone & Webster, Inc. has prepared this
Independent Technical Review (the "Review") of the Reliant Energy Mid-Atlantic
Power Holdings, LLC ("REMA") asset acquisition for PSEG Resources Inc., PSEGR
Conemaugh Generation, LLC, Conemaugh Lessor Genco LLC, PSEGR Keystone
Generation, LLC, Keystone Lessor Genco LLC, PSEGR Shawville Generation, LLC, and
Shawville Lessor Genco LLC. This Report contains a description of the electric
generating facilities acquired by REMA and the findings of an independent
engineering assessment of these electric generating facilities (collectively the
"Facilities"). The Facilities that REMA has acquired from Sithe Northeast
Generating Company, Inc. and affiliates (collectively "Sithe") include the
following:
o Conemaugh (16.45% ownership)
o Keystone (16.67% ownership)
o Shawville
o Portland
o Seward
o Titus
o Sayreville
o Warren
o Gilbert
o Combustion Turbines
o Piney
o Deep Creek
This report ("Report") includes Stone & Webster's independent technical
assessment of the Facilities, based on a review of the available technical data,
and presents our findings and conclusions regarding the following:
o Condition assessment of the plants
o Plant performance
o Operating and maintenance program and expenses
o Environmental issues relating to the future operation and maintenance
of the plants
o The proforma financial projections of cash flows and fixed charge
coverage ratios ("FCCRs") under base case and sensitivity assumptions
(collectively the "Financial Projections")
Sithe has sold the Facilities, which it had recently acquired from General
Public Utilities ("GPU"), to REMA. The Facilities include hydroelectric, oil,
gas, and coal-fired facilities that generate electricity for sale into the
Pennsylvania, New Jersey, Maryland Power Pool ("PJM"). The Facilities have an
average combined generation capacity of 4,262 MW. REMA has 100% ownership in all
the facilities with the exception of Keystone and Conemaugh. REMA owns 16.67%
and 16.45% of Keystone and Conemaugh,
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respectively. REMA may continue to operate Keystone and Conemaugh under
contracts with the joint owners ("Owners"), however, the Owners have announced
their intentions to bid out the operation and maintenance ("O&M") contract.
1.2 SCOPE OF SERVICES
Stone & Webster was retained by REMA to do the following:
o Review the Asset's performance
o Review the Asset's technical condition
o Review the environmental site assessment documents
o Review the operation and maintenance programs
o Review the applicable transition power agreements
o Develop the financial model
1.3 PLANT DESCRIPTION
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SUMMARY OF ASSET CHARACTERISTICS
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DATE NORMAL RATED CAPACITY
STATION/UNIT PRIME MOVER COMMISSIONED FUEL (MW)
- -----------------------------------------------------------------------------------------------------------------------
SUMMER WINTER
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CONEMAUGH STATION
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Unit 1 Steam Turbine 1970 Coal 140(1) 140(1)
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Unit 2 Steam Turbine 1971 Coal 140(1) 140(1)
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Four Diesels Diesel Generator 1970 No. 2 Oil 1.8(1) 1.8(1)
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KEYSTONE STATION
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Unit 1 Steam Turbine 1968 Coal 142(1) 142(1)
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Unit 2 Steam Turbine 1967 Coal 142(1) 142(1)
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Four Diesels Diesel Generator 1968 No. 2 Oil 1.8(1) 1.8(1)
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SHAWVILLE STATION
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Unit 1 Steam Turbine 1954 Coal 122 128
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Unit 2 Steam Turbine 1955 Coal 125 130
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Unit 3 Steam Turbine 1960 Coal 175 180
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Unit 4 Steam Turbine 1960 Coal 175 180
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Unit 5 Diesel Generator N/A No. 2 Oil 2 2
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Unit 6 Diesel Generator N/A No. 2 Oil 2 2
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Unit 7 Diesel Generator N/A No. 2 Oil 2 2
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(1) REMA ownership share.
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=======================================================================================================================
SUMMARY OF ASSET CHARACTERISTICS
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DATE NORMAL RATED CAPACITY
STATION/UNIT PRIME MOVER COMMISSIONED FUEL (MW)
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SUMMER WINTER
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PORTLAND STATION
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Unit 1 Steam Turbine 1958 Coal 156 158
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Unit 2 Steam Turbine 1962 Coal 243 243
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Unit 3 Combustion Turbine 1967 No. 2 Oil 15 19
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Unit 4 Combustion Turbine 1971 No. 2 Oil 20 26
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Unit 5 Combustion Turbine 1999 No. 2 Oil 134 156
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SEWARD STATION
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Unit 4 Steam Turbine 1950 Coal 60 60
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Unit 5 Steam Turbine 1957 Coal 136 136
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TITUS STATION
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Unit 1 Steam Turbine 1951 Coal 81 83
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Unit 2 Steam Turbine 1951 Coal 81 83
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Unit 3 Steam Turbine 1953 Coal 81 83
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Unit 4 Combustion Turbine 1967 Natural Gas / 15 19
No. 2 Oil
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Unit 5 Combustion Turbine 1970 Natural Gas / 16 20
No. 2 Oil
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SAYREVILLE STATION
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Unit 4 Steam Turbine 1955 Natural Gas / 90 90
No. 6 Oil
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Unit 5 Steam Turbine 1958 Natural Gas / 95 95
No. 6 Oil
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Combustion Turbine 1 Combustion Turbine 1972 Natural Gas / 57 77
No. 2 Oil
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Combustion Turbine 2 Combustion Turbine 1972 Natural Gas / 53 77
No. 2 Oil
- -----------------------------------------------------------------------------------------------------------------------
Combustion Turbine 3 Combustion Turbine 1972 Natural Gas / 57 73
No. 2 Oil
- -----------------------------------------------------------------------------------------------------------------------
Combustion Turbine 4 Combustion Turbine 1973 Natural Gas / 57 77
No. 2 Oil
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WARREN STATION
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Unit 1 Steam Turbine 1948 Coal 41 41
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Unit 2 Steam Turbine 1949 Coal 41 41
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Unit 3 Combustion Turbine 1972 Natural Gas / 57 79
No. 2 Oil
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=======================================================================================================================
SUMMARY OF ASSET CHARACTERISTICS
=======================================================================================================================
DATE NORMAL RATED CAPACITY
STATION/UNIT PRIME MOVER COMMISSIONED FUEL (MW)
- -----------------------------------------------------------------------------------------------------------------------
SUMMER WINTER
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GILBERT STATION
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Combustion Turbine 1 Combustion 1970 Natural Gas / 25 31
Turbine No. 2 Oil
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Combustion Turbine 2 Combustion 1970 Natural Gas / 25 31
Turbine No. 2 Oil
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Combustion Turbine 3 Combustion 1970 Natural Gas / 25 31
Turbine No. 2 Oil
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Combustion Turbine 4 Combustion 1970 Natural Gas / 23 31
Turbine No. 2 Oil
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Combustion Turbine 9 Combustion 1997 Natural Gas / 152 183
Turbine No. 2 Oil
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Combined Cycle 4 Combustion 1974 Natural Gas / 49 70
Turbine No. 2 Oil
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Combined Cycle 5 Combustion 1974 Natural Gas / 49 70
Turbine No. 2 Oil
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Combined Cycle 6 Combustion 1974 Natural Gas / 49 70
Turbine No. 2 Oil
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Combined Cycle 7 Combustion 1974 Natural Gas / 49 70
Turbine No. 2 Oil
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Combined Cycle 8 Steam Turbine 1977 N/A 90 104
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BLOSSBURG STATION
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Unit 1 Combustion 1972 Natural Gas 23 26
Turbine
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HAMILTON COMBUSTION TURBINE
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Unit 1 Combustion 1971 No. 2 Oil 20 26
Turbine
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HUNTERSTOWN STATION
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Unit 1 Combustion 1971 Natural Gas / 20 27
Turbine No. 2 Oil
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Unit 2 Combustion 1971 Natural Gas / 20 27
Turbine No. 2 Oil
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Unit 3 Combustion 1971 Natural Gas / 20 27
Turbine No. 2 Oil
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MOUNTAIN STATION
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Unit 1 Combustion 1972 Natural Gas / 20 27
Turbine No. 2 Oil
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Unit 2 Combustion 1972 Natural Gas / 20 27
Turbine No. 2 Oil
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ORRTANNA STATION
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Unit 1 Combustion 1971 No. 2 Oil 20 26
Turbine
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SHAWNEE COMBUSTION TURBINE
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Unit 1 Combustion 1972 No. 2 Oil 20 26
Turbine
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TOLNA STATION
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Unit 1 Combustion 1972 No. 2 Oil 20 27
Turbine
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Unit 2 Combustion 1972 No. 2 Oil 20 27
Turbine
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=======================================================================================================================
SUMMARY OF ASSET CHARACTERISTICS
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DATE NORMAL RATED CAPACITY
STATION/UNIT PRIME MOVER COMMISSIONED FUEL (MW)
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SUMMER WINTER
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GLEN GARDNER STATION
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CT 1 Combustion 1970 Natural Gas / 20 26
Turbine No. 2 Oil
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CT 2 Combustion 1970 Natural Gas / 20 26
Turbine No. 2 Oil
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CT 3 Combustion 1970 Natural Gas / 20 26
Turbine No. 2 Oil
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CT 4 Combustion 1970 Natural Gas / 20 26
Turbine No. 2 Oil
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CT 5 Combustion 1970 Natural Gas / 20 26
Turbine No. 2 Oil
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CT 6 Combustion 1970 Natural Gas / 20 26
Turbine No. 2 Oil
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CT 7 Combustion 1970 Natural Gas / 20 26
Turbine No. 2 Oil
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CT 8 Combustion 1970 Natural Gas / 20 26
Turbine No. 2 Oil
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WAYNE STATION
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CT 1 Combustion 1972 No. 2 Oil 56 76
Turbine
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WERNER STATION
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CT 1 Combustion 1972 No. 2 Oil 53 73
Turbine
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CT 2 Combustion 1972 No. 2 Oil 53 73
Turbine
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CT 3 Combustion 1972 No. 2 Oil 53 73
Turbine
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CT 4 Combustion 1972 No. 2 Oil 53 73
Turbine
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PINEY STATION
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Hydroelectric Unit 1, 2, 3 Hydroelectric 1924 - 1928 Hydro 28.8 28.8
Turbine
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DEEP CREEK STATION
- -----------------------------------------------------------------------------------------------------------------------
Hydroelectric Unit 1, 2 Hydroelectric 1925 Hydro 18 18
Turbine
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1.4 CONCLUSIONS
Set forth below are the principal findings and conclusions which Stone & Webster
has reached regarding the Facilities. For a complete understanding of the
assumptions upon which these findings and conclusions are based, the Report
should be read in its entirety. On the basis of our review and the assumptions
set forth in the Report, Stone & Webster is of the opinion that:
1. There are 21 plant sites with an average combined generation capacity of
4,262 MW provided by 19 steam units, five hydroelectric units, 11 diesel
units, 39 simple cycle units, and four combustion turbines ("CTs") and one
steam turbine ("ST") in combined cycle configuration. The Keystone and
Conemaugh stations are in very good condition, Sayreville, Warren, and
Seward stations are in fair to good condition and the remaining units are
in good condition. The Facilities have been constructed, operated, and
maintained according to good utility practice. They should operate as
projected provided they are operated and maintained in accordance with good
industry practice. We believe REMA and its affiliates have proven
experience operating power plants.
2. The Facilities are fully permitted and appear to be in material compliance
with their permits. REMA has developed a plan to address the impacts of
environmental compliance for the implementation
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of existing and for anticipated regulation. The compliance plan includes a
combination of capital expenditures for unit modification and emission
credit purchases.
3. REMA, and its subsidiaries owning facilities in New Jersey and Maryland,
directly, or through its wholly-owned subsidiary Reliant Energy Northeast
Management Company, will operate the Facilities (in the case of Conemaugh
and Keystone, the operations agreements expire December 31, 2002 and future
operations will be sent out for bid). The projected staffing levels are
well suited for the competitive market.
4. The project agreements, including the Purchase and Sale Agreement ("PSA")
and Transition Power Purchase Agreements ("TPPA") are technically
reasonable.
5. The Facilities' operations and maintenance ("O&M") and major maintenance
budgets appear reasonable and adequate to meet REMA's maintenance and
performance objectives excluding any catastrophic failures.
6. The overhaul schedules developed by REMA are prudent and consistent with
forecasted operations. The overhaul and capital expenses forecasted in the
financial model are adequate to support the continued operation of the
Facilities through the remaining life projected by REMA.
7. Based on Stone & Webster's review, there are no existing conditions that
would preclude the operation of the Facilities through the projected
remaining life assumed by REMA assuming the continuation of condition
assessments, maintenance and capital improvement programs as shown in the
Financial Projections.
8. Stone & Webster reviewed and provided input data that was used as inputs to
the PHB Hagler Bailly's ("Hagler Bailly") market simulation model. The key
input data, such as claimed capacity, scheduled and forced outage rates,
and heat rate were reasonable and were consistent with recent historic
experience.
9. The projected performance of the Facilities, as measured by the annual
capacity factors projected by Hagler Bailly, is consistent with recent
historical performance. The Facilities should be technically able to
perform at the levels projected by Hagler Bailly until the expected
retirement dates.
10. The technical assumptions assumed in the financial projections are
reasonable and are consistent with the agreements. The financial model
fairly presents, in our judgment, projected revenues and projected expenses
under the base case assumptions. Therefore, the financial projections are a
reasonable forecast of the financial results under the base case
assumptions.
11. The projected revenues are sufficient to pay the annual operating and
maintenance expenses (including provisions for major maintenance), other
operating expenses and fixed charges (excluding payments that are
subordinated to fixed charge obligations) based on Stone & Webster's
studies and analyses and the assumptions set forth in this Review. The
resulting Base Case average FCCR over the term of the certificates is 6.34.
The minimum FCCR beginning with the first full year over the term of the
certificates is 2.12, which occurs in the year 2001. The FCCR for the
partial year 2000 is 1.78. The FCCR for the year 2000 reflects a reduction
of the rental payment component of the fixed charges to reflect the
required maintenance of $50 million of cash by REMA from the closing date
to January 2, 2001.
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2. PLANT TECHNICAL DESCRIPTIONS SUMMARY
2.1 PLANT DESCRIPTION
2.1.1 CONEMAUGH STATION
Conemaugh Station ("Conemaugh") is near New Florence, Pennsylvania on a
2,539-acre site along the Conemaugh River. Conemaugh consists of two 850 MW
(net) coal-fired steam turbine generator units. Unit 1 was commissioned in 1970
and Unit 2 was commissioned in 1971. Conemaugh also includes four 2.75 MW diesel
generators. REMA owns a 16.45% undivided ownership interest (281 MW) with the
balance of interest in Conemaugh owned by eight other utilities.
Conemaugh has two 1.25 MW 480 V diesels for scrubber emergency power. Conemaugh
produces approximately 1.2 million tons of ash and residual wastes annually that
are disposed of in a licensed on-site 400-acre ash/residual waste disposal
facility. This site is currently permitted to receive fly ash, bottom ash,
impoundment sludges, scrubber sludge, coal refuse, asbestos wastes, and
non-combustible construction debris. Seward Station ("Seward") also utilizes the
Conemaugh site for similar disposal. The currently active landfill is expected
to be exhausted by 2011.
Conemaugh has two Marley Class 600 cross flow natural draft cooling towers,
which provide primary plant cooling. The towers each evaporate 7,000 to 8,000
gallons of water per minute depending on ambient conditions.
The Conemaugh/Keystone project office provides annually updated coal supply
plans, which are developed and implemented by a committee of the plant's owners.
Conemaugh receives its coal supply through the Norfolk Southern Railway ("NS")
from mines in the Monogahela coal region ("MG"), which is located in
Southwestern Pennsylvania, and by truck from mines in Central Pennsylvania. The
rail handling system includes three sidings and a rotary car dumper with 100-ton
capacity. Conemaugh maintains a coal storage pile of between 375,000 and 700,000
tons (a 45-day supply at maximum load). Conemaugh also has a separate rail spur
for limestone receiving and gypsum loading for the flue gas desulfurization
("FGD") systems added to Units 1 and 2 in 1994 and 1995, respectively. Conemaugh
has two 200,000 gallon No. 2 oil storage tanks on-site which provide fuel for
the diesel generators. Natural gas is utilized for boiler startup and flame
stabilization at low loads. Historically, natural gas has been supplied to the
plant by the local distributor through a 12-inch pipeline currently operating at
250 psig.
Conemaugh is connected to the PJM and East Central Area Reliability ("ECAR")
markets by the Keystone switchyard through a 500 kV tie line. Conemaugh and
Keystone are connected to the Baltimore, Maryland area by a 500 kV
Conemaugh-Conastone (Hunterstown) line. Conemaugh is also connected to the 500
kV Juniata line, which supplies eastern Pennsylvania.
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The following table summarizes the plant characteristics.
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CONEMAUGH CHARACTERISTICS SUMMARY
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2.75 MW 1.25 MW
ITEM UNIT 1 UNIT 2 DIESEL UNITS DIESEL UNITS
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STEAM TURBINE
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Type Tandem Cross Tandem Cross Emergency Scrubber
Compound Compound Emergency Power
- --------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric
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Commissioned (year) 1970 1971
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Average Capacity (MW) 850 850 2.75 each 1.25 each
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BOILER
- --------------------------------------------------------------------------------------------------------------
Manufacturer Combustion Combustion
Engineering Engineering
- --------------------------------------------------------------------------------------------------------------
Boiler (type) Supercritical Supercritical
Reheat Reheat
- --------------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 6,350 6,350
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Temperature, degree F 1005/1005 1005/1005
- --------------------------------------------------------------------------------------------------------------
Pressure, psig 4000 4000
- --------------------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal No. 2 Oil No. 2 Oil
- --------------------------------------------------------------------------------------------------------------
Secondary Fuel Natural Gas Natural Gas
No. 2 Oil No. 2 Oil
- --------------------------------------------------------------------------------------------------------------
NO(x) Control Method Low NO(x) Burners Low NO(x) Burners
- --------------------------------------------------------------------------------------------------------------
SO(2) Control Method FGD FGD
- --------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- --------------------------------------------------------------------------------------------------------------
Fuel Delivery Rail and truck delivered coal
No. 2 oil by truck
Natural gas by pipeline
- --------------------------------------------------------------------------------------------------------------
Fuel Storage On-site coal cleaning equipment plus coal pile of 45 days
Two 200,000 gallon No. 2 oil storage tanks
- --------------------------------------------------------------------------------------------------------------
Cooling Water Natural draft cooling towers
==============================================================================================================
2.1.2 KEYSTONE STATION
Keystone Station ("Keystone") is located in Plumcreek Township, Armstrong
County, Pennsylvania on a 1,459 acre site. The facility includes a 3,346-acre
reservoir located near the site. The site consists of two 850 MW coal-fired
steam turbine generator units and four 2.75 MW emergency diesel generators. Unit
1 began commercial operation in 1967 and Unit 2 began commercial operation in
1968. REMA owns a 16.67% undivided ownership interest (285 MW) with the balance
of the interest in Keystone owned by six other utilities.
Keystones produces approximately 650,000 tons of ash and refuse annually, which
are disposed of in a licensed on-site 254 acre ash/refuse disposal facility.
This site is currently permitted to receive fly ash, bottom ash, impoundment
sludges, coal refuse, asbestos wastes, and construction debris. The current east
valley disposal area will reach capacity in 2001. A new west valley disposal
site is in the permitting stage and will be developed during 2000 and 2001 for
use in late 2001. The estimated life of this new facility is until year 2023.
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Four reinforced concrete hyperbolic cooling towers provide primary plant
cooling. The towers evaporate 2,500 to 3,250 gallons of water per minute
depending on ambient conditions.
The Conemaugh/Keystone project office provides annually updated coal supply
plans, which are developed and implemented by a committee of plant's owners.
Keystone receives its coal supply through NS from mines in MG and by truck from
mines in central Pennsylvania. Keystone maintains a coal storage pile of between
375,000 and 600,000 tons (a 39-day supply at maximum load). Keystone uses No. 2
oil as a secondary fuel for boiler startup and as a primary fuel for the diesel
generators. Keystone has 400,000 gallons of No. 2 fuel oil storage capacity.
Keystone is connected to several transmission lines: a 120 mile 500 kV line, a
25 mile 500 kV line, a 40 mile 500 kV line, a 27 mile 500 kV line, and a 13 mile
230 kV line. Units 1 and 2 are capable of providing frequency regulation and
voltage control, if required. Keystone is connected to the PJM system by a 120
mile 500 kV line to Juniata. Keystone is connected to the Baltimore, Maryland
market by the 25 mile 500 kV Conemaugh-Constone line. Keystone is connected to
the Allegheny Power System by the 40 mile 500 kV Yukon line. Keystone is
connected to the New York market by a 13 mile 230 kV line to Homer City Station.
The following table summarizes the plant characteristics.
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KEYSTONE CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM UNIT 1 UNIT 2 2.75 MW DIESEL UNITS
- ----------------------------------------------------------------------------------------------------------------------
STEAM TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Type Cross Compound Cross Compound Emergency
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Manufacturer Westinghouse Westinghouse
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Commissioned (year) 1967 1967
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Average Capacity (MW) 850 850 2.75 each
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BOILER
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer Combustion Engineering Combustion Engineering
- ----------------------------------------------------------------------------------------------------------------------
Boiler (type) Supercritical Reheat Supercritical Reheat
- ----------------------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 6,350 6,350
- ----------------------------------------------------------------------------------------------------------------------
Temperature, degree F 1005/1005 1005/1005
- ----------------------------------------------------------------------------------------------------------------------
Pressure, psig 4000 4000
- ----------------------------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal No. 2 Oil
- ----------------------------------------------------------------------------------------------------------------------
Secondary Fuel No. 2 Oil No. 2 Oil
- ----------------------------------------------------------------------------------------------------------------------
NO(x) Control Method Low NO(x) Burners Low NO(x) Burners
- ----------------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------------
Fuel Delivery Rail and truck delivered coal
No. 2 oil by truck
- ----------------------------------------------------------------------------------------------------------------------
Fuel Storage On-site coal cleaning equipment plus coal pile of 39 days
400,000 gallon No. 2 oil storage
- ----------------------------------------------------------------------------------------------------------------------
Cooling Water Natural draft cooling towers
- ----------------------------------------------------------------------------------------------------------------------
Water Resources Site includes a reservoir and dams for makeup water control
======================================================================================================================
2.1.3 SHAWVILLE STATION
Shawville Station ("Shawville") is located in Bradford Township, Clearfield
County, Pennsylvania along the Susquehanna River on a 947-acre site. Shawville
consists of four coal-fired steam turbine generator
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units and three diesel generators for an average station capacity of 613 MW.
Shawville has two units, Units 1 and 2 that were installed in 1954 and 1955 with
average capacities of 125 MW and 128 MW respectively, and Units 3 and 4, also
duplicate units, were installed in 1960, each with an average capacity of 177
MW. The ash generated at the site is disposed of at an on-site landfill. The
Susquehanna River provides process water to the plant.
Shawville also operates three-diesel generators, Units 5, 6, and 7. These units
are General Motors Model 567D4 16-cylinder diesel generators rated at 2 MW each.
The generators can supply the 4160 V auxiliary power system or the 34.5 kV
distribution system.
Shawville receives central Pennsylvania coal by truck to the storage pile, which
can accommodate 125,000 tons (20-day supply at maximum load). No. 2 oil for
startup and flame stability of Units 1 and 2 is also delivered by truck. The
on-site No. 2 oil storage capacity is 500,000 gallons. No. 2 oil for the diesel
generators is also delivered by truck and stored in two separate 20,000 gallon
tanks.
Units 1 and 2 are connected to the 115 kV and 230 kV grid and Units 3 and 4 are
connected to the 230 kV grid. Diesels 5,6,and 7 can feed the 34.5 kV
distribution system.
The following tables summarize the plant characteristics.
======================================================================================================================
SHAWVILLE CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM UNIT 1 UNIT 2 UNIT 3 UNIT 4
- ----------------------------------------------------------------------------------------------------------------------
STEAM TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Type Tandem Compound Tandem Compound Tandem Compound Tandem Compound
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric General Electric General Electric
- ----------------------------------------------------------------------------------------------------------------------
Commissioned (year) 1954 1954 1960 1960
- ----------------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 125 128 177 177
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BOILER
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer Babcock & Wilcox Babcock & Wilcox Combustion Combustion
Engineering Engineering
- ----------------------------------------------------------------------------------------------------------------------
Boiler (type) Drum Type Drum Type Drum Type Drum Type
- ----------------------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 934 934 1200 1200
- ----------------------------------------------------------------------------------------------------------------------
Temperature, degree F 1860 1860 1055 1055
- ----------------------------------------------------------------------------------------------------------------------
Pressure, psig 2250 2250 2500 2500
- ----------------------------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal Coal Coal
- ----------------------------------------------------------------------------------------------------------------------
Secondary Fuel No. 2 Oil No. 2 Oil No. 2 Oil No. 2 Oil
- ----------------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------------
Fuel Delivery Coal is delivered by truck
No. 2 oil is delivered by truck
- ----------------------------------------------------------------------------------------------------------------------
Fuel Storage 125,000 tons of storage on the coal pile
One 500,000 gallon No. 2 oil tank and two 20,000 gallon No. 2 oil tanks
- ----------------------------------------------------------------------------------------------------------------------
Cooling Water Susquehanna River
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============================================================================================================
SHAWVILLE CHARACTERISTICS SUMMARY
============================================================================================================
ITEM UNIT 5 UNIT 6 UNIT 7
------------------------------------------------------------------------------------------------------------
STEAM TURBINE
------------------------------------------------------------------------------------------------------------
Type Diesel Generator Diesel Generator Diesel Generator
------------------------------------------------------------------------------------------------------------
Manufacturer General Motors General Motors General Motors
------------------------------------------------------------------------------------------------------------
Commissioned (year) 1963 1963 1963
------------------------------------------------------------------------------------------------------------
Primary Fuel No. 2 Oil No. 2 Oil No. 2 Oil
------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 2 2 2
------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
------------------------------------------------------------------------------------------------------------
Fuel Delivery No. 2 oil is delivered by truck
------------------------------------------------------------------------------------------------------------
Fuel Storage One 500,000 gallon No. 2 oil tank and two 20,000 gallon No.2 oil tanks
------------------------------------------------------------------------------------------------------------
Cooling Water Susquehanna River
============================================================================================================
2.1.4 PORTLAND STATION
Portland Station ("Portland") is located in Portland, Pennsylvania on a 190-acre
site along the Delaware River. Portland has an average capacity of 585 MW and
consists of two coal-fired steam turbine generators and three CTs. Unit 1 has an
average capacity of 157 MW and began operations in 1958; Unit 2 has an average
capacity of 243 MW and began operations in 1962. The boilers for both of these
units are tangentially-fired pulverized coal boilers with low NO(x) burners.
Unit 3 is a General Electric ("GE") Frame 5L CT with an average capacity of 17
MW that began commercial operation in 1967. Unit 4 is a GE Frame 5N CT that
began commercial operation in 1971 with an average capacity of 23 MW. Unit 5,
which went through initial startup in 1994, is a Siemens V84.3 dual-fuel CT with
an average capacity of 145 MW. Portland also owns and operates a 67-acre ash
disposal site in Bangor, Pennsylvania.
Coal for Portland Units 1 and 2 is supplied under contract with CONSOL from
mines in MG and is delivered by rail. This contract is scheduled to run through
December 2002 and also includes coal for the Titus Station ("Titus"). Coal is
delivered to Portland and Titus on a split train. Portland typically maintains a
30-day supply at maximum load of coal on-site. Units 1 and 2 utilize No. 2 oil
for start-up and flame stability on an as required basis. Portland's three CTs,
Units 3, 4, and 5, can also burn No. 2 oil. No. 2 oil is supplied to Portland
under short-term contracts with local suppliers by way of tanker trucks. No. 2
oil is stored in three on-site storage tanks totaling 4.2 million gallons.
Natural gas for the CTs is supplied to the site by pipeline. Historically,
natural gas has been purchased directly from the local distributor at tariff
rates.
All units provide voltage regulation and meet PJM spinning reserve requirements.
Unit 5 has black start capability and provides frequency regulation to the grid.
Units 1 and 2 are connected to 115 kV and 230 kV transmission lines. Units 3 and
4 are connected to a 115 kV transmission line. Unit 5 is connected to a 230 kV
transmission line.
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The following tables summarize the plant characteristics.
======================================================================================================================
PORTLAND CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM UNIT 1 UNIT 2
- ----------------------------------------------------------------------------------------------------------------------
STEAM TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Type Cross Compound Cross Compound
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric
- ----------------------------------------------------------------------------------------------------------------------
Commissioned (year) 1958 1962
- ----------------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 157 243
- ----------------------------------------------------------------------------------------------------------------------
BOILER
- ----------------------------------------------------------------------------------------------------------------------
Boiler (type) Once Through Reheat Drum Type Reheat
- ----------------------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 1150 1700
- ----------------------------------------------------------------------------------------------------------------------
Temperature, degree F 1050 1060
- ----------------------------------------------------------------------------------------------------------------------
Pressure, psig 2400 2610
- ----------------------------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal
- ----------------------------------------------------------------------------------------------------------------------
Secondary Fuel No. 2 Oil No. 2 Oil
- ----------------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------------
Fuel Delivery Coal delivered by rail
No. 2 oil by truck
- ----------------------------------------------------------------------------------------------------------------------
Fuel Storage 30 day coal supply
4.2 million gallons of fuel oil
- ----------------------------------------------------------------------------------------------------------------------
Cooling Water Delaware River
======================================================================================================================
======================================================================================================================
PORTLAND CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM UNIT 3 UNIT 4 UNIT 5
- ----------------------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle Simple Cycle
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric Siemens
- ----------------------------------------------------------------------------------------------------------------------
Model Frame 5L Frame 5N V84.3
- ----------------------------------------------------------------------------------------------------------------------
Primary Fuel No. 2 oil No. 2 oil No. 2 oil
- ----------------------------------------------------------------------------------------------------------------------
Secondary Fuel Natural gas Natural gas Natural gas
- ----------------------------------------------------------------------------------------------------------------------
Commissioned (year) 1967 1971 1994
- ----------------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 17 23 145
- ----------------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------------
Fuel Delivery No. 2 oil by truck
Natural gas by pipeline
- ----------------------------------------------------------------------------------------------------------------------
Fuel Storage 4.2 million gallons of fuel oil
- ----------------------------------------------------------------------------------------------------------------------
Cooling Water Delaware River
======================================================================================================================
2.1.5 SEWARD STATION
Seward is located in Seward, Pennsylvania on a 298-acre site adjacent to the
Conemaugh River. Seward has two operating coal-fired steam turbine generator
units, Units 4 and 5, with an average capacity of 196 MW. Unit 4 is a pulverized
coal unit that was built in 1950. The Westinghouse steam turbine generator has
an average capacity of 60 MW. Unit 5 is a pulverized coal unit that was
constructed in 1957. Unit 5 is a GE steam turbine generator, which has an
average capacity of 136. Seward disposes its ash residue at
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- --------------------------------------------------------------------------------
Conemaugh's ash disposal site. Seward also includes a 158-acre parcel of land
within a mile of the station.
Coal is currently purchased through short-term contracts or the spot market from
various local mines, and it is delivered by truck. Seward maintains a coal
storage pile of up to 225,000 tons (a 97 day supply at maximum load). No. 2 oil
is utilized in Units 4 and 5 for boiler startup and flame stabilization at low
loads. The oil is delivered by truck into two 16,000 gallon storage tanks.
Seward is located adjacent to the 23 kV / 115 kV / 230 kV local distribution and
transmission system. Four 23 kV, six 115 kV, and two 230 kV lines leave Seward.
Seward is also tied to Conemaugh by a 115 kV line.
Units 4 and 5 are capable of frequency regulation and have load-following
capability. Seward is capable of black start utilizing the diesel generators
from Conemaugh and the direct interconnect with Conemaugh.
The following table summarizes the plant characteristics.
======================================================================================================================
SEWARD CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM UNIT 4 UNIT 5
- ----------------------------------------------------------------------------------------------------------------------
STEAM TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Type Tandem Compound Tandem Compound
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer Westinghouse General Electric
- ----------------------------------------------------------------------------------------------------------------------
Commissioned (year) 1950 1957
- ----------------------------------------------------------------------------------------------------------------------
Summer Capacity (MW) 60 136
- ----------------------------------------------------------------------------------------------------------------------
BOILER
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer Babcock & Wilcox Combustion Engineering
- ----------------------------------------------------------------------------------------------------------------------
Boiler (type) Sterling Controlled Circulation
- ----------------------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 300 900
- ----------------------------------------------------------------------------------------------------------------------
Temperature, degree F 835 1055
- ----------------------------------------------------------------------------------------------------------------------
Pressure, psig 675 2200
- ----------------------------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal
- ----------------------------------------------------------------------------------------------------------------------
Secondary Fuel No. 2 Oil No. 2 Oil
- ----------------------------------------------------------------------------------------------------------------------
Miscellaneous
- ---------------------------------------- -----------------------------------------------------------------------------
Fuel Delivery Coal delivered by truck
No. 2 oil by truck
- ----------------------------------------------------------------------------------------------------------------------
Fuel Storage 225,000 ton coal supply
Two 16,000 gallon storage tanks
- ----------------------------------------------------------------------------------------------------------------------
Cooling Water Conemaugh River
======================================================================================================================
2.1.6 TITUS STATION
Titus is located in Reading, Pennsylvania on a 33-acre site with 244 acres of
adjoining property on the Schuylkill River. Titus consists of three duplicate
coal-fired steam turbine generator units and two simple cycle CTs with an
average station capacity of 281 MW. Units 1 and 2 were commissioned in 1951, and
Unit 3 was commissioned in 1953. Units 4 and 5 are GE 5001 L units. Unit 4 was
installed in 1967 and has an average capacity of 17 MW. Unit 5 was installed in
1970 and has an average capacity of 18 MW. CT 4 and CT 5 are dual-fuel units
burning either natural gas or No. 2 oil. Ash disposal for Titus is at the Beagle
Club landfill one mile from the plant site.
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Coal for Units 1, 2, and 3 is supplied under a contract with CONSOL and is
delivered to the plant by railroad on a "split train" with Portland. Titus
maintains a coal storage pile up to 160,000 tons (a 65-day supply at maximum
load). Units 1, 2, and 3 utilize No. 2 oil for start-up and flame control. No. 2
fuel oil is delivered by tank trucks to Titus, which has a tank capacity of
250,000 gallons. The CTs burn either No. 2 oil or natural gas. Historically,
natural gas has been purchased from the local distributor at tariff rates and
delivered to the site by pipeline.
Titus has access to a 69 kV transmission line and a 230 kV transmission line.
The existing Titus transmission lines can handle up to 160 MW of additional
capacity without transmission upgrades and up to 980 MW with transmission system
upgrades.
The following tables summarize the plant characteristics.
======================================================================================================================
TITUS CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM UNIT 1 UNIT 2 UNIT 3
- ----------------------------------------------------------------------------------------------------------------------
STEAM TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Type Tandem Compound Tandem Compound Tandem Compound
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric General Electric
- ----------------------------------------------------------------------------------------------------------------------
Commissioned (year) 1951 1951 1953
- ----------------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 82 82 82
- ----------------------------------------------------------------------------------------------------------------------
BOILER
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer Combustion Engineering Combustion Engineering Combustion Engineering
- ----------------------------------------------------------------------------------------------------------------------
Boiler (type) Drum Type Drum Type Drum Type
- ----------------------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 600 600 600
- ----------------------------------------------------------------------------------------------------------------------
Temperature, degree F 1005 1005 1005
- ----------------------------------------------------------------------------------------------------------------------
Pressure, psig 1450 1450 1450
- ----------------------------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal Coal
- ----------------------------------------------------------------------------------------------------------------------
Secondary Fuel No. 2 Oil No. 2 Oil No. 2 Oil
- ----------------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------------
Fuel Delivery Coal delivered by rail
No. 2 oil by truck
- ----------------------------------------------------------------------------------------------------------------------
Fuel Storage Up to 65 day coal supply
250,000 gallons of fuel oil
- ----------------------------------------------------------------------------------------------------------------------
Cooling Water Cooling tower with makeup from Delaware River
======================================================================================================================
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======================================================================================================================
TITUS CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM CT 4 CT 5
- ----------------------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Type Simple Cycle Combustion Turbine Simple Cycle Combustion Turbine
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric
- ----------------------------------------------------------------------------------------------------------------------
Model 5001 L 5001 L
- ----------------------------------------------------------------------------------------------------------------------
Commissioned (year) 1967 1970
- ----------------------------------------------------------------------------------------------------------------------
Primary Fuel Natural gas Natural gas
No. 2 oil No. 2 oil
- ----------------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 17 18
- ----------------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
No. 2 oil by truck
- ----------------------------------------------------------------------------------------------------------------------
Fuel Storage 250,000 gallons of fuel oil
- ----------------------------------------------------------------------------------------------------------------------
Cooling Water Cooling tower with makeup from Delaware River
======================================================================================================================
2.1.7 SAYREVILLE STATION
Sayreville Station ("Sayreville") is located in Sayreville, Middlesex County,
New Jersey on a 67 acre site on the bank of the Raritan River. Sayreville
consists of two dual-fuel fired steam turbine generator units, Units 4 and 5,
and four simple cycle CTs. Sayreville has an average station capacity of 449 MW.
Units 4 and 5 have average capacities of 90 MW and 95 MW, respectively. Unit 4
began commercial operation in 1955 and Unit 5 began commercial operation in
1958. These units initially burned coal; however, they were converted to oil in
1969. In 1982, a natural gas pipeline was installed, and henceforth the units
have burned primarily natural gas.
The four CTs are Westinghouse 501AA's. C-1 and C-4 have an average capacity of
67 MW. Units C-2 and C-3 have an average capacity of 63 MW. The CTs were
installed in 1972 and 1973. They initially burned only No. 2 fuel oil; however,
they now have the capability to burn natural gas. In 1995, water injection was
added for NO(x) control.
There are two 108,000 barrel No. 6 oil storage tanks on site, one 32,000 barrel
and two 16,000 barrel No. 2 oil storage tanks on site. There is also one 995
gallon above ground gasoline tank and one 500 gallon above ground diesel tank on
site. Short-term contracts with local suppliers provide No. 2 oil for the site
by truck or barge. Historically, natural gas is purchased from the local
distributor at tariff rates and delivered by pipeline.
Sayreville includes a key east PJM substation in addition to the station
transformers of the existing units and retired Units 1, 2, and 3. Sayreville is
capable of providing spinning reserve to the system.
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The following tables summarize the plant characteristics.
===========================================================================================================
SAYREVILLE CHARACTERISTICS SUMMARY
===========================================================================================================
ITEM UNIT 4 UNIT 5
- -----------------------------------------------------------------------------------------------------------
STEAM TURBINE
- -----------------------------------------------------------------------------------------------------------
Type Tandem Compound Tandem Compound
- -----------------------------------------------------------------------------------------------------------
Manufacturer General Electric Westinghouse
- -----------------------------------------------------------------------------------------------------------
Commissioned (year) 1955 1955
- -----------------------------------------------------------------------------------------------------------
Average Capacity (MW) 90 95
- -----------------------------------------------------------------------------------------------------------
BOILER
- -----------------------------------------------------------------------------------------------------------
Manufacturer Babcock & Wilcox Babcock & Wilcox
- -----------------------------------------------------------------------------------------------------------
Boiler (type) Drum Type Cyclone Drum Type Cyclone
- -----------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 900 900
- -----------------------------------------------------------------------------------------------------------
Temperature, degree F 1055 1055
- -----------------------------------------------------------------------------------------------------------
Pressure, psig 2250 2250
- -----------------------------------------------------------------------------------------------------------
Primary Fuel Natural Gas Natural Gas
- -----------------------------------------------------------------------------------------------------------
Secondary Fuel No. 6 oil No. 6 oil
- -----------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- -----------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
Fuel oil by truck or barge
- -----------------------------------------------------------------------------------------------------------
Fuel Storage 280,000 barrels in No. 6 and No. 2 oil capacity
- -----------------------------------------------------------------------------------------------------------
Cooling Water Raritan River
===========================================================================================================
===========================================================================================================
SAYREVILLE CHARACTERISTICS SUMMARY
===========================================================================================================
ITEM C-1 C-2 C-3 C-4
- -----------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
- -----------------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle Simple Cycle Simple Cycle
- -----------------------------------------------------------------------------------------------------------
Manufacturer Westinghouse Westinghouse Westinghouse Westinghouse
- -----------------------------------------------------------------------------------------------------------
Model 501AA 501AA 501AA 501AA
- -----------------------------------------------------------------------------------------------------------
Primary Fuel Natural gas or Natural gas or Natural gas or Natural gas
No. 2 oil No. 2 oil No. 2 oil or No. 2 oil
- -----------------------------------------------------------------------------------------------------------
Commissioned (year) 1973 1972 1972 1972
- -----------------------------------------------------------------------------------------------------------
Average Capacity (MW) 67 65 65 67
- -----------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- -----------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
Fuel oil by truck or barge
- -----------------------------------------------------------------------------------------------------------
Fuel Storage 280,000 barrels in No. 6 and No. 2 oil capacity
- -----------------------------------------------------------------------------------------------------------
Cooling Water Raritan River
===========================================================================================================
2.1.8 WARREN STATION
Warren Station ("Warren") is located on a 103-acre site one mile west of Warren,
Pennsylvania. Warren also includes a 67-acre plot located three miles from the
station. Warren consists of two duplicate coal-fired steam turbine generators
and a dual-fuel CT. Units 1 and 2, the coal units, entered commercial operation
in 1948 and 1949, respectively, and each has an average capacity of 41 MW. Unit
3 is a Westinghouse Model W-501AA CT has an average capacity of 65 MW. Unit 3
was installed in 1972 and
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can burn either No. 2 oil or natural gas. It has an average station capacity of
150 MW. Ash generated at the station is disposed of at an on-site landfill.
Coal for Units 1 and 2 is purchased from local surface mines through short-term
contracts. Coal is delivered to the plant by truck. The plant has a coal storage
pile of up to 50,000 tons (a 39-day supply at maximum load). Units 1 and 2 also
burn No. 2 oil for startup and flame stability. Unit 3 burns either No. 2 fuel
oil or natural gas. No. 2 oil is delivered to the site by tank trucks. The plant
has No. 2 oil storage, totaling 530,000 gallons. Historically, the local
distributor has supplied natural gas through a pipeline.
Warren utilizes the 230 kV Glade-Erie South transmission line for large
industrial loads and the 115 kV Warren South line.
The following tables summarize the plant characteristics.
=================================================================================================================
WARREN CHARACTERISTICS SUMMARY
=================================================================================================================
ITEM UNIT 1 UNIT 2
-----------------------------------------------------------------------------------------------------------------
STEAM TURBINE
-----------------------------------------------------------------------------------------------------------------
Type Tandem Compound Tandem Compound
-----------------------------------------------------------------------------------------------------------------
Manufacturer Westinghouse Westinghouse
-----------------------------------------------------------------------------------------------------------------
Commissioned (year) 1948 1949
-----------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 41 41
-----------------------------------------------------------------------------------------------------------------
BOILER
-----------------------------------------------------------------------------------------------------------------
Manufacturer Erie-City Erie-City
-----------------------------------------------------------------------------------------------------------------
Boiler (type) Drum Type Drum Type
-----------------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 185 185
-----------------------------------------------------------------------------------------------------------------
Temperature, degree F 875 875
-----------------------------------------------------------------------------------------------------------------
Pressure, psig 850 850
-----------------------------------------------------------------------------------------------------------------
Primary Fuel Coal Coal
-----------------------------------------------------------------------------------------------------------------
Secondary Fuel No. 2 Oil No. 2 Oil
-----------------------------------------------------------------------------------------------------------------
Miscellaneous
-----------------------------------------------------------------------------------------------------------------
Fuel Delivery Coal by truck
No. 2 oil by truck
-----------------------------------------------------------------------------------------------------------------
Fuel Storage 39-day coal supply
530,000 gallons of No. 2 oil
-----------------------------------------------------------------------------------------------------------------
Cooling Water Allegheny River
=================================================================================================================
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=========================================================================================
WARREN CHARACTERISTICS SUMMARY
=========================================================================================
ITEM CT 3
-----------------------------------------------------------------------------------------
Combustion Turbine
-----------------------------------------------------------------------------------------
Type Simple Cycle Combustion Turbine
-----------------------------------------------------------------------------------------
Manufacturer Westinghouse
-----------------------------------------------------------------------------------------
Model 501 AA
-----------------------------------------------------------------------------------------
Primary Fuel Natural gas or No. 2 oil
-----------------------------------------------------------------------------------------
Commissioned (year) 1972
-----------------------------------------------------------------------------------------
Average Capacity (MW) 65
-----------------------------------------------------------------------------------------
MISCELLANEOUS
-----------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
No. 2 oil by truck
-----------------------------------------------------------------------------------------
Fuel Storage 530,000 gallons of fuel oil
-----------------------------------------------------------------------------------------
Cooling Water Allegheny River
=========================================================================================
2.1.9 GILBERT STATION
Gilbert Station ("Gilbert") is located on a 232-acre site adjacent to the
Delaware River in Holland Township, Hunterdon County, New Jersey. Gilbert has an
average capacity of 614 MW in a four on one combined cycle train and five simple
cycle CTs.
Gilbert has five simple cycle CTs, C-1, C-2, C-3, C-4, and CT9. The C-1, C-2,
C-3, and C-4 units are dual-fuel simple cycle Westinghouse 251AA CTs that began
operation in 1970. C-1, C-2 and C-3 have an average capacity of 28 MW and C-4
has an average capacity of 27 MW. They are equipped with water injection for
NO(x) control when firing either oil or gas. Supplementary firing capability has
been removed to comply with the Clean Air Act ("CAA"). CT9 is an advanced ABB
GT24 that began operation in 1997. CT9 is a dual-fuel capable machine that
utilizes water injection for NO(x) control on No. 2 oil and has an average
capacity of 167 MW. This unit has gas compression facilities.
The combined cycle CTs, CC4, CC5, CC6, and CC7, are GE 7000C CTs each with heat
recovery steam generators ("HRSGs"). The CT's were installed as simple cycle
units in 1974, and the HRSGs were added in 1977. These units exhaust to CC8, a
steam turbine generator, with an average capacity of 97 MW. It was derated from
120 MW upon the removal of the supplementary firing due to the CAA.
The Gilbert cooling towers are of wood type construction.
Gilbert also includes the Hellertown facility located on an 89-acre site in
Hellertown, Pennsylvania, approximately 15 minutes from Gilbert. Hellertown
includes oil storage for up to 16.8 million gallons of No. 2 oil, an oil proving
facility, metering station, maintenance heaters, transfer pumps, a wastewater
treatment plant, and a foam fire protection system. No. 2 oil is typically
supplied to Hellertown under short-term contracts with local suppliers by a
pipeline. The Hellertown facility meters and stores the No. 2 oil for use at
Gilbert. An 8-inch pipeline transfers the No. 2 oil from Hellertown to Gilbert.
Custody transfer takes place at Hellertown. A bypass around is also provided to
receive No. 2 oil directly at Gilbert. Historically, the local distributor has
supplied natural gas to the site through a pipeline.
Gilbert ties into the 230 kV system within the PJM area of control. All units
feed the 230 kV grid. Existing plant capacity cannot be expanded without
transmission reinforcements. C-1, C-2, C-3, C-4, CT9, CC4, CC5, CC6, CC7, and
CC8 have reactive and voltage control capabilities. CC4, CC5, CC6, CC7, and CC8
have load-following capability. Supplemental reserve capability is also provided
by C-1,
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- --------------------------------------------------------------------------------
C-2, C-3, C-4, and CC4, CC5, CC6, and CC7 in simple-cycle operation. Spinning
reserve can be provided by C-1, C-2, C-3, and C-4. Diesel CTs also have black
start capability. CC 4, CC5, CC6, and CC7 can also provide frequency regulation.
The following tables summarize the plant characteristics.
===============================================================================================================
GILBERT CHARACTERISTICS SUMMARY
===============================================================================================================
ITEM C-1 C-2 C-3 C-4
---------------------------------------------------------------------------------------------------------------
Combustion Turbine
---------------------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle Simple Cycle Simple Cycle
---------------------------------------------------------------------------------------------------------------
Manufacturer Westinghouse Westinghouse Westinghouse Westinghouse
---------------------------------------------------------------------------------------------------------------
Model 251AA 251AA 251AA 251AA
---------------------------------------------------------------------------------------------------------------
Primary Fuel Natural gas or Natural gas or Natural gas or Natural gas or
No. 2 oil No. 2 oil No. 2 oil No. 2 oil
---------------------------------------------------------------------------------------------------------------
Commissioned (year) 1970 1970 1970 1970
---------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 28 28 28 27
---------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
---------------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
Fuel oil by pipeline directly or through Hellertown
---------------------------------------------------------------------------------------------------------------
Fuel Storage Limited at Gilbert
16.8 million gallons at Hellertown
---------------------------------------------------------------------------------------------------------------
Cooling Water Delaware River and cooling towers
===============================================================================================================
==============================================================================================================
GILBERT CHARACTERISTICS SUMMARY
==============================================================================================================
ITEM CT9
--------------------------------------------------------------------------------------------------------------
Combustion Turbine
--------------------------------------------------------------------------------------------------------------
Type Simple Cycle
--------------------------------------------------------------------------------------------------------------
Manufacturer ABB
--------------------------------------------------------------------------------------------------------------
Model GT24
--------------------------------------------------------------------------------------------------------------
Commissioned (year) 1997
--------------------------------------------------------------------------------------------------------------
Primary Fuel Natural Gas
--------------------------------------------------------------------------------------------------------------
Secondary Fuel No. 2 oil
--------------------------------------------------------------------------------------------------------------
NO(x) Control Method Water Injection
--------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 167
--------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
--------------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
No. 2 oil by pipeline directly or through Hellertown
--------------------------------------------------------------------------------------------------------------
Fuel Storage Limited at Gilbert
16.8 million gallons at Hellertown
--------------------------------------------------------------------------------------------------------------
Cooling Water Delaware River and cooling towers
==============================================================================================================
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================================================================================================================
GILBERT CHARACTERISTICS SUMMARY
================================================================================================================
ITEM CC4 CC5 CC6 CC7
- ----------------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
- ----------------------------------------------------------------------------------------------------------------
Type Combined Cycle Combined Cycle Combined Cycle Combined Cycle
- ----------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric General Electric General Electric
- ----------------------------------------------------------------------------------------------------------------
Model 7000C 7000C 7000C 7000C
- ----------------------------------------------------------------------------------------------------------------
Commissioned (year) 1974 1974 1974 1974
- ----------------------------------------------------------------------------------------------------------------
Primary Fuel Natural gas Natural gas Natural gas Natural gas
- ----------------------------------------------------------------------------------------------------------------
Secondary Fuel No. 2 oil No. 2 oil No. 2 oil No. 2 oil
- ----------------------------------------------------------------------------------------------------------------
NO(x) Control Method Steam Injection Steam Injection Steam Injection Steam Injection
- ----------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 59.5 59.5 59.5 59.5
- ----------------------------------------------------------------------------------------------------------------
HEAT RECOVERY BOILER
- ----------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric General Electric General Electric
- ----------------------------------------------------------------------------------------------------------------
Boiler (type) HRSG HRSG HRSG HRSG
- ----------------------------------------------------------------------------------------------------------------
Rated Main Steam Flow (kpph) 229 229 229 229
- ----------------------------------------------------------------------------------------------------------------
Temperature, degree F 730 730 730 730
- ----------------------------------------------------------------------------------------------------------------
Pressure, psig 420 420 420 420
- ----------------------------------------------------------------------------------------------------------------
STEAM TURBINE CC8
- ----------------------------------------------------------------------------------------------------------------
Manufacturer General Electric
- ----------------------------------------------------------------------------------------------------------------
Type Tandem Compound
- ----------------------------------------------------------------------------------------------------------------
Commissioned (year) 1977
- ----------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 97
- ----------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
No. 2 oil is supplied by pipeline directly or through Hellertown
- ----------------------------------------------------------------------------------------------------------------
Fuel Storage Limited at Gilbert
16.8 million gallons at Hellertown
- ----------------------------------------------------------------------------------------------------------------
Cooling Water Delaware River and cooling towers
================================================================================================================
2.1.10 COMBUSTION TURBINES
HAMILTON STATION
Hamilton Station ("Hamilton") is located in Hamilton Township southwest of
Harrisburg, Pennsylvania on a 40-acre site. The single unit has an average
capacity of 23 MW. The CT is a GE MS 5001 N that began operation in 1971 and
burns No. 2 oil. No. 2 oil is supplied to the site by truck. Site storage
capacity includes a 211,000 gallon tank (70 hours of operation).
The CT is primarily utilized for peaking service and is remotely dispatched from
Reading, Pennsylvania. The mobile maintenance crew based at Hunterstown
maintains it. The CT is black start capable and can operate in one of three
modes: spinning reserve, base, or peak.
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The following table summarizes the plant characteristics.
=================================================================================
HAMILTON CHARACTERISTICS SUMMARY
=================================================================================
ITEM CT1
- ---------------------------------------------------------------------------------
COMBUSTION TURBINE
- ---------------------------------------------------------------------------------
Type Simple Cycle
- ---------------------------------------------------------------------------------
Manufacturer General Electric
- ---------------------------------------------------------------------------------
Model MS 5001N
- ---------------------------------------------------------------------------------
Commissioned (year) 1971
- ---------------------------------------------------------------------------------
Primary Fuel No. 2 oil
- ---------------------------------------------------------------------------------
Average Capacity (MW) 23
- ---------------------------------------------------------------------------------
MISCELLANEOUS
- ---------------------------------------------------------------------------------
Fuel Delivery No. 2 oil by truck
- ---------------------------------------------------------------------------------
Operation Site is remote operated
=================================================================================
HUNTERSTOWN STATION
Hunterstown Station ("Hunterstown") is located in Straban Township, Pennsylvania
on a 257-acre site. The station has three CTs and an average station capacity of
71 MW. The CTs are GE MS 5001 N machines that began operation in 1971 and burn
No. 2 oil or natural gas.
No. 2 oil is delivered to the site by truck and stored in a tank with a capacity
of 393,000 gallons (43 hours of operation). Historically, natural gas has been
purchased from the local distributor and supplied by pipeline.
The station is primarily utilized for peaking service and is remotely
dispatched. The mobile maintenance crew maintains Hunterstown. The units are
black start capable and can operate in one of four modes: spinning reserve, load
frequency control, base, or peak.
The following table summarizes the plant characteristics.
======================================================================================================================
HUNTERSTOWN CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM CT1 CT2 CT3
- ----------------------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle Simple Cycle
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric General Electric
- ----------------------------------------------------------------------------------------------------------------------
Model MS 5001N MS 5001N MS 5001N
- ----------------------------------------------------------------------------------------------------------------------
Commissioned (year) 1971 1971 1971
- ----------------------------------------------------------------------------------------------------------------------
Primary Fuel Natural gas Natural gas Natural gas
No. 2 oil No. 2 oil No. 2 oil
- ----------------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 23.5 23.5 23.5
- ----------------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
No. 2 oil by truck
- ----------------------------------------------------------------------------------------------------------------------
Fuel Storage 393,000 gallon tank
- ----------------------------------------------------------------------------------------------------------------------
Operation Site is remote operated
======================================================================================================================
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MOUNTAIN STATION
Mountain Station ("Mountain") is located in Middleton Township, Pennsylvania on
an 88-acre site. The station includes two CTs with an average station capacity
of 47 MW. The CTs are GE MS 5001 N machines that began operation in 1972.
Mountain is a remotely operated peaking site maintained by the mobile
maintenance crew based at Hunterstown.
The Mountain CTs are dual-fuel machines that burn either natural gas or No. 2
fuel oil. No. 2 fuel oil is purchased under short-term contracts, delivered to
the site, and stored on site in one 308,000 gallon storage tank (48 hours of
operation). Historically, natural gas has been purchased and delivered to the
site by the local distributor.
The units are black start capable and can operate in one of four modes: spinning
reserve, load frequency control, base, or peak.
The following table summarizes the plant characteristics.
====================================================================================================
MOUNTAIN CHARACTERISTICS SUMMARY
====================================================================================================
ITEM CT1 CT2
----------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
----------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle
----------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric
----------------------------------------------------------------------------------------------------
Model MS 5001N MS 5001N
----------------------------------------------------------------------------------------------------
Commissioned (year) 1972 1972
----------------------------------------------------------------------------------------------------
Primary Fuel Natural gas Natural gas
Natural 2 oil No. 2 oil
----------------------------------------------------------------------------------------------------
Average Capacity (MW) 23.5 23.5
----------------------------------------------------------------------------------------------------
MISCELLANEOUS
----------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
No. 2 oil by truck
----------------------------------------------------------------------------------------------------
Fuel Storage 308,000 gallon tank
----------------------------------------------------------------------------------------------------
Operation Site is remote operated
====================================================================================================
ORRTANNA STATION
Orrtanna Station ("Orrtanna") is located in Highland Township southwest of
Harrisburg, Pennsylvania on a 10-acre site. The site operates one CT with an
average capacity of 23 MW. The CT is a GE Model MS 5000 N machine that began
commercial operation in 1971. Orrtanna is considered a peak load station.
Orrtanna is a remotely operated site and is maintained by the mobile maintenance
crew based at Hunterstown.
The Orrtanna CT burns No. 2 oil. No. 2 oil is purchased under short-term
contracts, delivered to site by truck, and is stored in a 211,000 gallon storage
tank (72 hours of operation).
The unit is black start capable and can operate in one of four modes: spinning
reserve, load frequency control, base, or peak.
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- --------------------------------------------------------------------------------
The following table summarizes the plant characteristics.
======================================================================================
ORRTANNA CHARACTERISTICS SUMMARY
======================================================================================
ITEM CT1
- --------------------------------------------------------------------------------------
COMBUSTION TURBINE
- --------------------------------------------------------------------------------------
Type Simple Cycle
- --------------------------------------------------------------------------------------
Manufacturer General Electric
- --------------------------------------------------------------------------------------
Model MS 5001N
- --------------------------------------------------------------------------------------
Commissioned (year) 1971
- --------------------------------------------------------------------------------------
Primary Fuel No. 2 oil
- --------------------------------------------------------------------------------------
Average Capacity (MW) 23
- --------------------------------------------------------------------------------------
MISCELLANEOUS
- --------------------------------------------------------------------------------------
Fuel Delivery No. 2 oil by truck
- --------------------------------------------------------------------------------------
Fuel Storage 211,000 gallon tank
- --------------------------------------------------------------------------------------
Operation Site is remote operated
======================================================================================
SHAWNEE COMBUSTION TURBINE
Shawnee Combustion Turbine ("Shawnee") is located in Shawnee, Pennsylvania on an
83-acre site. Shawnee consists of one CT with an average capacity of 23 MW. The
Shawnee CT is a GE MS 5001 N simple-cycle CT that began commercial operation in
1972. Shawnee is operated as a peaking unit. Shawnee is a remotely operated
station, which is maintained from Portland.
Shawnee burns No. 2 oil. Historically, No. 2 oil is purchased under short-term
contracts, delivered to site by truck, and stored in 300,000 gallon storage
tank.
The following table summarizes the plant characteristics.
======================================================================================
SHAWNEE CHARACTERISTICS SUMMARY
======================================================================================
ITEM CT1
- --------------------------------------------------------------------------------------
COMBUSTION TURBINE
- --------------------------------------------------------------------------------------
Type Simple Cycle
- --------------------------------------------------------------------------------------
Manufacturer General Electric
- --------------------------------------------------------------------------------------
Model MS 5001N
- --------------------------------------------------------------------------------------
Commissioned (year) 1972
- --------------------------------------------------------------------------------------
Primary Fuel No. 2 oil
- --------------------------------------------------------------------------------------
Average Capacity (MW) 23
- --------------------------------------------------------------------------------------
MISCELLANEOUS
- --------------------------------------------------------------------------------------
Fuel Delivery No. 2 oil by truck
- --------------------------------------------------------------------------------------
Fuel Storage 300,000 gallon tank
- --------------------------------------------------------------------------------------
Operation Site is remote operated
======================================================================================
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TOLNA STATION
Tolna Station ("Tolna") is located in Hopewell Township, south of Harrisburg,
Pennsylvania on a 136 acre site. Tolna operates two simple cycle CTs with an
average station capacity of 47 MW. The Tolna CTs are GE MS 5001 N machines
firing No. 2 oil which have been in service since 1972. Tolna is remote
operated. Tolna is normally operated as a peaking plant. The mobile maintenance
crew based at Hunterstown carries out Tolna's maintenance.
Historically, fuel oil for the facility has been purchased under short-term
contracts with local suppliers, delivered by truck, and stored in a 308,000
gallon tank (46 hours of operation).
The Tolna units are black start capable and can operate in one of the three
modes: spinning reserve, base, or peak.
The following table summarizes the plant characteristics.
=================================================================================================================
TOLNA CHARACTERISTICS SUMMARY
=================================================================================================================
ITEM CT1 CT2
-----------------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
-----------------------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle
-----------------------------------------------------------------------------------------------------------------
Manufacturer General Electric General Electric
-----------------------------------------------------------------------------------------------------------------
Model MS 5001N MS 5001N
-----------------------------------------------------------------------------------------------------------------
Commissioned (year) 1972 1972
-----------------------------------------------------------------------------------------------------------------
Primary No. 2 oil No. 2 oil
-----------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 23.5 23.5
-----------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
-----------------------------------------------------------------------------------------------------------------
Fuel Delivery No. 2 oil by truck
-----------------------------------------------------------------------------------------------------------------
Fuel Storage 308,000 gallon truck
-----------------------------------------------------------------------------------------------------------------
Operation Site is remotely operated
=================================================================================================================
GLEN GARDNER
Glen Gardner Station ("Glen Gardner") is located in Glen Gardner, Lebanon
Township, Huntertown County, New Jersey on a five acre site. Glen Gardner Units
A1, A2, A3, A4, B1, B2, B3, and B4 are GE Frame 5 CTs installed in 1970. The
units are dual-fired and burn either natural gas or No. 2 oil. The units are
operated primarily as peakers from the Gilbert control room.
No. 2 oil has been purchased under short-term contracts with local suppliers,
delivered by truck, and stored in a 1.1 million gallon tank (48 hours of
operation). Historically, natural gas has been purchased under short-term
contracts from the local distributor and received by pipeline.
Black start capability is provided for A and B blocks through diesel starting
devices on unit A1 and B1. Reactive and voltage control is provided for all
units by the GE static excitation systems. All units have spinning reserve
capability.
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- --------------------------------------------------------------------------------
The following tables summarize the plant characteristics.
=========================================================================================================
GLEN GARDNER CHARACTERISTICS SUMMARY
=========================================================================================================
ITEM A1 A2 A3 A4
---------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
---------------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle Simple Cycle Simple Cycle
---------------------------------------------------------------------------------------------------------
Manufacturer General General General General
Electric Electric Electric Electric
---------------------------------------------------------------------------------------------------------
Model Frame 5 Frame 5 Frame 5 Frame 5
---------------------------------------------------------------------------------------------------------
Commissioned (year) 1970 1970 1970 1970
---------------------------------------------------------------------------------------------------------
Primary Fuel Natural gas or Natural gas or Natural gas or Natural gas or
No. 2 oil No. 2 oil No. 2 oil No. 2 oil
---------------------------------------------------------------------------------------------------------
Average Capacity (MW) 23 23 23 23
---------------------------------------------------------------------------------------------------------
MISCELLANEOUS
---------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
No. 2 oil by truck
---------------------------------------------------------------------------------------------------------
Fuel Storage 1.1 million gallon tank
---------------------------------------------------------------------------------------------------------
Operation Remotely operated from Gilbert
=========================================================================================================
=========================================================================================================
GLEN GARDNER CHARACTERISTICS SUMMARY
=========================================================================================================
ITEM B1 B2 B3 B4
---------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
---------------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle Simple Cycle Simple Cycle
---------------------------------------------------------------------------------------------------------
Manufacturer General General General General
Electric Electric Electric Electric
---------------------------------------------------------------------------------------------------------
Model Frame 5 Frame 5 Frame 5 Frame 5
---------------------------------------------------------------------------------------------------------
Commissioned (year) 1970 1970 1970 1970
---------------------------------------------------------------------------------------------------------
Primary Fuel Natural gas or Natural gas or Natural gas or Natural gas or
No. 2 oil No. 2 oil No. 2 oil No. 2 oil
---------------------------------------------------------------------------------------------------------
Average Capacity (MW) 23 23 23 23
---------------------------------------------------------------------------------------------------------
MISCELLANEOUS
---------------------------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
No. 2 oil by truck
---------------------------------------------------------------------------------------------------------
Fuel Storage 1.1 million gallon tank
---------------------------------------------------------------------------------------------------------
Operation Remotely operated from Gilbert
=========================================================================================================
WERNER
Werner Station ("Werner") is located on a 28-acre site in South Amboy, Middlesex
County, New Jersey on the south bank of the Raritan River. Werner consists of
four simple cycle CTs with a total average capacity of 252 MW. Werner consists
of four oil-fired simple cycle Westinghouse 501AA CTs labeled C1, C2, C3, and C4
each with an average capacity of 63 MW. These units have been in operation since
1972. The station is operated as a peaking unit. Werner is controlled remotely
from the Sayreville control room.
No. 2 oil is supplied by various distributors and is delivered to the site by
barge. No. 2 oil is purchased on the spot market at the current Platt's New York
Harbor spot barge price plus mark-up and transportation. Werner has two oil
storage tanks with 2,000,000 gallons of total storage.
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- --------------------------------------------------------------------------------
The following table summarizes the plant characteristics.
===========================================================================================================
WERNER CHARACTERISTICS SUMMARY
===========================================================================================================
ITEM C1 C2 C3 C4
-----------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
-----------------------------------------------------------------------------------------------------------
Type Simple Cycle Simple Cycle Simple Cycle Simple Cycle
-----------------------------------------------------------------------------------------------------------
Manufacturer Westinghouse Westinghouse Westinghouse Westinghouse
-----------------------------------------------------------------------------------------------------------
Model 501 AA 501 AA 501 AA 501 AA
-----------------------------------------------------------------------------------------------------------
Commissioned (year) 1972 1972 1972 1972
-----------------------------------------------------------------------------------------------------------
Primary Fuel No. 2 oil No. 2 oil No. 2 oil No. 2 oil
-----------------------------------------------------------------------------------------------------------
Average Capacity (MW) 63 63 63 63
-----------------------------------------------------------------------------------------------------------
Miscellaneous
-----------------------------------------------------------------------------------------------------------
Fuel Delivery No. 2 oil by barge
-----------------------------------------------------------------------------------------------------------
Fuel Storage 2,000,000 gallons of tanks
-----------------------------------------------------------------------------------------------------------
Operation Remotely operated from Sayreville
===========================================================================================================
BLOSSBURG STATION
Blossburg Station ("Blossburg") is located in Blossburg, Pennsylvania on a
2.85-acre site. Blossburg operates one simple cycle CT with an average capacity
of 25 MW. The Blossburg CT is a GE MS 5001 machine firing natural gas. Blossburg
is a remotely operated station, which operates as a peaker. Historically, the
local distributor has delivered natural gas to the site through a pipeline. The
Blossburg CT has black start capability utilizing a diesel-fueled engine.
Blossburg is occasionally operated as spinning reserve.
The following table summarizes the plant characteristics.
========================================================================================
BLOSSBURG CHARACTERISTICS SUMMARY
========================================================================================
ITEM CT1
- ----------------------------------------------------------------------------------------
COMBUSTION TURBINE
- ----------------------------------------------------------------------------------------
Type Simple Cycle
- ----------------------------------------------------------------------------------------
Manufacturer General Electric
- ----------------------------------------------------------------------------------------
Model MS 5001
- ----------------------------------------------------------------------------------------
Commissioned (year) 1972
- ----------------------------------------------------------------------------------------
Primary Fuel Natural gas
- ----------------------------------------------------------------------------------------
Average Capacity (MW) 25
- ----------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------
Fuel Delivery Natural gas by pipeline
- ----------------------------------------------------------------------------------------
Operation Site is remote operated
========================================================================================
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WAYNE
Wayne Station ("Wayne") is located in Wayne Township, Pennsylvania on a 159-acre
site. Wayne is a simple cycle CT with an average capacity of 66 MW. The Wayne CT
is a Westinghouse 501AA machine firing No. 2 oil. Wayne is normally operated as
a peaking plant. Wayne is remote operated. Fuel oil is purchased under
short-term contract, delivered by truck, and stored in two 500,000 gallon
storage tanks (72 hours of operation).
The following table summarizes the plant characteristics.
============================================================================================================
WAYNE CHARACTERISTICS SUMMARY
============================================================================================================
ITEM CT1
- ------------------------------------------------------------------------------------------------------------
COMBUSTION TURBINE
- ------------------------------------------------------------------------------------------------------------
Type Simple Cycle
- ------------------------------------------------------------------------------------------------------------
Manufacturer Westinghouse
- ------------------------------------------------------------------------------------------------------------
Model 501 AA
- ------------------------------------------------------------------------------------------------------------
Commissioned (year) 1972
- ------------------------------------------------------------------------------------------------------------
Primary Fuel No. 2 oil
- ------------------------------------------------------------------------------------------------------------
Average Capacity (MW) 66
- ------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ------------------------------------------------------------------------------------------------------------
Fuel Delivery No. 2 oil by truck
- ------------------------------------------------------------------------------------------------------------
Fuel Storage Two 500,000 gallon tanks
- ------------------------------------------------------------------------------------------------------------
Operation Site is remote operated
============================================================================================================
2.1.11 PINEY STATION
Piney Hydroelectric Station ("Piney") is located in Piney Township, Pennsylvania
on the Clarion River and includes a watershed area of 939 acres. The powerhouse
includes three hydro turbine generators with an average capacity 29 MW. These
generators were placed in service between 1924 and 1928.
Piney includes an arch-type dam, 700 feet long by 127 feet high, producing a
lake 16 miles long covering 800 acres, and producing a 75-foot head for the
powerhouse. The dam has three penstocks, which connect the intake structure at
the dam to the turbines and a fourth penstock that is snubbed off.
All units can provide frequency regulation and automatic voltage regulation. The
units can also be operated as synchronous condensers and have black-start
capability.
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- --------------------------------------------------------------------------------
The following table summarizes the plant characteristics.
======================================================================================================================
PINEY CHARACTERISTICS SUMMARY
======================================================================================================================
ITEM UNIT 1 UNIT 2 UNIT 3
- ----------------------------------------------------------------------------------------------------------------------
HYDROELECTRIC TURBINE
- ----------------------------------------------------------------------------------------------------------------------
Manufacturer IP Morris IP Morris IP Morris
- ----------------------------------------------------------------------------------------------------------------------
Type Francis-type Francis-type Francis-type
- ----------------------------------------------------------------------------------------------------------------------
Commissioned (year) 1924 1924 1927
- ----------------------------------------------------------------------------------------------------------------------
Capacity (MW) 9 9 10
- ----------------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
- ----------------------------------------------------------------------------------------------------------------------
Penstocks Dam includes four penstocks
Three are used and the fourth is snubbed off
- ----------------------------------------------------------------------------------------------------------------------
Dam Concrete arch dam
- ----------------------------------------------------------------------------------------------------------------------
Water conduit Includes a power intake with slide gate, a Moody Cone type draft tube, and a draft
tube exit with no gate slots
======================================================================================================================
2.1.12 DEEP CREEK STATION
Deep Creek Station ("Deep Creek") is located on Deep Creek Lake in Garrett
County, Maryland on 467 acres. The powerhouse has two hydro turbine generators
with an average capacity of 18 MW. These generators were placed in service in
1925.
Deep Creek has three major components: a dam and reservoir, a water conduit
system and a powerhouse with two turbine-generator units and associated
equipment. The reservoir has a normal water elevation of 2,461 ft and is
impounded by an earthfill dam with a crest elevation of 2,475 ft. The dam
contains a concrete core wall with a top elevation at 2,467 ft. A long overflow
weir at the right abutment of the dam, oriented perpendicular to the dam axis
serves as the flood discharge control structure. Water that flows over this weir
passes over a secondary weir located downstream from the primary weir and then
into the natural channel downstream.
The following table summarizes the plant characteristics.
=================================================================================================================
DEEP CREEK CHARACTERISTICS SUMMARY
=================================================================================================================
ITEM UNIT 1 UNIT 2
-----------------------------------------------------------------------------------------------------------------
HYDROELECTRIC TURBINE
-----------------------------------------------------------------------------------------------------------------
Manufacturer Allis-Chalmers Allis-Chalmers
-----------------------------------------------------------------------------------------------------------------
Type Francis-type Francis-type
-----------------------------------------------------------------------------------------------------------------
Commissioned (year) 1925 1925
-----------------------------------------------------------------------------------------------------------------
Capacity (MW) 9 9
-----------------------------------------------------------------------------------------------------------------
MISCELLANEOUS
-----------------------------------------------------------------------------------------------------------------
Penstocks Dam includes two penstocks
-----------------------------------------------------------------------------------------------------------------
Dam Earth and rockfill dam
-----------------------------------------------------------------------------------------------------------------
Water conduit Includes a power intake with vertical slide gate, horseshoe tunnel,
and surge tank, Johnson-type inlet valve, and a labyrinth overflow
weir in the tailrace channel for aeration
=================================================================================================================
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- --------------------------------------------------------------------------------
3. PLANT PERFORMANCE
This section provides details on the historical and projected performance of the
electric generating stations owned by REMA. The major subsections are as
follows:
o Definitions
o Projected Performance
The historical performance of the facilities is shown 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 type of fuel fired. The most recent NERC plant data available is from
1999.
The key performance parameters include capacity factors, equivalent
availability, forced outage factors, and average heat rates.
3.1 DEFINITIONS
The following definitions were used for the performance factors in this report:
o CAPACITY FACTOR ("CF") - The ratio of the actual net generation to the
normal claimed capacity operating for 8760 hours/year.
o HEAT RATE (Btu/kWh) - The ratio of the heat input (based on the higher
heating value of fuel) and the net unit output (measured on the low
voltage side of the main transformers).
o 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 rated generation.
o FORCED OUTAGE FACTOR ("FOF") - The ratio of forced outages hours to
period hours.
A major difference between equivalent availability and forced outage factor is
that availability includes outages and planned overhauls while forced outage
factor is not affected by planned overhauls.
In reviewing the reasonableness of the projected performance, the key factors
are the capacity factor and the heat rate. The capacity factor is an indication
of the quantity of electricity generated by the unit. The projected capacity
factors are compared against recent historical capacity factors, both for the
unit and for the class of technology.
In reviewing the historical performance of electric generating units, the
reliability of the units is generally evaluated by looking at the EAF and FOF
values. The EAF is an indication of the ability of a unit to generate
electricity regardless of whether it is dispatched. The FOF is an indication of
the degree to which the unit was limited during operation by forced outages. The
availability and forced outage data are inputs into Hagler Bailly's market
forecast model.
The heat rate is also a key input to Hagler Bailly's market model and is
important in determining how often the unit is dispatched. The "full load" heat
rate is used in Hagler Bailly's market model. Electric generating units usually
have the lowest heat rates at full load. If a unit is run at partial loads, then
the heat rate can be expected to be higher. Hagler Bailly's model uses the
partial and full load heat rates to develop a heat rate curve, which allows heat
rates to be calculated at different loads.
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- --------------------------------------------------------------------------------
Stone & Webster has reviewed the availability, forced outage, and heat rate data
used by Hagler Bailly and conclude that they are reasonable.
The heat rate of simple cycle CTs is typically very high and is not ordinarily
the basis for their dispatch. These low dispatch units are operated last to meet
peak system demand, or for unique area demand requirements. In a competitive
market, the bid price for peak power can be very high, and the profitability of
peaking units is determined in large part by their availability to respond to
peak demand dispatch requirements.
This section discusses the current capacity of the units and any existing
capacity reratings in place or which may occur in the future.
3.2 PROJECTED PERFORMANCE
The historical performance data for the Facilities was obtained during our
recent site visits. The historical data was updated based on information
received from the operating staff at each station. The projected performance for
the period 2000 to 2020 was obtained from the market forecast developed by
Hagler Bailly. It was assumed that the projected performance for those units
that operate after 2020 would be consistent with how they operated in the past.
Therefore, the market forecast was extended by using the 2020 results through
the projected retirement dates. REMA has included in the budget an adequate
amount to keep the stations operating reliably through the projected retirement
dates.
3.2.1 CONEMAUGH STATION
Units 1 and 2 were built with positive pressure boilers, which were converted to
a balanced draft system to improve availability and housekeeping efforts.
Availability was improved by the reduction of tube failures due to erosion,
which caused tube leaks and resulted in forced outages. The following table
summarizes the historical and projected performance data for Conemaugh. The
projected performance is shown for the period 2000 through 2020 and is based on
the output from the Hagler Bailly market analysis model. The market forecast was
extended by using the 2020 results through the projected retirement date. Stone
& Webster has reviewed the key technical inputs from this model and found them
to be reasonable.
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- --------------------------------------------------------------------------------
================================================================================================================
CONEMAUGH HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999)(1) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit Class Unit Unit Unit
Average Maximum Minimum Average Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 85.4 94.3 71.2 71.3 84.28 84.82 82.12
- ----------------------------------------------------------------------------------------------------------------
Unit 2 79.6 92.7 67.8 71.3 81.68 83.11 80.58
- ----------------------------------------------------------------------------------------------------------------
HEAT RATE (Btu/kWh)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 9,642 9,783 9,447
- ----------------------------------------------------------------------------------------------------------------
Unit 2 9,425 9,491 9,322
- ----------------------------------------------------------------------------------------------------------------
EAF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 87.9 96.7 78.6 85.6 84.8
- ----------------------------------------------------------------------------------------------------------------
Unit 2 84.4 95.6 73.4 85.6 84.8
- ----------------------------------------------------------------------------------------------------------------
FOF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 6.7 12.2 2.5 3.8 3.7
- ----------------------------------------------------------------------------------------------------------------
Unit 2 6.0 10.7 2.0 3.8 3.7
================================================================================================================
(1) NERC GADS Classes are: 800-999 MW coal-fired units (25 units with an
average age of 20 years)
A review of the performance data indicates that both units are performing well.
In 1998, Conemaugh achieved a record net generation of 13,167 GWH while
operation and maintenance ("O&M") and capital expenditures were below budget.
Both units are essentially base loaded, which tends to keep heat rate at its
optimum condition. The heat rate has increased since the installation of an FGD
system on both units in 1994 and 1995, respectively, which is typical. This
system removes SO(2) from the flue gas exiting the boiler but increases the
station service load, which adversely effects the heat rate. The increase in
heat rate is typically found when an FGD is installed.
Both units have generally been operated and maintained in a manner reflective of
good utility practices. The station personnel are a mature staff with many years
of experience and appear motivated to improve the performance of their units.
The problem of outages due to tube failures is being addressed by the use of
chromized waterwall tubing.
The planned installation of a selective catalytic reducer ("SCR") on Units 1 and
2 will also slightly impact the heat rate because of the additional fan motor
horsepower required to overcome the pressure drop through the SCR system and the
addition of an electric vaporizer.
Personnel are evaluating a new performance system (Honeywell), which will
directly connect to the existing boiler/turbine control system and will provide
real-time heat rate information to the control system and the operators.
Based on a review of the in-house predictive and preventive maintenance programs
and the emphasis given to improving efficiency and the economy of the plant,
future goals are attainable.
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- --------------------------------------------------------------------------------
The future capacity factors are consistent with the historical capacity factors.
3.2.2 KEYSTONE STATION
The two coal burning units at Keystone were placed in service with positive
pressure boilers, but were converted to a balanced draft system in the
mid-eighties. The following table summarizes the historical and projected
performance data for Keystone. The projected performance is shown for the period
2000 through 2020 based on the output from the Hagler Bailly market analysis
model. The market forecast was extended by using the 2020 results through the
projected retirement date. Stone & Webster has reviewed the key technical inputs
from this model and found them to be reasonable.
================================================================================================================
KEYSTONE HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999)(1) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit Class Unit Unit Unit
Average Maximum Minimum Average Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 84.7 96.2 69.7 71.3 82.06 83.76 79.20
- ----------------------------------------------------------------------------------------------------------------
Unit 2 87.0 94.7 77.0 71.3 77.72 80.43 76.70
- ----------------------------------------------------------------------------------------------------------------
HEAT RATE (Btu/kWh)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 9,405 9,512 9,327
- ----------------------------------------------------------------------------------------------------------------
Unit 2 9,536 9,702 9,461
- ----------------------------------------------------------------------------------------------------------------
EAF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 88.2 97.7 76.4 85.6 84.8
- ----------------------------------------------------------------------------------------------------------------
Unit 2 90.8 97.0 81.9 85.6 84.8
- ----------------------------------------------------------------------------------------------------------------
FOF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 2.4 4.1 0.4 3.8 3.7
- ----------------------------------------------------------------------------------------------------------------
Unit 2 3.3 4.9 2.2 3.8 3.7
================================================================================================================
(1) NERC GADS Classes are: 800-999 MW coal-fired units (25 units with an
average age of 20 years)
A review of the performance data indicates that the performance of the units is
consistent with their age. There has been a steady improvement in heat rate from
1992-1997. Both units have generally been operated and maintained in a manner
reflective of good utility practices.
The station personnel are a mature staff with many years of experience and
appear motivated to improve the performance of those units. The problem of
outages due to tube failures is being addressed by the use of chromized
waterwall tubing.
The planned addition of an SCR in 2003 will affect the heat rate due to the
increased auxiliary power consumption. Increased fan load will be required to
accommodate the pressure drop of this system. The electric vaporizer will also
require load. The additional costs associated with the SCR in 2003 have been
included in the financial projections.
The future capacity factors are slightly lower than the historical capacity
factors and therefore they are readily achievable.
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REMA INDEPENDENT TECHNICAL REVIEW
- --------------------------------------------------------------------------------
3.2.3 SHAWVILLE STATION
Units 1 through 4 are coal-fired units designed for base load operation. The
following table summarizes the historical and projected performance data for
Shawville. The projected performance is shown for the period 2000 through 2020
based on the output from the Hagler Bailly market analysis model. The market
forecast was extended by using the 2020 results through the projected retirement
date. Stone & Webster has reviewed the key technical inputs from this model and
found them to be reasonable.
================================================================================================================
SHAWVILLE HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999)(1) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit Class Unit Unit Unit
Average Maximum Minimum Average Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 68.0 78.8 58.2 57.6 56.03 60.79 53.13
- ----------------------------------------------------------------------------------------------------------------
Unit 2 66.5 78.6 55.8 57.6 56.03 60.79 53.13
- ----------------------------------------------------------------------------------------------------------------
Unit 3 72.1 77.5 65.2 57.6 75.48 80.06 70.33
- ----------------------------------------------------------------------------------------------------------------
Unit 4 67.0 77.1 54.3 57.6 75.58 79.80 70.52
- ----------------------------------------------------------------------------------------------------------------
Unit 5 4.62 7.31 3.19
- ----------------------------------------------------------------------------------------------------------------
HEAT RATE (Btu/kWh)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 10,722 10,864 10,592
- ----------------------------------------------------------------------------------------------------------------
Unit 2 10,753 10,917 10,635
- ----------------------------------------------------------------------------------------------------------------
Unit 3 10,097 10,215 10,022
- ----------------------------------------------------------------------------------------------------------------
Unit 4 10,129 10,456 9,911
- ----------------------------------------------------------------------------------------------------------------
EAF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 85.8 93.0 73.3 84.4 83.7
- ----------------------------------------------------------------------------------------------------------------
Unit 2 87.1 96.4 72.3 84.4 83.7
- ----------------------------------------------------------------------------------------------------------------
Unit 3 86.4 91.9 75.5 84.4 83.7
- ----------------------------------------------------------------------------------------------------------------
Unit 4 81.2 91.0 66.8 84.4 83.7
- ----------------------------------------------------------------------------------------------------------------
FOF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 7.0 11.2 2.9 3.2 4.0
- ----------------------------------------------------------------------------------------------------------------
Unit 2 2.6 3.9 0.4 3.2 4.0
- ----------------------------------------------------------------------------------------------------------------
Unit 3 4.4 10.0 2.2 3.2 4.0
- ----------------------------------------------------------------------------------------------------------------
Unit 4 7.0 10.1 4.6 3.2 4.0
================================================================================================================
(1) NERC GADS Classes are: 100-199 MW coal-fired units (70 units with an
average age of 38 years)
A review of the performance data and discussion with plant personnel indicate
that emphasis has been on improving availability and heat rate. Repairs and
replacement of equipment have been performed on a regular basis. Continued
replacement of waterwall sections with chromized tubing will reduce outages for
repair and improve all performance factors. The proposed installation of a
selective non-catalytic reducer ("SNCR") system would cause a slight increase in
heat rate.
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- --------------------------------------------------------------------------------
The future capacity factors are similar to the historic capacity factors and
should be achievable given the projected O&M expenses.
3.2.4 SEWARD STATION
The following table summarizes the historical and projected performance data for
Seward. The projected performance is shown for the period 2000 through 2010
based on the output from the Hagler Bailly market analysis model. Stone &
Webster has reviewed the key technical inputs from this model and found them to
be reasonable.
================================================================================================================
SEWARD HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999)(1) (2000 - 2010)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit Class Unit Unit Unit
Average Maximum Minimum Average Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 44.9 61.0 20.4 40.0 38.04 40.30 36.22
- ----------------------------------------------------------------------------------------------------------------
Unit 5 67.4 79.2 50.3 57.6 66.50 70.41 64.22
- ----------------------------------------------------------------------------------------------------------------
HEAT RATE (Btu/kWh)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 14,332 15,088 13,790
- ----------------------------------------------------------------------------------------------------------------
Unit 5 10,414 10,688 10,186
- ----------------------------------------------------------------------------------------------------------------
EAF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 86.2 92.7 78.3 85.9 83.8
- ----------------------------------------------------------------------------------------------------------------
Unit 5 79.9 90.1 71.2 84.8 84.5
- ----------------------------------------------------------------------------------------------------------------
FOF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 1.1 3.3 0.0 3.1 3.1
- ----------------------------------------------------------------------------------------------------------------
Unit 5 10.1 20.2 6.1 3.2 3.2
================================================================================================================
(1) NERC GADS Classes are: 1-99 MW coal-fired units (45 units with an average
age of 39 years) for Unit 4 and 100-199 MW coal-fired units (70 units with
an average age of 38 years) for Unit 5.
A review of the recent historical data shows a decline in the performance of the
units. This is largely the result of the deferral of capital expenditures by the
prior owner. REMA has budgeted over the next ten years $7.17 million and $10.8
million for Units 4 and 5, respectively for life extension of these units
through 2010. These budgeted amounts are sufficient to keep these units
operating with the performance characteristics as projected in the financial
model.
The future capacity factors are slightly less than the historic values and can
be achieved based on the projected O&M expenses.
3.2.5 SAYREVILLE STATION
A summary of the historical and projected performance for the steam units (Units
4 and 5) and for the combustion turbine units (Units C-1 through C-4) at
Sayreville are shown in the following tables. The projected performance is shown
for the period 2000 through 2010 for the steam units and 2000 through 2020 for
the combustion turbine units based on the output from the Hagler Bailly market
analysis model.
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- --------------------------------------------------------------------------------
The market forecast for the combustion turbine units was extended by using the
2020 results through the projected retirement date. Stone & Webster has reviewed
the key technical inputs from this model and found them to be reasonable.
================================================================================================================
SAYREVILLE HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999)(1) (2000 - 2010)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit Class Unit Unit Unit
Average Maximum Minimum Average Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 3.4 6.8 1.8 25.4 8.42 9.58 7.36
- ----------------------------------------------------------------------------------------------------------------
Unit 5 4.2 8.9 1.5 25.4 8.42 9.58 7.36
- ----------------------------------------------------------------------------------------------------------------
HEAT RATE (Btu/kWh)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 13,318 14,088 12,695
- ----------------------------------------------------------------------------------------------------------------
Unit 5 14,156 17,229 12,624
- ----------------------------------------------------------------------------------------------------------------
EAF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 84.6 96.2 72.1 83.9 83.3
- ----------------------------------------------------------------------------------------------------------------
Unit 5 95.0 99.6 84.1 83.9 83.3
- ----------------------------------------------------------------------------------------------------------------
FOF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 12.1 24.3 3.3 3.7 9.0
- ----------------------------------------------------------------------------------------------------------------
Unit 5 2.8 6.2 0.0 3.7 9.0
================================================================================================================
(1) NERC GADS Classes are: 100-199 MW gas-fired units (57 units with an average
age of 36 years).
The historical forced outage factor at Unit 4 is high because of an extensive
delay in a decision to repair the boiler. The Unit 4 boiler required several
lower furnace tubes to be repaired and replaced during January of 1999. Sithe
delayed these repairs while deciding whether to make repairs or to discontinue
operation of the unit. REMA has budgeted funds to account for future boiler
repairs that are sufficient to meet the financial projections.
Due to the weakened condition of the boiler tubes, the main steam pressure and
temperature operating conditions have been reduced. The pressure was reduced
from 2250 psi to 1700 psi and the temperature was reduced from 1000 degrees F to
800 degrees F. The reduced steam condition has improved the reliability of the
units, however the heat rate has increased.
The future capacity factors are higher than the historic capacity factors. These
units will be in service about six weeks per year rather than three weeks per
year. The plant staff will need to monitor the condition of these units to
achieve the higher capacity factors.
The current operating plan calls for these units to be operated only during the
peak load season, which is mostly during the hot weather and for transmission
support.
The capacity rating at Units 4 and 5 have historically been 117 MW net. However,
reductions in boiler pressure and operating temperatures have lowered the
current output ratings to 90 and 95 MW (net) for Units 4 and 5, respectively.
The historical output ratings could be restored if the boiler tubes were
replaced including the furnace screen tubes with hydrogen embrittlement.
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- --------------------------------------------------------------------------------
A summary of the historical and projected performance for the CTs at Sayreville
is shown in the following table.
================================================================================================================
SAYREVILLE CTS HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
1995 1996 1997 1998 1999 Unit Unit Unit
Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 1.09 0.81 1.42 1.94 1.33 7.51 9.77 5.75
- ----------------------------------------------------------------------------------------------------------------
Unit 2 1.08 0.00 0.15 1.43 1.36 7.51 9.77 5.75
- ----------------------------------------------------------------------------------------------------------------
Unit 3 1.22 0.17 1.02 1.29 1.50 7.51 9.77 5.75
- ----------------------------------------------------------------------------------------------------------------
Unit 4 1.10 0.00 1.09 1.85 1.15 7.51 9.77 5.75
- ----------------------------------------------------------------------------------------------------------------
EQUIVALENT AVAILABILITY(%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 35.35 86.83 96.04 99.24 99.82
- ----------------------------------------------------------------------------------------------------------------
Unit 2 95.06 91.15 66.59 96.46 99.75
- ----------------------------------------------------------------------------------------------------------------
Unit 3 80.63 91.88 94.95 97.92 99.93
- ----------------------------------------------------------------------------------------------------------------
Unit 4 98.21 52.34 94.65 97.35 99.36
================================================================================================================
These future capacity factors are higher than the historic capacity factors.
There is sufficient O&M expense budgeted to achieve this increase.
For C-1, C-2, C-3, and C-4 the cumulative starts and operating hours since 1988
are estimated to average less than 50 starts and 500 service hours per year. The
historical operating availability has been variable over the life of the units
and appears to be improving in recent years. The operating record is average for
standby reserve peaking units.
3.2.6 PORTLAND STATION
A summary of the historical and projected performance for steam units at
Portland is shown in the following table. The projected performance is shown for
the period 2000 through 2020 and outputs from the Hagler Bailly market analysis
model. The market forecast was extended by using the 2020 results through the
projected retirement date. Stone & Webster has reviewed the key technical inputs
from this model and found them to be reasonable.
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- --------------------------------------------------------------------------------
================================================================================================================
PORTLAND HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999)(1) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit Class Unit Unit Unit
Average Maximum Minimum Average Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 54.5 60.3 47.9 57.6 65.95 69.62 64.10
- ----------------------------------------------------------------------------------------------------------------
Unit 2 48.2 56.4 32.8 63.2 67.43 72.89 64.66
- ----------------------------------------------------------------------------------------------------------------
HEAT RATE (Btu/kWh)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 10,595 10,776 10,428
- ----------------------------------------------------------------------------------------------------------------
Unit 2 10,032 10,364 9,802
- ----------------------------------------------------------------------------------------------------------------
EAF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 89.6 97.8 80.7 84.8 83.5
- ----------------------------------------------------------------------------------------------------------------
Unit 2 82.6 90.2 74.1 83.8 83.5
- ----------------------------------------------------------------------------------------------------------------
FOF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 4.7 9.5 1.7 3.2 4.0
- ----------------------------------------------------------------------------------------------------------------
Unit 2 8.4 11.6 2.6 4.0 4.0
================================================================================================================
(1) NERC GADS Classes are: 100-199 MW coal-fired units (70 units with an
average age of 38 years) for Unit 1 and 200-299 MW coal-fired units (50
units with an average age of 33 years) for Unit 2.
The future capacity factors are higher than the historic capacity factors but
appear achievable.
A summary of the historical and projected performance for CTs at Portland is
shown in the following table.
================================================================================================================
PORTLAND HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
1995 1996 1997 1998 1999 Unit Unit Unit
Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Units 3 1.35 0.67 0.84 0.92 1.21 4.97 5.00 4.70
- ----------------------------------------------------------------------------------------------------------------
Unit 4 1.73 1.15 1.14 1.10 1.38 5.00 5.00 4.99
- ----------------------------------------------------------------------------------------------------------------
Unit 5 NA NA NA 8.67 2.02 24.48 28.94 20.29
- ----------------------------------------------------------------------------------------------------------------
EQUIVALENT AVAILABILITY (%)
- ----------------------------------------------------------------------------------------------------------------
Units 3 94.77 91.96 99.19 99.22 95.08
- ----------------------------------------------------------------------------------------------------------------
Unit 4 99.19 100.00 97.59 97.43 99.96
- ----------------------------------------------------------------------------------------------------------------
Unit 5 NA NA NA 65.99 39.46
================================================================================================================
NA - Not Applicable
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- --------------------------------------------------------------------------------
These future capacity factors are higher than the historic capacity factors.
There is sufficient O&M expense budgeted to achieve this increase.
The cumulative starts and operating hours since 1992 for Unit 3 are less than
300 starts and 1,000 hours, respectively. The Unit 3 operating record is average
for standby reserve peaking units but has improved during 1998-1999.
The cumulative starts and operating hours since 1992 for Unit 4 are less than
250 starts and 1,000 hours, respectively. Recent starting reliability and unit
availability have been an excellent 100%. The Unit 4 operating record is above
average for standby reserve peaking units, and has been excellent during
1998-1999.
Unit 5 is very efficient in simple cycle operation. The unit records indicate
1,200 operating hours during 1998 and 1999 with an availability of only 53%. Due
to the first of a kind advanced technology, the Unit 5 operating results are
considered poor; however, improvements are to be expected. Stone & Webster did
not identify any near term unresolved performance problems. Unit 5 has
experienced 242 starts and 1,203 service hours during 1998-99. It also
experienced 27 unplanned outages during this period, 22 of which were forced
outages.
Based on past operating history and assuming continual predictive and preventive
maintenance programs, future goals are attainable.
3.2.7 TITUS STATION
A summary of the historical and projected performance for generating units at
Titus is shown in the following table. The projected performance is shown for
the period 2000 through 2020 based on the output from the Hagler Bailly market
analysis model. The market forecast was extended by using the 2020 results
through the projected retirement date. Stone & Webster has reviewed the key
technical inputs from this model and found them to be reasonable.
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- --------------------------------------------------------------------------------
================================================================================================================
TITUS HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999)(1) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit Class Unit Unit Unit
Average Maximum Minimum Average Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 53.6 58.6 45.0 25.4 61.50 66.27 58.49
- ----------------------------------------------------------------------------------------------------------------
Unit 2 54.4 57.3 48.1 25.4 62.33 66.92 59.93
- ----------------------------------------------------------------------------------------------------------------
Unit 3 53.2 60.0 46.5 25.4 62.29 66.95 59.11
- ----------------------------------------------------------------------------------------------------------------
HEAT RATE (Btu/kWh)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 10,628 10,898 10,271
- ----------------------------------------------------------------------------------------------------------------
Unit 2 10,650 10,863 10,402
- ----------------------------------------------------------------------------------------------------------------
Unit 3 10,846 11,179 10,491
- ----------------------------------------------------------------------------------------------------------------
EAF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 92.4 98.8 79.4 83.9 83.6
- ----------------------------------------------------------------------------------------------------------------
Unit 2 92.6 98.9 77.7 83.9 83.6
- ----------------------------------------------------------------------------------------------------------------
Unit 3 90.6 99.6 81.7 83.9 83.6
- ----------------------------------------------------------------------------------------------------------------
FOF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 0.8 1.6 0.2 3.7 3.3
- ----------------------------------------------------------------------------------------------------------------
Unit 2 0.7 1.6 0.0 3.7 3.3
- ----------------------------------------------------------------------------------------------------------------
Unit 3 1.0 2.6 0.0 3.7 3.3
================================================================================================================
(1) NERC GADS Classes are: 100-199 MW gas-fired units (57 units with an average
age of 36 years).
The future capacity factors are slightly higher than the historic capacity
factors. There is sufficient O&M expense budgeted to achieve this increase.
The key technical inputs to the market model were reviewed and found to be
reasonable by Stone & Webster. The Titus units have a significantly low forced
outage factor due to the plant design and the operation and maintenance
practices. This high reliability has been consistently achieved year after year.
The plant staff was found to be well trained and highly motivated.
The Titus plant has a performance monitoring system that compares ten operating
parameters with their optimum value. It converts the deviation in the parameter
to an equivalent heat rate and fuel cost value to assist the operator in
maintaining the lowest possible heat rate.
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- --------------------------------------------------------------------------------
A summary of the historical and projected performance for the CTs at Titus is
shown in the following table.
================================================================================================================
TITUS CTS HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit
1995 1996 1997 1998 1999 Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 1.05 0.5 0.85 1.3 2.1 3.75 5.04 2.61
- ----------------------------------------------------------------------------------------------------------------
Unit 5 1.24 0.62 0.73 1.4 1.8 3.75 5.04 2.61
- ----------------------------------------------------------------------------------------------------------------
EQUIVALENT AVAILABILITY(%)
- ----------------------------------------------------------------------------------------------------------------
Unit 4 99.28 94.81 100 99.8 99.3
- ----------------------------------------------------------------------------------------------------------------
Unit 5 99.62 99.26 99.76 100 99.0
================================================================================================================
The Unit 4 and 5 cumulative starts and operating hours since 1992, are less than
300 starts and 2,000 hours and 300 starts and 3,500 hours, respectively. The
Unit 4 and 5 operating availability has been excellent in recent years and
starting reliability has been very good. The Units 4 and 5 operating record has
been above average for standby reserve peaking units.
The future capacity factors are higher than the historic capacity factors. There
is sufficient O&M expense budgeted to achieve this increase.
3.2.8 WARREN STATION
A summary of the historical and projected performance for the steam units (Units
1 and 2) and the combustion turbine unit (Unit 3) at Warren are shown in the
following tables. The projected performance is shown for the period 2000 through
2010 for the steam units and 2000 through 2020 for the combustion turbine unit
based on the output from the Hagler Bailly market analysis model. The market
forecast for the combustion turbine unit was extended by using the 2020 results
through the projected retirement date. Stone & Webster has reviewed the key
technical inputs from this model and found them to be reasonable.
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- --------------------------------------------------------------------------------
================================================================================================================
WARREN HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1996 - 1998)(1) (2000 - 2010)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit Class Unit Unit Unit
Average Maximum Minimum Average Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 35.4 36.8 33.6 40.0 28.65 30.84 26.39
- ----------------------------------------------------------------------------------------------------------------
Unit 2 43.5 46.4 38.5 40.0 28.65 30.84 26.39
- ----------------------------------------------------------------------------------------------------------------
HEAT RATE (Btu/kWh)v
- ----------------------------------------------------------------------------------------------------------------
Unit 1 14,903 15,168 14,472
- ----------------------------------------------------------------------------------------------------------------
Unit 2 14,485 14,524 14,446
- ----------------------------------------------------------------------------------------------------------------
EAF (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 1 72.9 76.6 70.7 85.9 80.4
- ----------------------------------------------------------------------------------------------------------------
Unit 2 93.5 95.3 92.4 85.9 80.4
================================================================================================================
(1) NERC GADS Classes are: 1-99 MW coal-fired units (45 units with an average
age of 39 years)
The future capacity factors are less than the historic capacity factors and are
therefore readily achievable.
The Warren units were scheduled by GPU for retirement in 2002, therefore major
maintenance had been deferred. However, REMA has budgeted funds sufficient to
enable the plant to meet the financial projections through the retirement date.
A summary of the historical and projected performance for the CT at Warren is
shown in the following table.
================================================================================================================
WARREN CT'S HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
1995 1996 1997 1998 1999 Unit Unit Unit
Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Unit 3 0.96 2.72 1.6 5.00 5.00 4.99
- ----------------------------------------------------------------------------------------------------------------
EQUIVALENT AVAILABILITY(%)
- ----------------------------------------------------------------------------------------------------------------
Unit 3 97.31 93.46 96.18
================================================================================================================
The annual cumulative starts and operating hours for CT 3 since the last major
inspection have been typical of other Westinghouse 501 peaking units. The
history of operating availability and starting reliability has been generally
good. The CT 3 operating record is average for standby reserve peaking units.
The future capacity factors are higher than the historic capacity factors. There
is sufficient O&M expense budgeted to achieve this increase.
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3.2.9 GILBERT STATION
A summary of the historical and projected performance for the combined cycle
units at Gilbert is shown in the following table. The projected performance is
shown for the period 2000 through 2020 based on the output from the Hagler
Bailly market analysis model. The market forecast was extended by using the 2020
results through the projected retirement date. Stone & Webster has reviewed the
key technical inputs from this model and found them to be reasonable.
=====================================================================================================
GILBERT HISTORICAL AND PROJECTED PERFORMANCE
=====================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1993 - 1997) (2000 - 2020)
- -----------------------------------------------------------------------------------------------------
Unit Unit Unit Unit Unit Unit
Average Maximum Minimum Average Maximum Minimum
- -----------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- -----------------------------------------------------------------------------------------------------
CC4 13.46 15.28 7.54 8.78 11.09 6.29
- -----------------------------------------------------------------------------------------------------
CC5 13.69 16.92 7.96 8.78 11.09 6.29
- -----------------------------------------------------------------------------------------------------
CC6 14.15 16.77 7.89 8.78 11.09 6.29
- -----------------------------------------------------------------------------------------------------
CC7 14.11 17.73 8.14 8.78 11.09 6.29
- -----------------------------------------------------------------------------------------------------
CC8 11.99 16.16 5.94 17.89 21.05 15.50
- -----------------------------------------------------------------------------------------------------
EQUIVALENT AVAILABILITY (%)
- -----------------------------------------------------------------------------------------------------
CC4 90.45 98.45 73.09
- -----------------------------------------------------------------------------------------------------
CC5 86.92 93.92 77.90
- -----------------------------------------------------------------------------------------------------
CC6 91.33 98.04 80.53
- -----------------------------------------------------------------------------------------------------
CC7 93.30 97.52 84.37
- -----------------------------------------------------------------------------------------------------
CC8 83.09 91.20 74.83
=====================================================================================================
The future capacity factors for the combined cycle units in aggregate are
comparable to the historic capacity factors and should be readily achievable.
The operating availability history has been good over the life of the combined
cycle units, CC4, CC5, CC6, and CC7, and was very good in 1999. The CC4, CC5,
CC6, and CC7 unit availability was excellent in 1998 and 1999 with each unit
exceeding 94% in both years. Similarly, starting reliability exceeded 93% for
all units. CC4 and CC7 achieved 100% starting reliability in 1998. The water
injection systems can affect availability if not managed properly, however, no
water-related problems were noted and reliable operation is expected to
continue. The operating record is good.
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- --------------------------------------------------------------------------------
A summary of the historical and projected performance for the simple cycle units
at Gilbert is shown in the following table.
================================================================================================================
GILBERT CT'S HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1998) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit
1995 1996 1997 1998 Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
C-1 0.72 0.23 0.43 0.58 7.47 9.68 5.57
- ----------------------------------------------------------------------------------------------------------------
C-2 1.11 0.09 0.38 0.57 7.47 9.68 5.57
- ----------------------------------------------------------------------------------------------------------------
C-3 1.31 0.50 0.54 0.77 7.47 9.68 5.57
- ----------------------------------------------------------------------------------------------------------------
C-4 1.24 0.30 0.55 0.80 7.47 9.68 5.57
- ----------------------------------------------------------------------------------------------------------------
CT 9 NA NA 4.36 5.20 7.76 10.06 5.81
- ----------------------------------------------------------------------------------------------------------------
EQUIVALENT AVAILABILITY (%)
- ----------------------------------------------------------------------------------------------------------------
C-1 77.94 96.19 97.15 99.98
- ----------------------------------------------------------------------------------------------------------------
C-2 93.63 91.97 99.99 99.70
- ----------------------------------------------------------------------------------------------------------------
C-3 96.53 98.48 99.97 100.00
- ----------------------------------------------------------------------------------------------------------------
C-4 91.02 99.57 100.00 100.00
- ----------------------------------------------------------------------------------------------------------------
CT 9 NA NA 52.51 88.14
================================================================================================================
NA - Not Applicable
The future capacity factors are higher than the historic capacity factors. There
is sufficient O&M expense budgeted to achieve this increase.
The cumulative effect of starts and operating hours since the simple cycle
units', C-1, C-2, C-3, and C-4, most recent major inspection is measured in
terms of equivalent operating hours ("EOH"). The EOH accumulated by C-1, C-2,
C-3, and C-4 is 928, 1,880, 1,411, and 2,201, respectively. The historical
operating availability has been variable over the life of the units and now
appears to be improving significantly. Availability of all units was excellent
in 1999 with each unit exceeding 99.5%. Similarly, starting reliability exceeded
95% for all units. C-3 achieved 100% starting reliability in 1999. The water
injection systems can affect availability if not managed properly, however, no
water-related problems were noted and reliable operation is expected to
continue. The operating record is good for standby reserve peaking units.
3.3 COMBUSTION TURBINES
A summary of the historical and projected performance for the CTs is shown in
the following table. The projected performance is shown for the period 2000
through 2020 based on the output from the Hagler Bailly market analysis model.
The market forecast was extended by using the 2020 results through the projected
retirement date. Stone & Webster has reviewed the key technical inputs from this
model and found them to be reasonable.
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- --------------------------------------------------------------------------------
================================================================================================================
COMBUSTION TURBINES HISTORICAL AND PROJECTED PERFORMANCE
================================================================================================================
HISTORICAL PERFORMANCE PROJECTED PERFORMANCE
(1995 - 1999)(1) (2000 - 2020)
- ----------------------------------------------------------------------------------------------------------------
Unit Unit Unit
1995 1996 1997 1998 1999 Average Maximum Minimum
- ----------------------------------------------------------------------------------------------------------------
CAPACITY FACTOR (%)
- ----------------------------------------------------------------------------------------------------------------
Blossburg Unit 1 <1.0 <1.0 <1.0 <1.0 <1.0 0.52 1.21 0.08
- ----------------------------------------------------------------------------------------------------------------
Glen Gardner Units 1-8 <1.0 <1.0 <1.0 <1.8 <1.7 7.00 9.97 3.56
- ----------------------------------------------------------------------------------------------------------------
Hamilton Unit 1 <1.0 <1.0 <1.0 <3.4 2.68 1.95 2.79 1.34
- ----------------------------------------------------------------------------------------------------------------
Hunterstown Unit 1-3 <1.0 <1.0 <1.0 <3.9 <2.9 5.41 8.01 4.33
- ----------------------------------------------------------------------------------------------------------------
Mountain Units 1-2 <1.0 <1.0 <1.0 <4.2 <3.9 5.57 8.74 3.31
- ----------------------------------------------------------------------------------------------------------------
Orrtanna Unit 1 <1.0 <1.0 <1.0 3.2 2.6 1.95 2.79 1.34
- ----------------------------------------------------------------------------------------------------------------
Shawnee Unit 1 <1.0 <1.0 <1.0 <1.5 1.1 0.00 0.01 0.00
- ----------------------------------------------------------------------------------------------------------------
Tolna Units 1-2 <1.0 <1.0 <1.0 <2.9 <1.9 1.69 2.79 1.01
- ----------------------------------------------------------------------------------------------------------------
Wayne Unit 1 <1.0 <1.0 <1.0 2.0 1.1 2.35 4.19 1.47
- ----------------------------------------------------------------------------------------------------------------
Werner Unit 1-4 <1.0 <1.0 <1.0 <1.4 <1.0 2.35 4.19 1.47
- ----------------------------------------------------------------------------------------------------------------
EQUIVALENT AVAILABILITY (%)
- ----------------------------------------------------------------------------------------------------------------
Blossburg Unit 1 96.70 98.11
- ----------------------------------------------------------------------------------------------------------------
Glen Gardner Units 1-8 95.33 97.73 98.42 96.95 97.43
- ----------------------------------------------------------------------------------------------------------------
Hamilton Unit 1 78.19 98.32 98.83 99.30 99.88
- ----------------------------------------------------------------------------------------------------------------
Hunterstown Unit 1-3 96.14 83.89 99.11 96.37 95.13
- ----------------------------------------------------------------------------------------------------------------
Mountain Units 1-2 97.45 98.46 88.93 99.13 94.38
- ----------------------------------------------------------------------------------------------------------------
Orrtanna Unit 1 98.28 98.65 97.58 95.47 98.34
- ----------------------------------------------------------------------------------------------------------------
Shawnee Unit 1 97.89 100 99.69 100 100
- ----------------------------------------------------------------------------------------------------------------
Tolna Units 1-2 98.69 98.06 99.4 98.44 97.81
- ----------------------------------------------------------------------------------------------------------------
Wayne Unit 1 96.74 97.25
- ----------------------------------------------------------------------------------------------------------------
Werner Unit 1-4 45.45 74.05 99.46 99.09 71.64
================================================================================================================
These future capacity factors are higher than the historic capacity factors.
There is sufficient O&M expense budgeted to achieve this increase.
Starting reliability and operating availability have been very good and have
improved further during 1998-99. All units have demonstrated significant
starting reliability improvement during 1998-1999. The operating record is above
average for standby reserve peaking units. The units have accumulated fewer than
1,000 starts and less than 5,000 service hours since last major inspection
(1990-1993).
3.3.1 PINEY STATION
Piney operates in a peaking mode whenever there is insufficient water for full
time operation at full load. The historical and projected average annual energy
outputs, representative capacities and indicated capacity factors are included
in the following table. The projected performance is shown for the period 2000
through 2020 and is a combination of inputs and outputs from the Hagler Bailly
market analysis model. The market forecast was extended by using the 2020
results through the projected retirement date. Stone & Webster has reviewed the
key technical inputs from this model and found them to be reasonable.
[STONE & WEBSTER CONSULTANTS LOGO] 3-16
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- --------------------------------------------------------------------------------
========================================================================================================
PINEY HISTORICAL AND PROJECTED PERFORMANCE
========================================================================================================
PROJECTED UNIT AVERAGE
HISTORICAL (2000-2020)
--------------------------------------------------------------------------------------------------------
Average Annual Energy(1), (MWh) 71,612 70,737
--------------------------------------------------------------------------------------------------------
Capacity, (MW) 28.8 28.8
--------------------------------------------------------------------------------------------------------
Capacity Factor, (%) 29 28.04
========================================================================================================
(1) Since station start-up in the 1920's
Hydroelectric stations that operate in a peaking mode and have storage capacity
typically have low capacity factors. The capacity factors given for Piney
clearly illustrate the peaking nature of this station. The capacity factor for
Piney is about 29% and is projected to be approximately 28% over the next 20
years.
The performance of a hydropower plant is a function of the plant availability,
the unit efficiencies, and water availability. While the unit efficiency and the
plant availability are factors that can be addressed by a review of as few as
five years of recent plant records, a realistic assessment of the water
availability can only be addressed by reviewing the long-term average generation
of a plant. Typically, 15 to 20 years as a minimum, allowing a sufficient time
frame to reflect wet, dry, and average rainfall years to be included. Piney has
a long historical generation record of about 75 years upon which future average
generation may be based.
The long-term historical average generation is given above as approximately
72,000 MWh per year. Hagler Bailly has projected a unit average over 20 years of
approximately 70,737 MWh, in their market model, which is consistent with
historical performance and achievable under the 100 cfs minimum flow
requirement. Stone & Webster used the 2020 market forecast result of 70,762 MWh
through the projected retirement date.
The present Federal Energy Regulatory Commission ("FERC") license, issued in
1979 provides for a minimum continuous flow release of 100 cfs from May 1
through October 31 of each year. This flow rate is well below the minimum
acceptable flow for generation with one unit. Piney concentrates the available
water into the peak hours.
Piney's FERC license expires in October 2002 and the project is currently in the
process of applying for a new FERC license. The relicensing process includes
consultation with all stakeholders interested in the plant operation and the
effect of its operation on the environment. The interests of these stakeholders
are taken into consideration by FERC as it reviews Piney's license application
and sets license conditions for the term of the new license. These conditions
may include the same conditions or different operational parameters than are
included in the current license.
Piney's capacity, as indicated in the FERC license is 28.8 MW. Station personnel
advised that the limiting factor for this output is the generator cooling
capacity. It was also stated that the minimum load for each unit is about 1/3 of
the capacity for that unit. The typical regulating range was given as 2 MW to 8
MW per unit. This is the range through which the unit is generally cycled in
response to the changing needs of the system. Station personnel advised that,
during non-flood periods, Piney typically operates in a peaking mode with two
four-hour periods of operation with at least one unit each week-day. During
periods of high river flow, Piney would operate continuously.
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- --------------------------------------------------------------------------------
Starting time, from standstill, was given as 10 minutes. The limitation here is
that there is only one synchronizer. Loading time, from synchronous condensing,
was given as 1 minute. Station personnel advised that there was no regulatory
restriction on starting time but that there was a restriction on the shutdown
rate. That restriction is intended to keep the fish from being left high-and-dry
in the river downstream from the plant.
3.3.2 DEEP CREEK
Deep Creek operates in a peaking mode whenever there is insufficient water for
full time operation at full load. Historical and projected average annual energy
outputs, representative capacities, and indicated capacity factors are included
in the following table. The projected performance is shown for the period 2000
through 2020 and is a combination of inputs and outputs from the Hagler Bailly
market analysis model. The market forecast was extended by using the 2020
results through the projected retirement date. Stone & Webster has reviewed the
key technical inputs from this model and found them to be reasonable.
========================================================================================================
DEEP CREEK HISTORICAL AND PROJECTED PERFORMANCE
========================================================================================================
PROJECTED UNIT AVERAGE
HISTORICAL (2000-2020)
--------------------------------------------------------------------------------------------------------
Average Annual Energy(1), (MWh) 28,507 22,717
--------------------------------------------------------------------------------------------------------
Capacity, (MW) 19 19
--------------------------------------------------------------------------------------------------------
Capacity Factor, (%) 17 13.89
========================================================================================================
(1) Since station start-up in the 1920's
Stations that operate in a peaking mode and have storage capacity typically have
low capacity factors. The capacity factors given for Deep Creek clearly
illustrate the peaking nature of this station. The capacity factor for Deep
Creek is 17% and is projected to be approximately 14% over the next 20 years.
Deep Creek has a long historical generation record of about 75 years upon which
future average generation may be based. Maryland Department of Natural Resources
("DNR") has recently required a flow release as necessary to maintain a
continuous flow of at least 40 cfs in the Youghiogheny River, downstream from
the plant to maintain a 25 degrees C temperature in the river at that point
during the months of June, July, and August. Deep Creek concentrates the
available water into the peak hours.
The long-term historical average output is given above as about 28,507 MWh per
year. A value of 22,720 MWh would be a reasonable estimate for the average
annual output under the postulated conditions. Hagler Bailly has projected a
unit average over 20 years of approximately 22,717 MWh per year, which is
considered to be reasonable. Stone & Webster used the 2020 market forecast
result of 22,720 MWh through the projected retirement date.
Deep Creek's DNR Permit expires on January 1, 2006 and the project must apply
for a new permit. The repermitting process includes consultation with all
stakeholders interested in the plant operation and the effect of its operation
on the environment. The interests of these stakeholders are taken into
consideration by the DNR as it reviews the permit application and sets
conditions for the term of the new permit. These conditions may include the same
conditions or different operational parameters than are included in the current
license.
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Station personnel advised that the wicket gate timing was 10 seconds but the
actual loading was about 1 minute (from an on-line condition). The 1-minute
loading is achieved in a sequence of pulses that provide for opening of the
gates in 20-second increments. Station personnel advised that a faster opening
would produce difficulties with the regulating valve that bypasses water around
the turbine during the shutdown process.
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4. PLANT CONDITION ASSESSMENT
4.1 CONDITION ASSESSMENT
Stone & Webster reviewed the Facilities condition and provided a general
assessment through a combination of comprehensive plant walkdowns; interviews
with plant operating and maintenance management; and a review of operation and
maintenance records and inspection reports. The plant walkdowns were conducted
in March 2000 to assess the overall operability, effectiveness of maintenance
programs, apparent condition, and facility cleanliness and equipment
configuration. The equipment was not dismantled and no special tools or
equipment were employed. Boiler and turbine generator overhauls were not in
progress, and internal inspections were not conducted except as noted.
4.1.1 CONEMAUGH STATION
Units 1 and 2 have been operated as base load units since their commissioning.
BOILER
At the time of our site visit, both Units 1 and 2 were operating near full load.
A walkdown of both boilers indicated no external problems.
To reduce the NO(x) emissions, ABB's LNCFS III combustion modifications were
installed on Units 1 and 2 in 1994 and 1993, respectively. It is expected that
the burner nozzle tips will have to be replaced every four years and an amount
is included in the budget to account for this expense. Units 1 and 2 include
electrostatic precipitators ("ESP") which are well maintained and are in
operational condition. In general, the FGD system operation, performance, and
reliability appear to be excellent. In the FGD system, a gypsum byproduct is
formed and sold to a major wallboard manufacturer. The FGD system and ESPs have
operated well and have not caused unit major deratings or forced shutdowns.
A variety of routine inspections and repairs are made during each overhaul.
Conemaugh is currently executing a phased pressure part replacement program of
the critical boiler pressure parts. The overall condition of the boilers is good
and they are operated and maintained in an acceptable manner consistent with
good industry practice. It is anticipated that the Units 1 and 2 economizers may
need to be redesigned and replaced, and an amount is included in the budget to
account for this expense. The Units 1 and 2 high temperature superheaters are
only in satisfactory condition and may need to be replaced to maintain a high
availability. An amount is included in the budget to account for this expense.
The most significant problem on the Units 1 and 2 boilers is severe waterwall
tube wastage from low NO(x) operation. A majority (approximately 80%) of the
area with waterwall wastage is being overlaid to prevent fireside corrosion and
some sections are being replaced with an upgraded design. This material upgrade
has shown no evidence of short-term degradation and may represent an acceptable
long-term solution to tube wastage. This replacement is being performed in a
phased approached.
STEAM TURBINE
During the visual inspection of the steam turbine, it appeared to be in very
good condition considering it is completing 30 years of service.
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The most recent Unit 1 high pressure/intermediate pressure ("HP/IP") overhaul
was in 1998 when the HP rotor was replaced along with diaphragms 2 through 7.
The nozzle box was also replaced. It was recommended that the HP lower outer
shell be subjected to inner surface non-destructive testing ("NDT") during the
next scheduled outage. The most recent Unit 1 low pressure ("LP") turbine
overhaul was in 1996.
The most recent Unit 2 HP/IP overhaul was in 1997 when the HP inner shell,
rotor, nozzle and diaphragms 2 through 8 were replaced, and the rotor was
reused. It was recommended that the HP outer shell and IP shell be scheduled for
inner surface NDT along with some bucket cover repair and replacement of the IP
rotor. The most recent Unit 2 LP turbine overhaul was in 1995. The next
scheduled Unit 2 HP/IP outage is scheduled for 2003 and an amount is included in
the budget to account for this expense.
The Units 1 and 2 turbine and generator rotor bores have been inspected
throughout the life of the turbines. Nothing of significance was noted. As the
industry is shifting to longer overhaul intervals, combining the HP and IP
section overhauls and shifting to a six-year interval is acceptable. The LP
turbines can continue with the existing six-year inspection interval. Future
overhauls will need to address HP inner and outer shell cracking weld repairs.
HP diaphragm dishing and distortion and replacement of the first three HP and IP
inlet stage blades may be required at upcoming overhauls. REMA has provided an
amount in the budget to account for this expense.
ELECTRICAL AND CONTROLS
The most recent generator inspection for Unit 1 was September 1998 and for Unit
2 was November 1997. The Unit 1 HP and LP generators were determined to be in
satisfactory condition. The Unit 2 HP and LP generators were determined to be in
good condition. There are four 2.75 MW, 4.16 kV diesel generators located in
separate enclosures. They appear to be in reasonably good condition, test run
once a week, and are overhauled every seven years by an outside contractor.
Visual inspection indicated that there are various degrees of oil leakage on the
Units 1 and 2 generator step-up ("GSU"), step-up, auxiliary, and startup
transformers. Records suggest that the switchgear and circuit breakers are
maintained according to industry standards and are in good operating condition.
It was reported that the batteries are approximately 15 years old and with
proper maintenance can last approximately 20 years. The Units 1 and 2 125 VDC
battery systems associated with the distributed control system ("DCS") are
scheduled for replacement in the near future and an amount is included in the
budget to account for this expense.
The turbine control system for both Units 1 and 2 is the original GE Mark I
electrohydraulic ("EHC") type. The turbine EHC control is scheduled for
replacement with a new Woodward Governor system in the near future and an amount
is included in the budget to account for this expense. In general, the controls
appear to be well maintained and in good operating condition.
BALANCE OF PLANT
Visual inspections were conducted to assess the apparent condition, overall
operability of the major BOP equipment and piping.
The cooling towers and condensers are characterized as being in good condition.
No problems were cited with the circulating water pumps. Several of the Units 1
and 2 feedwater heaters, but not all, have been replaced since the 1980s. The
remaining feedwater heaters may need to be replaced and an amount is included in
the budget to account for this expense. No significant problems have been found
during
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deaerator examinations. The boiler feed pumps are characterized as being in
excellent condition. A well-documented In-Service Inspection ("ISI") program is
in place to monitor the condition of high energy piping. No major defects have
been found to date. The auxiliary boilers are characterized as being in good
condition.
Approximately 80% of the station's coal requirements are currently delivered to
the station by rail. The balance is delivered by truck (approximately 350 trucks
per day). Conemaugh has approximately 700,000 tons of coal storage space
available, which is equivalent to a 45-day supply load at full load. The coal
handling system is characterized as being in good condition. The No. 2 fuel is
delivered by truck and stored in a 200,000 gallon aboveground tank. Another
200,000 gallon tank has been taken out of service due to the low demand for fuel
oil on site. The tanks are characterized as being in excellent condition. Bottom
ash is removed to an onsite lined ash disposal area. No significant operating or
maintenance problems were noted.
4.1.2 KEYSTONE STATION
Units 1 and 2 have operated as base loaded units since their commercial
operation date.
BOILER
At the time of the site visit, Unit 2 was out of service for a scheduled outage
and Unit 1 was operating near full load.
To reduce the NO(x) emissions on Units 1 and 2, ABB's LNCFS III combustion
modifications have been installed. The coal nozzles tips may need to be replaced
every four years and an amount is included in the budget to account for this
expense. The Units 1 and 2 ESPs are well maintained and are in operational
condition. The ESPs have operated well and have not caused unit major deratings
or forced shutdowns.
A walkdown of both boilers indicated no external problems. A variety of routine
inspections and repairs are made during each overhaul. Keystone is currently
executing a phased pressure part replacement program of critical boiler pressure
parts. The overall condition of the boilers is good and they are operated and
maintained in an acceptable manner consistent with good industry practice. The
Units 1 and 2 high temperature superheaters are in satisfactory condition and
may need to be replaced to maintain a high availability. An amount is included
in the budget to account for this expense.
The most significant problem on the Units 1 and 2 boilers is severe waterwall
tube wastage resulting from low NO(x) operation. A majority of the areas of the
waterwalls affected by the wastage are being replaced with an upgraded chromized
surface design. Select areas have weld cladding applied to protect the tube
surfaces with an alloy material. The replacement is being performed in a phased
approach and the scheduled completion date is in year 2002.
STEAM TURBINE
During the visual inspection of Keystone, both turbines appeared to be in very
good condition considering they have been in service for about 33 years. The
plant staff reported no problems with carrying full load.
The most recent Unit 1 HP/LP overhaul was in 1997, and a spare HP rotor, a spare
inner cylinder, and spare LP rotor with a new style integral shroud blading were
installed. The LP "B" and "A" rotors were replaced with spares in 1991 and 1999,
respectively. The next scheduled HP/LP inspection is in 2003. The most recent
Unit 2 HP/LP overhaul was in 1996, and the HP spare rotor, inner cylinder with
new nozzle blocks, No. 1 blade rings, and the LP spare rotor were installed. The
LP "A" turbine rotor was
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replaced in 1994. The next scheduled HP/LP inspection is in 2002. The spare Unit
2 LP "B" turbine rotor is scheduled to be replaced in 2000.
The Units 1 and 2 turbine and generator rotor bores and the spare elements have
been inspected. A review of findings indicates that the HP rotors exhibited some
magnetic particle and sonic indications. They received a recommendation to be
reinspected either within 10 years or in two six-year runs. The industry is
shifting to a longer overhaul interval as is the current practice of six years
at Keystone. As the turbine components age, future overhauls will need to
address potential HP inner and outer shell cracking repairs. HP diaphragm
dishing and distortion and replacement of the first three HP and LP inlet stage
blades may be required at upcoming overhauls.
On July 26, 2000 Keystone Unit 1 tripped due to a HP turbine rotor position
trip. Eight turbine nozzle block bolts failed and went into the HP first stage
row and severely damaged the first and second stage row and moderately damaged
the third stage row. The root cause analysis has not been completed as of August
3, 2000 but the initial indication is that it was an isolated incident. The
outage should only last four weeks since Keystone has a spare HP turbine rotor
and blades, inner cylinder, and first row stationary blade ring. It is estimated
that Keystone will return to service in late August. REMA has indicated that
this event should not have a material impact on its financial position.
ELECTRICAL AND CONTROLS
The most recent generator inspection for Unit 1 was performed in May 1999 and
Unit 2 was April 1998. The generators were determined to be in fair to good
condition. There are four 2.75 MW diesel generators and associated 4.16 kV
switchgear located in separate enclosures. It was reported that maintenance on
these units is done on a routine schedule. Visual inspections indicate that
there were no signs of oil leaks from the oil filled circuit breakers ("OCBs")
and they appear to be in good condition. Visual inspection indicates there is
evidence of oil leakage on the transformers. Records suggest that the switchgear
and circuit breakers are maintained according to industry standards and are in
good operating condition. It is reported that the batteries are approximately 10
to 12 years old and with proper maintenance can last approximately 20 years. The
Units 1 and 2 125 VDC battery systems associated with the DCS are scheduled for
replacement in the near future and an amount is included in the budget to
account for this expense. In general, the original and upgraded control systems
appear to be well maintained and in good operating condition.
BALANCE OF PLANT
Visual inspections were conducted to assess the apparent condition, overall
operability of the major balance of plant ("BOP") equipment and piping.
The cooling towers are characterized as being in good condition. No problems
with the circulating water pumps were cited. The condensers are characterized as
being in good condition. The feedwater heaters are characterized as being in
excellent condition. No significant problems have been found during the
deaerator examinations. The boiler feed pumps are characterized as being in
excellent condition. A well-documented ISI Program is in place to monitor the
condition of high-energy piping. No major defects have been found to date. The
auxiliary boilers are characterized as being in good condition.
Coal is delivered to the station by rail and by truck. The trains are limited to
70 cars due to the power needed to climb the existing grades. The equipment,
including conveyors, feeders, and crushers, is duplicated downstream of the
stacker/reclaimer, but it is not fully redundant. The coal handling system was
characterized as being in good condition. Bottom ash is removed and trucked to
an onsite lined disposal area. No significant operating or maintenance problems
were noted.
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No. 2 fuel oil is stored in one 200,000 gallon and one 150,000 gallon
aboveground storage tanks. No. 2 fuel oil for the diesel generator peaking units
is stored in an aboveground 50,000 gallon storage tank. The tanks are
characterized as being in good condition.
4.1.3 SHAWVILLE STATION
Units 1, 2, 3, and 4 have operated as base load units since commercial
operation. At the time of the site visit, Units 1 and 3 were out of service due
to load dispatch. Units 2 and 4 were operating per system demand.
BOILER
To reduce the NO(x) emissions new low NO(x) "S" burners were installed on Units
1 and 2. To reduce the NO(x) emissions, ABB's LNCFS III combustion modifications
were installed on Units 3 and 4 boilers.
A walkdown of the boilers indicated no external problems. A variety of routine
inspections and repairs were made during each overhaul. The overall condition of
the boilers is good and they are operated and maintained in an acceptable manner
consistent with good industry practice. However, the most significant problem on
the Units 3 and 4 boilers is severe waterwall wastage due to NO(x) firing. The
areas of the waterwalls affected by the wastage are being replaced with an
upgraded chromized surface design. The replacement is being performed in a
phased approached.
STEAM TURBINE
The Units 1 and 2 turbines are reported to have cracks in the girth weld that
attaches the integral steam chests to the upper and lower HP outer cylinders.
The prior owner's philosophy was to monitor these areas and address any future
crack propagation. Unit 1 has some rotor surface cracking in the N-3 packing
area. These problems may be addressed with extensive repairs during the next
scheduled major overhauls.
Cracking is reported to have occurred in both the Units 3 and 4 HP/IP inner and
outer casings. Units 3 and 4 are reported to have exhibited some HP casing
distortion and diaphragm dishing. Replacement of the first three Units 3 and 4
HP stage blades may be required.
The turbines were recently switched to a nine-year overhaul cycle. Predictive
maintenance techniques including vibration analysis, lube oil analysis, and
performance testing are utilized to plan major maintenance.
ELECTRICAL AND CONTROLS
The Unit 1 generator was last inspected in December 1993. The Unit 2 generator's
last major inspection was performed in November 1992 when boresonic inspections
were made of the generator rotors and electrical maintenance testing was
performed with satisfactory results. In 1997, the Unit 3 generator's work was
limited to only cleaning coolers and testing. An internal inspection and routine
electrical tests were performed on the Unit 4 generator in 1999. The diesel
generators appear to be in reasonably good condition and there were no reported
problems. Visual inspection indicates that the OCBs and associated disconnect
switches appear to be in good condition except for one OCB that shows signs of
oil leakage. There was no evidence of oil leakage on the outdoor oil-filled
transformers and they appear to be in reasonably good condition. The Units 3 and
4 battery cells are in need of immediate maintenance. The
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uninterruptible power supply ("UPS") systems and voltage conditioners for all
four units appear to be in good condition. In general, the controls appear to be
well maintained and in good operating condition.
BALANCE OF PLANT
Visual inspections were conducted to assess the apparent condition, overall
operability of the major BOP equipment and piping. The Units 1 and 2 and Units 3
and 4 screenwell intake structures' traveling water screens were characterized
as being in fair condition. The circulating water pumps were characterized as
being in good condition. The Units 1, 2, 3, and 4 condensers were characterized
as being in fair to good condition. The Units 1 and 2 LP feedwater heaters were
characterized as being in fair condition and the Units 1 and 2 HP feedwater
heaters as being in good condition. The Unit 3 LP and HP feedwater heaters were
characterized as being in fair condition. The Unit 4 LP and HP feedwater heaters
were characterized as being in good condition. No significant problems have been
found during the deaerator examination. All of the boiler feedwater pumps were
characterized as being in good condition. A well-documented ISI Program is in
place to monitor the condition of high-energy piping. No major defects were
noted.
All coal is delivered by truck. There is a rail spur on site but it is not
maintained nor is it useable. The coal pile is normally maintained between
80,000 and 120,000 tons. The coal handling system was characterized as being in
fair condition. Bottom ash is transferred to an on-site lined landfill. No
significant operating or maintenance problems were noted with the bottom ash
transfer system. No. 2 fuel oil is delivered by truck and stored in a 500,000
gallon aboveground tank surrounded by an earthen dike. The tank was
characterized as being in good condition.
4.1.4 PORTLAND STATION
Units 1 and 2 have operated as base load units since their commercial operation
date.
BOILER
The Unit 1 and 2 boilers were found to be well maintained and in good overall
condition.
The burners on Units 1 and 2 were upgraded by ABB to a low NO(x) LNCFS Level III
firing system. Units 1 and 2 include ESPs, which are well maintained and are in
operational condition.
A variety of routine inspections and repairs are made during each overhaul. The
boilers are operated and maintained in an acceptable manner consistent with good
industry practice. Unit 1 presently has a reliability problem due to reheater
tube failures. The most significant problem on the Units 1 and 2 boilers was
severe waterwall wastage resulting from high temperature ash. Since the
low-NO(x) burner installation the waterwall panel wastage rate is now only 15-20
mills per year, which is considered reasonable.
STEAM TURBINE
Units 1 and 2 were originally base loaded but are now in intermediate service.
The most recent Unit 1 HP turbine overhaul was in 1997. GE recommended that the
HP inner shell be replaced. This has been recommended previously and will be
required to assure future reliable operation. It is anticipated that the packing
casings will require machining to correct out-of-roundness, the reheat
diaphragms distortion will require repair, the HP inner shell horizontal joint
opening will require repair and machining, the stage 2, 3, and 4 buckets will
require replacement, and several diaphragms will require repair. The most recent
Unit 1 LP turbine overhaul was in 1994. Replacement of the Unit 1 LP turbine
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diaphragm packing, welding and remachining of shell fit areas was recommended at
the next outage. Amounts are included in the budget to account for this expense.
The most recent Unit 2 major overhaul was on the HP section in 1995. More
complete HP shell inspection is recommended at the next outage. It is
anticipated that the LP bucket erosion shields will require replacement at the
next outage. An amount is included in the budget to account for these expenses.
ELECTRICAL AND CONTROLS
The Unit 1 generator was overhauled in 1992. The Unit 2 HP generator rotor was
rewound in 1993. Future maintenance plans include a generator rotor rewind for
Unit 1. All the transformers appear to be in good condition with no evidence of
constant oil leakage observed. The OCBs and associated disconnect switches
appear to be in good condition. The 4.16 kV and 480V switchgear and 480V motor
control centers for Unit 1 appear to be in good condition. The Units 1 and 2
emergency diesels appear to be in good condition. In general, based on the plant
walkdown, the areas around the electrical equipment appear to be well
maintained.
The Siemens V84.3 electrical equipment associated with the CTs is relatively new
and in good operating condition. The overall impression of the CT electrical
equipment is that it appears to be in good condition, and according to the plant
personnel preventive maintenance is ongoing.
BALANCE OF PLANT
Visual inspections were conducted to assess the apparent condition, plant
cleanliness, and overall operability of the major BOP equipment and piping.
No significant problems were cited with the circulating water system or
circulating water pumps. As of December 1999, approximately 10 to 15% of the
Unit 1 condenser tubes were plugged. There are plans to retube the Unit 1
condenser in the spring of 2001, using the original Admiralty tube material. The
Unit 2 condenser has less than 2% of the tubes plugged as of January 26, 2000.
Plant personnel stated that the condition of the waterboxes for both condensers
and the condensate pumps is good. No significant problems were cited with the
feedwater heaters and boiler feedwater pumps. There is a formal program in place
to inspect high-energy piping. There has been no history of pipe failures or
pipe support problems. The demineralizer is in excellent condition. The
auxiliary boiler was installed in 1998 and is in excellent condition.
Coal is delivered to the site by trains approximately every third day, with a
portion of the original train separated at Titus. There are no reported problems
with the coal handling system. The ash from Unit 1 is sent to an onsite
landfill. The bottom ash from Unit 2, absent of any pyrites, is sold for road
material. There are no major problems with the ash handling equipment, except
for the frequent replacement of the piping from the pulverizers which handles
pyrite rejects. No. 2 fuel oil is delivered to the station by truck; the site
has storage capability for 4.2 million gallons of oil.
COMBUSTION TURBINES
Units 3 and 4 have been operating in peaking service since commercial operation
and have operated successfully to date. The last major inspection and unit
overhaul for Units 3 and 4 occurred in 1991 and 1992, respectively. Units 3 and
4 demonstrate the effectiveness of good condition monitoring and O&M practices
in offsetting the effects of aging. No adverse conditions were observed or
identified. No unusual performance problems or degradation were noted.
Recommended upgrades, including improved
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materials and controls, and replacement of degraded components continue as
required. The physical appearance is satisfactory; functioning equipment is
clean and orderly; however, there is a general need for cleanup and painting of
structures. Corrosion does not appear to be a problem at this time. The overall
condition of Units 3 and 4 is good.
Unit 5, Siemens V84.3, has not yet demonstrated the capacity for reliable
long-term operation. This unit is a first of a kind advanced technology simple
cycle unit that was in the test and development mode during 1998 and 1999.
Siemens continues to conduct commercial in-service and start-up for Unit 5.
As with many developmental units, numerous operating problems have been
experienced which require continuing adjustments, changes and modifications.
Siemens has discontinued this model after delivering six units worldwide (four
in U.S.). No adverse conditions were observed, but it is anticipated that
problems may continue, albeit at a reduced level from the past. However, the
unit is only projected to be dispatched in the same range as its historical
capacity factor. Required upgrades, including improved materials and controls,
and replacement of degraded components continued as needed during testing and
development. The physical appearance is satisfactory; functioning equipment is
clean and orderly.
4.1.5 SEWARD STATION
Units 4 and 5 were operated as base loaded units when they were commissioned. In
recent years, the units have provided intermediate service. During our visit,
Units 4 and 5 were not operating. It was reported that Unit 4 was not called
upon to operate that day, and Unit 5 was undergoing maintenance for an
economizer tube leak. The units have historically been operated and maintained
in a manner consistent with good industry practice. However, the prior owner
deferred some maintenance. REMA has included a sufficient budget for these units
to operate through their projected retirement date of 2010.
BOILER
To reduce the NO(x) emissions low NO(x) burners were installed on the Unit 4
boilers. The Unit 5 burners are the original design and have not been replaced
with low NO(x) burners. Units 4 and 5 have ESPs, are well maintained, and are
presently in operational condition. Unit 5 has SNCR and SCR that were redesigned
for increased NO(x) reduction.
A walkdown of the boilers indicated no external problems. A variety of routine
inspections and repairs are made during each overhaul. The overall condition of
the boilers appears to be fair. Particularly, Unit 5 waterwall tubes have cold
side corrosion that results in tube leaks into the boiler building rather than
into the furnace. This has posed a safety concern for personnel. The units are
operated and maintained in an acceptable manner consistent with good industry
practice.
The overall condition of the Unit 4 generating tubes is fair with approximately
5% of the existing tubes plugged. The Units 4 and 5 superheaters have
experienced leaks. In particular, the Unit 4 finishing superheater is original
and in fair to poor condition. The Unit 5 primary superheater is original and in
poor condition.
The prior owner deferred capital expenditures; however, REMA has included a
sufficient amount in the budget for these units to operate through their
projected retirement date of 2010.
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STEAM TURBINE
The Seward Unit 4 and 5 turbine generators are 50 and 43 years old, respectively
and are currently utilized for intermediate service.
It was reported that the Unit 4 turbine was uprated from 40 to 60 MW in 1976
with two rows of HP blades removed. The unit was reported to have rotor bore
crack indications. The turbine has two original design features, which would be
undesirable by today's standards. These are last stage blade wheels shrunk on
the LP turbine rotor and LP turbine water seals. Both features can result in
turbine component damage that is difficult and costly to repair. The last major
Unit 4 turbine overhaul was in 1993. An overhaul is scheduled again in 2001 to
address various boiler maintenance concerns with no significant turbine work
scheduled.
It was reported that the LP turbine rotor has been replaced and new retractable
packing installed. Plant personnel advised that two new LP blade rows may be
required. There is a serious crack in the steam chest, which has not been
repaired but is being monitored. The last major Unit 5 overhaul was in 1995. An
overhaul to address various boiler maintenance concerns is scheduled for 2000
with no specific turbine work scheduled. In addition to HP shell cracking, there
is evidence of possible shell distortion. In order to operate until planned
retirement in 2010, the steam chest crack must be inspected at the next overhaul
to determine if it is necessary to replace any blades. An amount is included in
the budget to account for these potential expenses.
ELECTRICAL AND CONTROLS
The most recent generator inspections on Units 4 and 5 were performed in April
1994 and June 1995, respectively. During the 1994 Unit 4 generator inspection
routine, electrical maintenance tests were performed with satisfactory results.
Since the 1995 Unit 5 generator inspection, when a vibration problem was
corrected, the Unit 5 generator has operated successfully. Visual inspection
indicated that there are no signs of oil leakage from the OCBs, and they appear
to be in good condition. Visual inspection indicates there is oil leakage at the
GSU transformers, which should be repaired in the near future, and they are in
need of painting. A sufficient amount is included in the budget to account for
these expenses.
The 2.4 kV switchgear appears to be in good condition. There are no reported
problems with the 11 switchgear and circuit breakers, and visual inspection
indicates that the equipment appears to be in reasonably good condition,
especially given its age. The 125 VDC batteries and chargers appear to be well
maintained and in good condition. The UPS systems and power conditioners
associated with boiler controls appear to be in reasonably good condition. In
general, the controls appear to be in good condition with no reported problems.
BALANCE OF PLANT
The screenwell intake structures' traveling water screens are characterized as
being in good condition. The circulating water pumps are characterized as being
in good condition. Station personnel indicated that there have been no problems
with the piping or discharge tunnel. The Unit 4 condenser is characterized as
being in excellent condition and that it is unlikely that the condenser will
have to be retubed again. The Unit 5 condenser is characterized as being in good
condition. The Unit 4 and 5 feedwater heaters are characterized as being in good
condition. It is probable that the heaters will be maintained but not replaced
prior to the retirement of the units (before 2011). No significant problems have
been found during the deaerator examinations.
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All coal is delivered by truck. The units burn approximately 500,000 tons per
year total. At the time of Stone & Webster's site visit, approximately 50,000
tons were stored on-site (a 35 day supply). The coal handling system is
characterized as being in fair condition. Bottom ash is removed and trucked to
Conemaugh. No significant operating or maintenance problems have been noted. No.
2 fuel oil is delivered by truck and stored in two 16,000 gallon above ground
tanks. The tanks are characterized as being in good condition.
4.1.6 TITUS STATION
Units 1, 2 and 3 were operated as base load units after commercial operation and
in recent years they have operated as intermediate units.
BOILER
The burners were upgraded by ABB to a low-NO(x) LNCFS Level III firing system in
1995. It is reported that the ESPs were augmented in 1975 with two additional
parallel chambers. This added 56% to the collection area for each ESP. There is
no flue gas conditioning required to maintain opacity within 10%, and dust
loading levels are well within compliance levels. In the past, there were
opacity violations that included 38% being experienced during steady state
operation.
Major boiler outages are scheduled at intervals of three years. Mini-outages are
usually planned annually to insure specific repairs are made to maintain high
unit reliability. The coal mill and volumetric feeders are in good condition due
to a strict repair and overhaul schedule. The air heaters are in good condition,
and seals and baskets are replaced on a scheduled cycle. All fans are in good
condition and receive routine maintenance. Piping, pipe hangers, support steel,
thermal insulation, soot blowers, and metal casings are generally in good
condition. The flue gas ductwork, fans, expansion joints, and air heaters are
free of major gas leaks and are well insulated.
STEAM TURBINE
The three steam turbines were originally designed for baseload coal-fired
operation, but now they operate in an intermediate load following mode. There
are relatively few start/stop cycles on the units since they have operated at
relatively high capacity factors compared to other similar vintage units.
The turbines are currently on a scheduled nine-year overhaul schedule. The most
recent major Unit 1 overhaul was in 1993. The most significant concern on Unit 1
was the steam chest to HP shell attachment weld experienced cracking with the
upper half being the most serious. The cracks were partially ground out and weld
repaired. GE considered the repairs to be temporary with re-inspection
recommended and replacement of the outer shells conducted at the next overhaul.
Replacement of LP diaphragm packing was also recommended at the next overhaul. A
sufficient amount is included in the budget to account for these expenses.
The most recent major Unit 2 overhaul was in 1995. The last stage bucket tenons
were badly eroded and bucket replacement was recommended on both rows at the
next inspection. The most recent major Unit 3 overhaul was in 1996. Replacement
of the No. 1 water seal casing was recommended at the next overhaul. The Units 2
and 3 LP turbine rotors internal ultrasonic inspections have shown numerous
indications. Re-inspections of the rotors should be performed during scheduled
turbine overhauls.
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ELECTRICAL AND CONTROLS
The last major overhaul for the Unit 1 generator was in 1993 when the stator was
rewound and boresonic testing was done. The last major overhaul for the Unit 2
generator was in 1988 and the last internal inspection was done in 1995. The
last internal inspection for Unit 3 was done in 1996, which included a boresonic
inspection of the rotor. The Units 2, 3 and 4 generator rotors internal
ultrasonic inspections have shown numerous indications. Re-inspections of the
rotors should be performed during scheduled generator overhauls.
The transformers appear to be in good condition and no evidence of constant oil
leakage was observed. The OCBs and disconnect switches appear to be in good
condition. The switchgear and motor control centers appear to be in good
condition. The air blast type generator breakers may need to be replaced since
parts for these breakers are becoming hard to find. All the batteries were load
tested in 1999 and they appear to be well maintained and in good condition.
In general, the areas around the electrical equipment were well lit and the
electrical equipment appeared to be well maintained.
BALANCE OF PLANT
The cooling tower is characterized as being in good condition. The Units 1 and 2
condensers were retubed in the 1980's. The Unit 3 condenser retains the original
tubes, with some tubes being plugged. The plugged tubes have resulted in no
performance deficiencies with Unit 3.
The LP feedwater heaters for all three units are original. The HP heaters for
Units 1 and 2 are approximately 15 years old and Unit 3 has one original HP
feedwater heater, with the remaining two having been replaced. No problems with
the boiler feedwater pumps were cited. There is a formal ISI program for
high-energy components scheduled and administered internally. There has been no
history of pipe failures or problems with pipe supports.
Titus shares delivery of coal from a train with Portland, with approximately 50
cars being left at Titus. No significant deficiencies were observed in the
condition of the coal handling equipment. The bottom ash is sent to the station
owned landfill. Bottom ash is kept separate from the fly ash. The three No. 2
fuel oil storage tanks have a total capacity of 250,000 gallons. The oil is
delivered by truck.
No significant deficiencies of the general appearance, corrosion, structural
settlement, or overall housekeeping of Titus were observed during the
walk-through.
COMBUSTION TURBINES
Units 4 and 5 have been in peaking service since commercial operation and have
operated successfully to date. The last major inspection and overhaul for Units
4 and 5 was completed in 1992. Units 4 and 5 have demonstrated the effectiveness
of good condition monitoring and O&M practices in offsetting the effects of
aging. No adverse conditions were observed or identified. No unusual performance
problems or degradation were noted. Recommended upgrades, including improved
materials and controls and replacement of degraded components are undertaken as
needed. The physical appearance is satisfactory; functioning equipment is clean
and orderly. There is a general need for cleanup and painting of structures.
Corrosion does not appear to be a problem at this time. The overall condition is
very good.
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4.1.7 SAYREVILLE STATION
Units 4 and 5 were originally designed as baseload units and in recent years
have operated as peaking units. The four simple cycle CTs are operated as
peaking units.
BOILER
Units 4 and 5 have experienced boiler tube problems since the conversion from
coal to oil firing in 1969. The maximum achievable generation rating is 90 MW on
Unit 4 and 95 MW on Unit 5. The reduced generation is due to lower main steam
and hot reheat steam temperatures resulting from changes in furnace performance
due to switching fuels and reduced main steam pressure due to the poor physical
condition of the boilers.
In a study performed by Babcock & Wilcox in 1990, boiler waterwall screen tube
modifications were specified that would allow recovering steam temperatures and
preventing tube failures in the waterwall screen region. The prior owner elected
not to perform this major modification but instead replaced failed tubing with
rifled tube panels in approximately 50% of this section. The prior owners
deferred some maintenance. The overall condition of the Units 4 and 5 boilers is
considered marginal for continued service unless significant capital
expenditures are made. The budget includes sufficient funds to account for
boiler repairs.
The operating pressure was reduced to limit extensive tube failures in the lower
portion of the main furnace resulting from inadequate boiler water chemistry
control or chemical cleaning. This condition began in the 1990s and is presently
ongoing. The budget includes sufficient funds to prevent continuous recurrence
of this problem.
The high temperature superheater and reheater tubes and headers on both units
have not contributed to the forced outage rate, nor have they ever been
replaced. This is likely the result of the low terminal steam temperatures
during the last 25-30 years. The cyclone furnaces were reported to be in good
condition with the available resources to perform repairs. The forced draft fans
for both units were found to be in good condition and capable of maintaining the
reduced load on both units.
STEAM TURBINE
The most recent major Unit 4 turbine overhaul was in 1990. All three LP end L-0
buckets were severely eroded behind the erosion shields and replacement of all
three rows was recommended for the next outage. The budget includes sufficient
funds to account for the steam turbine repairs.
The most recent major Unit 5 turbine overhaul was in 1987. Re-inspection was
recommended if the unit was used for cycling or peaking. There were 23
reportable indications in the HP rotor bore, and re-inspection was recommended.
Control stage erosion was severe and replacement was recommended. The L-0
buckets were eroded and re-inspection was recommended and replacement at the
next overhaul.
ELECTRICAL AND CONTROLS
The last major inspection was performed in 1993 on the Unit 4 generator stator
and field. Overall, the Unit 4 generator was in satisfactory condition. The last
major inspection of the Unit 5 generator was performed in 1987. The Unit 5
generator was found to be in acceptable condition. Westinghouse recommended that
the rotor bore be re-inspected after five years of baseload or load cycling
operation and three years if the unit was used for intermediate or peaking
operation. Units 4 and 5 are reported to have their original windings.
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All the transformers are original equipment and appear to be in good condition
with no evidence of constant oil leakage observed. The circuit breakers and
disconnect switches appear to be in good condition. The switchgear and MCCs are
all original equipment and considering their age, appear to be in good
condition. All the batteries appear to be in good condition.
Since these Sayreville units were being considered for retirement by the prior
owner; equipment replacement and technology upgrades for the past several years
were kept to a minimum. However, the budget includes sufficient funds to account
for continual operation to the projected retirement dates.
BALANCE OF PLANT
Inspection of the intake canal walls in 1982 and 1985 indicated continued
deterioration through corrosion. The three traveling screens were replaced
between 1984 and 1985 for each of the two units. Although no problems with the
circulating water pumps were cited, a 1992 evaluation indicated that the Unit 5
circulating water pumps may require major overhauls for extended operation. The
condensers were characterized as being in good condition, with estimates of tube
pluggage given by plant personnel as 15% for Unit 4 and 10% for Unit 5. A recent
investigation recommended retubing the HP.
There is an ISI program in place for high energy piping systems. Presently,
there are no known defects. The water treatment system was installed in 1985,
and is in very good condition. Resins are original, and may require replacement
in the future. There was noticeable corrosion in structural and duct steel
observed during the walk-down. Additionally, some structural settlement and
cracking was observed. The condition of piping insulation and supports, and
ductwork insulation appears acceptable.
The original coal-fired units were converted to No. 6 fuel oil and natural
gas-firing. The fuel oil is delivered to the station by barge (20,000 to 25,000
barrels per delivery), and stored in one 108,000 barrel storage tank. No. 2 fuel
oil is used as an ignition fuel for the boilers. The No. 2 fuel oil is stored in
three above ground tanks, including two of 16,000 gallons each, and one of
32,000 gallon capacity. The No. 2 fuel is primarily used for the CTs.
Make-up water to the boilers is obtained from two 6-inch municipal water lines.
Boiler make-up is treated with a two-train anion, cation and mixed bed
demineralizer. There is no condensate polisher. Each demineralizer train is
sized for 100% of capacity. The system also includes regeneration equipment.
COMBUSTION TURBINES
The C-1, C-2, C-3, and C-4 units have been operated in peaking service since
commercial operation. The most recent major inspections and unit overhauls were
completed in 1988, 1994, 1992, and 1990 for C-1, C-2, C-3, and C-4,
respectively. Each unit was successfully modified in 1995-1996 to accommodate
water injection for NO(x) abatement in compliance with CAA requirements. Water
injection has been managed properly without serious incident to date. No major
issues or adverse conditions were observed or identified. A recent major
accident severely damaged the C-4 generator due to a switching error. The
accident is considered to be an isolated case. The C-4 generator has since been
repaired, and operating practices and procedures have been changed to avoid
possible recurrence. No other unusual performance problems or degradation were
noted. Recommended upgrades, including improved materials and controls, and
replacement of degraded components have been undertaken as needed. The physical
appearance is satisfactory; functioning equipment is clean and orderly; however,
there is a general need for cleanup and painting of structures. Corrosion does
not appear to be a problem at this time. The overall condition of the CTs is
good.
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4.1.8 WARREN STATION
Units 1 and 2 were operated as baseload units at commercial operation but in
recent years have operated as intermediate units.
BOILER
At the time of the site visit, all boilers were found to be operational. The
prior owner deferred some maintenance on these units. REMA has budgeted a
sufficient amount to support continual operation through the projected
retirement date.
There have been no modifications made to the combustion system to lower NO(x)
emission levels. The existing strategy is to bubble this plant with Portland and
Seward to meet the NO(x) emission levels. An ESP was added in 1976 to augment
the original ESP installed on each unit. In general, the ESPs are well
maintained and are presently in operational condition.
Recently, there have been waterwall tube failures in the boilers of Unit 1
caused by underdeposit corrosion resulting from the poor condition of the
condenser. The majority of the front and rear walls and about 20% of the
sidewalls have been replaced, but tube leaks are continuing even in the newer
tubing. Chemical cleaning is needed to remove the corrosion and additional
waterwall tubing replacements may be required. REMA has budgeted sufficient
funds to account for additional tube replacements. The coal mill and volumetric
feeders are in good condition. The tubular air heaters are in good condition.
All the fans are in good condition. Piping, pipe hangers, support steel, thermal
insulation, soot blowers, and metal casings are generally in good condition. The
flue gas ductwork, fans, expansion joints, and air heaters are free of major gas
leaks and are well insulated.
STEAM TURBINE
The units were designed for baseload operation but have been used for cycling
and local voltage support in recent years. A new 115 kV capacitor bank
connection has been installed which has reduced the need for the Warren units to
provide local voltage support. The plant was not operating during the
inspection.
The most recent major turbine overhauls were in 1989 and 1990. The prior owner
had deferred further turbine maintenance. The turbines did appear to be in very
good condition considering the age and recent availability data. It is
anticipated that the HP and LP turbine blades may need to be replaced, and the
nozzle block may need refurbishment. Plant personnel advised that there had been
no evidence of turbine shell distortion or flange leakage. There were no obvious
recent oil leaks. There were no turbine support pedestal concrete cracks,
although there were two condenser supports with some concrete cracking. Unit 1
boiler tube failures appear to be the major cause for most of the recent unit
outages. REMA has budgeted a sufficient amount to support continual operation
through the projected retirement date.
ELECTRICAL AND CONTROLS
The last major inspections for the Units 1 and 2 generators were in 1989 and
1990, respectively. An ultrasonic inspection of the Unit 1 generator rotor in
1984 found a cluster of indications in the body of the rotor. Another ultrasonic
inspection at the next overhaul is recommended. The Unit 3 CT generator has not
been overhauled since the in-service date.
The plant indicated that an inspection is needed on Unit 1 in 2001 and in 2002
for Unit 2. All the transformers appear to be in good condition with no reported
problems. The 11.5 kV switchgear and circuit breakers appear to be in good
condition. The 2.3 kV switchgear is original, appears to be well
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maintained, and in good operating condition. Units 1 and 2 have an emergency
diesel generator that appears to be in good condition and is started on a weekly
basis. The 125V DC batteries appear to be in good condition. Since Warren was
being considered for retirement by the prior owner, equipment replacement and
technology upgrades for the past several years were kept to a minimum. However,
the budget includes sufficient funds to account for continual operation through
the projected retirement dates.
BALANCE OF PLANT
No retubing of either Unit 1 or 2 condensers has been performed. There have been
significant condenser tube leaks in recent years. There have also been recent
problems with the feedwater heaters for Unit 2. The deaerator for Unit 1 is in
acceptable condition; however, the Unit 2 deaerator has vent condenser problems,
and may require retubing. The budget includes funds to cover these anticipated
repairs.
The boiler feedwater pumps are rebuilt on an as-needed basis; one pump for Unit
1 was being rebuilt during our walkdown. All of the boiler feedwater pumps have
been rebuilt within the last four years.
There is a program in place to inspect high-energy piping. Phase I of the
inspection program (initial pass at all high-energy systems) was completed in
1996-97. No work has been started on a second pass through the systems. There
were some deficiencies noted during the initial inspection of pipe saddles;
these are currently being rechecked.
All coal deliveries are by truck. Typically, a 30-day supply of coal is
maintained in the yard during winter, and 15 days supply in summer. The overall
appearance of the coal handling system is acceptable, with no noticeable
deterioration or corrosion of conveyor structural steel, transfer chutes, etc.
There have been no significant problems reported by station personnel for the
bottom ash system. No. 2 fuel oil is stored in two 15,000 gallon underground
tanks, and one 500,000 gallon above ground tank.
Overall housekeeping appearance indicated more coal dust than is normally
expected for a balanced draft unit. Visual observation indicated significant
peeling of boiler and ductwork asbestos insulation and lagging. There was no
significant settlement in structural foundations, or major leaks from
deteriorated roofing.
COMBUSTION TURBINE
Unit 3 has operated in peaking service since commercial operation. The last
major inspection and unit overhaul was completed in the early 1990's. The unit
has operated successfully to date. The Unit was successfully modified in
1995-1996 to accommodate water injection for NO(x) abatement in compliance with
CAA requirements. Water injection has been managed properly without serious
incident to date. No adverse conditions were observed or identified. No unusual
performance problems or degradation were noted. Upgrades, including improved
materials and controls, and replacement of degraded components are undertaken as
needed.
4.1.9 GILBERT STATION
Gilbert consists of five simple cycle units (C-1, C-2, C-3, C-4, and CT 9) and
four combined cycle CTs (CC5, CC6, CC7, and CC8) with a single ST.
C-1, C-2, C-3, and C-4 have each operated successfully in peaking service since
commercial operation. Each unit was successfully modified in 1995-1996 to
accommodate water injection for NO(x) abatement in compliance with CAA
requirements. Water injection has been managed properly without serious incident
to date. No major issues or adverse conditions were observed or identified. No
unusual performance
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problems or degradation were noted. Required upgrades, including improved
materials and controls, and replacement of degraded components have been
undertaken as needed. The physical appearance is satisfactory; functioning
equipment is clean and orderly; however, there is a general need for cleanup and
painting of structures. Corrosion does not appear to be a problem at this time.
CT 9, ABB GT-24, is a first of a kind advanced technology simple cycle unit that
utilizes innovative technology. CT 9 appears to be in satisfactory condition at
this time. The future operation of CT 9 is likely to meet expectations given
continued proper condition monitoring and maintenance practices.
The combined cycle units, CC5, CC6, CC7, and CC8 have operated as intermediate
and peaking units. They have operated successfully in peaking, spinning reserve,
and load-following service since commercial operation. These units no longer
operate in spinning reserve due to emissions limitations, but load frequency
control is possible. The most recent major inspections and unit overhauls were
completed in 1989 for CC5 and CC6, 1987 for CC7, and 1988 for CC8. Each unit was
modified in 1995 to accommodate water injection for NO(x) abatement in
compliance with CAA requirements. Water injection has been managed properly
without serious incident to date. No major issues or adverse conditions were
observed or identified. No unusual performance problems or degradation were
observed. Required upgrades, including improved materials and controls, and
replacement of degraded components have been undertaken as needed. The physical
appearance is satisfactory; functioning equipment is clean and orderly. There is
a general need for cleanup and painting of structures. Corrosion does not appear
to be a problem at this time. The overall unit condition is good.
ELECTRICAL AND CONTROLS
C-1, C-2, C-3, and C-4 are capable of black start, and the other units require a
back feed off the 230 kV switchyard. The station service transformer appears to
have been well maintained. The 250 V batteries were replaced in 1994. The
incoming feeds from the 13.8 kV switchyard as well as the medium voltage all
appear to be in good condition.
The ABB generator CT 9 went into operation in 1997. The electrical equipment
appears to be well maintained. The feed from the 230 kV yard to the 230 kV
step-up transformer is in excellent condition.
The C-1, C-2, C-3, and C-4 switchgear, although 30 years old, appears to be in
good condition. The circuit breakers were overhauled about two to three years
ago and the relays were recalibrated around the same time. The C-1 generator was
last megger tested in October 1995, C-2 in September 1996, C-3 in October 1993,
and C-4 in September 1995.
According to station personnel, preventive maintenance has been performed on CCs
4 through 7 last year including oil testing on the oil circuit breakers and
meggering the generators. There will be a CC6 generator outage in a few weeks at
which time the rotor is schedule to be rewound. On the steam turbine generator,
the rotor was rewound about four to six years ago. The generator received
preventive maintenance in 1998 and 1999 and was megger tested. The control room
is maintained in good condition. The three main step-up transformers, although
28 years old, all appear to be in good condition.
The general impression of this station is that it has received necessary
preventive maintenance and the electrical/controls equipment is in good
condition.
4.1.10 COMBUSTION TURBINES
The CTs include simple cycle units at the following locations: Blossburg,
Hamilton, Hunterstown, Mountain, Orrtanna, Shawnee, Tolna, Wayne, Glen Gardner,
and Werner.
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All units have been in peaking service since their commercial operation date.
The most recent major inspection and overhaul of each of the units were in the
1990-1993 period. No significant adverse conditions were identified. No unusual
performance problems or degradation were noted. Required upgrades, including
improved materials and controls, and replacement of degraded components have
continued as needed. The physical appearance is satisfactory; functioning
equipment is clean and orderly; however, there is a general need for cleanup and
painting of structures. Corrosion does not appear to be a problem at this time.
The overall condition of the simple cycle CTs is good.
The generators appear to be in satisfactory condition and suitable for
continuous peaking service. There have been some problems with the rotor top
turn insulation at Mountain Unit 1 and Hunterstown Unit 1, which were repaired
in 1997 and 1998, respectively. The Werner CT 4 generator was being overhauled
during our visit. All of the outdoor electrical equipment appears to be in good
condition but is weathered.
There is an inherent concern with the Frame 5 generators in that some rotors
were manufactured with non-magnetic 18Mn-5Cr retaining rings, which have a
history of possible failure while in service. Mountain Unit 1, Titus 5, and both
Tolna Units 1 and 2 have 18Mn-5Cr retaining rings. GE has developed a suitable
non-destructive, in place, ultrasonic test method to determine the condition of
these suspect rings. The Mountain Unit 1 and Tolna Unit 1 generator rotors were
inspected by GE using this method and were found to be in satisfactory
condition. Current scheduling is to perform this test on each affected unit
every five years.
The generator circuit breakers in each unit were modified during the major unit
overhauls. The Glen Gardner generator circuit breakers were replaced between
1994 and 1996. The protective relays are satisfactory for continued use as long
as they are maintained and calibrated on schedule. The DC batteries and chargers
for all of the units were replaced during their major overhauls with the
exception of the 60 cell batteries at Werner, which are 15 years old. A diesel
driver is used to start each CT. These diesels appear to operate satisfactorily
as indicated by the high percentage of successful combustion starts.
The overall impression of the CT electrical equipment is that it appears to be
in good condition, and according to the plant personnel preventive maintenance
is ongoing.
4.1.11 PINEY STATION
The Piney units can be operated in three modes of control: local-manual,
local-auto, and remote. The units are capable of providing load regulation of 2
to 8 MW per unit, spinning reserve, and voltage support.
CIVIL STRUCTURES
Piney owns the dam, the lake, and the shoreline. The civil structures appear to
be in good condition, with some surface deterioration on the face of the dam.
Since 1997, a repair program has been addressing the surface condition of the
dam. No dam repair work has been scheduled for the year 2000. About 40% of the
total planned effort has been completed.
MECHANICAL EQUIPMENT
All three units were operating at the start of the site visit. All three units
began shutting down, by remote dispatch, during the course of the visit. One
turbine runner was available for inspection, on the powerhouse floor. This
runner had been removed from Unit 1 and had been replaced by the spare runner
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that had been supplied as part of the original equipment. The old runner
exhibited the usual wear and tear but in addition it had pieces missing from the
trailing edges of nine of the sixteen blades. The blades with the pieces broken
off were not in sequence; there were intact blades between some of the broken
blades. That condition would suggest that the blades were not broken by a piece
of trapped metal. The condition might be related to pulsations often caused by
draft tube vortexes.
It is possible that the runners can continue to be repaired. If, however, a
runner replacement is considered, given current technology, a capacity increase
on the order of 20% may be obtained. It is recommended that if the runners are
replaced that it is determined whether the new runners are compatible with the
existing draft tube.
ELECTRICAL AND CONTROLS
The generators are in satisfactory condition with the last major inspection and
rebuilding of the stators (except Unit 2) and rotors completed in period between
1985 and 1987. The 12 kV station service switchgear was replaced in 1985. The
250 V DC lead calcium station battery appears to be in good condition, however,
it is near the end of reliable service life.
4.1.12 DEEP CREEK STATION
CIVIL STRUCTURES
The structures at Deep Creek appear to be in very good condition, to the extent
that these items were visible. Deep Creek has an earth fill dam with a long
overflow weir at the right-bank. We understand that considerable remedial work
was performed in the recent past and that the present condition requires only
normal O&M. The dam and associated structures appear to be in excellent
condition during the site visit. Station personnel advised that there had been
only three minor incidents of spillage in the history of the plant. That
statistic suggests that the turbine capacity is quite high relative to the
potential for flood formation.
MECHANICAL EQUIPMENT
The equipment at Deep Creek appears to be in very good condition, to the extent
that these items were visible. Station personnel advised that the turbine
runners were replaced, in 1972 and 1973, with new runners made of steel with
stainless steel overlay. A brief review of the parameters suggests that the
available diameter would support a further capacity increase but the tail water
level does not appear to provide cavitation protection for the existing
capacity. A capacity increase would serve only to shift more energy from
off-peak to on-peak. There would be no increase in total energy because of the
almost complete absence of spillage.
ELECTRICAL AND CONTROLS
The electrical equipment is maintained in good condition and the generating
units appeared to be operating satisfactorily.
4.2 REMAINING LIFE
Fossil power plants have been traditionally designed for an expected useful life
of 25 years. However, industry experience has shown that fossil plants can be
operated safely well beyond 40 years. The question becomes whether an additional
service life can be achieved at a reasonable cost.
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There are only a few technical issues that can lead to an abrupt or unpredicted
end of life of an electric generating station. These include the following:
o serious site flooding and other natural disasters
o geotechnical problems such as severe settling
o catastrophic failure of a major component which causes substantial
collateral damage
In addition, there are certain technical and environmental issues that affect
the economic viability of electric generating stations such as the imposition of
new restrictive environmental criteria such as additional limits on NO(x),
SO(2), fine particulate (sub 2.5 microns) and air toxics emissions.
In most cases, decisions to retire generating units are made for economic
reasons, which may be the result of technical or environmental issues. The cost
of replacing major equipment components such as boiler drums, furnaces,
superheaters, turbine rotor and casings, generator fields and stators, and
step-up transformers is often the most limiting factor in extending station
life. Therefore, life expectancy is evaluated in terms of the remaining life of
the costly major components. Generally, it is economical to repair or replace
the balance of plant equipment on an as-needed basis to sustain continued
operation.
While there is limited experience with the operation of electric generating
stations for 60 to 70 years, the technical factors, which may cause a unit to be
retired, are known. The primary technical reasons that would cause units to be
retired are likely to be fatigue and creep damage to major components such as
the boiler and turbine-generator. Many of the Facilities have accumulated
sufficient operating hours to begin to show wear. In order to operate the
Facilities to the projected retirement dates, REMA will need to perform
condition monitoring programs including nondestructive testing. REMA has
prepared an extensive review of the condition at each of the facilities and
included in the budget sufficient funds to extend the facilities life to the
projected retirement date. With proper operation and maintenance and continual
funding of required capital and overhaul expenses, all the units should be
capable of operating to the retirement dates projected by REMA.
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The following table summarizes the remaining life that REMA is projecting for
each of the Facilities.
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REMAINING LIFE OF THE FACILITIES AS PROJECTED BY REMA
================================================================================================
AGE AS OF JANUARY 1, ESTIMATED
STATION 2000 RETIREMENT DATE REMAINING LIFE
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Conemaugh Station
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Unit 1 30 2044 More than 30 years
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Unit 2 29 2044 More than 30 years
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Four Diesel 2044 More than 30 years
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Keystone Station
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Unit 1 33 2044 More than 30 years
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Unit 2 33 2044 More than 30 years
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Four Diesel 2044 More than 30 years
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Shawville Station
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Unit 1 46 2034 More than 30 years
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Unit 2 46 2034 More than 30 years
- ------------------------------------------------------------------------------------------------
Unit 3 40 2034 More than 30 years
- ------------------------------------------------------------------------------------------------
Unit 4 40 2034 More than 30 years
- ------------------------------------------------------------------------------------------------
Three Diesels 37 2034 More than 30 years
- ------------------------------------------------------------------------------------------------
Portland Station
- ------------------------------------------------------------------------------------------------
Unit 1 42 2024 25 years
- ------------------------------------------------------------------------------------------------
Unit 2 38 2024 25 years
- ------------------------------------------------------------------------------------------------
Three CTs 6-33 2029 30 years
- ------------------------------------------------------------------------------------------------
Seward Station
- ------------------------------------------------------------------------------------------------
Unit 4 50 2010 11 years
- ------------------------------------------------------------------------------------------------
Unit 5 43 2010 11 years
- ------------------------------------------------------------------------------------------------
Titus Station
- ------------------------------------------------------------------------------------------------
Unit 1 49 2024 25 years
- ------------------------------------------------------------------------------------------------
Unit 2 49 2024 25 years
- ------------------------------------------------------------------------------------------------
Unit 3 47 2024 25 years
- ------------------------------------------------------------------------------------------------
Two CTs 30-33 2029 30 years
- ------------------------------------------------------------------------------------------------
Sayreville Station
- ------------------------------------------------------------------------------------------------
Unit 1 45 2010 11 years
- ------------------------------------------------------------------------------------------------
Unit 2 42 2010 11 years
- ------------------------------------------------------------------------------------------------
Four CTs 27-28 2029 11 years
- ------------------------------------------------------------------------------------------------
Warren Station
- ------------------------------------------------------------------------------------------------
Unit 1 52 2010 11 years
- ------------------------------------------------------------------------------------------------
Unit 2 51 2010 11 years
- ------------------------------------------------------------------------------------------------
One CT 28 2029 11 years
- ------------------------------------------------------------------------------------------------
Gilbert Station
- ------------------------------------------------------------------------------------------------
Five CCs 23-26 2029 30 years
- ------------------------------------------------------------------------------------------------
Five CTs 3-30 2029 30 years
- ------------------------------------------------------------------------------------------------
Combustion Turbines
- ------------------------------------------------------------------------------------------------
Blossburg 28 2029 30 years
- ------------------------------------------------------------------------------------------------
Glen Gardner 30 2029 30 years
- ------------------------------------------------------------------------------------------------
Hamilton 29 2029 30 years
- ------------------------------------------------------------------------------------------------
Hunterstown 29 2029 30 years
- ------------------------------------------------------------------------------------------------
Mountain 28 2029 30 years
- ------------------------------------------------------------------------------------------------
Orrtanna 29 2029 30 years
- ------------------------------------------------------------------------------------------------
Shawnee 28 2029 30 years
- ------------------------------------------------------------------------------------------------
Tolna 28 2029 30 years
- ------------------------------------------------------------------------------------------------
Wayne 28 2029 30 years
- ------------------------------------------------------------------------------------------------
Werner 28 2029 30 years
- ------------------------------------------------------------------------------------------------
Hydroelectric Stations
- ------------------------------------------------------------------------------------------------
Piney 76 2029 30 years
- ------------------------------------------------------------------------------------------------
Deep Creek 77 2029 30 years
================================================================================================
Conemaugh and Keystone were found to be in excellent condition considering their
age and high capacity factor usage. The boilers at each station are identical
supercritical units and were retrofitted with low
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NO(x) burners and overfire air between 1993 and 1994. This change to the boilers
resulted in severe tube wall wastage due to the reducing (low oxygen) atmosphere
in the furnace and a solution has been implemented to correct the problem. An
estimated 80% of the affected areas in the Conemaugh boilers have been overlaid
and additional metal areas on the sidewalls are planned to be overlaid in the
near future. This material upgrade has shown no evidence of short-term
degradation and appears to represent an acceptable long-term solution to tube
wastage. The tube wastage problem at the Keystone boilers have been treated in a
different manner with the affected areas being replaced with chromized waterwall
panels.
The replacement of the waterwall sections in the Keystone boilers is taking
place in three phases with a target for completion in 2002. This material
replacement has shown no evidence of short-term degradation and appears to
represent an acceptable long-term solution to tube wastage.
The four Shawville units are 40 and 46 years old and have operated in baseload
operation. Operation until the projected 2034 plant retirement will require
ongoing NDE and component surveillance. Severe boiler waterwall wastage due to
low NO(x) firing will require extensive tube inspection and possible replacement
with corrosion resistant chromized tubes. Cracks in the Unit 1 and 2 steam chest
attachment welds to the HP shells may require extensive repairs or a complete
shell replacement may be preferred. Units 3 and 4 have experienced HP/IP inner
and outer shell cracking and replacement may be required to meet the projected
retirement date. HP casing distortion and diaphragm dishing are another
indication of possible turbine repairs. The condensers and most of the feedwater
heaters are reported to be in fair condition with condenser retubing and heater
replacement probable to maintain an acceptable forced outage rate. Ongoing NDE
and component inspections will be required to operate reliably for over 30
years.
The Portland Units 1 and 2 can be operated reliably until their projected
retirement in 2024. Both units appear to be in good condition and have been
properly maintained. The plant design was essentially comparable to current
state of the art with only a few exceptions. The design main steam temperature
of 1050 degrees F is 50 degrees F higher (approximately 5%) than most current
boiler designs. Although this increases efficiency, it also tends to increase
creep damage and may accelerate consumption of life. In order to operate for 24
additional years, the high temperature boiler, turbine, and piping components
should continue to be NDE tested.
There appears to be a history of significant boiler waterwall ash corrosion at
Portland, which will require extensive retubing over the next ten years. Unit 1
will also require a reheater replacement. The cracked Unit 1 HP inner shell
replacement has been postponed and the crack has been monitored for further
growth. The Unit 1 HP inner shell replacement may be considered for the next
major overhaul after inspection.
Seward, when inspected, was found to be in fair and serviceable condition for
the current service. Since the boilers were converted to residual oil and later
to natural gas, lower furnace screen tube overheated and were replaced with
rifled tubes leading to higher furnace heat absorption and reduced steam
temperature to the turbines. This would tend to extend boiler and turbine life.
The Seward units are capable of operating until the planned plant retirement in
2010. Routine maintenance is recommended to comply with insurance and safety
requirements. Surveillance of known problem areas should continue with repairs
and replacement to meet the projected retirement date of 2010.
The Sayreville Units 4 and 5 are 45 years old but should be capable of continued
peaking service until the projected retirement date in 2010. The boilers were
found to be in marginal condition due to continued lower furnace tube failures,
which required a reduction in operating steam pressure. The integral steam chest
turbine configuration may exhibit HP casing girth weld cracking due to cycling.
Turbine inlet
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- --------------------------------------------------------------------------------
nozzle and LP bucket erosion is increasing primarily due to the impact of
cycling. Inner shell cracking has been weld repaired but may reappear with use.
Rotor bore indications were removed from the Unit 5 rotor by overboring.
Additional indications were detected in 1987.
It is assumed that much of the existing electrical equipment and major balance
of plant mechanical auxiliaries are original. The projected 10 years of
additional peaking life can be expected to result in some component failures.
Only routine maintenance to address these problems should be performed.
Titus was found to be in very good condition considering its age of 50 years.
The Titus plant staff was found to be motivated, competent and well trained. The
units have been operated in baseload and intermediate service minimizing cycling
damage usually found on similar units. These turbines belong to a large class of
duplicate units with well-defined component history and risks. The steam chest
attachment weld cracking on Unit 1 does indicate that replacement of the HP
turbine shells will be required to operate until the anticipated 2024
retirement. LP turbine bucket erosion damage will probably require eventual
replacement. HP nozzle and blade replacements should also be planned. As in the
case of other base loaded units of this vintage, it may ultimately be preferable
to plan a turbine replacement rather than piecemeal component replacement.
Previous NDE findings should be reviewed to focus future inspections and
repairs.
Warren was found to be very clean and appeared to be in good condition for its
age of 52 years. The boiler waterwall tubes are in poor condition, particularly
on Unit 1. Although the turbines have not been overhauled in over 10 years, the
plant is used for intermediate and peaking service. It should be capable of
operating in this mode until the planned retirement in 2010. The only
significant impediment to extended life is the extension of the ash disposal
area or opening a new disposal area. Only routine equipment maintenance is
recommended although funds have been budgeted to replace boiler waterwall tubes
at each inspection outage. Leaking tubes are customarily replaced as identified
through hydrostatic testing. There is no indication from plant interviews of
turbine component cracking or distortion. This is attributed to the relatively
low design steam pressures and temperatures at Warren resulting in reduced
stress levels.
The simple cycle and combined cycle CTs were found to be in good condition.
There are 37 simple cycle units, which were installed between 1967 and 1974 and
operate in peaking service at average capacity factors less than 1% through
1997, and less than 3% in 1998 and 1999. These units are relatively low
temperature, low efficiency units by modern standards that appear to have been
properly maintained. They can continue to be operated in typical peaking service
until, their projected retirement in 2029. The manufacturers recommended
inspection intervals are based on a number of starts and hours of operation.
These intervals must be followed to assure reliable starting and operation. Most
are remotely operated and monitored at unmanned locations. A routine preventive
maintenance program has effectively supported reliable starting and operation of
these units in the past. The unit housings and enclosures must be painted and
weather sealed to protect the equipment. Gaskets, seals and rubber belts that
deteriorate with time must be replaced independently of operating hours. GE and
Westinghouse can be expected to supply parts into the future since this
represents a profitable business.
The ABB GT-24 unit at Gilbert was installed in 1995 and placed in commercial
operation in December of 1997. The operating efficiency is much better than the
older simple cycle units, and its design is favorable for future conversion to
combined cycle. Because of its superior efficiency, CT 9 will be dispatched at a
higher priority than the older units. Consequently it will see more frequent
starts, and more operating hours than the older simple cycle units. At 183 MW,
this unit is much larger than the above simple cycle units which are rated in
the 20 to 70 MW range. The unit is a first of a kind advanced technology design;
as such, it has received priority attention of the manufacturer and appears to
be in good condition. Although its availability has been below average, it is
expected to operate reliably
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through the projected 2029 retirement provided the manufacturer's maintenance
recommendations are followed.
The Siemens V 84.3 CT at Portland is a very efficient unit rated at 156 MW,
which was installed in 1997. The operating availability and reliability in 1998
and 1999 averaged 53%, which leads to an element of risk for this unit's
reliable long-term service through 2029. However, the unit is not forecasted to
perform above the historical levels. The Siemens V 84.3 unit is a first of a
kind design advanced technology unit. The manufacturer has provided intensive
support at Portland to resolve many of the developmental problems but a high
level of continued monitoring and maintenance can be expected. The manufacturer
has discontinued this specific model.
There are four duplicate combined cycle CT units at Gilbert that were installed
in 1974. These are more efficient than peaking units when operated in
combination with Heat Recovery Steam Generators ("HRSG") and a steam turbine
generator. The units operate at higher capacity factors than the simple cycle
units, averaging about 14% in recent years. The HRSGs were found to be in good
condition but economizer and some tube replacements can be expected for
continued operation through 2029. There have already been some economizer inlet
header tube leaks that may require at least partial tube replacement. The four
CTs will require the adherence to the manufacturer's inspection and maintenance
intervals.
There is extensive CT industry experience in the U.S. with similar units, which
have 30 years of service. These units will be approaching 60 years at
retirement. This 60-year life is attainable through continued adherence to the
manufacturer's recommendations and unit duty, which represents low annual usage.
Industry experience has shown that major components will degrade with time and
service. These components are rebuilt or replaced at scheduled outages, and the
units are typically restored to new or better than new conditions when improved
design and materials are used for replacement parts. Industry experience has
shown that old units are not ordinarily retired because of age. They are retired
because they are no longer needed, or because the economics of modern technology
offer more attractive alternatives.
Hydroelectric stations typically have long lives because their major components
are civil structures. With proper maintenance, the structures at Piney and Deep
Creek should remain useable over the life projected by REMA. Individual
equipment items may continue to need replacement from time to time as part of
the ongoing maintenance effort.
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5. ENVIRONMENTAL ASSESSMENT
Stone & Webster's environmental review and assessment of the Facilities is
focused on those environmental issues that have the potential to result in
significant mitigation expenditures or operating constraints.
The environmental assessment provided in this report is based on the results of
the following:
o an inspection of each electric generating station and associated
facilities such as fuel handling and storage and waste disposal
facilities
o interviews with environmental personnel at each station
o review of available environmental documents and records
The environmental assessment addresses liabilities assumed by REMA and issues
related to air quality, wastewater treatment and discharge, ash reuse/disposal,
site contamination, and other environmental topics.
5.1 AIR QUALITY
The major air quality issues affecting the thermal units include the following:
o Compliance with NO(x) emission limitations under the Clean Air Act
Amendment of 1990 ("CAAA") Title I (ozone attainment)
o Federal Acid Rain Program (SO(2) and NO(x))
o Demonstration of attainment with National Ambient Air Quality
Standards ("NAAQS") for SO(2) at various stations
5.1.1 AIR PERMITS AND EMISSION CONTROL SYSTEMS
Title V Operating Permit applications have been submitted in a timely manner for
each of the thermal units and each have been deemed administratively complete by
the appropriate regulatory agency. Therefore, the units are currently operating
under a permit shield pending issuance of a new five-year operating permit under
Title V of the CAAA.
The thermal generating units are subject to NO(x) Reasonably Available Control
Technology ("RACT") limitations, which became effective May 1995. Each of the
coal-fired generating units is affected by the Title IV NO(x) rules of the CAAA.
The unit-specific requirements for NO(x) RACT and Title IV NO(x) rules are
summarized below along with actual NO(x) emissions from 1999.
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- --------------------------------------------------------------------------------
=========================================================================================================
NO(x) RACT AND TITLE IV NO(x) RULES
=========================================================================================================
1999 ANNUAL 1999 OZONE
NO(x) RACT TITLE IV NO(x) AVERAGE NO(x) SEASON NO(x)
LIMIT(1) LIMIT(2), (3) EMISSION RATE EMISSION RATE
GENERATING UNIT (lb/mmBtu) (lb/mmBtu) (lb/mmBtu) (lb/mmBtu)
- ---------------------------------------------------------------------------------------------------------
Conemaugh 1 0.45 0.45 0.34 0.26
- ---------------------------------------------------------------------------------------------------------
Conemaugh 2 0.45 0.45 0.32 0.25
- ---------------------------------------------------------------------------------------------------------
Keystone 1 0.45 0.40 0.34 0.30
- ---------------------------------------------------------------------------------------------------------
Keystone 2 0.45 0.40 0.34 0.30
- ---------------------------------------------------------------------------------------------------------
Shawville 1 0.524 0.50 0.43 0.40
- ---------------------------------------------------------------------------------------------------------
Shawville 2 0.542 0.50 0.46 0.46
- ---------------------------------------------------------------------------------------------------------
Shawville 3 0.45 0.45 0.38 0.33
- ---------------------------------------------------------------------------------------------------------
Shawville 4 0.45 0.45 0.38 0.33
- ---------------------------------------------------------------------------------------------------------
Portland 1 0.37 0.45 0.24 0.21
- ---------------------------------------------------------------------------------------------------------
Portland 2 0.58 0.45 0.28 0.23
- ---------------------------------------------------------------------------------------------------------
Seward 4 - Boiler 12 0.82 0.46 0.62 0.66
- ---------------------------------------------------------------------------------------------------------
Seward 4 - Boiler 14 0.50 0.46 0.44 0.45
- ---------------------------------------------------------------------------------------------------------
Seward 5 0.51 0.40 0.45 0.44
- ---------------------------------------------------------------------------------------------------------
Titus 1 0.45 0.45 0.33 0.27
- ---------------------------------------------------------------------------------------------------------
Titus 2 0.45 0.45 0.34 0.25
- ---------------------------------------------------------------------------------------------------------
Titus 3 0.45 0.45 0.31 0.25
- ---------------------------------------------------------------------------------------------------------
Sayreville 4 0.43 N/A 0.26 0.27
- ---------------------------------------------------------------------------------------------------------
Sayreville 5 0.43 N/A 0.29 0.29
- ---------------------------------------------------------------------------------------------------------
Warren 1 0.62 0.46 0.52 0.49
- ---------------------------------------------------------------------------------------------------------
Warren 2 0.62 0.46 0.52 0.49
=========================================================================================================
(1) For PA units, limits based on 30-day rolling averages. For NJ units,
limits based on daily averages for ozone season and 30-day rolling
averages for the remaining period of the year.
(2) Limits based on annual averages.
(3) Sithe has submitted a Phase II NO(x) averaging plan to USEPA for the
Portland, Seward and Warren affected units.
In addition to NO(x) RACT and Title IV NO(x) rules, there are NO(x) programs
that are based on cap and trade systems, which allow system-wide NO(x)
compliance strategies. This includes the New Jersey and Pennsylvania NO(x)
Budget Rules, the NO(x) State Implementation Plan ("SIP") Call, and Section 126
Final Rulemaking. Additional discussion concerning these programs is provided in
Section 5.2.2.
SO(2) emissions at all of the thermal units, except Conemaugh Units 1 and 2, are
limited by fuel sulfur content. Conemaugh Units 1 and 2 use a FGD system to
reduce SO(2) emissions by approximately 97 to 98%. ESPs are installed on all of
the coal-fired thermal units to control particulate matter emissions and
opacity. Combustion NO(x) control is utilized on all of the thermal units,
except Sayreville Units 4 and 5 and Seward Unit 5. Seward Unit 5 currently uses
a hybrid NO(x) control system that uses SNCR in combination with SCR to reduce
NO(x) emissions. Portland Unit 5 has dry low NO(x) combustors for operation on
natural gas and water injection when firing oil.
Each of the thermal units is reported to be operating in general compliance with
applicable air emission limits. They are reported to operate without any
currently effective consent orders, stipulated emission limitations, or air
quality compliance plan requirements. Although there are occasional exceedances
in air emission limits, they do not indicate a consistent pattern of
noncompliance. On occasion, good operating practices, such as temporary load
reductions, are employed to avoid exceedances of air emission limits.
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The CTs at the thermal stations have restrictions on operating hours. Hagler
Bailly has taken these operating restrictions into account. These operating
restrictions are summarized below:
=================================================================================
OPERATING RESTRICTIONS
=================================================================================
GENERATING UNIT(S) HOURS/YEAR
- ---------------------------------------------------------------------------------
Portland Units 3 and 4 438
- ---------------------------------------------------------------------------------
Portland Unit 5 3,600 on gas, 1,980 on fuel oil
- ---------------------------------------------------------------------------------
Titus Unit 4 1,650 on gas, 150 on fuel oil
- ---------------------------------------------------------------------------------
Titus Unit 5 925 on gas, 150 on fuel oil
- ---------------------------------------------------------------------------------
CTs 3,000 total, 1,000 on fuel oil
- ---------------------------------------------------------------------------------
Warren CT 438
=================================================================================
Corrective action for excess NO(x) emissions at Portland Unit 5 resulted in an
operating output derate of approximately 15 MW to maintain NO(x) emissions below
the permitted limit.
5.2 SYSTEM-WIDE AIR EMISSIONS COMPLIANCE PROGRAMS
The thermal stations primarily affect the system-wide compliance plans for SO(2)
and NO(x). However, these programs also include selected CT sites. Therefore,
the following discussions also include the CT sites where appropriate.
5.2.1 SO(2) COMPLIANCE PLANS
Title IV of the CAAA requires that nationwide SO(2) emissions be reduced by 10
million tons per year from 1980 levels by the year 2000. Title IV provides for a
two-phase approach in meeting these reductions. Phase I began in 1995 and
required the 263 affected utility units to reduce SO(2) emissions. Phase II
starts in the year 2000 and restricts affected utility unit emissions to
allowances based on an emission rate of 1.2 lbs/mmBtu and the 1985 to 1987
baseline fuel usage. These allowances are a marketable commodity. Units that
emit less than their allocated allowances may save the unused allowances for
future growth, transfer them to other plants, or sell them to other utilities
that exceed their allowance allocations.
All of the thermal stations are affected by Title IV SO(2) requirements. The
Phase II SO(2) allowance allocations for each of the thermal stations are listed
on the following page.
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- --------------------------------------------------------------------------------
================================================================================
SO(2) ALLOWANCE ALLOCATIONS
================================================================================
SO(2) ALLOWANCES SO(2) ALLOWANCES
STATION (2000-2009) (2010+)
- --------------------------------------------------------------------------------
Conemaugh 8,993 9,011
- --------------------------------------------------------------------------------
Keystone 9,710 9,730
- --------------------------------------------------------------------------------
Shawville 21,061 21,103
- --------------------------------------------------------------------------------
Portland 6,971 6,986
- --------------------------------------------------------------------------------
Seward 7,192 7,206
- --------------------------------------------------------------------------------
Titus 6,614 6,074
- --------------------------------------------------------------------------------
Sayreville 1,742 1,744
- --------------------------------------------------------------------------------
Warren 2,920 2,924
- --------------------------------------------------------------------------------
Werner 194 195
- --------------------------------------------------------------------------------
Williamsburg(1) 935 936
- --------------------------------------------------------------------------------
Gilbert 3,191 3,196
- --------------------------------------------------------------------------------
TOTAL 69,523 69,105
================================================================================
(1) Allowances available from retired units
Listed below for each of the affected units are annual SO(2) emission rates for
1998 and 1999.
======================================================================================
SO(2) EMISSION RATES
======================================================================================
1998 SO(2) EMISSION 1999 SO(2) EMISSION
GENERATING UNIT RATE (lb/mmBtu) RATE (lb/mmBtu)
- --------------------------------------------------------------------------------------
Conemaugh Unit 1(1) 0.12 0.13
- --------------------------------------------------------------------------------------
Conemaugh Unit 2(1) 0.12 0.12
- --------------------------------------------------------------------------------------
Keystone Unit 1 2.78 2.61
- --------------------------------------------------------------------------------------
Keystone Unit 2 2.76 2.69
- --------------------------------------------------------------------------------------
Shawville Unit 1 3.05 2.99
- --------------------------------------------------------------------------------------
Shawville Unit 2 3.00 2.98
- --------------------------------------------------------------------------------------
Shawville Unit 3 2.71 2.75
- --------------------------------------------------------------------------------------
Shawville Unit 4 2.71 2.75
- --------------------------------------------------------------------------------------
Portland Unit 1 2.28 2.57
- --------------------------------------------------------------------------------------
Portland Unit 2 2.21 2.47
- --------------------------------------------------------------------------------------
Seward Unit 4 2.51 2.44
- --------------------------------------------------------------------------------------
Seward Unit 5 2.51 2.44
- --------------------------------------------------------------------------------------
Titus Unit 1 2.21 2.16
- --------------------------------------------------------------------------------------
Titus Unit 2 2.17 2.12
- --------------------------------------------------------------------------------------
Titus Unit 3 2.23 2.07
- --------------------------------------------------------------------------------------
Sayreville Unit 4 0.03 0.00
- --------------------------------------------------------------------------------------
Sayreville Unit 5 0.10 0.00
- --------------------------------------------------------------------------------------
Warren Unit 1 2.75 2.69
- --------------------------------------------------------------------------------------
Warren Unit 2 2.75 2.69
======================================================================================
(1) Conemaugh has an FGD system that treats the flue gas from Units 1 and
2.
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REMA has developed an SO(2) compliance plan that incorporates the following
activities to lower the SO(2) emissions.
==========================================================================================================
SO(2) COMPLIANCE PLAN
==========================================================================================================
CONTROLLED SO(2) EMISSION
GENERATING UNIT ACTIVITY EFFECTIVE DATE RATE (lb/mmBtu)
----------------------------------------------------------------------------------------------------------
Keystone Unit 1 FGD Retrofit 2024 0.14
----------------------------------------------------------------------------------------------------------
Keystone Unit 2 FGD Retrofit 2025 0.14
----------------------------------------------------------------------------------------------------------
Shawville Units 1 and 3 FGD Retrofit 2026 0.14
----------------------------------------------------------------------------------------------------------
Shawville Units 2 and 4 FGD Retrofit 2026 0.14
----------------------------------------------------------------------------------------------------------
Seward Units 4 and 5 Retirement 2011 N/A
----------------------------------------------------------------------------------------------------------
Sayreville Units 4 and 5 Retirement 2011 N/A
----------------------------------------------------------------------------------------------------------
Warren Units 1 and 2 Retirement 2011 N/A
==========================================================================================================
The addition of FGDs at Keystone and Shawville is based on REMA's assumption of
New Source Review ("NSR") requirements affecting these facilities during the
years 2021 to 2027. The near term strategy for SO(2) compliance is to purchase
or transfer SO(2) allowances. Stone & Webster has estimated the annual SO(2)
emissions and the required SO(2) allowances for the thermal units based on the
proposed SO(2) compliance plans from REMA. The annual SO(2) emissions are based
on the capacity factor projections developed by Hagler Bailly, existing SO(2)
emission rates (1999), and the controlled SO(2) emission rates listed above. The
SO(2) allocations are assumed to equal the Title IV allocations listed earlier.
The estimated SO(2) allowance purchases are as follows:
==============================================================
SO(2) ALLOWANCE PURCHASES
- --------------------------------------------------------------
AVERAGE ALLOWANCE PURCHASE
TIME PERIOD (TONS/YEAR)
- --------------------------------------------------------------
2000 to 2010 97,000
- --------------------------------------------------------------
2011 to 2025 72,000
- --------------------------------------------------------------
2021 to 2030 (37,000) sales
==============================================================
The decrease in allowance requirements in the years 2011 to 2020 is primarily
due to the retirement of the units at Sayreville, Seward, and Warren. The
addition of FGDs at Keystone and Shawville in the post 2020 time frame as well
as the retirement of the units at Portland and Titus further decreases the SO(2)
allowance requirements.
5.2.2 NO(x) COMPLIANCE PLANS
The Pennsylvania and New Jersey Phase II NO(x) Budget programs establish
specific NO(x) emission allowances and a trading program to limit NO(x)
emissions during the ozone season (May through September) for the years 1999
through 2002.
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- --------------------------------------------------------------------------------
The NO(x) allowance allocations for each of the affected stations for Phase II
are as follows:
========================================================
NO(x) ALLOWANCE ALLOCATIONS
========================================================
NO(x) ALLOWANCES
STATION (1999-2002)
--------------------------------------------------------
Conemaugh 1,232
--------------------------------------------------------
Keystone 1,299
--------------------------------------------------------
Shawville 3,473
--------------------------------------------------------
Portland 1,121
--------------------------------------------------------
Seward 964
--------------------------------------------------------
Titus 593
--------------------------------------------------------
Warren 306
--------------------------------------------------------
Williamsburg(1) 38
--------------------------------------------------------
PA CT Sites 89
--------------------------------------------------------
Gilbert 262
--------------------------------------------------------
Glen Gardner 34
--------------------------------------------------------
Sayreville 89
--------------------------------------------------------
Werner 29
--------------------------------------------------------
General Account 510
--------------------------------------------------------
TOTAL 10,056
========================================================
(1) Allowances available from retired units
Stone & Webster compared projections of ozone season (May through September)
NO(x) emissions to the Phase II NO(x) allocations for the affected units for the
years 2000 through 2003. This comparison is shown below.
====================================================================================
NO(x) EMISSIONS TO PHASE II NO(x) ALLOCATIONS COMPARISON
====================================================================================
2001 2002
------------------------------------------------------------------------------------
Total Ozone Season NO(x) Emissions (tons) 9,463 9,341
------------------------------------------------------------------------------------
Total NO(x) Allowances 10,056 10,056
------------------------------------------------------------------------------------
Surplus Allowances 593 715
====================================================================================
The projected ozone season NO(x) emissions are based on the capacity factor
projections provided by Hagler Bailly and the 1999-ozone season NO(x) emission
rates. The preceding table indicates that there are adequate NO(x) allowances to
cover the projected generation from the facilities during the Phase II period.
The actual 1999-ozone season NO(x) emissions were reported to total 8,951 tons
for the Facilities.
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- --------------------------------------------------------------------------------
FUTURE NO(x) REGULATORY PROGRAMS
On September 24, 1998, the U.S. Environmental Protection Agency ("EPA")
finalized a rule requiring 22 states and the District of Columbia to submit SIPs
to address the regional transport of ground-level ozone. The thermal generating
facilities would be effected by the SIP revisions. The final EPA rule contains a
state-by-state NO(x) emissions budget that applies to the ozone season (May
through September). A compliance date of May 1, 2003 is required by the final
SIP Call rules. On September 30, 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.
On March 3, 2000, a three-judge panel of the same court largely upheld the NO(x)
SIP Call rule allowing the EPA to move ahead with its plan. However, the panel
did not specifically lift the stay on the SIP submittals by the affected states
to the EPA, leaving the original schedule in doubt. It seems likely that the
delays caused by litigation will ultimately push the May 2003 compliance date
for the SIP Call out further.
Another set of statutory tools designed to remedy interstate pollution transport
is found in Section 126 of the CAAA. Section 126(b) authorizes states or
political subdivisions to petition the EPA for a finding that major stationary
sources in upwind states contribute significantly to "non-attainment" problems
in downwind states.
On December 17, 1999, the EPA decided to grant four of the eight petitions filed
in August, 1997 for the one-hour ozone standard: Connecticut, Massachusetts, New
York, and Pennsylvania. The EPA is planning on addressing the petitions from the
other four states (Maryland, New Jersey, Delaware, and the District of Columbia)
in the near future. 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. These stations include the Facilities located in Pennsylvania and New
Jersey. Each affected facility will participate in a federal NO(x) emissions
cap-and-trade program administered by the EPA. Under this program the facilities
are initially allocated annual NO(x) allowances by the EPA for the period 2003
through 2007 based on heat input and a NO(x) emission rate of 0.15 lb/mmBtu.
Sources must implement controls or acquire emission allowances to achieve their
budgets by May 1, 2003. Updated allocations will be based on output from
electric generating units. These allowances may be bought, sold, or traded
between affected sources and other private parties.
The State of Pennsylvania has issued draft final regulatory revisions
establishing an Interstate Ozone Transport Reduction Program. The draft final
regulation has been modified to be consistent with the emission limitations
established by the EPA in response to petitions submitted by Pennsylvania and
three other states under Section 126 of the CAAA. The draft final regulations
describe the process to establish state NO(x) budgets and allocate those budgets
to individual facilities. The budgets and allocations will be published at a
later date.
Appendix A of the Final Section 126 Rule lists NO(x) allocations for electric
generating units ("EGUs"). These allocations total 4,631 per year for REMA's
Pennsylvania facilities (based on REMA's share of Conemaugh and Keystone) for
the years 2003 through 2007. NO(x) allocations for subsequent control periods
are not known at this time.
New Jersey has issued proposed amendments to its NO(x) budget program that
addresses Phase III (2003 and beyond). The proposed amendments list an initial
NO(x) allowance allocation for the year 2003 for EGUs, plus formulas to be used
for future allocations. The initial NO(x) allowance allocations for the year
2003 for REMA's New Jersey assets total 341 allowances.
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REMA has developed a NO(x) compliance plan for meeting the requirements of the
Phase III NO(x) budgets.
=============================================================================================================
NO(x) COMPLIANCE PLAN
- -------------------------------------------------------------------------------------------------------------
CONTROLLED NO(x)
EFFECTIVE EMISSION RATE
GENERATING UNIT ACTIVITY DATE (lb/mmBtu)
- -------------------------------------------------------------------------------------------------------------
Conemaugh Unit 1 SCR Retrofit 2003 0.04
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Keystone Unit 2 LNB(1) Improvements/SCR Retrofit 2003 0.04
- -------------------------------------------------------------------------------------------------------------
Keystone Unit 1 SCR 2025 .04
- -------------------------------------------------------------------------------------------------------------
Shawville Unit 1 SNCR 2003 0.28
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Shawville Unit 2 SNCR 2003 0.32
- -------------------------------------------------------------------------------------------------------------
Shawville Units 3 and 4 SCR Retrofit 2003 0.04
- -------------------------------------------------------------------------------------------------------------
Shawville Units 1 and 2 SCR 2003 0.04
- -------------------------------------------------------------------------------------------------------------
Portland Unit 2 SNCR Retrofit 2003 0.16
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Seward Unit 4 Retirement 2011 N/A
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Seward Unit 5 LNB Retrofit/Replacement 2003 0.21
SNCR/SCR
- -------------------------------------------------------------------------------------------------------------
Sayreville Units 4 and 5 Retirement 2011 N/A
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Warren Units 1 and 2 Retirement 2011 N/A
=============================================================================================================
(1) LNB - Low NO(x) Burner
Stone & Webster compared projections of ozone season NO(x) emissions to the
initial NO(x) allowance allocations (2003-2007 for the Pennsylvania facilities
and 2003 for the New Jersey facilities). The projected ozone season NO(x)
emissions are based on the capacity factor projections provided by Hagler Bailly
and the NO(x) compliance plan listed above. For the period 2003 to 2029, the
NO(x) allowances per year ranged from a surplus of 1900 NO(x) allowances to 1000
NO(x) allowances that REMA would need to purchase.
5.2.3 SO(2) NAAQS COMPLIANCE ISSUES
Over the past several years, GPU had undertaken a number of dispersion modeling
impact assessments for its coal fired thermal plants relative to compliance with
the SO(2) NAAQS. These assessments have been prompted by a combination of
factors including the existence of SO(2) non-attainment areas in the vicinity of
the plants, their SO(2) emission rates, stack heights relative to Good
Engineering Practice ("GEP"), and complex terrain. These modeling studies have
resulted in some modifications of SO(2) emission rates below state standards and
may cause some additional SO(2) emission reductions or controls depending on the
outcome of regulatory reviews. The current status of the SO(2) NAAQS issues
relative and potential impact to the thermal plants is summarized below.
LAUREL/CHESTNUT RIDGE SO(2) NAAQS COMPLIANCE DEMONSTRATION: GPU conducted
extensive complex terrain (i.e., above stack top) dispersion modeling studies of
the impact of the Keystone, Conemaugh, Homer City, and Seward on SO(2)
concentrations in the Laurel/Chestnut Ridge area of Pennsylvania. An SO(2)
compliance demonstration was submitted to the Pennsylvania Department
Environmental Protection ("PaDEP") in December, 1998, which included modeling
studies using the EPA guideline model
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"RTDM" for Conemaugh and the non-guideline model "LAPPES" for Keystone, Homer
City, and Seward. Model comparison and evaluation reports were submitted to
demonstrate that "LAPPES" is the most appropriate model for this application, as
required by the EPA for the use of non-guideline models. Sithe staff members are
optimistic that the "LAPPES" model will be acceptable to the PaDEP and EPA
Region III.
The compliance demonstration report allows SO(2) emission rates that are less
than the SIP limits but higher than current actual emissions. These allowable
limits are as follows:
=============================================================================================================
SO(2) EMISSION MODEL COMPLIANCE DEMONSTRATION
- -------------------------------------------------------------------------------------------------------------
3-HR AVERAGE ANNUAL/24-HR AVERAGE
STATION SOURCE (lb/mmBtu) (lb/mmBtu)
- -------------------------------------------------------------------------------------------------------------
Conemaugh Units 1 and 2 0.20 0.20
- -------------------------------------------------------------------------------------------------------------
Keystone Units 1 and 2 3.55 3.45
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Homer City Units 1 and 2 3.10 3.05
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Homer City Units 3 1.20 1.20
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Seward Units 4 and 5 3.10 2.75
=============================================================================================================
At the request of the PaDEP, another modeling analysis was prepared and
submitted in July 1999. This analysis utilized the EPA AERMOD model, the next
generation dispersion model designed to supplant the heavily used Industrial
Source Complex ("ISC") model, that handles both simple and complex terrain.
AERMOD has not yet officially received "guideline" status but is expected to do
so at the next modeling conference. These modeling analyses were forwarded to
EPA Region III in December 1999 with no further contact being made to date.
SHAWVILLE: The modeling that has been performed for Shawville includes the use
of the actual stack height, which is greater than the GEP formula height. This
is only allowed if a fluid modeling study (i.e., wind tunnel modeling)
demonstrates that the actual height is justified as GEP due to terrain effects.
GPU has indicated that the fluid modeling study was performed and demonstrates
that the actual stack height meets the definition of GEP. The results of the
modeling studies demonstrate that three- and 24-hour SO(2) emission limits of
approximately 3.7 lb/mmBtu may be supportable. However, there is a possibility
that BART or emissions balancing with ERCs to an emission rate of 1.2 lb/mmBtu
could be imposed. Stone & Webster has estimated that, on average, approximately
19,000 ERCs would be required per year at Shawville Units 3 and 4 for the years
2000 to 2029 if the ratio is 1.2 lb/mmBtu. The likelihood of this outcome is
unknown at this time. Even though REMA is confident that ERCs will not be
imposed, an amount to cover their cost has been included in the financial model.
The estimated annual cost is $3.6 million per year.
SEWARD: The stack at Seward is higher than GEP formula height. There is also a
possibility that Best Available Retrofit Technology ("BART") or emissions
balancing with emission reduction credits ("ERCs") to an emission rate of 1.2
lb/mmBtu could be imposed at Seward. Stone & Webster has estimated that, on
average, approximately 7,000 ERCs would be required per year at Seward for the
years 2000 to 2010. The likelihood of this outcome is unknown at this time. Even
though REMA is confident that ERCs will not be imposed, an amount to cover their
cost has been included in the financial model. The estimated annual cost is $1.3
million per year.
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TITUS: Titus modeling analyses are tied to the fact that the stacks serving
Units 1 through 3 are not of GEP formula height, resulting in building downwash
effects causing higher ambient SO(2) impacts than would otherwise be the case.
The Titus SO(2) impact report was submitted to the PaDEP in February 1998 for
technical evaluation and not as a compliance report. The results of the modeling
indicate the possibility of 24-hour SO(2) emission limits of approximately 2.1
lb/mmBtu being imposed on these units (with the use of GEP stack height). REMA
has included capital costs for the addition of a new GEP stack at Titus.
Additional dispersion modeling was performed in 1999 using the AERMOD model,
producing somewhat less restrictive results than the earlier modeling (~ 2.4
lb/mmBtu). The AERMOD report has not been released and no further contact has
been made with the PaDEP.
PORTLAND: A dispersion modeling analysis has been performed for Portland to
demonstrate that it does not significantly contribute to the Warren County, New
Jersey SO(2) non-attainment area. The analysis was needed as a result of
modeling conducted by PP&L for its Martins Creek Station. Through participation
in a technical assessment group ("TAG") with EPA Regions II and III, PaDEP, New
Jersey Department Environmental Protection ("NJDEP"), and Pennsylvania Power and
Light ("PP&L"), GPU was able to provide a compliance demonstration, using the
AERMOD model and on-site meteorological data, supporting the continued use of
the existing SO(2) emission limits of 4.0 lb/mmBtu. The PaDEP submitted the
modeling analysis to EPA and NJDEP in February 2000.
WARREN: Dispersion modeling for Warren was conducted for the purpose of
addressing the SO(2) non-attainment area in Warren County, Pennsylvania. The
modeling was submitted to the PaDEP in May 1996 and subsequently submitted to
the EPA by PaDEP, referencing the station emission limits. Warren has been
issued a special permit for SO(2) with a more restrictive limit than imposed by
state regulations. These emission limits are 4.0 lb/mmBtu for a three-hour
period and 3.53 lb/mmBtu for 24-hour and annual average periods. These limits
have been incorporated into the draft Title V operating permit for the station.
5.3 WATER/WASTEWATER
5.3.1 CONEMAUGH
Conemaugh has a National Pollutant Discharge Elimination System ("NPDES")
permit, which expired in late 1998. The permit renewal application was filed
timely with the PaDEP on April 1, 1998, therefore the permit is on
administrative extension. The permit regulates discharges to the Conemaugh River
from multiple outfalls.
In February 1995, a Consent Order was signed which relates to acidity,
temperature, and residual chlorine in Conemaugh's discharge. The Consent Order
also provides for penalties for ongoing excesses of the permitted limits, and
especially for the scrubber wastewater treatment system discharge (Outfall 207).
For the years 1997 through 1999 a total of seventeen such exceedances were
recorded. Most discharge exceedances from Outfall 207 are for high selenium
concentrations.
PaDEP has established Water Quality Based Effluent Limitations ("WQBEL") to
protect aquatic life. In order to approach these as operating goals, Conemaugh
has agreed to perform a three year stream study, evaluate discharge toxics, and
assess modifications to the existing wastewater treatment systems. The first
year of the required three-year stream study was completed in early 1996, and is
awaiting approval of PaDEP before recommencing. It is not clear that any
equipment upgrades or replacement programs will
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be required within the next ten years as a result of these studies. However, the
study is being included in the pending discussions on renewal of the NPDES
permit.
NPDES sampling data for all other discharge points at Conemaugh were reported to
indicate current compliance with permit requirements. There are no other
outstanding water pollution control violations, enforcement issues or consent
orders for Conemaugh with PaDEP or EPA, nor reported public complaints regarding
water pollution from Conemaugh or its operational activities. There are no other
reported or known issues preventing reissuance of the NPDES Permit.
5.3.2 KEYSTONE
Keystone has an NPDES permit, which expires in November 2000. The permit
regulates two discharges to Crooked Creek and one to Plum Creek. The outfall to
Plum Creek is intake screen backwash water from the same creek. One of the
outfalls to Crooked Creek contains stormwater runoff from a vegetated area
adjacent to the cooling towers. The other outfall to Crooked Creek is the main
station outlet of the combined discharge lagoon, which includes:
o yard drainage from Unit 1
o bottom ash sump emergency overflow
o effluent from the sewage treatment plant
o low volume wastes from the industrial and final wastewater treatment
systems
o effluent from the ash ponds through the thermal pond
o yard drainage from Unit 2
o old ash disposal wetlands area discharge
o intake screen backwash
o transformer subyard drains
The thermal pond is concrete, polyethelene lined and was installed in 1995.
Prior to the installation of the thermal pond there were violations of the
thermal discharge limits at Keystone in the early 1990s. Since the installation
of the thermal pond there have not been any thermal discharge violations at
Keystone.
The existing permit calls for the application of WQBELs at the Keystone lagoon
discharge in 1998. To eliminate the need for or lessen the impact of these
potentially costly limits, Keystone has initiated a Toxic Reduction Evaluation
("TRE"), which is in progress.
Keystone monitors groundwater around the site and the ash disposal area. Data is
reported in accordance with a plan approved by the PaDEP.
An amendment to the NPDES permit regulates discharges from the coal mine areas
to the east of Keystone. This includes:
o runoff and acid mine drainage
o runoff from the R&P Coal Company property (transferred to Keystone)
o runoff from closed portions and perimeter, and groundwater from the
East Valley Ash disposal area
o runoff from ash disposal area
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NPDES sampling data for all discharge points discussed above are reported to
generally indicate current compliance with permit requirements. Keystone's
records indicate occasional incident notifications associated with excessive
flow at the lagoon discharge.
There are no outstanding water pollution control violations, enforcement issues
or consent orders for Keystone with PaDEP or EPA, nor reported public complaints
regarding water pollution from Keystone or its operational activities. There are
no reported or known compliance issues preventing reissuance of the NPDES
permit. Other issues include continued surveillance of acid mine drainage at
Outfall 004; maximum daily load on Crooked Creek; iron and manganese from the
old ash site wetlands and external sources affecting the lagoon.
5.3.3 SHAWVILLE
Shawville has an NPDES permit, which expires September 28, 2000. The permit
regulates discharges to the West Branch of the Susquehanna River from multiple
outfalls.
Shawville could be affected by the outcome of a study to determine the
applicability of Section 316(a) of the Federal Water Pollution Control Act. This
could require future reductions in heat rejection to the West Branch of the
Susquehanna River.
There have been notices of violations related to NPDES discharge limits related
to sampling problems, which have been resolved. A consent order in the early
1990s required the installation of an effluent holding tank for the sewage
treatment system. There are no outstanding water pollution control violations,
enforcement issues or consent orders for Shawville with PaDEP or EPA, nor
reported public complaints regarding water pollution from Shawville or its
operational activities. There are no reported or known compliance issues
preventing reissuance of the NPDES permit.
5.3.4 PORTLAND
Portland is authorized to withdraw and use water from the Delaware River by a
Certificate of Entitlement issued by the Delaware River Basin Commission
("DRBC"). Rights to this entitlement have been purchased by REMA as owners for
future operation. Adequate flow for Portland is regulated by the Merrill Creek
Reservoir where water is released during low flow periods under agreement with
downstream users.
A circulating water system provides condenser cooling water and plant service
water from the Delaware River. Potable water is provided from onsite wells and
treated in accordance with drinking water regulations.
The circulating water system intake includes a traveling fish screen and return
system. Water is pumped from the circulating water system for condenser cooling
and for plant service including boiler water makeup. Boiler makeup is treated in
a prefilter and a modular demineralizer after which boiler chemicals are added.
Boiler water chemistry is reported to be satisfactory.
Portland operates under a NPDES permit, No. PA-0012475, which is effective
through February 15, 2002. The permit does not contain conditions for studies
(316A or B).
The permit regulates discharges from three outfalls to the Delaware River; the
circulating water system including cooling water, intake screen backwash, water
tank drains and storm water, the sewage treatment
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plant, and the industrial wastewater treatment plant including coal pile runoff,
ash sluice water, low volume waste (including boiler blowdown and non-chemical
metal cleaning wastes).
In addition, Portland has an NPDES Permit, No. 0063606, which expires July 29,
2002 for two discharges from the Bangor Ash Disposal Site to the Brushy Meadow
Creek.
Four Noncompliance Reports have been submitted to the PaDEP within the last
three years. The noncompliance reports were due to inadvertent sample probe
placement, low flow conditions in the river, or required adjustment to the
cooling system. No notices of violation of NPDES permit requirements, consent
orders or legal actions have been made against Portland within the past three
years.
5.3.5 SEWARD
Seward has an NPDES permit, which expired September 30, 1999. The permit renewal
application was filed timely with PaDEP on March 25, 1999 therefore the permit
is on administrative extension. The permit regulates discharges to the Conemaugh
River from multiple outfalls.
An appeal of the five-year NPDES permit issued in 1994 resulted in a negotiated
Consent Order and Adjudication ("COA"). Two key areas covered in the COA are: 1)
thermal limits at the Seward's main condenser cooling water discharges; and 2)
the current management and future disposition of the abandoned 1.5 million-ton
refuse pile on Seward property, including surface water runoff permit limits for
metals.
Seward performed and submitted to PaDEP a 316(a) thermal variance study
indicating that Seward is not significantly impacting the aquatic life in the
Conemaugh River. PaDEP issued a 316(a) variance from the thermal discharge
requirements, but imposed a rate of temperature change limit (5 degrees F change
per hour) in the Conemaugh River at a location downstream of Seward. This limit
became effective September 1998. Station personnel indicated that under certain
river flow conditions, the rate of load change at Seward Unit 4 could impact the
ability to meet the rate of temperature change limit forcing a possible derating
of the unit.
Remediation plans for the refuse pile have been submitted to PaDEP. These plans
include mixing the refuse with ash from fluidized bed combustion ("FBC") boilers
and covering the mixed material with an ash cap. Comments on the remediation
plan have been received from PaDEP. Final remediation plans are still being
evaluated and have not been forwarded to PaDEP.
5.3.6 TITUS
Titus is authorized to withdraw and use water from the Schulykill River by a
Certificate of Entitlement issued by the DRBC. Rights to this entitlement have
been purchased by REMA as owners for future operation. Adequate flow for Titus
is regulated by the Merrill Creek Reservoir where water is released during low
flow periods under agreement with downstream users.
The river water system provides non-contact cooling water to the cooling tower
and plant service water from the Schulykill River. It includes an intake fish
screen and backwash system. Drinking and production water is provided from four
on-site wells. The drinking water is treated in accordance with drinking water
regulations.
Boiler makeup is well water treated by reverse osmosis and a demineralizer after
which boiler chemicals are added. Boiler water chemistry is reported to be
satisfactory.
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Titus operates under NPDES permit No. 0010782, which is effective through
September 12, 2000. The permit does not contain conditions for studies (316A or
B). It regulates discharges from four primary outfalls to the Schuylkill River;
the river water system including non-contact cooling water, intake screen
backwash, and water tank drains, the industrial wastewater treatment plant
including coal pile runoff, ash sluice water, and low volume waste (including
boiler blowdown, the sewage treatment plant, and the storm water and leachate
collection system).
In the past three years, there have been non-compliance reports submitted to
PaDEP for lesser concerns such as total suspended solids ("TSS") in storm water.
Discharge temperature and pollutant levels are reported to run well within
limits. In the same period no penalties, notices of violation of NPDES permit
requirements, consent orders or legal actions have been made against Titus.
5.3.7 SAYREVILLE
For Sayreville, water withdrawal from the Raritan River is not regulated nor
does its require any permits. Although other plants are located on tidal
stretches of river and need regulation and approval, salt water intrusion
upstream is not an issue at Sayreville. There are no other reported issues
associated with use of the river.
The circulating water system provides condenser cooling, intake wash and boiler
seal water from the Raritan River. Low pressure cooling, potable and boiler
makeup water is provided from the Sayreville municipal water supply. Boiler
makeup water is demineralized after which boiler chemicals are added.
Sayreville operates under NPDES permit No. NJ0002747 issued by the NJDEP, which
expires June 30, 2003. The permit currently regulates discharges from two
outfalls for stormwater and wastewater. Outfall 002 includes groundwater
infiltration from the boiler building, condensate and floor drains. Outfall 001
includes all other wastewater streams. Stormwater discharges are permitted
separately under NJPDES No. NJ008315.
Although thermal discharge compliance is generally not a problem, tidal
fluctuations can occasionally result in discharge recirculation and brief
insignificant output derates.
Sanitary wastewater is discharged under TWA Permit No. 91-6102-41 to the
Middlesex County Utilities Authority sewer system.
In the past three years, there have been two non-compliance reports submitted to
PaDEP for oil discharges. In the same period no penalties, notices of violation
of NPDES permit requirements, consent orders or legal actions have been made
against Sayreville.
5.3.8 WARREN
Warren withdraws non-contact cooling water and makeup water from the Allegheny
River. No permit is required to use this supply of water. Flow is regulated
upstream at 500 cfs minimum flow by the Kinzua Dam which is operated by the US
Corps of Engineers. There are no other reported issues associated with use of
the river. Potable water is taken from the municipal water supply system.
Warren operates under NPDES permit No. PA 0005053, which is effective through
May 14, 2001. It regulates discharges from four primary outfalls to the
Allegheny River; the condenser cooling water system including storm water, coal,
and ash pile runoff including low volume wastewater, coal pile surge pond
overflow, and stormwater.
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In the past three years, there have been no non-compliance reports submitted to
PaDEP. Discharge temperature and pollutant levels are reported to run well
within limits. In the same period no penalties, notices of violation of NPDES
permit requirements, consent orders or legal actions have been reported against
Warren.
5.4 SOLID WASTES
5.4.1 CONEMAUGH
Conemaugh owns and utilizes an ash fill approximately 6,000 feet north of the
plant property. It is permitted under PaDEP Solid Waste and Coal Refuse Disposal
permits effective through November 4, 2008 to dispose of the following materials
from Conemaugh and nearby Seward:
o Fly and bottom ash
o Pyrites from coal pulverizers
o FGD by-product gypsum
o Miscellaneous wastes including pond sediments, dredgings, demolition
wastes, refractory lining and waste lime and sand blasting residues
o Asbestos containing materials
o Coal refuse (nearby coal plant closed in 1993)
The ash fill site has three stages. Stage I was opened in 1970 and closed in
1987. It is approximately 160 acres, is unlined and covered with soil. Stage II
has been active since 1985 and covers approximately 120 acres. It has a 50 mil
PVC liner and a leachate collection system with a combination leak
detection/subgrade drainage system.
A 1996 Groundwater Assessment Report including the results of ground water
monitoring finds that the existing liner system performs well for this site.
Application has been made to the PaDEP to continue this liner design for the
remainder of the site.
Conemaugh personnel reported that the remaining life of the currently operating
Phase II disposal area is approximately 20 years, assuming the FGD gypsum
byproduct continues to be sold. A Phase III ash disposal area is permitted. The
expected life of Phase III is approximately 30 years with gypsum disposal and 60
years without gypsum disposal.
5.4.2 KEYSTONE
Keystone utilizes an ash landfill, which is on a 254-acre parcel and is operated
by R&L Development. It is permitted under Coal Refuse Disposal Permit No.
03820701 and regulated by the Office of Solid Waste. Engineering and permitting
is being performed for a new West Valley disposal site as discussed in a
subsequent paragraph. The following materials from Keystone are disposed in the
ashfill:
o Fly and bottom ash
o Pyrites from coal pulverizers
o Noncombustible demolition wastes
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o Miscellaneous wastes including sludges, pond sediments, dredgings and
intake debris
o Asbestos containing materials
o Mine refuse from nearby mines
The existing disposal site, the East Valley disposal site, is located
approximately 4,000 feet north of Keystone, and has been in operation since
1984. Since that time all waste has been placed on a single 50 mil PVC synthetic
liner with a leachate collection system and a combination leak
detection/subgrade drainage system. The current East Valley disposal area (125
acres) will reach capacity in 2001.
Engineering and permitting is being performed for a new West Valley disposal
site, which should be available for use in late 2001. The proposed facility will
include the remaining currently permitted East Valley site and a contiguous
lateral expansion of 108 acres to the west. The estimated life of the expansion
facility is until year 2023.
The results of groundwater monitoring have shown the existing liner to be
protecting groundwater. The existing design will be improved for the West Valley
Disposal Site by adding another PVC liner and modifying the leachate collection
system.
5.4.3 SHAWVILLE
Bottom and fly ash from Shawville Units 1 through 4 are currently disposed of
on-site at a permitted ash disposal area. The solid waste disposal permit was
issued June 5, 1997 and expires June 5, 2007. The existing landfill is located
on top of a previous unlined ash disposal area and includes a liner with
leachate collection and treatment. It was reported that the existing ash site is
expected to reach capacity by the end of 2003. Shawville is in the process of
preparing preliminary engineering and permitting for the expansion of the ash
disposal area. Shawville personnel reported that the expected life of the
disposal area expansion is approximately 27 years.
5.4.4 PORTLAND
Portland utilizes the Bangor Ash Site, which is approximately 17 acres on a
67-acre parcel and is now owned by REMA. It is permitted under PaDEP Solid Waste
Disposal Permit No. 300002 and effective through December 3, 2008.
The Bangor Ash Site is being upgraded as part of requirements of the permit
renewal. To date, work on a new compliance liner and drain system is reported to
be 90% complete. Installation of the cap is ongoing as filling progresses. With
the upgrades, the life of the Bangor Ash Site is projected to extended through
2018. Fly and bottom ash reuse programs at Portland may further extend this
life.
Groundwater monitoring is reported quarterly to the PaDEP as required by the
permit. Samples are reported to indicate that levels of potential leachate
contaminants are not significant.
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5.4.5 SEWARD
Bottom and fly ash from Seward are disposed of at the Conemaugh solid waste
disposal area. The co-owners of Conemaugh have indicated that the contract to
dispose of Seward's coal ash will not be extended past the end of the year 2000.
A partial list of options for future ash disposal that are being considered
include:
o Renegotiating the Conemaugh ash disposal contract
o Negotiating a contract for disposing of ash at Homer City or Keystone
o Use as structural fill on-site for possible CFB repowering project
o Disposal at the Shawville solid waste disposal site
Amendments to existing permits would be required if Seward's ash were disposed
of off-site.
5.4.6 TITUS
Titus utilizes the Beagle Club Ash Site, which is located approximately one mile
from Titus. It is permitted under PaDEP Solid Waste Disposal Permit No. 300668
issued as a repermit on October 18, 1999. The following Titus materials are
allowable for disposal:
o Coal-derived bottom ash
o Coal-derived fly ash
o Industrial wastewater treatment sludge
If the Beagle Club Ash Site continues to operate in accordance with its
permitted plan, it will have capacity for Titus through 2008. Fly and bottom ash
reuse programs at Titus might extend this life, but are limited due to the
composition of the Titus fly ash. During the last life extension study in 1987
an additional site was evaluated nearby.
Approval of a waiver of PaDEP requirements for liner upgrades is contingent on
the satisfactory completion of a groundwater assessment. Groundwater monitoring
is reported quarterly to the PaDEP as required by the permit. Samples are
reported to indicate that levels of potential leachate contaminants are not
significant. A final closure plan will be submitted for approval to the PaDEP
one year before closure.
5.4.7 SAYREVILLE
Units fired with natural gas and oil, have very little bottom or fly ash
generated or retained in either the CTs or the boilers. There is no need for a
supporting ashfill for disposal of ash. Any small quantities of ash recovered
from maintenance activities are removed for disposal by contractors.
5.4.8 WARREN
Warren utilizes an on-site ash disposal facility of approximately 16 acres for
disposal of fly and bottom ash from Units 1 and 2. The ash site is permitted
under a PaDEP Permit for Solid Waste Disposal and/or Processing Facility (No.
300858) which is effective through 2002. An extension of closure of the ash
facility through 2003 has been requested.
Although a recent plan has not been advanced for life extension, past studies
have explored options including ash backhauling to the mine, fill over one of
the existing ash ponds, and use of the 67 acre borrow area.
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Groundwater monitoring at 14 monitoring wells is reported quarterly to the PaDEP
as required by the permit. Samples are reported to indicate that levels of
potential leachate contaminants are not significant.
5.5 SITE CONTAMINATION/REMEDIATION
REMA is assuming the liabilities for existing environmental conditions of the
Facilities with the exception of off-site liabilities associated with the
disposal of hazardous materials and certain other environmental liabilities.
Woodward-Clyde prepared Phase I and Phase II Environmental Site Assessments
("ESA") for each of the thermal stations for GPU during 1998 in preparation for
the sale of the Facilities. The objective of the Phase I ESAs was to recognize
environmental conditions and other potential or known environmental liabilities
at the properties related to site contamination issues, asbestos issues, and
impacts to the properties from historical site uses. The Phase II ESAs included
sampling activities to investigate areas of concern identified in the Phase I
ESAs. Gilbert and Sayreville were required to comply with the Industrial Site
Recovery Act ("ISRA") which is implemented by the NJDEP. Remediation Agreements
were signed with NJDEP on November 24, 1999 for Gilbert and Sayreville.
Black & Veatch ("B&V") prepared an "Environmental Evaluation of GPU Generating
Assets" for Sithe Energies dated April 6, 1999. B&V reviewed the Phase I and
Phase II ESAs, conducted site visits, interviewed GPU corporate and facility
personnel, and estimated costs to address environmental liabilities. The B&V
report also addressed other environmental liabilities not covered in the Phase I
and Phase II ESAs (e.g. thermal issues and NPDES discharge issues). The
potential areas of concern as reported by B&V for each of the facilities are
summarized below.
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===========================================================================================================
SUMMARY OF SITE CONTAMINATION ISSUES
- -----------------------------------------------------------------------------------------------------------
STATION/UNIT POTENTIAL AREAS OF CONCERN
- -----------------------------------------------------------------------------------------------------------
Conemaugh o Ash disposal landfill
o Four ash settling ponds
o Florence mine
- -----------------------------------------------------------------------------------------------------------
Keystone o Former ash pond
o Surface impoundments
o Fuel oil above ground storage tanks, truck unloading area and underground
fuel piping for peaking generators
o Electrical substation
o Former Stage I ash landfill
o The 3,346 acre reservoir
- -----------------------------------------------------------------------------------------------------------
Shawville o Aboveground storage tank ("AST") testing and potential upgrades
o Miscellaneous petroleum contaminated areas
o Asbestos removal
o Area-wide groundwater contamination from unlined coal pile, ash pond areas,
and unlined ash landfill (including landfill capping)
o Lining of surface impoundments
- -----------------------------------------------------------------------------------------------------------
Portland o Oil tank and handling improvements
o Replace liners for industrial wastewater treatment ("IWT") retention ponds
o Replace liners for coal pile runoff pond
o Asbestos abatement and replacement
o Soil/groundwater contamination at former ash ponds
o Sediment contamination in river
- -----------------------------------------------------------------------------------------------------------
Seward o Area-wide groundwater contamination
o Remediation of coal refuse pile
o Vacant 158 acre parcel
o Abandoned underground storage tanks ("USTs") at former gas station property
o Miscellaneous petroleum contaminated soil areas
o Asbestos removal
- -----------------------------------------------------------------------------------------------------------
Titus o Oil tank improvements
o Spill at fuel unloading area
o Uncontrolled drain at CT containment area
o Liner installation at Beagle Club Ash Disposal Site
o Liner replacement for IWT settling ponds
o Asbestos abatement and removal
o Soil/groundwater contamination from coal pile area, closed ash disposal
sites, salvage yard, Beagle ash site runoff and leachate
- -----------------------------------------------------------------------------------------------------------
Sayreville o Petroleum bulk storage tank improvements
o Chemical storage tank improvements
o Separate/treat site drainage prior to discharge
o Asbestos abatement and control
o Soil, groundwater, and sediment contamination related to former disposal
area, former AST sites, former ash ponds, and former coal pile
o Sediment contamination in the Raritan River
- -----------------------------------------------------------------------------------------------------------
Warren o Oil tank improvements
o Underground storage tank removal/replacement
o SPDES Permit renewal
o Replace liner for ash ponds
o Landfill expansion
o Landfill leachate treatment
o Asbestos abatement and removal
o Soil/groundwater contamination from coal pile, current ash disposal site,
former ash disposal site and former coal storage site
===========================================================================================================
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- --------------------------------------------------------------------------------
B&V estimated the expected cost for environmental liabilities at the thermal
stations. Using an expected value approach, B&V calculated the expected value of
the present worth for each environmental issue. Stone & Webster reviewed the B&V
values at each station and adjusted the estimates to remove environmental issues
not considered to be site contamination issues (e.g. thermal discharge, intake
structure modifications, etc.). Stone & Webster reviewed the REMA environmental
estimates to verify that the expected cost for the environmental liabilities
(including site contamination) are included in the financial model.
Oil handling at Warren is a potential operating and environmental compliance
liability for use of the CT, Unit 3. With continued operation planned for
Warren, priority should be given to oil handling and storage upgrades and
safeguards. B&V has indicated:
o Reported spills in the past from the 500,000 gallon aboveground
distillate oil tank
o Unlined containment area at the AST
o Petroleum hydrocarbons in the surrounding soil
o Two 15,000 gallon underground distillate oil tanks not meeting spill
prevention requirements
Although these items do not constitute major upgrade costs, ruptures, spills or
leaks can result in significant compliance and mitigation expenses as well as
possible disruption of operation of Unit 3. Inspection indicates that the AST
and truck unloading connections are on higher ground to the north of Warren and
serve Unit 3 by steel oil pipes of approximately 1500 ft crossing under a
service road and under the through rail line.
5.6 COMBUSTION TURBINES
5.6.1 AIR QUALITY
The Blossburg, Hamilton, Hunterstown, Mountain, Orrtanna, Shawnee, Tolna, and
Wayne units in Pennsylvania contain only simple cycle gas and oil-fired peaking
CTs. The CT generating units in New Jersey include Gilbert, Glen Gardner, and
Werner, which are a combination of gas and oil-fired simple cycle and combined
cycle CTs. The distribution of CTs at these sites is summarized below:
The CTs began operation in either 1971 or 1972 and are controlled remotely by
dispatchers in other locations with the exception of Gilbert and Werner.
Presently, there are no emission controls on the simple cycle CTs. Three of the
units in combined cycle operation at Gilbert have water injection and one unit
has dry low NO(x) combustors and water injection for NO(x) control.
Relative to permitting status, the Blossburg, Hamilton, Hunterstown, Mountain,
Orrtanna, Shawnee, and Tolna stations have applied for "synthetic minor" status,
which avoids the Title V operating permit requirements, but places restrictions
on operating hours to remain below the "major source" threshold. Gilbert and
Glen Gardner have timely submitted Title V operating permit applications, which
received administrative completeness determinations in April 1996. Therefore,
these units are operating under the application shield of the Title V program.
Wayne and Werner received their Title V operating permits on June 11, 1998 and
August 17, 1999, respectively. These permits expire five years from the date of
issuance.
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As mentioned earlier, a number of the CTs have "synthetic minor" permits which
restrict hours of operation and/or annual fuel usage. The other stations either
have Title V permits or complete applications also have some permit
restrictions. These restrictions are summarized as follows:
===================================================================================
COMBUSTION TURBINE STATIONS OPERATING RESTRICTIONS
===================================================================================
SITE HOURS PER YEAR mmBtu/year
-----------------------------------------------------------------------------------
Blossburg 1,038 N/A
-----------------------------------------------------------------------------------
Hamilton 1,100 336,000 - oil
-----------------------------------------------------------------------------------
Hunterstown 1,700 - gas 554,000 - gas
210 - oil 64,000 - oil
-----------------------------------------------------------------------------------
Mountain 1,700 - gas 554,000 - gas
210 - oil 64,000 - oil
-----------------------------------------------------------------------------------
Orrtanna 1,100 336,000 - oil
-----------------------------------------------------------------------------------
Shawnee 1,100 N/A
-----------------------------------------------------------------------------------
Tolna 1,100 336,000 - oil
-----------------------------------------------------------------------------------
Wayne 5% capacity factor N/A
-----------------------------------------------------------------------------------
Gilbert Westinghouse 1,942 - gas N/A
Turbines (simple cycle) 1,077 - oil N/A
Gilbert ABB Turbine 1,037 - gas N/A
(simple cycle) 1,453 - oil N/A
-----------------------------------------------------------------------------------
Gilbert GE Turbines 4,172 - gas N/A
(combined cycle) 2,977 - oil N/A
-----------------------------------------------------------------------------------
Glen Gardner 1,941 - gas N/A
1,453 - oil N/A
-----------------------------------------------------------------------------------
Werner 1,453 - oil N/A
===================================================================================
These restrictions should not have a negative effect on the station operations
as peaking units.
Gilbert is required to comply with Phase I of NO(x) RACT by May, 1995 with
emission limits of 0.26 and 0.17 lb/mmBtu firing oil and gas, respectively for
all turbines except the ABB turbine, CT 9. The RACT limits for Gilbert CT 9 are
emission limits of 0.165 and 0.019 lb/mmBtu firing oil and gas, respectively.
The statutory RACT emission limits for Glen Gardner and Werner are 0.4 and 0.2
lb/mmBtu firing oil and gas, respectively. RACT does not apply to the
Pennsylvania stations other than Wayne as they are not "major" sources of NO(x).
Emissions data for 1998 indicates that these CTs are running comfortably below
their NO(x) RACT limits where applicable. As discussed earlier for the thermal
stations, Phase II of NO(x) RACT, also known as the "NO(x) Budget Program", in
Pennsylvania and New Jersey imposed further restrictions on NO(x) emissions by
May, 1999 in terms of ozone season NO(x) allowances (tons). The "NO(x) Budget
Rule" applies to fossil fuel-fired indirect heat exchange combustion units with
a maximum rated heat input capacity of 250 mmBtu/hour and all fossil fuel fired
electric generating facilities rated at 15 MW or greater.
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The initial allowance allocations for the CT units are as follows:
=================================================================
COMBUSTION TURBINE STATIONS NO(x) ALLOWANCES
=================================================================
SITE NO(x) ALLOWANCES
- -----------------------------------------------------------------
Blossburg N/A
- -----------------------------------------------------------------
Hamilton 4
- -----------------------------------------------------------------
Hunterstown 37
- -----------------------------------------------------------------
Mountain 20
- -----------------------------------------------------------------
Orrtanna 3
- -----------------------------------------------------------------
Shawnee 3
- -----------------------------------------------------------------
Tolna 8
- -----------------------------------------------------------------
Wayne 11
- -----------------------------------------------------------------
Gilbert N/A
- -----------------------------------------------------------------
Glen Gardner N/A
- -----------------------------------------------------------------
Werner N/A
=================================================================
Of the CTs, only Gilbert and Werner in New Jersey have been allocated Phase II
SO(2) allowances starting in the year 2000. Gilbert and Werner have been
allocated a total of 3,191 and 194 SO(2) allowances, respectively.
There are no outstanding air pollution control violations, enforcement issues or
consent orders for the simple-cycle stations with PaDEP or the NJDEP, or
reported public complaints regarding air pollution from the stations or their
operational activities. There are no reported or known issues preventing
issuance of the Title V operating permits for those stations that applied for
but have not yet received their permits.
5.6.2 WATER/WASTEWATER
The Pennsylvania CTs are not required to hold NPDES permits at this time.
However, industrial stormwater discharges are required to be permitted by August
7, 2001 under a 1995 amendment to the Clean Water Act ("CWA"). A general permit
application will need to be submitted to the PaDEP indicating compliance with
these Phase II stormwater regulations. A monitoring program must also be
prepared and implemented. The New Jersey stations currently hold NPDES permits
issued by the NJDEP. Gilbert permit No. NJ0005517 expires on October 31, 2001
and covers industrial and stormwater discharges. A Groundwater Discharge Permit
and Protection Plan is currently under review. The Glen Gardner NPDES permit No.
NJ00084034 expires on May 31, 2001 and also covers industrial and stormwater
discharges. The permit for Werner No. NJ0002755 covers industrial and thermal
discharges and expires on September 30, 2001. No significant problems concerning
compliance with discharge permit requirements have been noted.
According to an evaluation study of these stations conducted by B&V in April
1999, the total estimated costs of complying with the Phase II stormwater
regulations are summarized in the following table. REMA has included an amount
in the budget for potential Phase II stormwater compliance.
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===================================================================================
PHASE II STORMWATER COMPLIANCE COST ESTIMATES
===================================================================================
BEST CASE WORST CASE
SITE TOTAL COST ($) TOTAL COST ($)
-----------------------------------------------------------------------------------
Blossburg 210,000 420,000
-----------------------------------------------------------------------------------
Hamilton 420,000 860,000
-----------------------------------------------------------------------------------
Hunterstown 420,000 860,000
-----------------------------------------------------------------------------------
Mountain 420,000 860,000
-----------------------------------------------------------------------------------
Orrtanna 420,000 860,000
-----------------------------------------------------------------------------------
Shawnee 420,000 860,000
-----------------------------------------------------------------------------------
Tolna 420,000 860,000
-----------------------------------------------------------------------------------
Wayne 420,000 860,000
===================================================================================
5.6.3 SITE CONTAMINATION REMEDIATION
The B&V report mentioned earlier also provides an understanding of environmental
liabilities associated with soil and groundwater contamination as well as ranges
of remediation cost estimates associated with best and worst case probabilities.
These estimated costs are summarized in the following table. REMA has included
an appropriate amount in the budget for potential site contamination issues.
==============================================================================================================
SUMMARY OF SITE CONTAMINATION ISSUES
==============================================================================================================
BEST CASE WORST CASE
STATION ISSUE TOTAL COST ($) TOTAL COST ($)
- --------------------------------------------------------------------------------------------------------------
Blossburg Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Hamilton Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Hunterstown Down-gradient Drainage Areas 25,000 225,000
Groundwater Remediation 175,000 500,000
Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Mountain Open Remediation Issue 20,000 260,000
Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Orrtanna Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Shawnee Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Tolna Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Wayne Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Glen Gardner Groundwater Remediation 1,725,000 3,450,000
Site Investigation 12,000 322,000
Remedial Investigation 0 345,000
Remedial Action 0 86,000
Contingency for unknowns 10,000 100,000
- --------------------------------------------------------------------------------------------------------------
Werner Remedial Investigation &
Work Plan 1,150,000 1,150,000
Remedial Action 1,012,000 12,935,000
==============================================================================================================
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5.7 HYDROELECTRIC STATIONS
5.7.1 SITE CONTAMINATION/REMEDIATION
The only environmental issues associated with Piney and Deep Creek include
secondary containment for the lube oil tanks and emergency batteries and
petroleum hydrocarbon contaminated soil at Piney. The extent of the
contamination has not yet been determined. There are no sources of air pollution
at either station as there are no combustion sources.
The following table provides a summary of estimated costs associated with soil
remediation activities for best and worst case probability scenarios.
=============================================================================================================
SUMMARY OF SITE CONTAMINATION ISSUES
=============================================================================================================
BEST CASE WORST CASE
STATION ISSUE TOTAL COST ($) TOTAL COST ($)
- -------------------------------------------------------------------------------------------------------------
Piney Contaminated Soil 0 147,000
- -------------------------------------------------------------------------------------------------------------
Deep Creek N/A N/A N/A
=============================================================================================================
5.7.2 OPERATING LICENSES
PINEY
Piney is licensed by FERC as Licensed Project No. P-309 issued in June 29, 1979
and expiring on October 12, 2002. As of the FERC Operation Report dated August
1997, the Project had no noted violations and appeared to be in compliance with
its license. Stone & Webster has reviewed the Project's compliance record with
the FERC requirements for 1996 through 1999 based upon the titles of all
correspondence and filings posted on the FERC Records Information Management
System. FERC has identified no outstanding license compliance issues related to
the Project.
DEEP CREEK
Although Deep Creek was originally licensed by FERC, FERC notified the Maryland
Water Resources Administration by letter dated January 11, 1994 that the project
was no longer under FERC jurisdiction. Deep Creek presently operates under a
State of Maryland DNR Water Appropriations Permit Number GA92S009 (02). This
permit was issued on October 1, 1999 and expires on January 1, 2006. Deep Creek
personnel advised that the DNR plans to transfer this permit to REMA without
change to the conditions or the expiration date. At the expiration, the
operating conditions stipulated by the permit would be subject to revision.
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6. OPERATION & MAINTENANCE
6.1 GENERAL
Stone & Webster reviewed the projected station staffing plans, O&M budgets,
overhaul schedules, and capital and overhaul expenses provided by REMA. In
addition, we reviewed the station maintenance management practices and spare
parts inventories for effectiveness and adequacy.
The projections provided by REMA were reviewed in relation to the projected
operation of the stations and, where appropriate, were compared to station
historical experience and industry data.
6.2 APPROACH
Stone & Webster interviewed management personnel and reviewed station records
during our recent site visits. The review focused on REMA's O&M program,
overhaul, and capital expenditure forecasts. Stone & Webster reviewed historic
O&M performance and cost data contained in various documents that were made
available.
6.3 OPERATION AND MAINTENANCE REVIEW
6.3.1 CONEMAUGH STATION
STAFFING
The present staffing level is 198 personnel, 144 union personnel and 54
management employees. This number includes personnel assigned to the scrubber
and has been reduced from 268 in 1993. The long-term forecast according to the
current station staff is to run with 197 employees through 2009. Mobile
maintenance crew supplements the existing staff during outages and overhauls.
Janitorial services and specialized machine work are outsourced. Due to the 25%
staffing reduction conducted prior to acquisition and their comfort with the
competitiveness of current staffing levels, REMA and the owners are not
currently planning any additional workforce reductions. The staffing level is
adequate for the current mode of operation.
OPERATION AND MAINTENANCE EXPENSES
The historical labor and other O&M expenses and REMA's and the other owners'
projected labor and other O&M expenses are shown in the following table. The
projected expenses are an annual average of the projected expenses from 2000
through 2029. The O&M expenses do not include the cost of any SO(2) and NO(x)
credits that may be purchased by REMA, which are estimated and included as a
separate expense item. These costs are discussed in detail in the Assessment of
Financial Projections section of the report.
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HISTORICAL AND PROJECTED O&M EXPENSES(1)
===========================================================
EXPENSE(2)
YEAR ($, MILLION)
- -----------------------------------------------------------
1995 9.4
- -----------------------------------------------------------
1996 11.2
- -----------------------------------------------------------
1997 9.7
- -----------------------------------------------------------
1998 9.8
- -----------------------------------------------------------
1999 9.3
- -----------------------------------------------------------
2000-2029 10.8
===========================================================
(1) Historical expenses reported in current year dollars and projected expenses
in 2000 dollars
(2) REMA's share
The total O&M expenses, excluding cost of fuel for 1999 were 3.8% under budget.
Labor costs have declined since the mid-nineties due to the reduction in labor
by a voluntary early retirement program ("VERP"). The reduction in payroll has
helped to offset the increased maintenance cost and resulted in levelizing the
total expenses. Both the labor and O&M expenses appear to be adequate based on
the performance of the plant.
OVERHAUL SCHEDULE
Stone & Webster reviewed REMA's and the other owners' planned overhaul and
maintenance schedule. A nine-week overhaul is scheduled in 2000 on Unit 1 to
inspect the LP turbine internals, IP turbine internals, replace the turbine EHC
controls and boiler intermediate reheater. The units currently are in a two-year
outage cycle and management is evaluating shifting to a three-year cycle once
more experience is gained with waterwall corrosion protection methods and
erosion resistant designs for turbine nozzle blocks and blades.
MAINTENANCE MANAGEMENT
Conemaugh uses a computerized mainframe planning system. Job tickets are
handwritten and entered into the system by maintenance planners. Tickets are
assigned priorities and scheduled. This system is also used to initiate
scheduled preventive maintenance assignments. Predictive maintenance work is
also tracked by this system. Investigation of a PC based system was delayed by
retirement of one of the planners. The present system appears adequate to
support the daily requirements of the station.
The spare parts inventory has been reduced from $30 million in the early
nineties to $17 million in 1999. Conemaugh was able to reduce the inventory by
purchasing a spare complement of major turbine components for inventory, which
is used to replace damaged elements. The elements are then refurbished and
returned to inventory. Station personnel are comfortable with the current parts
inventory, and it should be sufficient for normal replacement of equipment.
CAPITAL AND OVERHAUL EXPENSES
The capital expenses planned by REMA and the other owners were reviewed. In
Stone & Webster's opinion, the assumed level of capital and overhaul expenses
included in the detailed forecast is adequate to keep the station operating
reliably through the projected retirement date.
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6.3.2 KEYSTONE STATION
STAFFING
The present staff consists of 167 personnel, 44 management and 123 union
employees. The figure is down from a total of 229 positions in 1993. Reductions
have been accomplished through the VERP. This 27% reduction did not have any
adverse effect on the performance of the units. This can be attributed to the
new style of management, which was introduced and accepted by all. Both
management and union leadership work together to adopt new concepts in easing
work restrictions. The staffing level is adequate for the current mode of
operation.
OPERATION AND MAINTENANCE EXPENSES
The historical labor and other O&M expenses and REMA's and the other owners'
projected labor and other O&M expenses are shown in the following table. The
projected expenses are an annual average of the projected expenses from 2000
through 2029. The O&M expenses do not include the cost of any SO(2) and NO(x)
credits that may be purchased by REMA, which are estimated and included as a
separate expense item. These costs are discussed in detail in the Assessment of
Financial Projections section of the report.
===========================================================
HISTORICAL AND PROJECTED O&M EXPENSES(1)
- -----------------------------------------------------------
EXPENSE(2)
YEAR ($, MILLION)
- -----------------------------------------------------------
1995 7.9
- -----------------------------------------------------------
1996 8.0
- -----------------------------------------------------------
1997 6.8
- -----------------------------------------------------------
1998 6.4
- -----------------------------------------------------------
1999 6.8
- -----------------------------------------------------------
2000-2029 6.2
===========================================================
(1) Historical expenses reported in current year dollars and projected expenses
in 2000 dollars
(2) REMA's share
Total O&M expense (excluding fuel) in 1999 was under budget by 5.3%. Monies have
been included in the budget to support availability improvement and continued
emphasis on thermal performances. There is an anticipated increase in the O&M
budget of $940,000/year starting in 2003. This will result from the operation of
an SCR for NO(x) control after it is installed. Both labor and O&M expenses
appear to be adequate based on the performance of the plant.
OVERHAUL SCHEDULE
Stone & Webster reviewed REMA's and the other owners' planned overhaul and
maintenance schedule. Keystone is currently on a scheduled five to six week
outage every other year for boiler and partial turbine/generator work. During
the plant visit, Unit 2 was in a six-week scheduled outage with a capital
appropriations budget of $22.3 million to replace the boiler waterwall panels
and air heater baskets. A bulldozer will be replaced with a wheel loader for
coal handling. There is also an environmentally
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mandated project for ash disposal and residual waste in process costing $11.7
million over 2000 and 2001.
MAINTENANCE MANAGEMENT
The maintenance management system utilized by Keystone is similar to that at
Conemaugh. Predictive maintenance work is also tracked by this system. The
present system appears adequate to support the daily requirements of the
station.
The spare parts inventory has been reduced from $31 million to $17 million in
recent years. Major spare parts (turbine rotors and stationary components, fan
blading, etc.) are on-site in case of a failure. Keystone has purchased a spare
complement of major turbine components for inventory, which is used to replace
damaged elements. The elements are then refurbished and returned to inventory.
CAPITAL AND OVERHAUL EXPENSES
The capital expenses planned by REMA and the other owners were reviewed. In
Stone & Webster's opinion, the assumed level of capital and overhaul expenses
included in the detailed forecast are adequate to keep the station operating
reliably through the projected retirement date.
6.3.3 SHAWVILLE STATION
STAFFING
The approved personnel for the year 2000 is 98, 20 management and 78 union
employees, down from 132 in 1994. Reductions were accomplished through VERP. As
of March, Shawville was below the approved complement by nine positions, two
management and seven union. The work force is supplemented during outages and
overhauls by the mobile maintenance crew, which also services the other
stations. Currently, the mobile maintenance crew includes 178 members, 19
management, and 159 union. There is a unique agreement with this group that
allows temporary layoffs based on workload. The staffing level is adequate for
the current mode of operation.
OPERATION AND MAINTENANCE EXPENSES
The historical labor and other O&M expenses and REMA's projected labor and other
O&M expenses are shown in the following table. The projected expenses are an
annual average of the projected expenses from 2000 through 2029. The O&M
expenses do not include the cost of any SO(2) and NO(x) credits that may be
purchased by REMA, which are estimated and included as a separate expense item.
These costs are discussed in detail in the Assessment of Financial Projections
section of the report.
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===========================================================
HISTORICAL AND PROJECTED O&M EXPENSES(1)
- -----------------------------------------------------------
EXPENSE
YEAR ($, MILLION)
- -----------------------------------------------------------
1995 24.1
- -----------------------------------------------------------
1996 24.2
- -----------------------------------------------------------
1997 21.2
- -----------------------------------------------------------
1998 20.6
- -----------------------------------------------------------
1999 19.5
- -----------------------------------------------------------
2000-2029 21.6
===========================================================
(1) Historical expenses reported in current year dollars and projected expenses
in 2000 dollars
In 1999, the total authorized budget was $21.2 million, while actual
expenditures were $19.5 million. The station was under budget by $1.8 million or
8.3%. In 1998, the station was also under budget by $1.1 million or 5.5%. A
review of the O&M expenses and discussions with plant personnel indicate that
Shawville is being maintained and operated consistent with good utility
practices.
OVERHAUL SCHEDULE
Stone & Webster reviewed REMA's planned overhaul and maintenance schedule.
Shawville has successfully converted to a three-year boiler maintenance schedule
(four weeks) and a nine-year turbine/generator major maintenance cycle
(six-seven weeks).
Unit 3 is scheduled for waterwall replacement with chromized tubing and pumps
and feedwater heater work in 2000. In 2001, both Units 1 and 2 are scheduled for
overhauls. Unit 1 is scheduled for a generator rewind, partial condenser retube
and feedwater heater replacement. Unit 2 is scheduled for a generator rewind,
electrical refurbishment, and other work. In 2003 Unit 4 is scheduled for a
superheater replacement, a generator rewind, feedwater heater replacement, and
balance of plant work.
MAINTENANCE MANAGEMENT
Shawville has a GMS maintenance management system similar to many of the other
units. Manual written work orders are submitted to a clerk, who inputs the
information into the computer. A maintenance planner coordinates the priority
and issuing of the work order on major jobs. The clerk sends orders to the group
responsible. The tagging procedure is computerized and tags issued with final
work order. Predictive maintenance jobs are also computerized. This system
appears adequate and has not created any problems.
REMA will convert the maintenance management to the SAP America system that it
currently uses at its utility and merchant plants. REMA plans to integrate this
with human resource features for time keeping as well as ordering materials.
This system should be fully implemented by the end of this year. The SAP America
system is a system that stores a significant amount of information including
financial as well as maintenance tracking. It is considered to be an acceptable
maintenance tracking system in the industry.
There is an inventory of approximately $10 million in spare parts on site.
Inventory levels have been reduced by establishing alliances with Babcock &
Wilcox and ABB, which allows ready, access to parts needed and the old motors
are saved to use for emergency repair in case of failures.
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CAPITAL AND OVERHAUL EXPENSES
The capital expenses planned by REMA were reviewed. In Stone & Webster's
opinion, the assumed level of capital and overhaul expenses included in the
detailed forecast are adequate to keep the station operating reliably through
the projected retirement date.
6.3.4 PORTLAND STATION
STAFFING
The staffing level at Portland is currently 82. REMA plans to increase the level
to 92, and has budgeted for this number. The full complement will include 54
assigned to operation, 33 assigned to maintenance and five assigned to
administration. The hiring of the new employees will reduce the large amount of
overtime currently worked by operators due to previous staffing reductions. The
staffing level was 108 positions two years ago.
The Portland staff operates and maintains two GE frame 5 units and the advanced
technology Siemens V-84.3 at Portland and two GE frame 5 simple cycle units at
Shawnee. The Shawnee units are started remotely. They are normally unattended
except when alarm signal is received at Portland. In this case a maintenance
technician or an operator is sent from Portland to attend the alarmed unit.
The bargaining unit agreement now allows assignment flexibility between the
operations and maintenance positions. Each of these groups will help each other
if needed. The previous union work rules restricted employees to their
respective assigned job descriptions. This flexible staffing arrangement allows
a lower staffing level to be sufficient. The new staffing level is adequate for
the current mode of operation. The numbers are typical of those found in
similarly configured plants that Stone & Webster has reviewed.
OPERATION AND MAINTENANCE EXPENSES
The historical labor and other O&M expenses and REMA's projected labor and other
O&M expenses are shown in the following table. The projected expenses are an
annual average of the projected expenses from 2000 through 2024. The O&M
expenses do not include the cost of any SO(2) and NO(x) credits that may be
purchased by REMA, which are estimated and included as a separate expense item.
These costs are discussed in detail in the Assessment of Financial Projections
section of the report.
===================================================================
HISTORICAL AND PROJECTED O&M EXPENSES(1)
- -------------------------------------------------------------------
PROJECTED EXPENSE
YEAR ($, MILLION)
- -------------------------------------------------------------------
1995 19.6
- -------------------------------------------------------------------
1996 16.2
- -------------------------------------------------------------------
1997 16.8
- -------------------------------------------------------------------
1998 15.9
- -------------------------------------------------------------------
1999 10.5
- -------------------------------------------------------------------
2000-2024(2) 14.2
===================================================================
(1) Historical expenses reported in current year dollars and projected expenses
in 2000 dollars
(2) Includes $1,876,000 in levelized Portland CTs projected expenses
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As can be seen by the data in the table, the O&M cost has significantly declined
over the past five years, which is due to decreased staffing and expenditures at
the plant. The O&M expenses appear to be adequate based on the staffing level,
projected operating level, and historical experience.
The Shawnee CT is operated and maintained from Portland. The Shawnee CT O&M is
budgeted at a levelized $128,600 per year, which is intended to cover any major
maintenance, repairs, and parts replacement.
OVERHAUL SCHEDULE
Stone & Webster reviewed REMA's planned overhaul and maintenance schedule. Units
1 and 2 turbines were last overhauled in 1994 and 1997, respectively. Both units
are scheduled to have a major turbine overhaul every seven to eight years.
Portland has been doing boiler overhauls at two and a half year intervals. While
this is a longer time between boiler overhauls than is usually seen, the
Portland plant has been successfully accomplishing this extended schedule.
There are no scheduled CT major maintenance overhauls due to the CTs' infrequent
operation in peaking service.
MAINTENANCE MANAGEMENT
The functionality of the current maintenance information system and the
knowledge and skills of the employees who will use the system were observed and
found to be satisfactory to support maintenance control and reporting
requirements.
A REMA power plant maintenance information system will be used to control
maintenance information. The current system used is on the GPU central computer
mainframe. REMA will convert the maintenance management to the SAP America
system as discussed in section 6.3.3. It is considered to be an acceptable
maintenance tracking system in the industry.
The spare parts inventory at the station appears to be sufficient and adequate
to support operations. The reported dollar value of parts and material inventory
was $8,843,359.
CAPITAL AND OVERHAUL EXPENSES
The capital expenses planned by REMA were reviewed. In Stone & Webster's
opinion, the assumed level of capital and overhaul expenses included in the
detailed forecast are adequate to keep the station operating reliably through
the projected retirement date.
Funds have been allocated in 2021 and 2022, in the amount of $11.4 million and
$3.4 million, respectively for the major maintenance/overhaul of the Portland
CTs. The infrequent operation of the equipment and recent improvements in
condition monitoring and preventive maintenance practices are expected to
control the risk of premature unforeseen equipment maintenance and repair
expense. REMA has also included $2 million in 2000 for major maintenance to
account for any unforeseen expenditures.
An additional $1.5 million is allocated in 2022 for a major inspection and
overhaul of the Shawnee CT.
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6.3.5 SEWARD STATION
STAFFING
The current approved personnel at Seward is 60, 13 non-union, 47 union
employees. As of March 1, there were two union vacancies. Over the past five
years, the station complement has been reduced from 104 positions through VERP.
Some services have been contracted out, as a result of this reduction, such as
janitorial services. The adoption of flexible work rules by union and management
teams working together has helped during this transition. The projected staffing
level for the future is 50 employees each year through 2009. This is expected to
be achieved through natural attrition. The projected staffing level is adequate
for the current mode of operation.
OPERATION AND MAINTENANCE EXPENSES
The historical labor and other O&M expenses and REMA's projected labor and other
O&M expenses are shown in the following table. The projected expenses are an
annual average of the projected expenses from 2000 through 2010. The O&M
expenses do not include the cost of any SO(2) and NO(x) credits that may be
purchased by REMA, which are estimated and included as a separate expense item.
These costs are discussed in detail in the Assessment of Financial Projections
section of the report.
============================================================
HISTORICAL AND PROJECTED O&M EXPENSES(1)
- ------------------------------------------------------------
EXPENSE
YEAR ($, MILLION)
- ------------------------------------------------------------
1995 14.7
- ------------------------------------------------------------
1996 10.0
- ------------------------------------------------------------
1997 10.2
- ------------------------------------------------------------
1998 12.7
- ------------------------------------------------------------
1999 13.1
- ------------------------------------------------------------
2000-2010 10.1
============================================================
(1) Historical expenses reported in current year dollars and projected expenses
in 2000 dollars
The actual 1999 expenditure was $1.2 million over budget due to an unusual event
occurring in July 1999, that cost approximately $1.7 million. Unit 5 experienced
a furnace explosion causing damage not covered by insurance.
Projected O&M expenses include planned repairs or replacements, since no capital
additions are planned. In the present year, according to REMA projections, $4.6
million will be allocated for O&M. Major items are for a scheduled outage on
Unit 5, which will include the turbine and auxiliary equipment and electrical
controls. The O&M budget appears adequate to alleviate any maintenance deferrals
by the prior owner.
OVERHAUL SCHEDULE
Stone & Webster reviewed REMA's planned overhaul and maintenance schedule.
Outages are scheduled for each unit every two years.
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MAINTENANCE MANAGEMENT
Seward uses a computerized maintenance management system for tracking of work
orders. A work ticket is written and forwarded to maintenance. The maintenance
supervisor enters the information into the computer. The tagging procedure will
be printed out with the work assignment for the operator to secure the
equipment. REMA will convert the maintenance management to the SAP America
system as discussed in section 6.3.3. It is considered to be an acceptable
maintenance tracking system in the industry.
The spare parts inventory at the station appears to be sufficient and adequate
to support operations. The reported dollar value of parts and material inventory
was $4.3 million.
CAPITAL AND OVERHAUL EXPENSES
The capital expenses planned by REMA were reviewed. In Stone & Webster's
opinion, the assumed level of capital and overhaul expenses included in the
detailed forecast are adequate to keep the station operating reliably through
the projected retirement date.
6.3.6 TITUS STATION
STAFFING
The staffing level at Titus is currently 68. REMA plans to increase the level to
77, 61 union and 16 nonunion and has budgeted for this number. The hiring of
these additional people is in process. The full complement will include 42
assigned to operation, 29 assigned to maintenance, three assigned to
administration, and three instrument technicians. The staffing level had been
102 positions in 1994. The staffing level is adequate for the current mode of
operation.
Titus has historically been operated as an intermediate load plant, which is
on-line most of the time during the year with the load level usually varying
from full load to minimum load on a typical day.
The Titus staff appeared to have a cooperative attitude toward sharing
responsibility between maintenance and operations. This flexible staffing
arrangement is enhanced by an apparent lack of adversarial relationship with the
union.
Titus operates and maintains two GE frame 5 CTs. These units are remotely
operated from the Titus control room.
OPERATION AND MAINTENANCE EXPENSES
The historical labor and other O&M expenses and REMA's projected labor and other
O&M expenses are shown in the following table. The projected expenses are an
annual average of the projected expenses from 2000 through 2024. The O&M
expenses do not include the cost of any SO(2) and NO(x) credits that may be
purchased by REMA, which are estimated and included as a separate expense item.
These costs are discussed in detail in the Assessment of Financial Projections
section of the report.
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========================================================================
HISTORICAL AND PROJECTED O&M EXPENSES(1)
========================================================================
EXPENSES
YEAR ($, MILLION)
- ------------------------------------------------------------------------
1995 17.7
- ------------------------------------------------------------------------
1996 14.6
- ------------------------------------------------------------------------
1997 13.2
- ------------------------------------------------------------------------
1998 11.4
- ------------------------------------------------------------------------
1999 9.9
- ------------------------------------------------------------------------
2000-2024(2) 11.9
========================================================================
(1) Historical expenses reported in current year dollars and projected expenses
in 2000 dollars
(2) Includes $203,000 in levelized Titus CT projected expenses
As can be seen by the data in the table, the O&M cost has declined over the past
five years, which is due to decreased staffing and expenditures at the plant.
The plant has been reducing costs to stay competitive in an increasingly
aggressive market. The annual CT O&M expenses are levelized at $203,000, total
for both units, per year. This amount is reasonable based on past experience.
The O&M expenses appear to be adequate based on the staffing level, projected
operating level, and historical experience.
OVERHAUL SCHEDULE
Stone & Webster reviewed REMA's planned overhaul and maintenance schedule. Major
turbine overhauls were performed on Units 1, 2, and 3 in 1993, 1995, and 1996,
respectively. The units are scheduled to have major overhauls every nine years
starting in 2002 for Unit 1, 2004 for Unit 2, and 2008 for Unit 3. REMA is
planning boiler overhauls at three-year intervals with a three-day outage each
year before the summer peak load season to assure reliability.
The boiler condition and reliability is good for a plant of this vintage. A
three-year interval between boiler overhauls is longer than usual for this type
of plant; however, since there are very few boiler tube leaks this interval is
achievable. This boiler condition is also improved by low starts (12 per year).
The two CTs are scheduled for major maintenance overhaul in 2021 and 2022
because of their infrequent operation in peaking service.
MAINTENANCE MANAGEMENT
The functionality of the current maintenance information system and the
knowledge and skills of the employees who will use the system was observed and
found to be satisfactory to support maintenance control and reporting
requirements.
A REMA power plant maintenance information system will be used to control
maintenance information. The current system is used on the GPU central computer
mainframe. REMA will convert the maintenance management to the SAP America
system as discussed in section 6.3.3. It is considered to be an acceptable
maintenance tracking system in the industry.
The spare parts inventory at Titus appears to be sufficient and adequate to
support operations. The reported dollar value of parts and material inventory
was $5,209,317.
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CAPITAL AND OVERHAUL EXPENSES
The capital expenses planned by REMA were reviewed. In Stone & Webster's
opinion, the assumed level of capital and overhaul expenses included in the
detailed forecast are adequate to keep the station operating reliably through
the projected retirement date.
Funds have been allocated in 2021 and 2022, in the amount of $1.5 million each
year for the major maintenance/overhaul of the Titus CTs. The infrequent
operation of the equipment and recent improvements in condition monitoring and
preventive maintenance practices are expected to control the risk of premature
unforeseen equipment maintenance and repair expense.
6.3.7 SAYREVILLE STATION
STAFFING
The staffing level at Sayreville is currently 21. REMA plans to increase the
level to 26, and has budgeted for this number. There are currently a few people
who took the VERP but returned to work at Sayreville on a part-time, contract
basis. Sayreville has historically been operated only during periods of peak
power demand. The units generally do not operate during the off-season for
economic reasons but are available to start with 48 hours notice.
The staffing level two years ago was 80 positions. This large decrease in staff
has made it difficult to maintain the cleanliness of the plant. Throughout the
plant there is accumulation of debris, as well as, signs of neglect such as bent
gratings and rusted components. The maintenance activities have been
concentrated on operating reliability issues.
Scheduled maintenance on the units is performed during the off-season with the
operations staff being used for maintenance activities. This flexible staffing
arrangement enables the low staffing level for this type of limited operation.
The flexibility was accomplished with close cooperation between management and
the union. The staffing level is adequate for the current mode of operation
including limited operation during the summer peak season.
The Sayreville plant staff operates and maintains four Westinghouse 501AA units
at Sayreville and four identical units at Werner. The units are started and
operated from the Sayreville control room. The Sayreville staff performs routine
maintenance, normal preventive maintenance, and operating functions for Werner.
Historically, temporary workers have been contracted to support major
maintenance.
OPERATION AND MAINTENANCE EXPENSES
The historical labor and other O&M expenses and REMA's projected labor and other
O&M expenses are shown in the following table. The projected expenses are an
annual average of the projected expenses from 2000 through 2010. The O&M
expenses do not include the cost of any SO(2) and NO(x) credits that may be
purchased by REMA, which are estimated and included as a separate expense item.
These costs are discussed in detail in the Assessment of Financial Projections
section of the report.
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==============================================================
HISTORICAL AND PROJECTED O&M EXPENSES(1)
- --------------------------------------------------------------
EXPENSES
YEAR ($, MILLION)
- --------------------------------------------------------------
1995 8.2
- --------------------------------------------------------------
1996 10.1
- --------------------------------------------------------------
1997 7.4
- --------------------------------------------------------------
1998 5.7
- --------------------------------------------------------------
1999 4.4
- --------------------------------------------------------------
2000-2010(2) 7.1
- --------------------------------------------------------------
2011-2029(2) 1.88
==============================================================
(1) Historical expenses reported in current year dollars and projected expenses
in 2000 dollars
(2) Includes $1,880,000 in levelized Sayreville and Werner CT (each $940,000)
projected expenses continuing after the steam units retire in 2010.
The Werner CT is operated and maintained from Sayreville. The Werner CT budget
includes a levelized $940,000 per year between 2000 and 2029. The Sayreville CT
levelized budget includes $940,000 per year. The Sayreville and Werner CT budget
will continue after the steam units retire at the end of 2010. The O&M cost for
the steam plant has declined over the past four years, which is due to decreased
staffing and expenditures at the plant. The plant has changed from a traditional
utility operation to a more competitive business organization. The overall O&M
expenses appear to be adequate based on the staffing level, projected operating
level, and historical experience.
OVERHAUL SCHEDULE
Stone & Webster reviewed REMA's planned overhaul and maintenance schedule. The
Units 4 and 5 steam turbines were last overhauled in 1990 and 1986,
respectively. The units are scheduled to have a major turbine overhauls in 2004
for Unit 4 and 2005 for Unit 5. These units have significantly reduced the
number of operating hours per year. Even though the turbines are beyond the
normal interval between inspections this increased time is warranted based on
the limited operation, providing they are maintained properly during extended
shutdown periods. Regular boiler overhauls are no longer scheduled since this
type of major work can be accomplished while the units are out of service.
During our visit boiler tube replacement was ongoing and the unit was still
available on 48-hour notice.
There are no major maintenance inspections scheduled until 2020 for the CT units
because of their infrequent operation.
Given the low capacity factors, a deferred overhaul cycle is adequate and
reasonable assuming that the unit down time is used effectively. While a
nine-year major turbine overhaul cycle may be reasonable, the deferring of the
next major overhaul for Unit 5 may be optimistic as it will be 18 years since
the last major overhaul for this unit.
MAINTENANCE MANAGEMENT
The functionality of the current maintenance information system and the
knowledge and skills of the employees who will use the system was observed and
found to be satisfactory to support maintenance control and reporting
requirements.
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A REMA power plant maintenance information system will be used to control
maintenance information work orders, record maintenance history, and manage
parts inventory. The current system is used on the GPU central computer
mainframe. Reliant Mid-Atlanitc will convert the maintenance management to the
SAP America system as discussed in section 6.3.3. It is considered to be an
acceptable maintenance tracking system in the industry.
Stone & Webster reviewed REMA's summary O&M and capital budgets for Sayreville.
Stone & Webster visited the warehouse and observed that the inventory stock was
well organized and appeared well maintained. The spare parts inventory at
Sayreville appears to be sufficient and adequate to support operations. The
reported dollar value of parts and material inventory was $6,893,243.
CAPITAL AND OVERHAUL EXPENSES
The capital expenses planned by REMA were reviewed. In Stone & Webster's
opinion, the assumed level of capital and overhaul expenses included in the
detailed forecast for the steam units is adequate to keep the station operating
reliably through the projected retirement date.
In addition, $4.94 million has been budgeted for the major maintenance/overhaul
of the four CTs at Sayreville between 2020 and 2023. Similarly, $4.94 million
has been budgeted for the major maintenance/overhaul of the four CTs at Werner
between 2022 and 2025. In Stone & Webster's opinion, the assumed overhaul
expenses for the CTs are adequate to keep them operating reliably through 2029.
6.3.8 WARREN STATION
STAFFING
The staffing level at Warren is currently 29. REMA plans to increase the level
to 30, and has budgeted for this number. The staffing level has been reduced
significantly in recent years.
Since the units do not operate during periods of low demand, the operating
personnel are mostly all reassigned to help with maintenance tasks. This
flexibility makes the reduced staffing level possible. There is also some use of
contractors for major maintenance work. The staffing level is adequate for the
current mode of operation including economy outages in the spring and fall
seasons.
OPERATION AND MAINTENANCE EXPENSES
The historical labor and other O&M expenses are shown in the following table
along with REMA's projected O&M expenses. The projected expenses are an annual
average of the projected expenses from 2000 through the projected retirement
date. The O&M expenses do not include the cost of any SO(2) and NO(x) credits
that may be purchased by REMA, which are estimated and included as a separate
expense item. These costs are discussed in detail in the Assessment of the
Financial Projections section of the report.
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============================================================================
HISTORICAL AND PROJECTED O&M EXPENSES(1)
- ----------------------------------------------------------------------------
EXPENSES
YEAR ($, MILLION)
- ----------------------------------------------------------------------------
1995 $ 7.2
- ----------------------------------------------------------------------------
1996 $ 5.9
- ----------------------------------------------------------------------------
1997 $ 6.4
- ----------------------------------------------------------------------------
1998 $ 5.3
- ----------------------------------------------------------------------------
1999 $ 4.2
- ----------------------------------------------------------------------------
2000-2010(2) $ 4.1
- ----------------------------------------------------------------------------
2011-2029(2) $0.467
============================================================================
(1) Historical expenses reported in current year dollars and projected expenses
in $2000
(2) Includes $467,330 in levelized projected expenses for the Warren CT and the
Wayne CT (each $233,665) continuing after the steam units retire in 2010
The Warren budget includes a levelized $233,665 per year between 2000 and 2029.
The Warren CT budget will continue after the steam units retire in 2010. The
Warren staff also provides O&M services to the Wayne CT. The Wayne budget
includes a levelized $233,665 per year between 2000 and 2029. Warren has changed
from a traditional utility operation to a more competitive business
organization. The O&M expenses appear to be adequate based on the staffing
level, projected operating level, and historical experience.
OVERHAUL SCHEDULE
Stone & Webster reviewed REMA's planned overhaul and maintenance schedule. Major
turbine overhauls on Units 1 and 2 are scheduled every ten years. Turbine
overhauls are usually more frequent than every ten years, however, since the
amount of operating hours in each year is low due to the low dispatch of the
units then the ten year interval is adequate. REMA is planning boiler overhauls
at three-year intervals. This schedule is adequate since these units are out of
service during periods of low demand and many routine maintenance activities can
be done at those times.
MAINTENANCE MANAGEMENT
A REMA power plant maintenance information system will be used to control
maintenance information. REMA will convert the maintenance management to the SAP
America system as discussed in section 6.3.3. It is considered to be an
acceptable maintenance tracking system in the industry.
Stone & Webster reviewed REMA's summary O&M and capital budgets for Warren. The
spare parts inventory at Warren appears to be sufficient and adequate to support
operations. The reported dollar value of parts and material inventory was $1.9
million.
CAPITAL AND OVERHAUL EXPENSES
The capital expenses planned by REMA were reviewed. In Stone & Webster's
opinion, the assumed level of capital and overhaul expenses included in the
detailed forecast are adequate to keep the station operating reliably through
the retirement date.
In addition, $4.0 million has been budgeted for major maintenance/overhaul for
the CT at Wayne in 2021. Similarly, $4.0 million has been budgeted for major
maintenance/overhaul for the CT at Warren in 2021.
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In Stone & Webster's opinion, the assumed overhaul expenses for the CTs are
adequate to keep them operating reliably through the projected retirement date.
6.3.9 GILBERT STATION
STAFFING
The current approved staffing level at Gilbert is 49 including, 12 management
and 37 bargaining unit employees. The employees are organized to provide the
maximum coverage during the week, recognizing that the units are usually in
stand-by reserve and infrequently operated. The operators are assigned to one of
the three rotating shifts on a five days per week basis. Weekends do not
normally require supervised coverage by a full shift. The present arrangement
for shift coverage appears to provide greater coverage than is actually required
and REMA is examining the current staffing levels. The staffing level is more
than adequate for the current mode of operation.
The bargaining unit contract allows flexibility for work assignments. Operators
can do light maintenance on shift and can support heavy maintenance work off
shift. The worker attitude and work ethic appears to be quite positive. The
workers and their union appear to understand the demands of the competitive
market and the need for competitive performance. The station maintenance staff
has the skill, craftsmen, and shop equipment necessary to perform almost all
maintenance with in-house resources. However, if staffing is reduced outside
support for some outages may become necessary.
OPERATION AND MAINTENANCE EXPENSES
A levelized amount equal to approximately $6 million covers the cost of labor,
materials, consumables, all routine O&M and minor inspections, maintenance and
repair for four simple cycle CTs, four combined cycle units with four HRSGs and
a single steam turbine generator, and one advanced technology ABB GT-24 simple
cycle unit. The O&M expenses do not include the cost of any SO(2) and NO(x)
credits that may be purchased by REMA, which are estimated and included as a
separate expense item. These costs are discussed in detail in the Assessment of
Financial Projections section of the report. The actual distribution will vary
from year to year, as will the actual total expenditure for any given year. In
conclusion, the levelized $6 million budget is achievable.
OVERHAUL SCHEDULE
Major inspection and overhauls for the generating units are not scheduled for
2020; however, this is reasonable due to the peaking operation of the facility.
MAINTENANCE MANAGEMENT
A REMA power plant maintenance information system will be used to control
maintenance information. REMA will convert the maintenance management to the SAP
America system as discussed in section 6.3.3. It is considered to be an
acceptable maintenance tracking system in the industry.
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CAPITAL AND OVERHEAD EXPENSES
A total of $40 million is allocated for major inspection and overhaul of all the
generation equipment between 2021 and 2024. A total of $6 million in the first
year and $4 million in each of the years two through 4 has been allocated to
cover unforeseen major maintenance. Stone & Webster believes that this is a
reasonable conservative allocation that provides adequate allowance for
uncertainty.
6.3.10 COMBUSTION TURBINES
STAFFING
The remote location CTs at Hunterstown, Orrtanna, Hamilton, Mountain, and Tolna
are maintained by a four-person group based at Hunterstown. They are monitored
and serviced for routine preventive maintenance and condition monitoring by
three technicians and a supervisor. The important operating data and alarms are
available to the technicians at Hunterstown through a computer network. The
units are started remotely from the GPU / PJM dispatch center. The staffing
level is adequate for the current mode of operation.
Glen Gardner was modified so that it can be operated remotely from Gilbert.
OPERATION AND MAINTENANCE EXPENSES
The REMA's projected labor and other O&M expenses are shown in the following
table. The projected expenses are levelized over the period from 2000 through
2020. The O&M expenses do not include the cost of any SO(2) and NO(x) credits
that may be purchased by REMA, which are estimated and included as a separate
expense item. These costs are discussed in detail in the Assessment of Financial
Projections section of the report.
===========================================================
PROJECTED O&M EXPENSES
- ----------------------------------------------------------
EXPENSES
YEAR ($, MILLION)
- ----------------------------------------------------------
Hunterstown 0.39
- ----------------------------------------------------------
Orrtanna 0.13
- ----------------------------------------------------------
Hamilton 0.13
- ----------------------------------------------------------
Mountain 0.26
- ----------------------------------------------------------
Tolna 0.26
- ----------------------------------------------------------
Blossburg 0.13
- ----------------------------------------------------------
Glen Gardner 1.05
==========================================================
REMA has allocated a levelized O&M budget per year for each unit, which is
intended to cover the cost of routine maintenance and periodic minor
inspections. Because of the infrequent operation, and low accumulation of starts
and operating hours, the need for a costly major inspection is not expected to
materialize before 2020. The capital expenditure budget is minimal but adequate,
and is dedicated to environmental requirements.
OVERHAUL SCHEDULE
Each of the units will have a major inspection and overhaul between 2020 and
2024; however, this is reasonable due to the peaking operation of the
facilities.
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MAINTENANCE MANAGEMENT
REMA will convert the maintenance management to the SAP America system that it
currently uses at its utility and merchant plants. REMA will convert the
maintenance management to the SAP America system as discussed in section 6.3.3.
It is considered to be an acceptable maintenance tracking system in the
industry.
CAPITAL AND OVERHAUL EXPENSES
Each of the units is allocated $1.5 million for a major inspection and overhaul
that will occur between 2020 and 2024. In Stone & Webster's opinion, the assumed
level of capital and overhaul expenses included in the detailed forecast are
adequate to keep the stations operating reliably through the projected
retirement dates.
6.3.11 PINEY STATION
STAFFING
Piney has a permanent staff of six people - five union and one non-union. There
is at least one person at the site at all times. Personnel from Warren also
provide support to Piney, as needed. This support amounts to the equivalent of
about one full-time person. Piney personnel also provide operational support to
Warren. This support consists of routine attention to the CT. The staffing level
is adequate for the current mode of operation.
OPERATION AND MAINTENANCE AND CAPITAL EXPENDITURES
Information provided by station personnel indicates that all three units are
provided with an annual inspection that includes routine maintenance. The level
of annual maintenance appears to have increased after 1983, when a fire caused
replacement of the control system and required further inspections and cleanup
of the generators.
Repairs to the spillway were recommended by an independent consultant as result
of the five-year safety inspection on a prioritized basis with six spillway bays
to be completed within five years of the inspection and the remainder of the
spillway to be completed within ten years of the inspection. Repairs were begun
in 1997 under GPU ownership. Total budget for this work was $4.6 million.
Station personnel have advised that the repairs on the spillway toe and five of
the six highest priority bays are complete. About 60% of the recommended
spillway repairs, including one higher priority bay, remain to be performed. The
remaining 2000 budget for this activity is $0.9 million.
We understand that the annual O&M costs for the 10-year period through 1999 were
about $1,330,000. REMA's projected labor, other O&M, and capital expenses are
shown in the following table.
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=====================================================================================
PROJECTED O&M EXPENSES
=====================================================================================
YEAR O&M CAPITAL TOTAL
- -------------------------------------------------------------------------------------
2000 $906,000 $ 700,000 $ 1,606,000
- -------------------------------------------------------------------------------------
2001 $912,000 $ 725,000 $ 1,637,000
- -------------------------------------------------------------------------------------
2002 $902,000 $1,149,000 $ 2,051,000
- -------------------------------------------------------------------------------------
2003 $902,000 $ 816,000 $ 1,718,000
- -------------------------------------------------------------------------------------
2004 $902,000 $ 150,000 $ 1,052,000
=====================================================================================
These budgets appear be reasonable for typical use. Currently, the turbine
runner has been replaced with the spare turbine runner that had been provided in
the initial installation. In Stone & Webster's opinion, the assumed level of
capital and overhaul expenses included in the detailed forecast are adequate to
keep the station operating reliably through the projected retirement date.
OVERHAUL SCHEDULE
Information provided indicates that all three units are provided with an annual
inspection that includes routine maintenance. Piney appears to be maintained in
a good operational condition, based on the observations made during the site
visit of March 14, 2000. This schedule is adequate given the projected
operation.
MAINTENANCE MANAGEMENT
REMA will convert the maintenance management to the SAP America system as
discussed in section 6.3.3. It is considered to be an acceptable maintenance
tracking system in the industry.
6.3.12 DEEP CREEK
STAFFING
Deep Creek has a staff of two full-time people, with an off-site superintendent
at Seward. This staffing level represents a reduction from three full-time
people in 1997 and from four full-time people in 1995. Supplementary staffing
has been provided by temporary employees.
OPERATION AND MAINTENANCE AND CAPITAL EXPENSES
Deep Creek personnel provided the following data on historical expenditures for
O&M.
===============================================
HISTORICAL O&M EXPENSES
- -----------------------------------------------
YEAR EXPENSES
- -----------------------------------------------
1997 $506,000
- -----------------------------------------------
1998 $501,000
- -----------------------------------------------
1999 $351,000
===============================================
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REMA's projected labor, other O&M, and capital expenses are shown in the
following table.
=======================================================================================
PROJECTED O&M EXPENSES
- ---------------------------------------------------------------------------------------
YEAR O&M CAPITAL TOTAL
- ---------------------------------------------------------------------------------------
2000 $ 450,000 $ 95,000 $ 545,000
- ---------------------------------------------------------------------------------------
2001 $ 450,000 $ 600,000 $1,050,000
- ---------------------------------------------------------------------------------------
2002 $ 450,000 $ 0 $ 450,000
- ---------------------------------------------------------------------------------------
2003 $ 450,000 $ 600,000 $1,050,000
- ---------------------------------------------------------------------------------------
2004 $ 450,000 $ 450,000 $ 900,000
=======================================================================================
The O&M costs for the year 2000 include $250,000 for OCB replacement that has
already been completed. The O&M costs for 2001 include $150,000 for voltage
regulator upgrade. The budget provided appears to be reasonable. In Stone &
Webster's opinion, the assumed level of capital and overhaul expenses included
in the detailed forecast are adequate to keep the station operating reliably
through the projected retirement date.
OVERHAUL SCHEDULE
Deep Creek appears to be maintained in very good operational condition based on
the observations made during our site visit. The following maintenance
activities are scheduled for the next five years:
2001 Two week clean-up inspection
2002 Two week clean-up inspection
2003 Three week internal inspection/unit
2004 Two week clean-up inspection
2005 Two week clean-up inspection
MAINTENANCE MANAGEMENT
REMA will convert the maintenance management to the SAP America system as
discussed in section 6.3.3. It is considered to be an acceptable maintenance
tracking system in the industry.
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7. PROJECT AGREEMENTS
Stone & Webster reviewed the primary contracts and agreements associated with
the Facilities. These included the Purchase and Sale Agreement and Transition
Power Purchase Agreements.
Stone & Webster reviewed the agreements from a technical and economic standpoint
to assess the adequacy and reasonableness of their terms and conditions. Legal,
financial, and other important aspects of the agreements associated with the
Facilities were not considered under this review. This Report describes only
portions of the Project Agreements needed for the discussion issues related to
the Facilities. A complete description or legal evaluation of the contracts and
documents related to the Facilities is beyond the scope of this report, and
Stone & Webster is not providing legal counsel opinions regarding the legal
interpretation of any contract language. Adherence to industry standards and
good engineering practice was assessed where appropriate. Provided below is a
summary of our findings for each of the reviewed agreements.
7.1 PURCHASE AND SALE AGREEMENT
Stone & Webster reviewed the executed PSA between Reliant Energy Power
Generation, Inc. ("REPG"), Reliant Energy, Incorporated, and Sithe dated
February 19, 2000. In general, the text of the PSA appears to be reasonable and
contains the typical requirements included in documents of this kind. It should
be noted that Stone & Webster is not a qualified legal counsel and so directs
the reader to obtain comfort concerning the legal warranties and representations
made in the agreement from legal counsel.
The PSA provides for the transfer of ownership of (a) all of the issued and
outstanding stock of Sithe Mid-Atlantic, (b) all of the limited liability
company interests, and (c) all the intercompany notes held by Sithe for a fixed
purchase price plus an adjustment, either positive or negative, at closing. In
addition, REPG is required to provide Letters of Credit ("LOC") or performance
bonds totaling approximately $23.9 million, which will be used to replace the
existing Sithe LOCs.
The schedules attached to the PSA include, but are not limited to:
identification of the contracts and agreements entered into by Sithe and its
affiliates, including the limited liability companies, which describe the
properties acquired from GPU; a list of other material contracts including
environmental agreements; development assets (primarily referencing letters and
Memorandums of Understanding); lists of real estate related documents; titles to
real property; financial information; a list of contracts which will not be
amended; and an Interim Services Agreement between Sithe and REPG.
If Sithe requests, REPG will use reasonable efforts to cause all third parties
to release Sithe and its affiliates from all GPU liabilities. REPG will assume
those liabilities. Under the PSA, REPG will assume all obligations and
liabilities of Sithe in connection with (a) six specified development projects,
(b) certain obligations arising from Sithe's acquisition of the Facilities from
GPU, and (c) the intercompany notes.
Sithe has an agreement with the NJDEP to perform remediation of the Glen
Gardner, Sayreville, Werner, and Gilbert generating facilities. REPG agrees
that, upon closing, Sithe and their affiliates shall have no responsibility for
compliance with the New Jersey Industrial Site Recovery Act ("ISRA"). REPG will
assume all of Sithe's ISRA obligations and liabilities related to the GPU
assets, and shall indemnify and hold harmless Sithe and its affiliates (except
the limited liability companies and their subsidiaries) and its shareholders for
any costs or liabilities addressed in the existing Remediation Agreements
between Sithe New Jersey Holding LLC and NJDEP. Remediation under ISRA for the
New Jersey facilities is estimated at $5 million. Schedule 3.17 of the PSA
includes information on other environmental matters.
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Seward is subject to a Consent Order and Agreement that includes remediation of
a coal ash site, the cost of which has been estimated to cost between $5 million
and $20 million.
URS Greiner Woodward-Clyde Consultants prepared a number of reports for the GPU
stations including Phase I Environmental Site Assessment Reports, Preliminary
Assessment Reports, Reports on Surrounding Properties, Final Reports of Review
of Database Records, and Phase II Investigation Reports and a December 1999
Update. Stone & Webster has reviewed these reports to determine, based on our
site visit in March 2000, if there are any material differences between the
latest December 1999 Update and our site visits.
This agreement may be assigned to a subsidiary of REPG or Reliant Energy,
Incorporated. Either party may assign this agreement to a third party upon the
written agreement of the non-assigning party. The Buyer may not assign its
rights, interests, and obligations if such assignment could be expected to delay
the closing.
7.2 TRANSITION POWER PURCHASE AGREEMENTS
Stone & Webster reviewed three executed Amended and Restated TPPAs between Sithe
and in the case of each TPPA either Metropolitan Edison Company, Pennsylvania
Electric Company, or Jersey Central Power & Light Company (collectively known as
"GPU"); all dated November 24, 1999. In connection with the acquisition of the
Facilities, REMA will acquire the rights and obligations of Sithe under the
TPPAs. Stone & Webster reviewed the TPPAs and concludes that they are reasonable
and adequate.
The TPPAs establish that REMA and GPU have option agreements for the purchase
and sale of electric generating capacity, but not energy or ancillary services.
REMA has "put options" whereby GPU is obligated to accept and purchase capacity
from REMA up to the maximum put capacity. GPU has "call options" whereby REMA is
required to provide and sell capacity to GPU up to the maximum call capacity.
REMA must notify GPU of its decision whether or not to exercise its put option
before GPU can exercise its call option.
The maximum put capacity for each contract year equals GPU's forecast of the
amount of installed capacity that it will need to satisfy its installed capacity
obligations during that contract year minus the installed capacity available to
GPU from specified other sources. The maximum call capacity for each contract
year equals the maximum put capacity minus the amount of installed capacity for
which REMA exercises its put option for that contract year.
The term of the TPPAs began November 24, 1999 and will end on May 31, 2002 (or,
if the PJM planning year changes, the last day of the PJM planning year ending
in 2002). There is no provision included for unilateral extension or early
termination.
Each TPPA includes a schedule that lists the electric generating facilities
owned by REMA specific to each TPPA. The summer installed capacity ("ICF") for
each of these facilities is listed in Schedule B of each TPPA.
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A schedule of put and call prices is included and is common to all three
agreements. The prices, in $/MW-day, are:
======================================================================================================
PUT AND CALL PRICE SCHEDULE
======================================================================================================
CALL PRICE PUT PRICE
TIME PERIOD ($/MW-DAY) ($/MW-DAY)
- ------------------------------------------------------------------------------------------------------
November 24, 1999 to May 31, 2000 85.20 65.80
- ------------------------------------------------------------------------------------------------------
June 1, 2000 to May 31, 2001 110.90 85.10
- ------------------------------------------------------------------------------------------------------
June 1, 2001 to May 31, 2002 120.40 93.00
======================================================================================================
The monthly payments are calculated as:
MP = Payment Amount times Days in the month times Forced Outage Adjustment
The payment amount is the (call price times call capacity) plus (put price times
put capacity). The forced outage adjustment is the ratio of the unforced
capacity/purchased capacity, but limited to a maximum of 0.91.
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8. ASSESSMENT OF FINANCIAL PROJECTIONS
8.1 OVERVIEW
The Financial Projections consist of a financial model for REMA (the "Base
Case") and the sensitivity cases. Stone & Webster developed the financial model
for REMA based on a model developed by REMA. Key inputs into the financial model
were obtained from Hagler Bailly and REMA. Babcock & Brown, LP ("Babcock &
Brown") and Chase Securities Inc. provided the financing assumptions including
the schedule of fixed charge payments.
The Financial Projections show the cash available for the fixed charges from
2000 (partial year beginning on July 1, 2000) through the maturity of the
certificates, 2026 (partial year ending on July 1, 2026), and include the
revenues and expenses for all of the plants. The first and last years, 2000 and
2026, consist of two quarters of operation each. The Financial Projections are
calculated in nominal dollars based on an assumed inflation rate of 2.5% per
annum. The sensitivity cases address the impact of changes in key variables on
the coverage of fixed charges.
Stone & Webster integrated the market cases prepared by Hagler Bailly for the
period 2000 through 2020. The information obtained from Hagler Bailly included
the following:
o Energy generation by unit
o Market revenues by unit
o Average market prices by unit
o Fuel expenses by unit
o SO(2) and NO(x) emission credit unit prices
The integration of Hagler Bailly's forecasts into the financial model required
certain adjustments to be made to the market revenues to reflect contract energy
sales for the remaining portion of 2000 and the first two months of 2001. These
adjustments were made using Hagler Bailly's regional energy prices. In addition,
as the Financial Projections are for the years 2000 through 2026, the market
forecast was extended from 2020 through 2026 by escalating the 2020 market
prices by the assumed inflation rate used for the Financial Projections (2.5%
per year).
For the first and last year of the Financial Projections, the annual projections
were adjusted to address the partial years. Fixed costs were reduced by
approximately 50%, as were the electric generation, market revenues, and fuel
expenses. The Financial Projections show cash available for fixed charges for
the partial years 2000 and 2026. Currently, REMA makes interest payments on
intercompany notes at the end of each quarter. The third quarter payment is due
on September 30th, 2000. At closing, the fixed charges will become senior in
right of payment to the interest on intercompany notes (including for the third
quarter) and therefore the projection for cash available for fixed charges
begins on July 1, 2000.
Stone & Webster has reviewed the assumptions and the data necessary to support
the projections of cash flow available for the fixed charge payments. Stone &
Webster has verified that the underlying model assumptions are consistent with
the Hagler Bailly projected generation and pricing. Stone & Webster has not
reviewed the tax, depreciation, and financing assumptions, including the fixed
charge payment, which was provided by Chase Securities Inc. and Babcock & Brown.
Lastly, Stone & Webster performed several sensitivities to determine the impact
of certain variables on the FCCRs.
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8.2 PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
In preparing this Report and the conclusions contained herein, Stone & Webster
has made certain assumptions with respect to the conditions, which may exist, or
events, which may occur in the future. While Stone & Webster believes these
assumptions to be reasonable for the purpose of this Report, they are dependent
on future events, and actual conditions may differ from those assumed. In
addition, Stone & Webster has used and relied on information provided to us by
sources that we believe to be reliable. Stone & Webster believes that the use of
this information and assumptions is reasonable for the purposes of our Report.
However, some assumptions may vary significantly due to unanticipated events and
circumstances. To the extent that actual future conditions may differ from those
assumed in this Report, or provided to us by others, the actual results will
vary from those forecast. This Report summarizes our work up to the date of the
Report and changes in conditions occurring or that became known after such date
could affect the Financial Projections.
The principal considerations and assumptions related to the Financial
Projections are listed below:
1. Stone & Webster has made no determination as to the validity and
enforceability of any contract, agreement, rule, or regulation as
applicable to the Facilities and their operations. For the purposes of this
Report, Stone & Webster has assumed that all contracts, agreements, rules,
or regulations will be valid and fully enforceable in accordance with the
terms and that all parties will comply with the provisions of their
respective agreements.
2. The electricity market price projections were prepared by Hagler Bailly for
REMA, using a market simulation model. Stone & Webster reviewed the
technical inputs to the Hagler Bailly model and found them to be
reasonable. Stone & Webster did not independently verify the methodology
used by Hagler Bailly to develop the energy price forecasts nor verify the
accuracy of the forecasts.
3. Stone & Webster has reviewed the capital and O&M budgets for the
Facilities. We have assumed that the Facilities will be operated and
maintained in accordance with the O&M, major maintenance, and capital
budgets, standard industry practice, and in a safe and environmentally
responsible manner.
4. Stone & Webster has assumed that the maintenance will be performed by REMA
in accordance with standard industry practice.
5. The coal, natural gas, and fuel oil prices are inputs to the Hagler Bailly
model. Stone & Webster has not reviewed the fuel price forecasts provided
by Hagler Bailly. It is assumed that fuel will be available in sufficient
quantities and at the prices forecasted for the period covered in the
Financial Projections.
6. Stone & Webster has assumed that all licenses, permits, and approvals
required to operate the Facilities which need to be renewed during the
period covered by the Financial Projections will be obtained on a timely
basis.
7. Stone & Webster has assumed that REMA will be able to purchase SO(2) and
NO(x) emission credits in order to comply with its emission limits for
these pollutants. We have assumed that emission offsets will be available
for purchase by REMA and that sufficient demand exists for the sale of
certain emission credits by REMA at the projected prices or at higher
prices. REMA can either purchase the credits (if they are available) or
implement other methods of reducing emissions including using alternate
fuels and/or installing additional air pollution control equipment.
8. Stone & Webster has not evaluated the non-operating expenses projected by
REMA including property taxes, insurance, and general and administrative
expenses. We have assumed that these expenses are as projected by REMA.
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9. Stone & Webster has reviewed the staffing plans prepared by REMA. We assume
that REMA will operate the Facilities in accordance with the staffing
plans.
10. The projected overhaul schedule and major maintenance and capital
expenditure forecasts prepared by REMA were reviewed by Stone & Webster. We
are assuming that REMA will be overhauling the Facilities and incurring
overhaul and capital expenses in accordance with the forecasts shown in the
Financial Projections.
11. Stone & Webster has assumed for purposes of the Financial Projections that
all the Facilities operate to the retirement dates forecasted by REMA. The
Financial Projections assume no additional generation assets are acquired
or constructed by REMA.
8.3 REVENUES
The revenues forecasted in the Financial Projections include market revenues and
contract revenues. The market revenues are the sum of the market revenues and a
market valuation. The market revenues were provided by Hagler Bailly based on
the projected dispatch of each plant and the relevant market prices. Hagler
Bailly has developed a proprietary market valuation process ("MVP") to estimate
the value of electric generation units based on the level of prices and their
volatility. MVP captures the value of price volatility.
REMA will assume the TPPAs that Sithe had negotiated with GPU for the years 2000
through 2002. In addition to the TPPAs, REMA negotiated market energy contracts
for the period from transfer of ownership through February 2001. The resulting
change in revenue includes an additional $5.139 million and $0.46 million over
the projected market prices for years 2000 and 2001, respectively. The contract
payment price under the TPPA and the total contract revenues including the REMA
negotiated market energy contracts are summarized in the following table.
================================================================================
CONTRACT REVENUES
================================================================================
CONTRACT PURCHASE PRICE TOTAL CONTRACT REVENUES
YEAR ($/kW-YR) ($ ,000)
- --------------------------------------------------------------------------------
2000 28.00 43,546(1)
- --------------------------------------------------------------------------------
2001 32.00 88,012
- --------------------------------------------------------------------------------
2002 21.12 57,782(2)
================================================================================
(1) Revenue for the period from July 1 through the end of the year
(2) Revenue for the period through May 31, 2002
The total operating revenue for the first full operating year (Year 2001)
including the market revenue and the contract revenues is $747 million.
8.4 OPERATING EXPENSES
The major expenses estimated in the Financial Projections include the following:
o Fixed O&M costs
o Variable O&M costs
o Administrative costs
o Insurance and property taxes
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o Major maintenance and capitalized maintenance
o Environmental expenditures
o Direct and indirect plant labor expenses
o Fuel supply and transportation costs
8.4.1 FIXED AND VARIABLE O&M EXPENSES
In the financial model, the estimated O&M expenses are in nominal dollars
reflecting an assumed 2.5% inflation per year. The first full calendar year
(Year 2001) non-fuel O&M expenses, which total $151.4 million, are detailed in
the following table.
================================================================================
ESTIMATED NON-FUEL O&M EXPENSES
(2001 $ ,000)
================================================================================
Plant O&M 114,954
- --------------------------------------------------------------------------------
Taxes 4,273
- --------------------------------------------------------------------------------
General and Administration $ 12,902
- --------------------------------------------------------------------------------
Insurance 815
- --------------------------------------------------------------------------------
Emission Costs 18,423
- --------------------------------------------------------------------------------
TOTAL NON-FUEL O&M EXPENSES $151,367
================================================================================
The plant O&M includes labor, routine non-labor O&M, remaining life extension
budget, inspection and outage, auxiliary power, and environmental costs. Stone &
Webster reviewed the O&M assumptions utilized in the Financial Projections. The
information reviewed included assumptions and forecasts for unit performance;
staffing functions and levels; annual O&M budget summary; and unit overhaul
plans and schedules. Stone & Webster compared the information with its
experience for similarly configured plants and cost and staffing information for
similar plants. Stone & Webster considers these assumptions to be reasonable and
comparable to other facilities of similar design.
The other O&M costs include general and administrative expenses, taxes, and
insurance. In 2001, the other expenses are projected to be approximately $18
million. The general and administration costs include the costs associated with
administrating the Facilities, the fuel supply and power marketing fees, and
corporate services. The corporate services and fuel supply and power marketing
fees are subordinated to the fixed charges, which for year 2001 are
approximately $11.8 million.
Stone & Webster reviewed the non-fuel fixed, variable, and major maintenance
expenses in the Financial Projections. Stone & Webster believes that the O&M
budget is sufficient to support the planned staffing level, the maintenance and
overhaul schedule, and the project's performance and business objectives.
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8.4.2 CAPITAL IMPROVEMENTS
The Financial Projections reflect the capital improvement budget shown in the
following table.
================================================================================
ANNUAL CAPITAL BUDGET
($ ,000)
================================================================================
YEAR CAPITAL EXPENDITURES
- --------------------------------------------------------------------------------
2000 8,599
- --------------------------------------------------------------------------------
2001 28,843
- --------------------------------------------------------------------------------
2002 67,803
- --------------------------------------------------------------------------------
2003 38,362
- --------------------------------------------------------------------------------
2004 21,104
- --------------------------------------------------------------------------------
2005 6,091
- --------------------------------------------------------------------------------
2006 27,206
- --------------------------------------------------------------------------------
2007 24,693
- --------------------------------------------------------------------------------
2008 15,911
- --------------------------------------------------------------------------------
2009 14,644
- --------------------------------------------------------------------------------
2010 5,164
- --------------------------------------------------------------------------------
2011 4,382
- --------------------------------------------------------------------------------
2012 1,268
- --------------------------------------------------------------------------------
2013 1,710
- --------------------------------------------------------------------------------
2014 4,939
- --------------------------------------------------------------------------------
2015 16,932
- --------------------------------------------------------------------------------
2016 1,009
- --------------------------------------------------------------------------------
2017 12,095
- --------------------------------------------------------------------------------
2018 488
- --------------------------------------------------------------------------------
2019 3,973
- --------------------------------------------------------------------------------
2020 15,946
- --------------------------------------------------------------------------------
2021 1,558
- --------------------------------------------------------------------------------
2022 5,907
- --------------------------------------------------------------------------------
2023 32,000
- --------------------------------------------------------------------------------
2024 51,642
- --------------------------------------------------------------------------------
2025 132,999
- --------------------------------------------------------------------------------
2026 112,727
- --------------------------------------------------------------------------------
2027 50,222
- --------------------------------------------------------------------------------
2028 4,245
- --------------------------------------------------------------------------------
2029 14,917
================================================================================
The capital budget includes projected environmental capital expenditures. All
major maintenance items are included in the remaining life extension budget.
8.4.3 EMISSION COMPLIANCE COSTS/REVENUES
The emission compliance costs/revenues consist of the cost/revenues associated
with the purchase/sale of NO(x) and SO(2) emission credits. REMA is currently
planning on complying with NO(x) and SO(2) emission limits through the purchase
of emission credits and the installation of environmental controls. The required
NO(x) emission credits are calculated from the emission rate and the heat input
for each facility.
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The required SO(2) emission credits are calculated from the fuel usage and the
fuel sulfur content. The unit prices for the emission credits were obtained from
Hagler Bailly.
The unit pricing for NO(x) emission credits (in 1999$'s) is projected to average
approximately $4,200 per ton. The projections indicate that credits will cost
$3,400 per ton for three years and rise to $4,700 per ton in 2003. After 2003,
the unit price for the NO(x) emission credits ranges from $4,200 to $4,300 per
ton (all in 1999$'s).
The unit pricing for SO(2) emission credits (in 1999$'s) is projected to average
$341 per ton. The projections start at $187 per ton and increase to $404 per ton
in 2010. After 2010, the unit price for SO(2) emission credits remains at $404
per ton (in 1999$'s).
The SO(2) and NO(x) allowances allocated to the Facilities and used in the
Financial Projections are shown in the following table along with the emission
reduction credits that are to be purchased or sold. The allowances and credits
are shown as average values for 2000 through 2004, 2005 through 2009, and from
2010 through 2029. The SO(2) allowances and the Phase II NO(x) allowances were
obtained from independent engineer's report performed for Sithe, Appendix A of
the Final Section 126 Rule for the Pennsylvania facilities, and from proposed
amendments to the New Jersey NO(x) budget program for the New Jersey facilities.
The NO(x) allowances for Phase III (starting in the 2003 ozone season) are
calculated based on the New York, Connecticut and Massachusetts SIP Call draft
allocation proposals.
================================================================================
SO(2) AND NO(X) EMISSIONS AND ALLOWANCES
(TONS PER YEAR)
================================================================================
SO(2) ALLOCATED NO(X) ALLOCATED
YEAR SO(2) EMISSION ALLOWANCE NO(X) EMISSION ALLOWANCE
- --------------------------------------------------------------------------------
2000 166,031 166,031 9,418 9,418
- --------------------------------------------------------------------------------
2001 166,018 69,523 9,463 10,056
- --------------------------------------------------------------------------------
2002 165,400 69,523 9,341 10,056
- --------------------------------------------------------------------------------
2003 169,726 69,523 6,042 4,972
- --------------------------------------------------------------------------------
2004 171,030 69,523 6,026 4,972
- --------------------------------------------------------------------------------
2005 168,812 69,523 5,933 4,972
- --------------------------------------------------------------------------------
2006 167,430 69,523 5,784 4,972
- --------------------------------------------------------------------------------
2007 164,743 69,523 5,736 4,972
- --------------------------------------------------------------------------------
2008 165,530 69,523 5,700 4,972
- --------------------------------------------------------------------------------
2009 166,214 69,523 5,761 4,972
- --------------------------------------------------------------------------------
2010 164,283 69,105 5,671 4,972
- --------------------------------------------------------------------------------
2011 140,850 69,105 4,602 4,972
- --------------------------------------------------------------------------------
2012 141,251 69,105 4,581 4,972
- --------------------------------------------------------------------------------
2013 141,448 69,105 4,625 4,972
- --------------------------------------------------------------------------------
2014 142,011 69,105 4,644 4,926
- --------------------------------------------------------------------------------
2015 142,374 69,105 4,690 4,926
- --------------------------------------------------------------------------------
2016 145,063 69,105 4,796 4,926
- --------------------------------------------------------------------------------
2017 147,083 69,105 4,766 4,926
- --------------------------------------------------------------------------------
2018 148,856 69,105 4,867 4,420
- --------------------------------------------------------------------------------
2019 149,843 69,105 4,803 4,420
- --------------------------------------------------------------------------------
2020 151,809 69,105 4,814 4,420
- --------------------------------------------------------------------------------
2021 151,809 69,105 4,814 4,420
- --------------------------------------------------------------------------------
2022 151,809 69,105 4,814 4,420
- --------------------------------------------------------------------------------
2023 151,809 69,105 4,814 4,420
- --------------------------------------------------------------------------------
2024 139,601 69,105 4,276 4,420
- --------------------------------------------------------------------------------
2025 79,188 69,105 2,469 2,834
- --------------------------------------------------------------------------------
2026 52,200 69,105 2,469 2,834
- --------------------------------------------------------------------------------
2027 25,140 69,105 2,469 2,834
- --------------------------------------------------------------------------------
2028 25,140 69,105 2,469 2,466
- --------------------------------------------------------------------------------
2029 25,140 69,105 2,469 2,466
================================================================================
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8.4.4 FUEL EXPENSE
Hagler Bailly developed the fuel expense forecast for the Facilities. Stone &
Webster has not reviewed the fuel price forecasts used by Hagler Bailly. The
Facilities are fueled by natural gas, No. 2 fuel oil, and/or coal. It is assumed
that the fuel for the Facilities is purchased from the spot market and through
short-term contracts.
Hagler Bailly's model representation of coal costs included the following:
o The total tonnage of coal
o The coal tonnage taken under each railroad and producer contract
o The contract pricing, including escalation formulas in some cases
o The pricing of non-contract coal and rail freight for the period after
the expiration of the current contracts
The delivered natural gas cost forecast for the gas-fired plants is based on
Hagler Bailly's projection of gas market prices.
================================================================================
HAGLER BAILLY'S TOTAL DELIVERED NATURAL GAS COST PROJECTIONS
(1999$ ,000S)
================================================================================
STATION 2000 2005 2010 2015 2020(1)
- --------------------------------------------------------------------------------
Blossburg 2.77 2.83 2.95 3.03 3.23
- --------------------------------------------------------------------------------
Gilbert 2.79 2.85 2.97 3.06 3.31
- --------------------------------------------------------------------------------
Glen Gardner 2.77 2.83 2.95 3.03 3.23
- --------------------------------------------------------------------------------
Hunterstown 2.77 2.83 2.95 3.03 3.23
- --------------------------------------------------------------------------------
Mountain 2.77 2.83 2.95 3.03 3.23
- --------------------------------------------------------------------------------
Portland 2.77 2.83 2.95 3.02 3.22
- --------------------------------------------------------------------------------
Sayreville ST 2.94 3.02 3.18 NA NA
- --------------------------------------------------------------------------------
Sayreville C GT 2.77 2.83 2.95 3.03 3.28
- --------------------------------------------------------------------------------
Titus 2.77 2.83 2.95 3.03 3.23
- --------------------------------------------------------------------------------
Warren 2.71 2.75 2.94 2.95 3.14
================================================================================
NA - Not Applicable
(1) Fuel after 2020 was escalated at inflation for those facilities
remaining in operation
The delivered fuel oil cost forecast for the oil-fired plants is based on Hagler
Bailly's projection of fuel oil market prices. The following table summarizes
expected fuel oil prices.
================================================================================
HAGLER BAILLY'S AVERAGE DELIVERED FUEL OIL PRICE PROJECTIONS
(1999$/mmBtu)
================================================================================
2000 2005 2010 2015 2020(1)
- --------------------------------------------------------------------------------
All Oil Stations 3.82 4.24 4.53 4.70 4.89
================================================================================
(1) Fuel after 2020 was escalated at inflation
The fuel expense for the first full calendar year of operation (2001) is $213.4
million.
[STONE & WEBSTER CONSULTANTS LOGO] 8-7
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- --------------------------------------------------------------------------------
8.5 FINANCING ASSUMPTIONS
Chase Securities Inc. and Babcock & Brown provided the financing assumptions for
the pass through certificates.
8.6 FINANCIAL PROJECTIONS
On the basis of our studies and analyses of the Facilities and the assumptions
set forth in this Report, the projected revenues from the sale of capacity and
energy are more than adequate to pay the annual O&M expenses (including
provisions for major maintenance), other operating expenses, and fixed charge
payments. The resulting Base Case average FCCR over the term of the certificates
is 6.34. The minimum FCCR beginning with the first full year over the term of
the certificates is 2.12, which occurs in the year 2001. The FCCR for the
partial year 2000 is 1.78. The FCCR for the year 2000 reflects a reduction of
the rental payment component of the fixed charges to reflect the required
maintenance of $50 million of cash by REMA from the closing date to January 2,
2001. The Base Case Financial Projections are included in Exhibit I.
8.7 SENSITIVITY ANALYSES
Due to uncertainties necessarily inherent in relying on assumptions and
projections, it should be anticipated that actual operating results may differ,
perhaps, materially, from those assumed and described herein. In order to
demonstrate the impact of changes in certain circumstances on the Financial
Projections, certain sensitivity analyses have been developed by Stone &
Webster. It should be noted that other examples could have been considered, and
those presented are not intended to reflect the full extent of possible impacts
on the Project.
8.7.1 PROJECT SENSITIVITIES
Stone & Webster performed several sensitivity analyses using the pro-forma
financial model by increasing the heat rates, increasing the O&M expenditures,
increasing the capital expenditures, and lowering the capacity factors. The four
sensitivities are as follows:
INCREASED HEAT RATES - The heat rate for each of the units was increased by 10%,
which increased fuel expenses. The market model was not rerun to develop new
electricity generation and market prices based on the 10% higher heat rates. The
resulting average FCCR over the term of the certificates is 5.92 and the minimum
FCCR beginning with the first full year over the term of the certificates is
1.99, which occurs in the year 2001. (The FCCR for the partial year 2000 is
1.67).
INCREASED O&M EXPENDITURES - The annual labor, fixed O&M, variable O&M,
overhaul, and other O&M expenses were increased by 10%. The resulting average
FCCR over the term of the certificates is 6.06 and the minimum FCCR beginning
with the first full year over the term of the certificates is 2.05, which occurs
in the year 2001. (The FCCR for the partial year 2000 is 1.73).
INCREASED CAPITAL EXPENDITURES - The annual capital expenditures for each of the
units were increased by 10%. The resulting average FCCR over the term of the
certificates is 6.25 and the minimum FCCR beginning with the first full year
over the term of the certificates is 2.10, which occurs in the year 2001. (The
FCCR for the partial year 2000 is 1.77).
LOWER CAPACITY FACTORS - The annual electricity generation and fuel expenses for
each of the units were decreased by 10%. The market model was not rerun to
develop new energy prices based on the 10% lower generation. The 10% lower
capacity factors resulted in an average FCCR over the term of the
[STONE & WEBSTER CONSULTANTS LOGO] 8-8
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- --------------------------------------------------------------------------------
certificates of 5.24 and the minimum FCCR beginning with the first full year
over the term of the certificates is 1.80, which occurs in the year 2001. (The
FCCR for the partial year 2000 is 1.53).
8.7.2 HAGLER BAILLY SENSITIVITIES
In addition, the sensitivity of the Facilities to macroeconomic changes was
assessed. These scenarios incorporated Hagler Bailly sensitivity cases.
ASSET OVERBUILD CASE - Hagler Bailly prepared new projections with additional
electric generation capacity coming on-line, over that which was assumed in the
Base Case projections, as well as continued operation of all nuclear plants. In
this scenario, 12,447 MW of merchant capacity comes online by 2003 in PJM and
NPCC in addition to the 8,147 MW of confirmed new merchant capacity that is
reflected in the Base Case. Using these projections in the financial model
results in an average FCCR over the term of the certificates of 5.62. The
minimum FCCR beginning with the first full year over the term of the
certificates is 1.78, which occurs in the year 2001. (The FCCR for the partial
year 2000 is 1.72).
LOWER FUEL PRICES - Hagler Bailly prepared new projections based on lower fuel
prices than those used in the Base Case projections. The 1999 gas and oil prices
used in the Base Case are reduced by $0.50/mmBtu with escalation remaining
unchanged (coal prices are not changed). Using these projections in the
Financial Projections results in an average FCCR over the term of the
certificates of 4.15. The minimum FCCR beginning with the first full year over
the term of the certificates is 1.82, which occurs in the year 2001. (The FCCR
for the partial year 2000 is 1.55).
8.7.3 SUMMARY
Below is a summary of the Base Case and sensitivities:
================================================================================
BASE CASE AND SENSITIVITY SUMMARY
================================================================================
MINIMUM FCCR AVERAGE FCCR
(2001-2026) (2000-2026)
- --------------------------------------------------------------------------------
Base Case 2.12 6.34
- --------------------------------------------------------------------------------
Increased Heat Rates 1.99 5.92
- --------------------------------------------------------------------------------
Increased O&M Expenditures 2.05 6.06
- --------------------------------------------------------------------------------
Increased Capital Expenditures 2.10 6.25
- --------------------------------------------------------------------------------
Lower Capacity Factors 1.80 5.24
- --------------------------------------------------------------------------------
Asset Overbuild Case 1.78 5.62
- --------------------------------------------------------------------------------
Lower Fuel Prices 1.82 4.15
================================================================================
[STONE & WEBSTER CONSULTANTS LOGO] 8-9
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- --------------------------------------------------------------------------------
EXHIBIT I
[STONE & WEBSTER CONSULTANTS LOGO] 8-10
321
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
BASE CASE
2000 2001 2002 2003 2004 2005 2006
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 50% 100% 100% 100% 100% 100% 100%
Year of Operation 0.5 1.5 2.5 3.5 4.5 5.5 6.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues 43,546 88,012 57,782 -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 312,238 659,122 659,292 691,778 710,976 686,408 669,281
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 355,784 747,135 717,074 691,778 710,976 686,408 669,281
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 107,299 217,557 214,791 223,570 224,152 219,853 213,610
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 107,299 217,557 214,791 223,570 224,152 219,853 213,610
Non-Fuel O&M
Plant O&M 50,316 114,954 109,439 120,357 119,208 115,340 123,866
Ad Valorem Taxes 2,090 4,273 4,380 4,489 4,601 4,716 4,834
G&A 5,025 12,902 13,225 13,555 13,894 14,242 14,598
Emissions Costs -- 18,423 20,021 31,793 34,820 36,780 38,868
Insurance 399 815 836 856 878 900 922
Total, Non-Fuel O&M 57,830 151,367 147,900 171,051 173,401 171,979 183,088
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 165,129 368,924 362,691 394,621 397,553 391,832 396,698
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 190,655 378,211 354,383 297,157 313,423 294,576 272,582
Capital Expenditures 8,599 28,843 67,803 38,362 21,104 6,091 27,206
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 182,056 349,368 286,580 258,795 292,319 288,486 245,377
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 151,832 163,405 108,369 75,525 83,021 73,636 62,976
Working Capital and Letter of Credit Fees 607 1,210 1,210 610 610 610 610
Cash at REMA 50,000
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 102,438 164,615 109,579 76,135 83,631 74,246 63,586
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 1.78 2.12 2.62 3.40 3.50 3.89 3.86
2007 2008 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 7.5 8.5 9.5 10.5 11.5 12.5 13.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 686,064 698,861 725,132 736,935 664,979 682,194 698,144
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 686,064 698,861 725,132 736,935 664,979 682,194 698,144
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 217,364 215,987 224,114 221,140 200,926 203,763 207,085
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 217,364 215,987 224,114 221,140 200,926 203,763 207,085
Non-Fuel O&M
Plant O&M 127,536 132,649 143,707 184,578 101,048 150,367 124,529
Ad Valorem Taxes 4,955 5,079 5,206 5,336 5,166 5,295 5,427
G&A 14,963 15,337 15,720 14,608 10,658 10,925 11,198
Emissions Costs 41,362 45,539 50,671 54,349 36,925 37,910 39,236
Insurance 945 969 993 1,018 881 903 925
Total, Non-Fuel O&M 189,762 199,573 216,298 259,888 154,678 205,399 181,317
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 407,125 415,560 440,412 481,028 355,604 409,162 388,402
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 278,939 283,301 284,720 255,907 309,375 273,032 309,742
Capital Expenditures 24,693 15,911 14,644 5,164 4,382 1,268 1,710
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 254,246 267,390 270,076 250,743 304,993 271,763 308,032
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 63,756 61,227 61,869 51,940 62,360 55,552 63,036
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 64,366 61,837 62,479 52,550 62,970 56,162 63,646
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 3.95 4.32 4.32 4.77 4.84 4.84 4.84
-----------
Average Fixed Charge Coverage Ratio 6.34
-----------
322
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
BASE CASE
2014 2015 2016 2017 2018 2019 2020
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 14.5 15.5 16.5 17.5 18.5 19.5 20.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 720,152 774,066 807,478 827,926 866,437 883,293 906,447
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 720,152 774,066 807,478 827,926 866,437 883,293 906,447
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 211,770 217,660 226,630 223,698 235,855 233,141 234,338
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 211,770 217,660 226,630 223,698 235,855 233,141 234,338
Non-Fuel O&M
Plant O&M 110,791 157,475 166,049 130,032 144,002 159,079 153,709
Ad Valorem Taxes 5,563 5,702 5,845 5,991 6,140 6,294 6,451
G&A 11,478 11,765 12,059 12,361 12,670 12,986 13,311
Emissions Costs 40,947 42,482 45,890 48,108 54,611 56,179 59,003
Insurance 949 972 997 1,022 1,047 1,073 1,100
Total, Non-Fuel O&M 169,728 218,396 230,839 197,513 218,470 235,611 233,575
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 381,497 436,056 457,470 421,210 454,325 468,752 467,912
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 338,655 338,011 350,009 406,716 412,113 414,540 438,534
Capital Expenditures 4,939 16,932 1,009 12,095 488 3,973 15,946
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 333,716 321,078 348,999 394,620 411,625 410,568 422,588
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 62,014 54,685 59,723 62,289 53,219 63,400 57,967
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 62,624 55,295 60,333 62,899 53,829 64,010 58,577
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 5.33 5.81 5.78 6.27 7.65 6.41 7.21
2021 2022 2023 2024 2025 2026
---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 50%
Year of Operation 21.5 22.5 23.5 24.5 25.5 26.0
---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
Contract Sales -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- --
Merchant Energy Revenues 920,463 943,475 967,062 991,238 725,557 371,848
Commercial Values -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 920,463 943,475 967,062 991,238 725,557 371,848
---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 240,196 246,201 252,356 258,665 173,701 89,022
Lost Fuel Expense -- -- -- -- -- --
Total Fuel 240,196 246,201 252,356 258,665 173,701 89,022
Non-Fuel O&M
Plant O&M 198,837 201,396 168,949 206,509 133,425 55,114
Ad Valorem Taxes 6,613 6,778 6,947 7,121 1,275 653
G&A 13,644 13,985 14,334 14,693 5,605 2,872
Emissions Costs 60,478 61,990 63,540 51,706 (8,118) (14,788)
Insurance 1,128 1,156 1,185 1,214 924 474
Total, Non-Fuel O&M 280,699 285,305 254,955 281,243 133,111 44,325
---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 520,895 531,506 507,311 539,908 306,812 133,347
---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 399,568 411,969 459,750 451,330 418,745 238,501
Capital Expenditures 1,558 5,907 32,000 51,642 132,999 84,545
---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 398,010 406,062 427,751 399,688 285,745 153,956
---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 45,187 45,471 39,514 24,170 25,204 7,863
Working Capital and Letter of Credit Fees 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 45,797 46,081 40,124 24,780 25,814 8,473
---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 8.69 8.81 10.66 16.13 11.07 18.17
-----------
Average Fixed Charge Coverage Ratio 6.34
-----------
323
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
INCREASED HEAT RATE
2000 2001 2002 2003 2004 2005 2006
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 50% 100% 100% 100% 100% 100% 100%
Year of Operation 0.5 1.5 2.5 3.5 4.5 5.5 6.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues 43,546 88,012 57,782 -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 312,238 659,122 659,292 691,778 710,976 686,408 669,281
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 355,784 747,135 717,074 691,778 710,976 686,408 669,281
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 118,029 239,313 236,270 245,927 246,567 241,839 234,971
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 118,029 239,313 236,270 245,927 246,567 241,839 234,971
Non-Fuel O&M
Plant O&M 50,316 114,954 109,439 120,357 119,208 115,340 123,866
Ad Valorem Taxes 2,090 4,273 4,380 4,489 4,601 4,716 4,834
G&A 5,025 12,902 13,225 13,555 13,894 14,242 14,598
Emissions Costs -- 18,423 20,021 31,793 34,820 36,780 38,868
Insurance 399 815 836 856 878 900 922
Total, Non-Fuel O&M 57,830 151,367 147,900 171,051 173,401 171,979 183,088
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 175,859 390,680 384,170 416,978 419,968 413,817 418,060
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 179,925 356,455 332,904 274,800 291,007 272,591 251,221
Capital Expenditures 8,599 28,843 67,803 38,362 21,104 6,091 27,206
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 171,326 327,612 265,100 236,438 269,904 266,500 224,016
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 151,832 163,405 108,369 75,525 83,021 73,636 62,976
Working Capital and Letter of Credit Fees 607 1,210 1,210 610 610 610 610
Cash at REMA 50,000
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 102,438 164,615 109,579 76,135 83,631 74,246 63,586
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 1.67 1.99 2.42 3.11 3.23 3.59 3.52
2007 2008 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 7.5 8.5 9.5 10.5 11.5 12.5 13.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 686,064 698,861 725,132 736,935 664,979 682,194 698,144
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 686,064 698,861 725,132 736,935 664,979 682,194 698,144
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 239,100 237,585 246,525 243,254 221,018 224,139 227,794
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 239,100 237,585 246,525 243,254 221,018 224,139 227,794
Non-Fuel O&M
Plant O&M 127,536 132,649 143,707 184,578 101,048 150,367 124,529
Ad Valorem Taxes 4,955 5,079 5,206 5,336 5,166 5,295 5,427
G&A 14,963 15,337 15,720 14,608 10,658 10,925 11,198
Emissions Costs 41,362 45,539 50,671 54,349 36,925 37,910 39,236
Insurance 945 969 993 1,018 881 903 925
Total, Non-Fuel O&M 189,762 199,573 216,298 259,888 154,678 205,399 181,317
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 428,862 437,159 462,823 503,142 375,696 429,538 409,110
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 257,202 261,702 262,309 233,793 289,282 252,655 289,034
Capital Expenditures 24,693 15,911 14,644 5,164 4,382 1,268 1,710
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 232,509 245,791 247,665 228,629 284,900 251,387 287,324
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 63,756 61,227 61,869 51,940 62,360 55,552 63,036
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 64,366 61,837 62,479 52,550 62,970 56,162 63,646
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 3.61 3.97 3.96 4.35 4.52 4.48 4.51
-----------
Average Fixed Charge Coverage Ratio 5.92
-----------
324
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
INCREASED HEAT RATE
2014 2015 2016 2017 2018 2019 2020
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 14.5 15.5 16.5 17.5 18.5 19.5 20.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 720,152 774,066 807,478 827,926 866,437 883,293 906,447
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 720,152 774,066 807,478 827,926 866,437 883,293 906,447
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 232,947 239,426 249,293 246,067 259,441 256,455 257,772
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 232,947 239,426 249,293 246,067 259,441 256,455 257,772
Non-Fuel O&M
Plant O&M 110,791 157,475 166,049 130,032 144,002 159,079 153,709
Ad Valorem Taxes 5,563 5,702 5,845 5,991 6,140 6,294 6,451
G&A 11,478 11,765 12,059 12,361 12,670 12,986 13,311
Emissions Costs 40,947 42,482 45,890 48,108 54,611 56,179 59,003
Insurance 949 972 997 1,022 1,047 1,073 1,100
Total, Non-Fuel O&M 169,728 218,396 230,839 197,513 218,470 235,611 233,575
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 402,674 457,822 480,133 443,580 477,910 492,067 491,346
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 317,478 316,245 327,346 384,346 388,527 391,226 415,101
Capital Expenditures 4,939 16,932 1,009 12,095 488 3,973 15,946
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 312,540 299,312 326,336 372,251 388,039 387,254 399,154
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 62,014 54,685 59,723 62,289 53,219 63,400 57,967
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 62,624 55,295 60,333 62,899 53,829 64,010 58,577
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 4.99 5.41 5.41 5.92 7.21 6.05 6.81
2021 2022 2023 2024 2025 2026
---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 50%
Year of Operation 21.5 22.5 23.5 24.5 25.5 26.0
---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
Contract Sales -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- --
Merchant Energy Revenues 920,463 943,475 967,062 991,238 725,557 371,848
Commercial Values -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 920,463 943,475 967,062 991,238 725,557 371,848
---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 264,216 270,821 277,592 284,532 191,071 97,924
Lost Fuel Expense -- -- -- -- -- --
Total Fuel 264,216 270,821 277,592 284,532 191,071 97,924
Non-Fuel O&M
Plant O&M 198,837 201,396 168,949 206,509 133,425 55,114
Ad Valorem Taxes 6,613 6,778 6,947 7,121 1,275 653
G&A 13,644 13,985 14,334 14,693 5,605 2,872
Emissions Costs 60,478 61,990 63,540 51,706 (8,118) (14,788)
Insurance 1,128 1,156 1,185 1,214 924 474
Total, Non-Fuel O&M 280,699 285,305 254,955 281,243 133,111 44,325
---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 544,915 556,126 532,547 565,775 324,182 142,249
---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 375,549 387,349 434,515 425,464 401,375 229,599
Capital Expenditures 1,558 5,907 32,000 51,642 132,999 84,545
---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 373,991 381,442 402,515 373,822 268,375 145,054
---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 45,187 45,471 39,514 24,170 25,204 7,863
Working Capital and Letter of Credit Fees 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 45,797 46,081 40,124 24,780 25,814 8,473
---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 8.17 8.28 10.03 15.09 10.40 17.12
-----------
Average Fixed Charge Coverage Ratio 5.92
-----------
325
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
INCREASED CAPITAL EXPENDITURES
2000 2001 2002 2003 2004 2005 2006
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 50% 100% 100% 100% 100% 100% 100%
Year of Operation 0.5 1.5 2.5 3.5 4.5 5.5 6.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues 43,546 88,012 57,782 -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 312,238 659,122 659,292 691,778 710,976 686,408 669,281
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 355,784 747,135 717,074 691,778 710,976 686,408 669,281
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 107,299 217,557 214,791 223,570 224,152 219,853 213,610
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 107,299 217,557 214,791 223,570 224,152 219,853 213,610
Non-Fuel O&M
Plant O&M 50,316 114,954 109,439 120,357 119,208 115,340 123,866
Ad Valorem Taxes 2,090 4,273 4,380 4,489 4,601 4,716 4,834
G&A 5,025 12,902 13,225 13,555 13,894 14,242 14,598
Emissions Costs -- 18,423 20,021 31,793 34,820 36,780 38,868
Insurance 399 815 836 856 878 900 922
Total, Non-Fuel O&M 57,830 151,367 147,900 171,051 173,401 171,979 183,088
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 165,129 368,924 362,691 394,621 397,553 391,832 396,698
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 190,655 378,211 354,383 297,157 313,423 294,576 272,582
Capital Expenditures 9,459 31,727 74,583 42,198 23,214 6,700 29,926
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 181,196 346,483 279,799 254,959 290,208 287,877 242,656
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 151,832 163,405 108,369 75,525 83,021 73,636 62,976
Working Capital and Letter of Credit Fees 607 1,210 1,210 610 610 610 610
Cash at REMA 50,000
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 102,438 164,615 109,579 76,135 83,631 74,246 63,586
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 1.77 2.10 2.55 3.35 3.47 3.88 3.82
2007 2008 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 7.5 8.5 9.5 10.5 11.5 12.5 13.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 686,064 698,861 725,132 736,935 664,979 682,194 698,144
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 686,064 698,861 725,132 736,935 664,979 682,194 698,144
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 217,364 215,987 224,114 221,140 200,926 203,763 207,085
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 217,364 215,987 224,114 221,140 200,926 203,763 207,085
Non-Fuel O&M
Plant O&M 127,536 132,649 143,707 184,578 101,048 150,367 124,529
Ad Valorem Taxes 4,955 5,079 5,206 5,336 5,166 5,295 5,427
G&A 14,963 15,337 15,720 14,608 10,658 10,925 11,198
Emissions Costs 41,362 45,539 50,671 54,349 36,925 37,910 39,236
Insurance 945 969 993 1,018 881 903 925
Total, Non-Fuel O&M 189,762 199,573 216,298 259,888 154,678 205,399 181,317
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 407,125 415,560 440,412 481,028 355,604 409,162 388,402
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 278,939 283,301 284,720 255,907 309,375 273,032 309,742
Capital Expenditures 27,162 17,502 16,108 5,681 4,820 1,395 1,881
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 251,777 265,799 268,612 250,226 304,555 271,637 307,861
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 63,756 61,227 61,869 51,940 62,360 55,552 63,036
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 64,366 61,837 62,479 52,550 62,970 56,162 63,646
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 3.91 4.30 4.30 4.76 4.84 4.84 4.84
-----------
Average Fixed Charge Coverage Ratio 6.25
-----------
326
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
INCREASED CAPITAL EXPENDITURES
2014 2015 2016 2017 2018 2019 2020
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 14.5 15.5 16.5 17.5 18.5 19.5 20.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 720,152 774,066 807,478 827,926 866,437 883,293 906,447
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 720,152 774,066 807,478 827,926 866,437 883,293 906,447
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 211,770 217,660 226,630 223,698 235,855 233,141 234,338
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 211,770 217,660 226,630 223,698 235,855 233,141 234,338
Non-Fuel O&M
Plant O&M 110,791 157,475 166,049 130,032 144,002 159,079 153,709
Ad Valorem Taxes 5,563 5,702 5,845 5,991 6,140 6,294 6,451
G&A 11,478 11,765 12,059 12,361 12,670 12,986 13,311
Emissions Costs 40,947 42,482 45,890 48,108 54,611 56,179 59,003
Insurance 949 972 997 1,022 1,047 1,073 1,100
Total, Non-Fuel O&M 169,728 218,396 230,839 197,513 218,470 235,611 233,575
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 381,497 436,056 457,470 421,210 454,325 468,752 467,912
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 338,655 338,011 350,009 406,716 412,113 414,540 438,534
Capital Expenditures 5,433 18,625 1,110 13,305 536 4,370 17,541
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 333,223 319,385 348,899 393,411 411,576 410,171 420,993
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 62,014 54,685 59,723 62,289 53,219 63,400 57,967
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 62,624 55,295 60,333 62,899 53,829 64,010 58,577
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 5.32 5.78 5.78 6.25 7.65 6.41 7.19
2021 2022 2023 2024 2025 2026
---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 50%
Year of Operation 21.5 22.5 23.5 24.5 25.5 26.0
---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
Contract Sales -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- --
Merchant Energy Revenues 920,463 943,475 967,062 991,238 725,557 371,848
Commercial Values -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 920,463 943,475 967,062 991,238 725,557 371,848
---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 240,196 246,201 252,356 258,665 173,701 89,022
Lost Fuel Expense -- -- -- -- -- --
Total Fuel 240,196 246,201 252,356 258,665 173,701 89,022
Non-Fuel O&M
Plant O&M 198,837 201,396 168,949 206,509 133,425 55,114
Ad Valorem Taxes 6,613 6,778 6,947 7,121 1,275 653
G&A 13,644 13,985 14,334 14,693 5,605 2,872
Emissions Costs 60,478 61,990 63,540 51,706 (8,118) (14,788)
Insurance 1,128 1,156 1,185 1,214 924 474
Total, Non-Fuel O&M 280,699 285,305 254,955 281,243 133,111 44,325
---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 520,895 531,506 507,311 539,908 306,812 133,347
---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 399,568 411,969 459,750 451,330 418,745 238,501
Capital Expenditures 1,714 6,497 35,200 56,806 146,299 93,000
---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 397,855 405,472 424,551 394,524 272,445 145,501
---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 45,187 45,471 39,514 24,170 25,204 7,863
Working Capital and Letter of Credit Fees 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 45,797 46,081 40,124 24,780 25,814 8,473
---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 8.69 8.80 10.58 15.92 10.55 17.17
-----------
Average Fixed Charge Coverage Ratio 6.25
-----------
327
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
LOWER CAPACITY FACTOR
2000 2001 2002 2003 2004 2005 2006
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 50% 100% 100% 100% 100% 100% 100%
Year of Operation 0.5 1.5 2.5 3.5 4.5 5.5 6.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 6,383,283 12,753,892 12,587,116 12,832,930 12,855,688 12,703,983 12,484,977
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 6,383,283 12,753,892 12,587,116 12,832,930 12,855,688 12,703,983 12,484,977
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 6,383,283 12,753,892 12,587,116 12,832,930 12,855,688 12,703,983 12,484,977
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues 39,192 79,211 52,004 -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 281,014 593,210 593,363 622,600 639,878 617,767 602,353
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 320,206 672,421 645,367 622,600 639,878 617,767 602,353
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 96,569 195,801 193,312 201,213 201,736 197,868 192,249
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 96,569 195,801 193,312 201,213 201,736 197,868 192,249
Non-Fuel O&M
Plant O&M 50,316 114,954 109,439 120,357 119,208 115,340 123,866
Ad Valorem Taxes 2,090 4,273 4,380 4,489 4,601 4,716 4,834
G&A 5,025 12,902 13,225 13,555 13,894 14,242 14,598
Emissions Costs -- 18,423 20,021 31,793 34,820 36,780 38,868
Insurance 399 815 836 856 878 900 922
Total, Non-Fuel O&M 57,830 151,367 147,900 171,051 173,401 171,979 183,088
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 154,399 347,168 341,212 372,264 375,138 369,847 375,337
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 165,807 325,253 304,154 250,336 264,740 247,921 227,015
Capital Expenditures 8,599 28,843 67,803 38,362 21,104 6,091 27,206
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 157,207 296,410 236,351 211,974 243,636 241,830 199,810
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 151,832 163,405 108,369 75,525 83,021 73,636 62,976
Working Capital and Letter of Credit Fees 607 1,210 1,210 610 610 610 610
Cash in REMA 50,000
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 102,438 164,615 109,579 76,135 83,631 74,246 63,586
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 1.53 1.80 2.16 2.78 2.91 3.26 3.14
2007 2008 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 7.5 8.5 9.5 10.5 11.5 12.5 13.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,375,396 12,330,318 12,471,078 12,295,508 11,110,111 11,145,033 11,164,821
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,375,396 12,330,318 12,471,078 12,295,508 11,110,111 11,145,033 11,164,821
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,375,396 12,330,318 12,471,078 12,295,508 11,110,111 11,145,033 11,164,821
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 617,458 628,975 652,618 663,242 598,481 613,974 628,329
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 617,458 628,975 652,618 663,242 598,481 613,974 628,329
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 195,627 194,388 201,703 199,026 180,833 183,387 186,377
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 195,627 194,388 201,703 199,026 180,833 183,387 186,377
Non-Fuel O&M
Plant O&M 127,536 132,649 143,707 184,578 101,048 150,367 124,529
Ad Valorem Taxes 4,955 5,079 5,206 5,336 5,166 5,295 5,427
G&A 14,963 15,337 15,720 14,608 10,658 10,925 11,198
Emissions Costs 41,362 45,539 50,671 54,349 36,925 37,910 39,236
Insurance 945 969 993 1,018 881 903 925
Total, Non-Fuel O&M 189,762 199,573 216,298 259,888 154,678 205,399 181,317
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 385,389 393,961 418,000 458,914 335,511 388,786 367,693
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 232,069 235,013 234,618 204,327 262,970 225,189 260,636
Capital Expenditures 24,693 15,911 14,644 5,164 4,382 1,268 1,710
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 207,376 219,102 219,974 199,163 258,588 223,920 258,927
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 63,756 61,227 61,869 51,940 62,360 55,552 63,036
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 64,366 61,837 62,479 52,550 62,970 56,162 63,646
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 3.22 3.54 3.52 3.79 4.11 3.99 4.07
-----------
Average Fixed Charge Coverage Ratio 5.24
-----------
328
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
LOWER CAPACITY FACTOR
2014 2015 2016 2017 2018 2019 2020
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 14.5 15.5 16.5 17.5 18.5 19.5 20.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 11,192,206 11,264,173 11,446,124 11,460,279 11,653,467 11,593,332 11,679,215
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 11,192,206 11,264,173 11,446,124 11,460,279 11,653,467 11,593,332 11,679,215
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 11,192,206 11,264,173 11,446,124 11,460,279 11,653,467 11,593,332 11,679,215
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 648,137 696,660 726,731 745,133 779,794 794,964 815,802
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 648,137 696,660 726,731 745,133 779,794 794,964 815,802
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 190,593 195,894 203,967 201,328 212,270 209,827 210,904
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 190,593 195,894 203,967 201,328 212,270 209,827 210,904
Non-Fuel O&M
Plant O&M 110,791 157,475 166,049 130,032 144,002 159,079 153,709
Ad Valorem Taxes 5,563 5,702 5,845 5,991 6,140 6,294 6,451
G&A 11,478 11,765 12,059 12,361 12,670 12,986 13,311
Emissions Costs 40,947 42,482 45,890 48,108 54,611 56,179 59,003
Insurance 949 972 997 1,022 1,047 1,073 1,100
Total, Non-Fuel O&M 169,728 218,396 230,839 197,513 218,470 235,611 233,575
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 360,320 414,290 434,807 398,841 430,739 445,438 444,479
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 287,817 282,370 291,924 346,293 349,054 349,525 371,323
Capital Expenditures 4,939 16,932 1,009 12,095 488 3,973 15,946
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 282,878 265,438 290,915 334,198 348,567 345,553 355,377
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 62,014 54,685 59,723 62,289 53,219 63,400 57,967
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 62,624 55,295 60,333 62,899 53,829 64,010 58,577
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 4.52 4.80 4.82 5.31 6.48 5.40 6.07
2021 2022 2023 2024 2025 2026
---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 50%
Year of Operation 21.5 22.5 23.5 24.5 25.5 26.0
---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 11,679,207 11,679,207 11,679,207 11,679,207 8,105,908 4,052,954
---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 11,679,207 11,679,207 11,679,207 11,679,207 8,105,908 4,052,954
Contract Sales -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Sales 11,679,207 11,679,207 11,679,207 11,679,207 8,105,908 4,052,954
---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- --
Merchant Energy Revenues 828,417 849,127 870,355 892,114 653,001 334,663
Commercial Values -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 828,417 849,127 870,355 892,114 653,001 334,663
---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 216,177 221,581 227,121 232,799 156,331 80,119
Lost Fuel Expense -- -- -- -- -- --
Total Fuel 216,177 221,581 227,121 232,799 156,331 80,119
Non-Fuel O&M
Plant O&M 198,837 201,396 168,949 206,509 133,425 55,114
Ad Valorem Taxes 6,613 6,778 6,947 7,121 1,275 653
G&A 13,644 13,985 14,334 14,693 5,605 2,872
Emissions Costs 60,478 61,990 63,540 51,706 (8,118) (14,788)
Insurance 1,128 1,156 1,185 1,214 924 474
Total, Non-Fuel O&M 280,699 285,305 254,955 281,243 133,111 44,325
---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 496,875 506,886 482,075 514,042 289,442 124,444
---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 331,541 342,241 388,280 378,073 363,559 210,219
Capital Expenditures 1,558 5,907 32,000 51,642 132,999 84,545
---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 329,984 336,335 356,280 326,431 230,560 125,673
---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 45,187 45,471 39,514 24,170 25,204 7,863
Working Capital and Letter of Credit Fees 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 45,797 46,081 40,124 24,780 25,814 8,473
---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 7.21 7.30 8.88 13.17 8.93 14.83
-----------
Average Fixed Charge Coverage Ratio 5.24
-----------
329
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
ASSET OVERBUILD CASE
2000 2001 2002 2003 2004 2005 2006
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 50% 100% 100% 100% 100% 100% 100%
Year of Operation 0.5 1.5 2.5 3.5 4.5 5.5 6.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 7,078,559 13,884,384 13,275,162 12,677,721 12,905,455 13,071,187 13,204,667
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 7,078,559 13,884,384 13,275,162 12,677,721 12,905,455 13,071,187 13,204,667
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 7,078,559 13,884,384 13,275,162 12,677,721 12,905,455 13,071,187 13,204,667
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues 43,546 88,012 57,782 -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 305,685 589,217 562,801 557,066 581,978 580,382 584,657
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 349,231 677,229 620,583 557,066 581,978 580,382 584,657
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 106,807 206,557 197,827 189,096 192,891 197,188 200,440
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 106,807 206,557 197,827 189,096 192,891 197,188 200,440
Non-Fuel O&M
Plant O&M 50,187 113,109 107,729 116,746 116,891 113,292 122,621
Ad Valorem Taxes 2,090 4,273 4,380 4,489 4,601 4,716 4,834
G&A 5,025 12,902 13,225 13,555 13,894 14,242 14,598
Emissions Costs -- 17,553 16,565 22,686 26,680 30,346 34,528
Insurance 399 815 836 856 878 900 922
Total, Non-Fuel O&M 57,701 148,653 142,734 158,333 162,945 163,496 177,504
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 164,508 355,210 340,560 347,429 355,836 360,684 377,944
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 184,723 322,019 280,023 209,637 226,142 219,698 206,714
Capital Expenditures 8,599 28,843 67,803 38,362 21,104 6,091 27,206
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 176,124 293,177 212,220 171,275 205,038 213,608 179,508
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 151,832 163,405 108,369 75,525 83,021 73,636 62,976
Working Capital and Letter of Credit Fees 607 1,210 1,210 610 610 610 610
Cash in REMA 50,000
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 102,438 164,615 109,579 76,135 83,631 74,246 63,586
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 1.72 1.78 1.94 2.25 2.45 2.88 2.82
2007 2008 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 7.5 8.5 9.5 10.5 11.5 12.5 13.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 13,313,206 13,712,331 13,526,993 13,504,386 12,261,205 12,282,616 12,329,349
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 13,313,206 13,712,331 13,526,993 13,504,386 12,261,205 12,282,616 12,329,349
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 13,313,206 13,712,331 13,526,993 13,504,386 12,261,205 12,282,616 12,329,349
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 604,088 707,347 678,879 688,692 624,199 639,939 657,348
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 604,088 707,347 678,879 688,692 624,199 639,939 657,348
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 206,413 222,644 216,562 215,967 200,297 203,588 206,463
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 206,413 222,644 216,562 215,967 200,297 203,588 206,463
Non-Fuel O&M
Plant O&M 126,323 133,100 142,648 183,683 100,854 150,363 124,221
Ad Valorem Taxes 4,955 5,079 5,206 5,336 5,166 5,295 5,427
G&A 14,963 15,337 15,720 14,608 10,658 10,925 11,198
Emissions Costs 38,417 45,183 48,521 53,555 36,428 37,260 39,009
Insurance 945 969 993 1,018 881 903 925
Total, Non-Fuel O&M 185,603 199,668 213,088 258,200 153,987 204,745 180,781
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 392,016 422,312 429,650 474,167 354,284 408,333 387,243
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 212,072 285,035 249,229 214,526 269,916 231,607 270,104
Capital Expenditures 24,693 15,911 14,644 5,164 4,382 1,268 1,710
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 187,379 269,124 234,585 209,361 265,533 230,338 268,395
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 63,756 61,227 61,869 51,940 62,360 55,552 63,036
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 64,366 61,837 62,479 52,550 62,970 56,162 63,646
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 2.91 4.35 3.75 3.98 4.22 4.10 4.22
-----------
Average Fixed Charge Coverage Ratio 5.62
-----------
330
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
ASSET OVERBUILD CASE
2014 2015 2016 2017 2018 2019 2020
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 14.5 15.5 16.5 17.5 18.5 19.5 20.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,369,232 12,482,087 12,718,101 12,722,257 12,976,984 12,898,418 12,991,356
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,369,232 12,482,087 12,718,101 12,722,257 12,976,984 12,898,418 12,991,356
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,369,232 12,482,087 12,718,101 12,722,257 12,976,984 12,898,418 12,991,356
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 717,895 737,909 773,116 795,533 842,299 847,640 875,419
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 717,895 737,909 773,116 795,533 842,299 847,640 875,419
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 209,555 216,491 226,205 223,480 237,598 235,066 236,426
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 209,555 216,491 226,205 223,480 237,598 235,066 236,426
Non-Fuel O&M
Plant O&M 110,505 157,105 165,780 129,849 144,068 159,093 153,762
Ad Valorem Taxes 5,563 5,702 5,845 5,991 6,140 6,294 6,451
G&A 11,478 11,765 12,059 12,361 12,670 12,986 13,311
Emissions Costs 40,852 42,563 46,237 48,304 55,151 56,252 59,236
Insurance 949 972 997 1,022 1,047 1,073 1,100
Total, Non-Fuel O&M 169,347 218,107 230,917 197,526 219,077 235,698 233,861
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 378,901 434,598 457,122 421,006 456,675 470,764 470,287
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 338,994 303,311 315,994 374,528 385,624 376,876 405,132
Capital Expenditures 4,939 16,932 1,009 12,095 488 3,973 15,946
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 334,055 286,378 314,985 362,433 385,136 372,904 389,185
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 62,014 54,685 59,723 62,289 53,219 63,400 57,967
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 62,624 55,295 60,333 62,899 53,829 64,010 58,577
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 5.33 5.18 5.22 5.76 7.15 5.83 6.64
2021 2022 2023 2024 2025 2026
---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 50%
Year of Operation 21.5 22.5 23.5 24.5 25.5 26.0
---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,991,356 12,991,356 12,991,356 12,991,356 9,028,373 4,514,186
---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,991,356 12,991,356 12,991,356 12,991,356 9,028,373 4,514,186
Contract Sales -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,991,356 12,991,356 12,991,356 12,991,356 9,028,373 4,514,186
---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- --
Merchant Energy Revenues 891,959 914,258 937,114 960,542 710,952 364,363
Commercial Values -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 891,959 914,258 937,114 960,542 710,952 364,363
---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 242,337 248,395 254,605 260,970 185,644 95,143
Lost Fuel Expense -- -- -- -- -- --
Total Fuel 242,337 248,395 254,605 260,970 185,644 95,143
Non-Fuel O&M
Plant O&M 198,787 201,144 168,869 206,428 133,502 55,162
Ad Valorem Taxes 6,613 6,778 6,947 7,121 1,275 653
G&A 13,644 13,985 14,334 14,693 5,605 2,872
Emissions Costs 60,717 62,235 63,791 52,516 (7,515) (14,569)
Insurance 1,128 1,156 1,185 1,214 924 474
Total, Non-Fuel O&M 280,888 285,297 255,126 281,972 133,791 44,593
---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 523,225 533,693 509,731 542,942 319,435 139,735
---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 368,734 380,565 427,383 417,600 391,517 224,628
Capital Expenditures 1,558 5,907 32,000 51,642 132,999 84,545
---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 367,177 374,659 395,383 365,958 258,518 140,083
---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 45,187 45,471 39,514 24,170 25,204 7,863
Working Capital and Letter of Credit Fees 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 45,797 46,081 40,124 24,780 25,814 8,473
---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 8.02 8.13 9.85 14.77 10.01 16.53
-----------
Average Fixed Charge Coverage Ratio 5.62
-----------
331
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
LOWER FUEL PRICES
2000 2001 2002 2003 2004 2005 2006
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 50% 100% 100% 100% 100% 100% 100%
Year of Operation 0.5 1.5 2.5 3.5 4.5 5.5 6.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 6,773,647 13,538,850 13,208,756 13,541,192 13,469,867 13,156,226 13,000,416
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 6,773,647 13,538,850 13,208,756 13,541,192 13,469,867 13,156,226 13,000,416
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 6,773,647 13,538,850 13,208,756 13,541,192 13,469,867 13,156,226 13,000,416
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues 43,546 88,012 57,782 -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 283,813 594,314 584,084 611,758 616,935 581,980 571,177
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 327,360 682,326 641,867 611,758 616,935 581,980 571,177
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 102,027 206,336 201,169 209,259 208,207 204,864 201,828
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 102,027 206,336 201,169 209,259 208,207 204,864 201,828
Non-Fuel O&M
Plant O&M 50,456 115,139 109,609 120,584 118,984 114,811 123,503
Ad Valorem Taxes 2,090 4,273 4,380 4,489 4,601 4,716 4,834
G&A 5,025 12,902 13,225 13,555 13,894 14,242 14,598
Emissions Costs -- 13,954 14,324 26,122 28,388 29,234 31,160
Insurance 399 815 836 856 878 900 922
Total, Non-Fuel O&M 57,970 147,083 142,373 165,606 166,745 163,903 175,017
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 159,997 353,418 343,542 374,865 374,952 368,767 376,846
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 167,363 328,908 298,325 236,892 241,983 213,213 194,331
Capital Expenditures 8,599 28,843 67,803 38,362 21,104 6,091 27,206
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 158,763 300,065 230,522 198,530 220,879 207,123 167,125
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 151,832 163,405 108,369 75,525 83,021 73,636 62,976
Working Capital and Letter of Credit Fees 607 1,210 1,210 610 610 610 610
Cash in REMA 50,000
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 102,438 164,615 109,579 76,135 83,631 74,246 63,586
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 1.55 1.82 2.10 2.61 2.64 2.79 2.63
2007 2008 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 7.5 8.5 9.5 10.5 11.5 12.5 13.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,827,938 12,741,825 12,791,059 12,537,443 11,468,514 11,431,227 11,486,903
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,827,938 12,741,825 12,791,059 12,537,443 11,468,514 11,431,227 11,486,903
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,827,938 12,741,825 12,791,059 12,537,443 11,468,514 11,431,227 11,486,903
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 578,577 591,451 600,295 604,359 554,526 562,529 579,771
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 578,577 591,451 600,295 604,359 554,526 562,529 579,771
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 203,621 202,573 207,510 204,032 188,586 189,867 193,825
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 203,621 202,573 207,510 204,032 188,586 189,867 193,825
Non-Fuel O&M
Plant O&M 126,916 131,693 142,384 182,850 99,706 148,893 123,025
Ad Valorem Taxes 4,955 5,079 5,206 5,336 5,166 5,295 5,427
G&A 14,963 15,337 15,720 14,608 10,658 10,925 11,198
Emissions Costs 32,873 35,830 39,512 41,806 27,853 27,930 29,323
Insurance 945 969 993 1,018 881 903 925
Total, Non-Fuel O&M 180,652 188,908 203,816 245,618 144,265 193,946 169,899
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 384,273 391,480 411,325 449,650 332,851 383,813 363,724
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 194,304 199,970 188,969 154,709 221,676 178,716 216,047
Capital Expenditures 24,693 15,911 14,644 5,164 4,382 1,268 1,710
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 169,612 184,059 174,325 149,544 217,293 177,448 214,338
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 63,756 61,227 61,869 51,940 62,360 55,552 63,036
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 64,366 61,837 62,479 52,550 62,970 56,162 63,646
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 2.64 2.98 2.79 2.85 3.45 3.16 3.37
-----------
Average Fixed Charge Coverage Ratio 4.15
-----------
332
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
LOWER FUEL PRICES
2014 2015 2016 2017 2018 2019 2020
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 14.5 15.5 16.5 17.5 18.5 19.5 20.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 11,477,891 11,531,814 11,805,251 11,873,161 12,086,250 12,001,458 12,170,420
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 11,477,891 11,531,814 11,805,251 11,873,161 12,086,250 12,001,458 12,170,420
Contract Sales -- -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 11,477,891 11,531,814 11,805,251 11,873,161 12,086,250 12,001,458 12,170,420
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 595,479 639,799 667,620 685,345 717,005 727,309 749,288
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 595,479 639,799 667,620 685,345 717,005 727,309 749,288
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 197,378 202,560 212,003 211,378 222,629 219,570 223,378
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 197,378 202,560 212,003 211,378 222,629 219,570 223,378
Non-Fuel O&M
Plant O&M 109,352 155,763 164,514 128,560 142,515 157,369 152,157
Ad Valorem Taxes 5,563 5,702 5,845 5,991 6,140 6,294 6,451
G&A 11,478 11,765 12,059 12,361 12,670 12,986 13,311
Emissions Costs 30,234 31,352 35,205 37,856 43,772 45,277 48,650
Insurance 949 972 997 1,022 1,047 1,073 1,100
Total, Non-Fuel O&M 157,575 205,554 218,620 185,789 206,143 223,000 221,670
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 354,953 408,113 430,623 397,167 428,772 442,571 445,048
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 240,526 231,686 236,998 288,177 288,233 284,739 304,240
Capital Expenditures 4,939 16,932 1,009 12,095 488 3,973 15,946
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 235,587 214,753 235,988 276,082 287,746 280,766 288,294
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 62,014 54,685 59,723 62,289 53,219 63,400 57,967
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 62,624 55,295 60,333 62,899 53,829 64,010 58,577
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 3.76 3.88 3.91 4.39 5.35 4.39 4.92
2021 2022 2023 2024 2025 2026
---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 50%
Year of Operation 21.5 22.5 23.5 24.5 25.5 26.0
---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 11,975,907 11,975,907 11,975,907 11,975,907 8,401,155 4,200,577
---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 11,975,907 11,975,907 11,975,907 11,975,907 8,401,155 4,200,577
Contract Sales -- -- -- -- -- --
Purchases to supply Sales Contract -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Sales 11,975,907 11,975,907 11,975,907 11,975,907 8,401,155 4,200,577
---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- --
Merchant Energy Revenues 749,512 768,250 787,456 807,142 599,044 307,010
Commercial Values -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 749,512 768,250 787,456 807,142 599,044 307,010
---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 228,962 234,686 240,553 246,567 182,516 93,539
Lost Fuel Expense -- -- -- -- -- --
Total Fuel 228,962 234,686 240,553 246,567 182,516 93,539
Non-Fuel O&M
Plant O&M 197,157 199,800 167,184 204,668 131,965 54,285
Ad Valorem Taxes 6,613 6,778 6,947 7,121 1,275 653
G&A 13,644 13,985 14,334 14,693 5,605 2,872
Emissions Costs 48,944 50,168 51,422 39,800 (14,965) (17,493)
Insurance 1,128 1,156 1,185 1,214 924 474
Total, Non-Fuel O&M 267,485 271,886 241,072 267,497 124,804 40,791
---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 496,447 506,573 481,626 514,064 307,320 134,330
---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 253,065 261,677 305,830 293,078 291,725 172,680
Capital Expenditures 1,558 5,907 32,000 51,642 132,999 84,545
---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 251,507 255,770 273,830 241,436 158,725 88,135
---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 45,187 45,471 39,514 24,170 25,204 7,863
Working Capital and Letter of Credit Fees 610 610 610 610 610 610
Cash in REMA
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 45,797 46,081 40,124 24,780 25,814 8,473
---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 5.49 5.55 6.82 9.74 6.15 10.40
-----------
Average Fixed Charge Coverage Ratio 4.15
-----------
333
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
INCREASED O&M EXPENDITURES
2000 2001 2002 2003 2004 2005 2006
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 50% 100% 100% 100% 100% 100% 100%
Year of Operation 0.5 1.5 2.5 3.5 4.5 5.5 6.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
Contract Sales -- -- -- -- -- -- --
Purchases to Supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 7,092,537 14,170,992 13,985,684 14,258,811 14,284,098 14,115,537 13,872,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues 43,546 88,012 57,782 -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 312,238 659,122 659,292 691,778 710,976 686,408 669,281
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 355,784 747,135 717,074 691,778 710,976 686,408 669,281
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 107,299 217,557 214,791 223,570 224,152 219,853 213,610
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 107,299 217,557 214,791 223,570 224,152 219,853 213,610
Non-Fuel O&M
Plant O&M 55,348 126,449 120,383 132,393 131,129 126,874 136,252
Ad Valorem Taxes 2,090 4,273 4,380 4,489 4,601 4,716 4,834
G&A 5,025 12,902 13,225 13,555 13,894 14,242 14,598
Emissions Costs -- 18,423 20,021 31,793 34,820 36,780 38,868
Insurance 399 815 836 856 878 900 922
Total, Non-Fuel O&M 62,861 162,863 158,844 183,087 185,322 183,513 195,475
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 170,161 380,420 373,635 406,657 409,474 403,366 409,085
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 185,624 366,715 343,439 285,122 301,502 283,042 260,196
Capital Expenditures 8,599 28,843 67,803 38,362 21,104 6,091 27,206
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 177,024 337,872 275,636 246,759 280,398 276,952 232,990
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 151,832 163,405 108,369 75,525 83,021 73,636 62,976
Working Capital and Letter of Credit Fees 607 1,210 1,210 610 610 610 610
Cash at REMA 50,000
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 102,438 164,615 109,579 76,135 83,631 74,246 63,586
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 1.73 2.05 2.52 3.24 3.35 3.73 3.66
2007 2008 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 7.5 8.5 9.5 10.5 11.5 12.5 13.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
Contract Sales -- -- -- -- -- -- --
Purchases to Supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 13,750,440 13,700,354 13,856,753 13,661,675 12,344,567 12,383,370 12,405,357
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 686,064 698,861 725,132 736,935 664,979 682,194 698,144
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 686,064 698,861 725,132 736,935 664,979 682,194 698,144
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 217,364 215,987 224,114 221,140 200,926 203,763 207,085
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 217,364 215,987 224,114 221,140 200,926 203,763 207,085
Non-Fuel O&M
Plant O&M 140,290 145,914 158,078 203,035 111,153 165,403 136,982
Ad Valorem Taxes 4,955 5,079 5,206 5,336 5,166 5,295 5,427
G&A 14,963 15,337 15,720 14,608 10,658 10,925 11,198
Emissions Costs 41,362 45,539 50,671 54,349 36,925 37,910 39,236
Insurance 945 969 993 1,018 881 903 925
Total, Non-Fuel O&M 202,515 212,838 230,668 278,346 164,783 220,436 193,770
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 419,879 428,825 454,782 499,486 365,709 424,199 400,855
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 266,185 270,036 270,349 237,449 299,270 257,995 297,289
Capital Expenditures 24,693 15,911 14,644 5,164 4,382 1,268 1,710
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 241,492 254,125 255,705 232,285 294,888 256,727 295,579
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 63,756 61,227 61,869 51,940 62,360 55,552 63,036
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 64,366 61,837 62,479 52,550 62,970 56,162 63,646
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 3.75 4.11 4.09 4.42 4.68 4.57 4.64
-----------
Average Fixed Charge Coverage Ratio 6.06
-----------
334
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
INCREASED O&M EXPENDITURES
2014 2015 2016 2017 2018 2019 2020
---------- ---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 100% 100%
Year of Operation 15.5 16.5 17.5 18.5 19.5 20.5
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
---------- ---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
Contract Sales -- -- -- -- -- -- --
Purchases to Supply Sales Contract -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,435,785 12,515,748 12,717,916 12,733,643 12,948,297 12,881,480 12,976,905
---------- ---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- -- --
Merchant Energy Revenues 720,152 774,066 807,478 827,926 866,437 883,293 906,447
Commercial Values -- -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 720,152 774,066 807,478 827,926 866,437 883,293 906,447
---------- ---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 211,770 217,660 226,630 223,698 235,855 233,141 234,338
Lost Fuel Expense -- -- -- -- -- -- --
Total Fuel 211,770 217,660 226,630 223,698 235,855 233,141 234,338
Non-Fuel O&M
Plant O&M 121,870 173,223 182,654 143,035 158,402 174,987 169,080
Ad Valorem Taxes 5,563 5,702 5,845 5,991 6,140 6,294 6,451
G&A 11,478 11,765 12,059 12,361 12,670 12,986 13,311
Emissions Costs 40,947 42,482 45,890 48,108 54,611 56,179 59,003
Insurance 949 972 997 1,022 1,047 1,073 1,100
Total, Non-Fuel O&M 180,807 234,144 247,444 210,516 232,870 251,519 248,946
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 392,576 451,803 474,074 434,214 468,725 484,660 483,283
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 327,576 322,263 333,404 393,712 397,712 398,633 423,163
Capital Expenditures 4,939 16,932 1,009 12,095 488 3,973 15,946
---------- ---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 322,637 305,331 332,395 381,617 397,225 394,660 407,217
---------- ---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 62,014 54,685 59,723 62,289 53,219 63,400 57,967
Working Capital and Letter of Credit Fees 610 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 62,624 55,295 60,333 62,899 53,829 64,010 58,577
---------- ---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 5.15 5.52 5.51 6.07 7.38 6.17 6.95
2021 2022 2023 2024 2025 2026
---------- ---------- ---------- ---------- ---------- ----------
Percent Of Year of Operations 100% 100% 100% 100% 100% 50%
Year of Operation 21.5 22.5 23.5 24.5 25.5 26.0
---------- ---------- ---------- ---------- ---------- ----------
Total Generation (MWh) 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
---------- ---------- ---------- ---------- ---------- ----------
Power Sales (MWh)
Merchant Energy Sales 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
Contract Sales -- -- -- -- -- --
Purchases to Supply Sales Contract -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Sales 12,976,897 12,976,897 12,976,897 12,976,897 9,006,565 4,503,282
---------- ---------- ---------- ---------- ---------- ----------
Revenues ($000)
Contract Capacity Revenues -- -- -- -- -- --
Contract Energy Revenues -- -- -- -- -- --
Merchant Energy Revenues 920,463 943,475 967,062 991,238 725,557 371,848
Commercial Values -- -- -- -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 920,463 943,475 967,062 991,238 725,557 371,848
---------- ---------- ---------- ---------- ---------- ----------
Expenses ($000)
Fuel
Fossil Fuel 240,196 246,201 252,356 258,665 173,701 89,022
Lost Fuel Expense -- -- -- -- -- --
Total Fuel 240,196 246,201 252,356 258,665 173,701 89,022
Non-Fuel O&M
Plant O&M 218,720 221,536 185,843 227,160 146,767 60,625
Ad Valorem Taxes 6,613 6,778 6,947 7,121 1,275 653
G&A 13,644 13,985 14,334 14,693 5,605 2,872
Emissions Costs 60,478 61,990 63,540 51,706 (8,118) (14,788)
Insurance 1,128 1,156 1,185 1,214 924 474
Total, Non-Fuel O&M 300,582 305,444 271,850 301,894 146,454 49,836
---------- ---------- ---------- ---------- ---------- ----------
Total Expenses 540,779 551,645 524,206 560,559 320,154 138,858
---------- ---------- ---------- ---------- ---------- ----------
Operating Cash Flow ($000) 379,684 391,829 442,856 430,679 405,402 232,990
Capital Expenditures 1,558 5,907 32,000 51,642 132,999 84,545
---------- ---------- ---------- ---------- ---------- ----------
Cash Available for Fixed Charge 378,127 385,923 410,856 379,037 272,403 148,445
---------- ---------- ---------- ---------- ---------- ----------
Annual Fixed Charge
Lease Payment 45,187 45,471 39,514 24,170 25,204 7,863
Working Capital and Letter of Credit Fees 610 610 610 610 610 610
Cash at REMA
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 45,797 46,081 40,124 24,780 25,814 8,473
---------- ---------- ---------- ---------- ---------- ----------
FIXED CHARGE COVERAGE RATIO 8.26 8.37 10.24 15.30 10.55 17.52
-----------
Average Fixed Charge Coverage Ratio 6.06
-----------
335
APPENDIX B
INDEPENDENT MARKET CONSULTANT'S REPORT
336
INDEPENDENT MARKET EXPERT REPORT
FOR THE RELIANT ENERGY MID-ATLANTIC
POWER HOLDINGS, LLC ASSETS IN THE PJM
REGION
Final Report
Prepared for:
Chase Securities Inc.
Prepared by:
PHB Hagler Bailly, Inc.
1881 Ninth Street, Suite 302
Boulder, Colorado 80302
303-449-5515
Contact:
Todd Filsinger
May 5, 2000
337
- --------------------------------------------------------------------------------
DISCLAIMER
This report presents PHB Hagler Bailly, Inc.'s (PHB Hagler Bailly) analysis of
the Pennsylvania-New Jersey-Maryland (PJM) power markets.
(i) some information in the report is necessarily based on predictions and
estimates of future events and behaviors,
(ii) such predictions or estimates may differ from that which other experts
specializing in the electricity industry might present,
(iii) Actual results may differ, perhaps materially, from those projected,
(iv) the provision of a report by PHB Hagler Bailly does not obviate the
need for potential investors to make further appropriate inquiries as
to the accuracy of the information included herein, or to undertake an
analysis of their own,
(v) this report is not intended to be a complete and exhaustive analysis
of the subject issues and therefore will not consider some factors
that are important to a potential investor's decision making, and
(vi) PHB Hagler Bailly and its employees cannot accept liability for loss,
whether direct or consequential, suffered in consequence of reliance
on the report. Nothing in PHB Hagler Bailly's report should be taken
as a promise or guarantee as to the occurrence of any future
events.
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CONTENTS
EXECUTIVE SUMMARY ...........................................................S-1
CHAPTER 1 INTRODUCTION
1.1 Background ...................................................1-1
1.2 Facilities Description .......................................1-1
1.3 Structure of the Report ......................................1-1
CHAPTER 2 PJM MARKET STRUCTURES
2.1 Introduction .................................................2-1
2.2 The PJM Market ...............................................2-2
2.2.1 The Spot Energy Market ................................2-2
2.2.2 The Energy Imbalance and Operating Reserves Market ....2-3
2.2.3 Fixed Transmission Rights .............................2-4
2.2.4 The Capacity Credit Market ............................2-5
CHAPTER 3 APPROACH TO MARKET PRICE FORECASTING
3.1 Introduction .................................................3-1
3.2 Issues in Forecasting Market Prices ..........................3-1
3.3 Relationship between Energy Markets and Compensation for
Capacity .....................................................3-2
3.4 Approach to Market Price Forecasting .........................3-3
3.4.1 Market Characteristics ................................3-4
3.4.2 Predicting Energy Prices and Dispatch .................3-5
3.4.3 Predicting Prices Related to Capacity:
The Capacity Market Simulation Model ..................3-5
3.4.4 Market Entry and Exit .................................3-7
3.4.5 Volatility Analysis ...................................3-8
CHAPTER 4 ASSUMPTIONS
4.1 Introduction .................................................4-1
4.2 General Assumptions ..........................................4-1
4.3 Pricing Areas ................................................4-1
4.4 Fuel Prices ..................................................4-2
4.4.1 Natural Gas ...........................................4-2
4.4.2 Fuel Oil ..............................................4-4
4.4.3 Coal ..................................................4-7
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4.5 Demand and Energy Forecasts ..................................4-8
4.6 Electricity Imports ..........................................4-9
4.7 Existing Generation Units ...................................4-10
4.7.1 Fossil Units .........................................4-10
4.1.2 Hydroelectric Units ..................................4-15
4.1.3 Nuclear Units ........................................4-15
4.8 Capacity Market Simulation Model Input Assumptions ..........4-18
4.8.1 Existing Units Going-Forward Costs ...................4-18
4.8.2 Capacity Additions through 2002 ......................4-18
4.8.3 Capacity Additions Post 2002 .........................4-20
CHAPTER 5 MARKET PRICE FORECASTS
5.1 Introduction .................................................5-1
5.2 PJM Market Conditions ........................................5-2
5.3 Base Case Analysis ...........................................5-4
5.4 Sensitivity Cases ............................................5-8
APPENDICES
A METHODOLOGY FOR COAL PRICE FORECASTING
B TRANSFER CAPABILITY
C DISPATCH CURVES
GLOSSARY
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EXECUTIVE SUMMARY
S.1 INTRODUCTION
PHB Hagler Bailly, Inc. (PHB Hagler Bailly) was retained by Chase Securities
Inc. to provide an Independent Market Expert Report to assess future prices for
electric energy and capacity in the Pennsylvania, New Jersey, and Maryland (PJM)
market in support of the financing of Reliant Energy Mid-Atlantic Power Holdings
LLC's (REMA) generating assets based on the assumptions agreed upon herein. This
document presents the results of PHB Hagler Bailly's analysis.
S.2 MARKET CHARACTERISTICS
The United States is currently experimenting with a variety of regional market
structures. Some regions currently have fixed reserve margin requirements
coupled with capacity markets, while others implicitly price capacity through
on-peak energy prices, ancillary service prices, and bilateral option
contracts. In addition, some regions have developed bid-based markets for the
provision of energy, ancillary services, and/or capacity, while others continue
to rely on bilateral contracts. It is not clear which model will eventually
become more widespread. Nevertheless, in both types of markets, new generating
capacity will be developed based on the revenue streams determined through
competition. While the type of market in place in a given region will determine
the composition of the revenue streams and will affect the mix and timing of
new generating units, the financial return on new assets is likely to be
similar in both types of markets, as generators seek to cover their total
going-forward costs. The PJM market has developed as a bid-based market.
The Northeast power markets are undergoing profound change. Many of the
vertically integrated utilities are divesting their generation assets, and
tight power pools (such as the PJM Power Pool, the New York Power Pool, and the
New England Power Pool) are changing as well. Historically, these pools were
formed to obtain the benefits of economic efficiency and reliability through
coordinated planning and operation. Independent system operators (ISOs) with
both system operations and market operations functions are replacing the tight
pools. Through the creation of the new market institutions, the market
participants intend to create an open and competitive market where a large
number of buyers and sellers of generation services will be able to transact
business.
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EXECUTIVE SUMMARY -- S-2
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S.3 FORECASTING METHODOLOGY
PHD Hagler Bailly employs its proprietary market valuation process, MVP(SM), to
estimate the value of electric generation units based upon the level of energy
prices and their volatility. As shown in Figure S-1, MVP(SM) is a three-step
process. The first step is to conduct the "fundamental analysis" to examine how
the level of prices responds to changes in the fundamental drivers of supply
and demand. The next step uses the results of the first step, but puts a real
market price shape on the price levels and characterizes the volatility in
prices. The third step examines how the generation unit responds to those
prices and derives value from operational decisions.
FIGURE S-1
MARKET VALUATION PROCESS
[PROCESS CHART]
Note that MVP(SM) does not replace the fundamental analysis of market drivers
of supply and demand through a production cost model. The production-cost model
provides insights into the fundamental drivers (such as fuel prices, demand,
entry, and exit) that a volatility analysis cannot address. MVP(SM) integrates
the two approaches to create a better estimate of the value of a generating
unit by accounting for volatility effects and changes in the fundamental
drivers of electricity prices.
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EXECUTIVE SUMMARY -- S-3
- --------------------------------------------------------------------------------
As shown in Figure S-2, volatility analysis takes into account the annual trend
of prices (from a fundamental approach), and the patterns and fluctuations
exhibited in the marketplace.
FIGURE S-2
COMPONENTS OF A PRICE TRAJECTORY
[ANALYSIS CHART]
MVP(SM) uses a real options approach to value electric generating capacity, and
thereby captures the value of price volatility. An electric generating unit can
be viewed as a strip of European call options on the spread between electricity
prices and the variable cost of production (which is largely fuel). Unlike most
option analyses, however, a generation unit does not have perfect flexibility
to adjust to the price-cost spread. A generation unit may have costs that must
be incurred to start up, as well as constraints on its operation that may limit
its ability to capture margins when the spread is positive (price is greater
than variable cost) or avoid losses when the spread is negative (variable cost
is greater than price). Hence, the second step of MVP(SM) focuses on the
ability of a generation unit to capture margins, given its cost structure and
constraints on operation.
PHB Hagler Bailly's fundamental model, which is a driver of the volatility
model, forecasts two price streams:
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EXECUTIVE SUMMARY -- S-4
- ------------------------------------------------------------------------------
- -- energy based upon a production-cost model with price set to marginal cost
in each hour
- -- compensation for capacity, which represents the additional margin
necessary to keep an economic amount of capacity in the market.
PHB Hagler Bailly uses a detailed chronological production-costing model to
simulate energy price formation in the market area of interest. From the energy
price analysis, PHB Hagler Bailly determines the energy margin (price minus
variable cost) attributable to each generating unit in the market. These
margins, along with estimates of "going-forward costs" (fixed costs, such as
fixed operation and maintenance (O&M), property taxes, employee benefits, and
incremental capital expenditures), are used in PHB Hagler Bailly's Capacity
Market Simulation Model to predict the additional margins related to the
provision of capacity.
Compensation for capacity may take many forms. Payments could be in the form of
a capacity price arising from a capacity market, a regulated payment fee,
bilateral contracts, payments by the ISO for ancillary services, or in the form
of prices above the marginal cost of the price-setting plant. Regardless of the
form, compensation for capacity will be set to retain an amount of generation
capability available in the market. Ultimately, the sum of the compensation for
capacity and the market price for energy will reflect what customers are
willing to pay for reliability.
S.4 KEY ASSUMPTIONS
The key assumptions in this analysis include demand growth, fuel prices, and
capacity additions.
DEMAND. PJM peak demand is forecasted to grow at an average annual growth
rate of approximately 1.6% from 2000 from 2020.(1)
FUEL PRICES. Forecasts for natural gas and oil use a consensus fuel price
forecast derived from published fuel price forecasts. Table S-1 summarizes the
fuel price forecasts used in the Base Case for the PJM-East, West and Central
regions where REMA's assets are located.
- -----------
(1) 1999 MAAC Annual Electric Control and Planning Area Report.
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EXECUTIVE SUMMARY -- S-5
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TABLE S-1
DELIVERED FUEL PRICES IN PJM(1999 $/MMBtu)
FUEL 2000 2005 2010 2015 2020
- -------------------------- ---- ---- ---- ---- ----
Natural Gas-PJM East 2.81 2.87 2.99 3.06 3.31
Natural Gas-PJM West 2.72 2.79 2.91 3.00 3.25
Natural Gas-PJM Central 2.77 2.83 2.95 3.03 3.28
Fuel Oil No. 2-PJM East 3.87 4.28 4.57 4.74 4.98
Fuel Oil No. 2-PJM West 3.84 4.25 4.54 4.72 4.95
Fuel Oil No. 2-PJM Central 3.82 4.24 4.53 4.70 4.93
Fuel Oil No. 6 PJM East 2.52 2.73 2.86 2.91 2.99
Fuel Oil No. 6 PJM West 2.43 2.64 2.77 2.82 2.90
Fuel Oil No. 6 PJM Central 2.41 2.62 2.75 2.80 2.88
Capacity additions. Based on assessments of the status of announced
plants, PHB Hagler Bailly has estimated operational capacity additions of 8,147
MW in PJM and NPCC by 2003. Thereafter, capacity additions are based on the
results of modeling and simulation of developer's decisions. In the Base Case
presented in this report, 22,855 MW of new capacity is added in PJM from 2003
through 2020, and 7,529 MW is retired.
RESULTS AND CONCLUSIONS
Using the assumptions presented in Chapter 4, PHB Hagler Bailly developed a
"Base Case" for each region that reflects our best assessment of future market
conditions. It should be recognized that this Base Case will vary to the extent
the input assumptions change, and such assumptions should be reviewed with the
same rigor as the resulting forecast. In addition to the Base Case, PHB Hagler
Bailly developed four sensitivities as outlined below:
- -- "Low Fuel Price Case" which tests the sensitivity of the market price
forecasts to lower gas and oil prices represented as a $0.50/MMBtu
reduction in the 1999 gas and oil prices with escalation remaining
unchanged (coal prices are not changed).
- -- "Overbuild Case" which tests the sensitivity of the market price forecasts
to an exuberance of merchant plant development as well as continued
operation of all nuclear plants. In this scenario, an additional 12,447 MW
of merchant capacity comes online by 2003, in addition, to the 8,147 MW of
confirmed new merchant capacity that is reflected in the Base Case.
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EXECUTIVE SUMMARY -- S-6
- --------------------------------------------------------------------------------
The all-in market price combines the energy price with the price received by
generators for other relevant generation services and energy products in the
market. The all-in price reflects PHB Hagler Bailly's estimate of the total
market price that generators will recover in PJM-East, PJM West and PJM
Central. The all-in price results of the study are summarized in Figures S-3,
S-4, and S-5.
FIGURE S-3
PJM-EAST ESTIMATED ALL-IN PRICE FORECAST
[PERFORMANCE CHART]
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EXECUTIVE SUMMARY -- S-7
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FIGURE S-4
PJM-CENTRAL ESTIMATED ALL-IN PRICE FORECAST
[PERFORMANCE CHART]
FIGURE S-5
PJM-WEST ESTIMATED ALL-IN PRICE FORECAST
[PERFORMANCE CHART]
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EXECUTIVE SUMMARY -- S-8
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S.5 CONCLUSIONS
Power markets throughout the United States are presently undergoing fundamental
change. Market structures are changing to support the introduction of a more
competitive environment in the power generation industry. Power pools are being
replaced by independent system operators (ISOs) with both system operations and
market operations functions. Through the creation of the new market
institutions, participants intend to create efficient power markets where
buyers and sellers of generation services will be able to transact business
with greater speed.
In this new environment the nature of electricity pricing, and consequently
revenue generation, is shifting away from administered regulation and toward
market mechanisms driven by competition. The expected increase in price
volatility and related risks associated with these new markets presents both
tremendous upside and downside potential for certain generators. In response to
these changes, many vertically integrated utilities are re-examining their
business model and adjusting their generation asset portfolios. A select group
of these utilities have adopted a diverse approach in assembling generation
asset portfolios that take advantage of market opportunities. These portfolios
are being assembled through utility mergers, new construction, and through the
acquisition of assets divested from producers partially or completely exiting
the generation business. These portfolios, like the REMA portfolio, offer
decreased risk, as they portray fuel and unit diversity.
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CHAPTER 1
INTRODUCTION
1.1 BACKGROUND
PHB Hagler Bailly, Inc. (PHB Hagler Bailly) was retained by Chase Securities
Inc. to provide an Independent Market Expert Report to assess future prices for
electric energy and capacity in the Pennsylvania, New Jersey, and Maryland (PJM)
market in support of the financing of Reliant Energy Mid-Atlantic Power
Holdings, LLC's (REMA) generating facilities. This document presents the
results of PHB Hagler Bailly's analysis.
1.2 FACILITIES DESCRIPTION
The generating facilities total over 4,200 MW (average annual rating) of
generation in the PJM-East, PJM-Central, and PJM-West transmission areas. This
generation includes approximately 2,400 MW of steam energy (88% of the steam
generation is coal-powered, the remaining 12% has dual fuel capability), 1,580
MW of combustion turbines (73% of the generation have dual fuel capabilities,
i.e., No. 2 fuel oil and natural gas, while the remaining 23% are powered by
distillate fuel, i.e., No. 2 fuel oil), 23 MW of diesels, and 47 MW of hydro
generation.
1.3 STRUCTURE OF THE REPORT
This document describes the anticipated market structures as well as our
approach to constructing forward-price forecasts for generation services. The
document is organized as follows:
- - Chapter 2 describes the structure of the markets in PJM
- - Chapter 3 presents our approach to developing forward-price forecasts for
generation services
- - Chapter 4 discusses the development of assumptions and data to describe the
PJM marketplace
- - Chapter 5 presents market price forecasts for the Base Case and two
sensitivity cases
- - Appendix A supplements the fuel forecast presentation in Chapter 4 with
further details concerning regional coal pricing trends
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- - Appendix B details regional energy transfer capabilities
- - Appendix C illustrates the projected position of the REMA portfolio in the
regional market dispatch curve
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CHAPTER 2
PJM MARKET STRUCTURES
2.1 INTRODUCTION
The PJM power pool was the first centrally dispatched power pool in the United
States and is one of the largest power pools in the world, with over 220
million MWh of annual electricity sales. PJM operates the largest centrally
dispatched control area in the United States, which covers all or part of the
states of Pennsylvania, New Jersey, Maryland, Delaware, Virginia and the
District of Columbia.
The Federal Energy Regulatory Commission (FERC) in its Open Access Rule(1)
ordered public utilities that are members of tight power pools(2) such as PJM
to file an open access transmission tariff and to open membership in the pool
on a non-discriminatory basis. In response to FERC Order 888, the members of
the PJM power pool developed a restructuring proposal and a pool-wide
open-access tariff. This restructuring proposal created an Independent System
Operator (ISO) to operate the regional bulk power system, maintain system
reliability, administer specified electricity markets, and facilitate open
access to the regional transmission system under the PJM tariff. The PJM
electricity market uses market pricing for various generation services, thereby
facilitating the development of a competitive bid price wholesale electricity
market.
PJM Interconnection, LLC (PJM-ISO) was certified as an ISO by FERC on November
25, 1997, and the ISO began operations on April 1, 1998. The PJM-ISO's stated
objectives are to ensure reliability of the bulk power transmission system and
to facilitate an open, competitive wholesale electricity market. To achieve
these objectives, the PJM-ISO manages the PJM open access transmission tariff
(the first power pool open access tariff approved by FERC).
The PJM-ISO also operates the PJM interchange energy market, which is the
region's spot market (power exchange, or PX) for wholesale electricity. The
PJM-ISO also provides ancillary services for its transmission customers and
performs transmission planning for the region. The energy market was initiated
on April 1, 1997, and locational marginal pricing (LMP) took effect on April 1,
1998. The PJM-ISO's capacity credit market was launched on October 15, 1998,
and in 1999 the PJM-ISO introduced market-based prices for energy and certain
ancillary services and established a market for fixed transmission rights
(FTRs).
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(1) Order No. 888, FERC Stats. & Regs. 31,036 at 31,726-27.
(2) A "tight power pool" is formed by a group of utilities who dedicate their
generating and transmission resources for economic dispatch. Usually in tight
power pools costs and revenues are divided among the members after the fact and
no one pool member is responsible for the procurement of individual power
supply.
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2.2 THE PJM MARKET
The PJM-ISO wholesale market structure includes the following markets for the
services of generators:
- -- spot energy market
- -- energy imbalance and operating reserves market
- -- FTR auction
- -- capacity credit market
Load-serving entities (LSEs) have obligations to provide or acquire installed
capacity, regulation, and operating reserves. In addition to spot market
purchases, bilateral transactions are also allowed in PJM. While bilateral
transactions are not subject to the market-clearing prices, they are subject to
the same charges for transmission congestion included in the market-clearing
prices.
Generators are compensated for providing energy and ancillary services through
the PJM PX as follows:
- -- LMPs are determined based on the applicable energy bids
- -- generators providing regulation services receive a payment that is computed
based on a formula intended to reflect the opportunity costs of being
available for regulation service rather than energy supply
- -- energy imbalance and operating reserves are compensated according to bids
submitted to the PX
- -- other ancillary services are compensated based on cost
- -- any shortfall payments continue to be determined based on the difference
between total revenue and total revenue requirement (as reflected in the
three-part bid)
2.2.1 THE SPOT ENERGY MARKET
The PJM-ISO manages the regional spot energy market. The closing time for
submitting bids to the PJM-ISO energy markets is noon for the following day
(for example, noon on Tuesday for bids on energy to be generated on Wednesday).
A bid to supply generation consists of an incremental energy bid curve composed
of three parts: start-up costs, no load costs and operating costs. For each
generation level, the bid curve represents the minimum price a bidder is
willing to accept to be dispatched at that generation level. The bid curve is
specified by up to 10 price-quantity pairs. The same curve is used for all 24
hours of dispatch. As of October 1, 1999, the PJM-ISO now publishes historical
bids for the PJM market six months after-the-fact for steam, combustion
turbine, and hydro generators.
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In the past, bids into the market were capped at cost. Thus, generators
bidding into the spot market were forced to cap their energy bid at the
marginal operating cost of producing energy, which would generally consist of
fuel costs plus variable operation and maintenance costs. The start-up cost bid
was capped at the costs, mostly fuel costs, incurred to bring a generator
on-line. The no load cost bid, also mostly fuel costs, was capped at the costs
incurred to maintain a generator at minimum load after it has been started and
synchronized with the system. Any shortfall between the revenue requirement of
the generator and the revenue received through the market was compensated
through a make whole payment.
On April 1, 1999 the spot market replaced its cost-based pricing system with a
market-based pricing approach. Generators continue to provide 3-part bids, but
these bids are not necessarily capped at cost. While bids are no longer capped
at cost, they are subject to a $1000/MWh ceiling cap. The PJM PX bidding rules
allow generators to submit different energy bids for each hour, and generators
can submit a new set of bids daily. However, a generator's start-up and no-load
bids, once submitted, remain in effect for six months at a time. The PJM-ISO
uses these bids and technical plant data to determine on a day-ahead basis which
generators it will schedule, and for each of those generators, the amount, if
any, of energy, and ancillary services, each will supply at various times during
the next day.
The PJM-ISO also uses the energy bids to determine in real time the LMPs for
each point of energy injection/withdrawal on the system for each hour. LMPs
reflect the costs associated with the out-of-order dispatch due to transmission
congestion. Congestion occurs when the transmission system becomes constrained,
and some generating capacity is dispatched while other generating capacity with
lower bids is not dispatched. The result is that the market-clearing prices may
differ from location to location. LMPs are quoted in dollars per megawatt-hour
($/MWh) and are based on bids for generation, actual loads, scheduled bilateral
transactions, and transmission congestion. The PJM-ISO constructs a commitment
schedule based upon day-ahead bids. Real-time dispatch is conducted by the
PJM-ISO by sending price signals to those generators on the margin. These
marginal generators then respond by ramping up or ramping down. The PJM-ISO can
also command units to change their output. Settlement prices are calculated
after the fact, based on the actual dispatch data.
2.2.2 THE ENERGY IMBALANCE AND OPERATING RESERVES MARKET
In addition to energy, generators can bid to supply certain ancillary services.
These services include energy imbalance and operating reserves. The energy
imbalance market supplies energy to compensate for any mismatch between
scheduled delivery and actual loads that have occurred over an hour. The
operating reserves market provides capacity scheduled to be available for
specified periods of an operating day to ensure the reliable system operation.
The PJM-ISO defines three categories of operating reserves: spinning reserves,
primary (or ten-minute reserves), and thirty-minute reserves. Spinning reserves
are provided from the unloaded capacity of generating units, which are
currently on-line and synchronized with the grid. The PJM-ISO currently
requires approximately 1,100 MW of spinning reserves; an amount that provides
for
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the sudden contingency loss of the largest generating unit operating on the
system. Primary and thirty-minute reserves are provided by units on-line and
synchronized, but these reserves may also be provided by quick start units. The
PJM-ISO requirement for primary reserves is approximately 1,700 MW (including
1,100 MW of spinning reserves), and the requirement for thirty-minute reserves
is approximated based on an amount equal to 10% of the forecasted daily peak
load.
2.2.3 FIXED TRANSMISSION RIGHTS
Fixed transmission rights (FTRs) allow generators, LSEs, and others to hedge
the costs associated with transmission congestion. An FTR has a financial
analogue (transmission congestion credit) which is a financial right entitling
holders of FTRs to a share of the congestion charges associated with the
difference in prices from a point of power injection to a point of delivery.
When one obtains an FTR, one also acquires a transmission congestion credit,
which may be used to offset the costs of transmission congestion. FTRs are
obtained through two means: by subscription to network service, where FTRs are
assigned to the load based upon the location of the capacity resource and the
load, or through the purchase of firm point-to-point transmission service. The
PJM-ISO began facilitating the auction of FTRs on April 15, 1999.
FTRs are available to all PJM firm transmission service customers (network
integration service or firm point-to-point service), since these customers pay
through embedded costs for the PJM transmission system. The purpose of FTRs is
to protect firm transmission service customers from increased cost due to
transmission congestion when their energy deliveries are consistent with their
firm reservations. Essentially, FTRs are financial instruments that entitle firm
transaction customers to rebates of congestion charges paid by the firm
transmission service customers. They do not represent a right for physical
delivery of power. The holder of the FTR is not required to deliver energy in
order to receive a congestion credit. If a constraint exists on the transmission
system, the holders of FTRs receive a credit based on the FTR MW reservation and
the LMP difference between point of delivery and point of receipt. This credit
is paid to the holder regardless of who delivered energy or the amount delivered
across the path designated in the FTR.
FTRs can be acquired in four ways:
- -- NETWORK INTEGRATION SERVICE. Network service FTRs are designated along paths
from specific generation resource(s) to the customer's aggregated load. The
network service customer has the option to request FTRs for all or any
portion of its generation resources. A network service customer's total FTR
designation to a zone cannot exceed the customer's total network load in
that zone. Network service customers make FTR requests and modifications
through an Internet computer application called eCapacity.
- -- FIRM POINT-TO-POINT SERVICE. The PJM Office of the Interconnection (OI)
allocates FTRs to firm point-to-point service customers for approved service
requests. The point of
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receipt is either a generation resource within the PJM control area or the
interconnection point with the sending control area. The point of delivery
is the set of load buses designated in Open Access Same-time Information
System (OASIS) or the point of interconnection with the receiving control
area. The duration of the FTR is the same as for the associated service
request. Point-to-point FTRs may be requested with the transmission
reservation, as an option
- -- FTR AUCTION. The PJM-ISO conducts a monthly process of selling and buying
FTRs through an auction. The FTR auction offers for sale any residual
transmission entitlement that is available after network and long-term
point-to-point transmission service FTRs are awarded. The auction also
allows market participants an opportunity to sell FTRs that they are
currently holding. Market participants offer to sell or request to buy
FTRs through an Internet computer application called eFTR. In addition,
when an existing FTR is sold in the auction, it is actually surrendered to
the PJM-ISO which issues it to the third party buyer. The PJM-ISO conducts
separate auctions for on-peak and off-peak periods (class) each month.
FTRs awarded in the on-peak auction are valid for hours ending 0800 to
2300 on weekdays. FTRs awarded in the off-peak auction are valid for hours
ending 2400 to 0700 on weekdays and for all hours on weekends and PJM
holidays
- -- SECONDARY MARKET. The FTR secondary market is a bilateral trading system
that facilitates trading of existing FTRs directly between PJM Members
through an eFTR transaction
The hourly dollar value of an FTR is based on the FTR MW reservation and the
difference between LMPs at the point of delivery and the point of receipt
designated in the FTR. Therefore, it is important to note that an FTR can
provide financial benefit, but it can also be a financial liability resulting
in additional charges to the holder.
- -- It is a benefit when the path designated in the FTR is in the same
direction as the congested flow. (The LMP at the point of delivery is
higher than the LMP at the point of receipt)
- -- An FTR can be a liability when the designated path is in the direction
opposite to the congested flow. (The LMP at the point of receipt is higher
than the LMP at the point of delivery.) However, if the holder were to
actually deliver energy along the designated path, he would receive a
congestion credit that would offset the FTR charge
2.2.4 THE CAPACITY CREDIT MARKET
To ensure that sufficient capacity is available in the market to meet
reliability standards, the PJM-ISO requires LSEs to own or contract with the
owner of generation capacity to cover both their peak demand and reserve margin.
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An LSE's installed capacity obligation is determined two years in advance by
the PJM-ISO based on forecast conditions. This obligation remains in place and
is known as the "planned-for" obligation. The "planned-for" obligation is then
adjusted for actual conditions. This adjusted obligation is known as the
"accounted-for" obligation. Capacity acquired in the capacity credit market also
satisfies the "accounted-for" obligation.
The amount of capacity each generator can supply is determined by a
twelve-month rolling average availability, calculated two months in advance of
the period for which the capacity is supplied. Availability statistics are kept
by the PJM-ISO. These statistics are averaged over the past twelve months and
applied to the "planned-for" obligation two months hence.
External resources may be designed as resources to meet the capacity
requirement. These resources, however, must: (1) be rated upon the extent to
which they improve the ability of the PJM pool to obtain emergency assistance
from other control areas and (2) be made available to the PJM-ISO for
scheduling and dispatch. Should the resource not be made available to the
PJM-ISO, it adversely affects the resource's availability rating.
If an LSE fails to meet its capacity requirement, a penalty is assessed.
The PJM capacity credit market allows market participants to buy and sell
capacity credits through a process that establishes a market-clearing price.
The PJM capacity credit market consists of both the daily and monthly market.
Each installed capacity market has a single market-clearing price for each day
the market is in operation.
DAILY MARKET OPERATION
The daily market is a day-ahead market. Currently, a mandatory aspect to the
day-ahead market is in effect. If a participant does not submit enough buy bids
or sell offers to cover his projected deficient or excess position, the PJM-ISO
will submit a mandatory buy bid or sell offer to cover the projected deficient
or excess amount. Mandatory buy bids will be submitted at a price equal to the
prevailing capacity deficiency rate.
Buy bids or sell offers are accepted between 7:00 a.m. and 10:00 a.m. on the
day the market is run. The PJM-ISO strives to clear the market and post market
results by 12:00 p.m. on the day the market is run.
The daily market is conducted based on the estimated position of a participant
for the market day at 10:05 a.m. on the day the market is run. If a participant
has a deficient position, the PJM-ISO will only accept buy bids up to the
deficiency amount. If a participant has an excess position, the PJM-ISO will
only accept sell offers up to the excess amount. Buy bids or sell offers are
accepted into the daily market in order of time submitted.
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MONTHLY MARKET OPERATION
The capacity credit market currently operates both monthly and multi-monthly
markets. These monthly markets are voluntary, and participants may submit buy
bids and sell offers in the same market. There are currently two multi-monthly
markets, a seven-month and a twelve-month.
Similar to the daily market, buy bids and sell offers are accepted between
7:00 a.m. and 10:00 a.m. on the day the market accepts bids. The PMJ-ISO
strives to clear the market and post market results by 12:00 p.m. on the same
day. On three scheduled days each month, monthly market bids are accepted for
the three respective succeeding months. Multi-monthly market bids are accepted
on a scheduled day approximately four months prior to the beginning of the
multi-monthly period.
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CHAPTER 3
APPROACH TO MARKET PRICE FORECASTING
3.1 INTRODUCTION
This chapter discusses PHB Hagler Bailly's approach to forecasting forward
prices for the services of generation units. The first section discusses the
issues faced while forming these forecasts, namely the distinction between
capacity and energy markets and the evolution of market structures. The second
section describes the relationship between energy markets and compensation for
capacity and the implications for forecasting forward prices. The third section
summarizes the methodology used for estimating market prices for electricity in
this analysis.
3.2 ISSUES IN FORECASTING MARKET PRICES
For price forecasts to be relevant, one must consider the institutions that
define the market. Some electricity markets, such as England and Wales, allow a
separate pricing mechanism to encourage and compensate generating capacity in
the market. Other markets, such as Australia and New Zealand, are energy-only
markets in which the market does not separately pay generators for their
installed capacity.(1) Theoretically, an energy-only market will lead to
economically efficient capacity levels in the long run, as long as spot prices
are allowed to rise to levels that clear the market, no matter how high those
prices must be. Thus, the average energy price should rise to a level sufficient
to cover the costs of new capacity in an energy-only market, even if there is
not a separate capacity adder administered by the market operator.
The structure of all U.S. electric power markets is in a state of flux. New
forms of market organization have been adopted in areas such as California and
the Northeast and are proposed for the Midwest. These structures continue to
evolve as the electric power markets develop and move through the transition
period from regulated monopolies to fully functioning competitive markets.
Indeed, competitive market structures may continue to change even after a market
is considered mature, as is occurring in England and Wales.
Some of the basic economic principles concerning price forecasts are
independent of the market structure. Regardless of the pricing mechanisms that
are adopted for ensuring sufficient capacity reserves (e.g., capacity market,
energy-only market), the markets will reflect, through one
- -------------------
(1) Forms of energy-only pricing systems also may include payments for spinning
and operating reserves. However, payments for ancillary services are
differentiated from capacity reserve payments for purposes of this discussion.
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mechanism or another, the need for price signals to induce the construction of
new generating capacity.
Current market structures and new designs can best be judged against a sense of
what the market structure eventually will look like. Although no region in the
United States has a fully mature market today, there is an emerging consensus on
what a competitively restructured electricity industry should look like.
Principle facets of the market include:
- -- formation of an entity to operate transmission and coordinate schedules
that is independent of any generation owner or market participant, either
through an ISO or a TRANSCO
- -- formation of a power exchange with, at a minimum, an hourly spot market
- -- some form of "congestion pricing" for transmission constrained areas
In addition, a competitive market would allow effective competition among
generators, resulting in efficient outcomes unhindered by the exercise of
market power. Most production-cost models are consistent with these facets of a
competitive market, or can be modified from a traditional structure to consider
the "end-state" of competition.
For purposes of this study, the markets under examination have been modeled
based on two separate end-state markets. However, the latest information
available concerning the rules and procedures, both in place and announced by
the governing market institutions, has been considered in the analysis.
3.3 RELATIONSHIP BETWEEN ENERGY MARKETS AND COMPENSATION FOR CAPACITY
The United States is currently experimenting with markets that have fixed
reserve margin requirements coupled with capacity markets and those that
implicitly price capacity through high on-peak energy prices, ancillary service
prices, and bilateral option contracts. It is not clear which model will
eventually become more widespread. Nevertheless, in both types of markets, new
generating capacity will be developed based on the revenue streams determined
through competition. While the type of market in place in a given region will
determine the composition of the revenue streams and will affect the mix and
timing of new generating units, the financial return on new facilities is likely
to be similar in both types of markets as generators seek to cover their total
going-forward costs.
In power markets, such as PJM, New York, or New England, where load-serving
entities are required to maintain a minimum generating capacity reserve level,
the capacity obligation creates a market between those that are short on their
capacity obligation and those that have surplus capacity. In a competitive
market, potential suppliers compete to provide this capacity. Markets
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have been developed to support the provision of this capacity, typically in the
form of monthly or annual payments to generators, to compensate them for being
available to produce when required. The capacity price essentially is the
payment needed to keep the marginal capacity required for reliability purposes
in the market. In such markets, generators cover their total going-forward
costs through a combination of revenue from the energy, capacity, and ancillary
service markets.
Recent development of market structures devoid of capacity payments (e.g., the
California-ISO) have forced generators to recover all of their going-forward
costs, both fixed and variable, from the energy and ancillary services markets
and through reliability payments [e.g., reliability must run (RMR) contracts in
California]. Competition will continue to produce energy prices approaching the
short-run marginal cost in those periods where there is ample capacity
available (such as off-peak periods). However, as markets tighten (i.e., as
capacity surpluses diminish), particularly in peak demand periods, the hourly
price of energy may reflect a scarcity value that is in excess of the short-run
marginal costs of even the most expensive peaking units. This scarcity value is
necessary to allow marginal units to recover their going-forward costs in a
market without capacity payments.
The terms "compensation for capacity" and "energy price" as used in this report
reflect the prices needed by the marginal units to recover their fixed and
variable costs. These prices together form the all-in price. Compensation for
capacity and energy prices are somewhat inversely related; as one rises the
other falls, so that the all-in price remains relatively in balance.
PHB Hagler Bailly forecasts two price streams:
1. energy based on a production-cost model with price set to marginal cost in
each hour
2. compensation for capacity, which represents the additional margin
necessary to keep an economic amount of capacity in the market
Compensation for capacity may take many forms. Payments could be in the form of
a capacity price arising from a capacity market, a regulated payment fee,
bilateral contracts, payments by the ISO for ancillary services, or in the form
of energy prices above the marginal cost of the price-setting plant. Regardless
of the form, compensation for capacity will be set to retain an amount of
generation capability available in the market. Ultimately, the sum of the
compensation for capacity and the market price for energy will reflect what
customers are willing to pay for reliability.
3.4 APPROACH TO MARKET PRICE FORECASTING
Projecting forward prices (and generation product sales) requires PHB Hagler
Bailly to consider not only price formation in the market, but also the issues
of market entry and exit. Figure 3-1 provides a graphical view of PHB Hagler
Bailly's process for producing forward-price forecasts.
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FIGURE 3.1
APPROACH TO DEVELOPING COMPENSATION FOR CAPACITY AND ENERGY PRICES
[FLOW CHART]
The process begins with a definition of the characteristics of the market,
including the electric generating units currently in operation, their
production efficiencies (including heat rate curves), a projection of plant
additions (based, in part, on announcements and, in part, on an equilibrium
evaluation of market price signals and new investments), consumer demand and
load, and generation fuel prices.
Thus, this process develops prices based on a dynamic examination of market
entry and exit (including retirement) decisions made by the supply-side players
in the market. The following sections will briefly discuss PHB Hagler Bailly's
approach to each of these steps.
3.4.1 MARKET CHARACTERISTICS
The first step includes a detailed examination of the nature and parameters of
the market and the generation assets that participate in that market. PHB
Hagler Bailly uses a variety of data sources and methods to characterize the
market. These include:
- -- Published data identifying the generating units, consumer demand and
load, and production capacities of existing plants
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- -- Fuel price forecasts
- -- Planned additions, which are developed based on announced plans of
developers (tracked in the PHB Hagler Bailly IPP Database) and utilities
(contained in planning council reports), weighted by PHB Hagler Bailly's
assessment of how much capacity will actually be built in the early stages
of the analysis time horizon. Capacity additions subsequent to 2002 are
tested in the entry and exit logic as discussed below
- -- Retirements of nuclear plants. PHB Hagler Bailly reviews the experience of
nuclear power plant operators (tracked in the PHB Hagler Bailly Operating
Plant Experience Code Database) to identify the plants most likely to be
retired before the end of their operating licenses (and to estimate
potential retirement dates)
3.4.2 PREDICTING ENERGY PRICES AND DISPATCH
PHB Hagler Bailly uses a detailed chronological production-cost model to
simulate energy price formation in the market area of interest. The results of
the dispatch analysis for the REMA facilities are shown in Appendix C.
From the energy price analysis, PHB Hagler Bailly determines the energy margin
(price minus variable cost) attributable to each generating unit in the market.
These margins, along with estimates of "going-forward costs" (fixed costs, such
as fixed operation and maintenance (FO&M), property taxes, employee benefits,
and incremental capital expenditures), are used in the Capacity Market
Simulation Model to predict the additional margins related to the provision of
capacity.
3.4.3 PREDICTING PRICES RELATED TO CAPACITY: THE CAPACITY MARKET SIMULATION
MODEL
Compensation for capacity is a mechanism for supporting an appropriate amount
of generating capability in the system. There are two reasons for including a
measure of the compensation for capacity or shortage payment in a forward-price
analysis. First, if generators bid their short-run marginal costs into an
energy market, only inframarginal plants (those below the marginal price) earn
a contribution toward their going-forward costs. Secondly, some of the baseload
and cycling plants that are not at the top of the supply curve but have
high going-forward costs may not earn a sufficient operating margin from the
energy market alone to cover all of those costs.
PHB Hagler Bailly predicts a value for compensation of capacity using the
Capacity Market Simulation Model. This model presumes that the market will
retain a sufficient amount of capacity to meet economic reliability targets. In
other words, PHB Hagler Bailly simulates a capacity market consisting of a
supply curve and a demand curve for reliability (or capacity) services. PHB
Hagler Bailly assumes that the organized capacity market is a competitive
market, and that the market-clearing price for capacity is determined by the
intersection of the supply and
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demand curves. The supply and demand curves are derived for each year in the
simulation time horizon.
The supply curve is calculated from the going-forward cost of each generating
unit. The net of going-forward costs and energy market margins, expressed on a
per-kilowatt basis, represent the minimum amount a generating unit needs to go
forward. Ranking these net costs in ascending order produces a supply curve for
capacity.
Next, the demand curve is estimated. The demand curve is estimated by
representing the capacity associated with a target reliability level. The demand
curve is a vertical line derived using a target reserve margin or target level
of installed capacity.
Finally, the intersection of the demand curve and the supply curve represents
the capacity payment that the market would support in that year. The capacity
price forecast is the capacity payment derived for each year of the study
period. An example supply and demand curve for a hypothetical year is shown in
Figure 3-2.
FIGURE 3-2
EXAMPLE SUPPLY AND DEMAND CURVE
[LINE GRAPH]
[Plot points to come]
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3.4.4 MARKET ENTRY AND EXIT
In accessing the feasibility and timing of new capacity additions, as well as
the exit of uneconomic existing capacity, PHB Hagler Bailly's proprietary
modeling approach serves two purposes:
- -- First, it identifies generating units that are not able to recover their
going-forward costs in the energy and capacity market and are, therefore,
at risk of abandoning the market
- -- Second, it provides a rational method for ascertaining the amount, timing,
and type of capacity additions
Capacity additions through 2002 are based on known, planned additions.
Thereafter, PHB Hagler Bailly's approach uses a financial model to assess the
decision to add new capacity and to retire existing capacity. The approach to
plant additions is based on a set of generic plant characteristics, financing
assumptions, and economic parameters. This "add/retire" analysis is an iterative
process performed simultaneously with the development of the energy price
forecast and the projected compensation for capacity.
The methodology assesses the feasibility of annual capacity additions based on
a Discounted Cash Flow (DCF) model using net energy revenues determined in the
production-cost simulations and compensation for capacity determined from the
Capacity Market Simulation approach. For each increment of new capacity, a "Go"
or a "No Go" decision is made based on whether the entrant would experience
sufficient returns (developed in the DCF model) to merit entry. In addition,
economic retirement decisions are made at each step in the iterative process
based on the scientific financial and operating characteristics of the existing
plant.
The iterative process begins with the addition of new capacity when needed. A
production-cost run is executed to determine energy prices, dispatch, and
operating costs. The Capacity Market Simulation is then performed. Financial
results for the energy and capacity markets are combined in the DCF model to
determine whether the new unit is a "Go" or a "No Go." If the new unit is a
"Go," another new unit is added in that year, and the process repeated. This
occurs until the next new unit returns a "No Go." Should the analysis show a
"No Go," the unit is removed (e.g., not added).
Annual retirements are determined after new units are added for that year. A
financial analysis of each unit is performed beginning in 2002, based on the
results of the energy and capacity markets. If the operating profit for an
existing unit is negative for any five-year consecutive period, it is retired
at the end of the third year of consecutive operating losses. Thus, if a unit
loses money for two years, is profitable over the third year, and then loses
money for two more years, the unit is maintained online.
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If units are retired, the iterative process begins again with the addition of
new capacity. In this way, the introduction of new units influences the
retirement of existing units, and the retirement of existing units enable the
introduction of new units. The iteration generally stops with new generators
earning a small increment above their cost of debt and equity. The addition of
one or more new unit(s) then pushes many of the previous additions into losses.
This process is repeated chronologically through the end of the analysis for
each year continuing to show a financial deficiency after the most recent new
unit addition. This approach reflects a game theoretic concept of market
equilibrium.
3.4.5 VOLATILITY ANALYSIS
The standard method for valuing specific electric generating units uses
discounted cash flows constructed from production-cost models. Simulating
regional electricity operations, production-cost models weigh the fundamental
drivers of market supply and demand, with detailed attention to supply. By
aiming at cost, production-cost models can potentially miss the true target,
price. Production-cost models may underestimate the volatility of electricity
prices. This is illustrated by a comparison of historical prices from the spot
market (Figure 3-3) with forecast prices from a production-cost model (Figure
3-4). Note that both the means and the variations of prices from the
production-cost model are lower than the actual market for the same time period.
FIGURE 3-3
PJM HOURLY ENERGY PRICES, SUMMER 1999
[GRAPH PLOT POINTS TO COME]
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FIGURE 3-4
PJM HOURLY ENERGY PRICES, PRODUCTION-COST MODEL, SUMMER 1999
[GRAPH PLOT POINTS TO COME]
Electric generating units can respond to volatility in electricity prices by
increasing output (and revenues) when market conditions are favorable and
decreasing output (and costs) when market conditions are unfavorable. The
consequence is that valuation methods based on production-cost modeling tend to
underestimate the value of cycling (i.e., midmerit) and peaking electric
generating units.
A SIMPLE ONE-HOUR EXAMPLE
To demonstrate why analyses based on conventional production-cost model
simulations may not capture the effects of price volatility, PHB Hagler Bailly
presents the following simplified example of a power system dispatched for a
single hour.
In a competitive electricity market, a number of key variables determine the
price of electricity, all of which involve varying degrees of uncertainty,
including:
- -- electricity demand
- -- fuel prices
- -- generating unit forced outages
- -- transmission forced outages
- -- water availability (in systems with hydropower)
- -- suboptimal dispatch decisions by the system operator
- -- bidding behavior (i.e., the generator submits a bid which departs from
marginal cost)
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- ------------------------------------------------------------------------------
However, analyses done with conventional production-cost models only represent
generator-forced outages as random variables. Among the other random variables,
hourly demand has one of the largest impacts on price uncertainty and
hour-to-hour volatility. Conventional production-cost models typically
represent hourly demand as a certain, known quantity, as illustrated in Figure
3-5a. A more realistic representation is that demand is a random variable drawn
from a continuous probability distribution. To make the calculations
transparent in this example, PHB Hagler Bailly will approximate the continuous
distribution of demand with the discrete distribution shown in Figure 3-5b.
PRODUCTION-COST MODEL SIMULATION RESULTS. Based on the representation of
expected demand, shown in Figure 3-5a, and the target generator's cost curves,
a conventional production-cost model will simulate the system hourly dispatch
as shown in Figure 3-6.
FIGURE 3-5
TWO DIFFERENT APPROACHES TO MODELING HOURLY DEMAND
[Bar Chart Figure 3-5a] [Bar Chart Figure 3-5b]
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FIGURE 3-6
DISPATCH RESULTS SIMULATED BY A CONVENTIONAL PRODUCTION-COST MODEL
Production cost model assumes demand is certain
[FLOW CHART]
----------------------------------------------
*Assumes target unit production cost = $20/MWh
In this example, the Hourly System Marginal Price is $20.50/MWh, at which price
the target generating unit runs at full output because its marginal cost at
that output is only $20.00/MWh. Thus, the unit is projected to earn an
operating profit of $100 in that hour. Because the inputs to the model are
expected values, the outputs, including the candidate unit's revenues, are
assumed to also be expected values. This is not necessarily true, as is
discussed below.
REAL WORLD RESULTS. Now, consider what actually happens in the real world when
demand uncertainty manifests itself. Recall that Figure 3-5b reflects the
distribution of probable demand. When this is combined with the target
generating unit's cost characteristics, yields the results shown in Table 3-1.
Because the operator has the flexibility to adjust the output of the plant to
avoid losses and capture margins, the expected value of the margin is greater
than the result captured in the production-cost model.
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TABLE 3-1
POSSIBLE TARGET GENERATING UNIT PROFIT LEVELS
System Target Generating Unit
Marginal -------------------------------------------
Demand Price Sales Average Cost Profit Margin Profit
Likelihood (MW) ($ per MWh) (MWh) ($ per MWh) ($ per MWh) ($)
- -------------------------------------------------------------------------------
10% 28,000 $19.50 0 $20.00 ($0.25) $0
- -------------------------------------------------------------------------------
20% 29,000 $20.00 200 $20.00 $0.00 $0
- -------------------------------------------------------------------------------
40% 30,000 $20.50 200 $20.00 $0.50 $100
- -------------------------------------------------------------------------------
20% 31,000 $21.00 200 $20.00 $1.00 $200
- -------------------------------------------------------------------------------
10% 32,000 $21.50 200 $20.00 $1.50 $300
- -------------------------------------------------------------------------------
Expected Value 30,000 $20.50 $110
- -------------------------------------------------------------------------------
Production-
Cost Result 30,000 $20.50 200 $20.00 $0.50 $100
- -------------------------------------------------------------------------------
Examining Table 3-1 provides insight into the volatility analysis. If load in
the area is 28,000 MW, the resulting market-clearing price is $19.50 per MWh.
The margin for the plant at that load level is negative (the costs are greater
than the revenue), so the plant operator would not operate the plant if that
were the result. At 29,000 MW of load, the price is $20.00 per MWh. At this
load level, the price is established by the bid submitted by this plant, and
the plant is dispatched to its full load. However, it makes no money -- its
revenues are exactly equal to its costs. But at higher load levels, the
generation unit makes money, and will be started and ramped to full load.
The conventional production-cost model assumes that the load is certain and,
hence, the resulting prices are certain. Since prices are, in reality,
uncertain, the production-cost model misses the flexibility the generation unit
may have to respond to prices as they are revealed. This flexibility provides
tangible value that is in excess of the value calculated by the production-cost
model. In this simple example, the value of the plant is 10% greater than that
estimated by the production-cost model.
Note that this increase in value depends on two conditions. First, the plant
must have the ability to respond to prices. The greater the flexibility, the
greater the potential value the plant can extract by adjusting its operating
strategy to take advantage of favorable prices while minimizing the losses from
unfavorable prices. Second, the plant must be subject to price volatility that
actually causes it to alter its operating strategy. A plant that is either so
low-cost or so high-cost that it never would adjust its operating strategy has
no option value, or may have a negative option value (as compared to the
fundamental model). It is only by adjusting its operating strategy that a plant
will accrue value from price volatility. Hence, a plant that sets the price
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(is "at the money") will have higher volatility value than a plant with similar
flexibility, but which has lower or higher operating costs.
A key feature of electricity markets, currently and in the future, is
volatility in prices. This volatility stems most directly from the fact that
electricity has to be produced in real time with few storage opportunities. In
fact, electricity is among the most volatile commodities traded in the world.
To ignore price volatility is to ignore one of the most important aspects of
the wholesale electricity markets.
ESTIMATING THE VOLATILITY COMPONENT
PHB Hagler Bailly has developed a proprietary market valuation process,
MVP(SM), to estimate the value of electric generation units based on the level
of prices and their volatility. As shown in Figure 3-7, MVP(SM) is a two-step
process. The first step is to characterize the volatility in prices, while the
second step examines how the generation unit responds to those prices and
derives value from operational decisions.
FIGURE 3-7
PHB HAGLER BAILLY'S MARKET VALUATION PROCESS (MVP(SM))
[FLOW CHART]
Characterize Examine How MVP
Electric and Fuel + Generator Responds = Value
Price Volatility to Price Outcomes
Simulate
Assumptions Market with DCF
and Market + Production = - Value
Characteristics Cost Model ---------
MVP Value
Incremental to
DCF Analysis
Note that MVP(SM) does not replace the use of a production-cost model. The
production-cost model provides insights into the fundamental drivers (such as
fuel prices, demand, entry, and exit) that a volatility analysis cannot
address. MVP(SM) integrates the two approaches to create a better estimate of
the value of a generating unit by accounting for both volatility effects and
changes in the fundamental drivers of electricity prices.
MVP(SM) uses a real option approach to value electric generating capacity, and
thereby captures the value of price volatility. An electric generating unit can
be viewed as a strip of European call
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- --------------------------------------------------------------------------------
options on the spread between electricity prices and the variable cost of
production (which is largely fuel). Unlike most option analyses, however, a
generation unit does not have perfect flexibility to adjust to the price-cost
spread. A generation unit may have costs that must be incurred to start up, as
well as constraints on its operation that may limit its ability to capture
margins when the spread is positive (price is greater than variable cost) or
avoid losses when the spread is negative (variable cost is greater than price).
Hence, the second step of MVP(SM) focuses on the ability of a generation unit to
capture margins, given its cost structure and constraints on operation.
The steps to the approach are as follows:
- -- The volatility in electric and fuel prices is first characterized. PHB
Hagler Bailly characterizes volatility by estimating a stochastic process
that describes not only the uncertainty in price, but also likely sequences
(evolution) of prices. Stochastic processes are estimated from historical
data on wholesale spot electricity and fuel markets. Observed volatilities
from forward-price data, or estimated volatilities from option price data,
are used when available
- -- Annual average price levels of the stochastic processes are indexed to fuel
price assumptions and production-cost price projections for energy and
capacity
- -- The natural gas and electricity price processes are simulated for the time
horizon of interest. The generating units of interest are dispatched against
these fuel and electricity price processes. The result is a calculation of
annual net revenues
Different generating units have different capabilities of responding to
electricity and fuel price volatility. Thus, the same price patterns for
electricity and fuel may yield different option values for different generating
units, depending on the operating costs and characteristics of the generating
units. Those generating units with the greatest flexibility to respond to
different market prices and that often set energy prices will have the highest
option values, while those plants that never set energy prices have little or
no ability to respond and will have virtually no option value.
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CHAPTER 4
ASSUMPTIONS
4.1 INTRODUCTION
This chapter describes the key assumptions used in the development of the
annual energy and capacity market price forecasts for the NPCC/MAAC markets.
Based on the assumptions below, PHB Hagler Bailly simulates the hourly
market-clearing price of energy using MULTISYM(1), a production-costing
framework that allows the characterization of multiple pricing areas within
larger transmission regions. Each major generating unit within a transmission
area is represented individually in the MULTISYM production-costing model using
unit-specific cost and operating characteristics. The MULTISYM model is used to
perform an hour-by-hour chronological simulation of the commitment and dispatch
of generation resources. As discussed in Chapter 3, the output of this model is
then used in PHB Hagler Bailly's Capacity Market Simulation Model to develop
the annual capacity contribution.
4.2 GENERAL ASSUMPTIONS
Below are the general assumptions utilized in this study:
- -- the hourly market clearing price of energy was developed using MULTISYM, a
production-cost model that allows the characterization of multiple
transmission areas
- -- the analysis has been prepared in real 1999 dollars
- -- a study period 2000 through 2020 was used
4.3 PRICING AREAS
Transmission areas for the NPCC and MAAC regions are defined as follows:
- -- NYPP-East
- -- NYPP-West
- -- NYPP-In-City
- -- NYPP-Long Island
- -- PJM-East
- ---------
(1) MULTISYM is a product developed by Henwood Energy Services, Inc. (HESI).
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- -------------------------------------------------------------------------------
- -- PJM-Central
- -- PJM-West
- -- NEPOOL-South East
- -- NEPOOL-Maine
- -- NEPOOL-West
- -- Ontario Hydro
- -- Hydro Quebec
- -- New Brunswick/Nova Scotia
4.4 FUEL PRICES
All fuel types were analyzed on either a regional (natural gas and oil) or
plant location (coal) basis in order to capture pricing variations among major
delivery points. The forecast prices for each fuel include the cost of
transportation to the power plant site. The fuel issues are further discussed
in a separate report, under separate cover. The nuclear fuel price is estimated
as $5.70 per MWh.(2)
4.4.1 NATURAL GAS
The primary inputs into the analysis were forecasts from the Energy Information
Administration (EIA), the Gas Research Institute (GRI), The WEFA Group (WEFA),
and Standard and Poor's (S&P)(3.) These widely used sources present a broad
perspective on the potential changes in commodity fuel markets. Each forecast
was equally weighted in an effort to arrive at an unbiased consensus projection
of fuel prices (see Table 4-1). This forecast is currently being updated as of
the date of this report. The updated forecast will likely result in higher
short-term gas prices than these set-forth herein. This updated forecast would
provide upside for the REMA facilities.
- ------------------
(2) Nuclear power plants are relatively inflexible in terms of ramping, thus
they are typically operated as "must-run" units. These units almost never
set the market price of electricity (i.e., they are rarely the marginal
unit) and, if they do set the market price, it is in those few hours where
there is surplus energy available at times of minimum load. In those hours
when there is surplus energy, prices are effectively depressed to zero to
allow the inflexible plants to stay on-line.
(3) The source forecast are as follows: 1999 Annual Energy Outlook, EIA; 1999
Baseline Projection; GRI; 1998 Natural Gas Outlook, WEFA; Standard &
Poor's World Energy Service U.S. Outlook, Fall-Winter 1998-1999.
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- -------------------------------------------------------------------------------
TABLE 4-1
HENRY HUB NATURAL GAS PROJECTION (REAL 1999 $/MMBtu)
2000 2005 2010 2015 2020
EIA 2.46 2.76 2.95 3.07 3.14
GRI 1.99 1.90 2.06 2.23 N/A
WEFA 2.20 2.21 2.33 2.46 2.59
S&P 2.11 2.28 2.46 2.61 2.81
Consensus 2.19 2.28 2.45 2.59 2.85
The Henry Hub forecast is used as a basis for projecting regional market center
prices. The Henry Hub forecast plus the basis differential to a particular
region equals the commodity component of each region's natural gas forecast.
The Henry Hub forecast was adjusted based on historical (1994-1998) spot price
differentials and projected changes in these differentials for some regions.
Projections of changes in basis differentials are based on increased
deliverability in some areas resulting from new pipeline construction.
Table 4-2 presents the NPCC/MAAC reference hub assignments used in the analysis.
TABLE 4-2
REFERENCE HUB ASSIGNMENTS FOR DIFFERENTIAL ANALYSIS
REGION REFERENCE HUB GRI REGION
PJM East NY Citygate Middle Atlantic
PJM West Pittsburgh Citygate Middle Atlantic
PJM Central Average of PJM East and PJM West Middle Atlantic
New York-East(1) NY Citygate Middle Atlantic
New York-West Average of Waddington and Buffalo, NY Middle Atlantic
NEPOOL(2) Boston Citygate New England
Canada Niagara Spot New England
(1) Includes In-City and Long Island transmission areas.
(2) Comprised on Maine, Southeast, and West transmission areas.
The transportation cost associated with each forecast is equal to the regional
average distribution costs paid by electricity generators. These costs,
provided by GRI, are expected to decline slightly, in real terms, over the
forecast horizon.
Some merchants baseload combined cycle plants will be located on the
interstate pipeline system and will not be subject to Local Distribution
Company (LDC) charges. In a deregulated industry,
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- --------------------------------------------------------------------------------
most new capacity will be sited so as to minimize costs. As a result, it is
likely that gas-fired generation will seek to avoid these charges in order to
increase price competitiveness in the market. Therefore, it is assumed that new
plants will be sited to take advantage of direct connections to interstate
pipeline systems.
Some baseload gas-fired plants, however, may incur fixed costs in the range of
$8-$10/kW-year to ensure firm natural gas supplies. The EIA projects that as
industry restructuring increasingly puts pressure on generators to reduce costs,
generating stations will rely on interruptible deliveries and will ensure fuel
supplies by using oil as a backup fuel.(4) The total delivered price for natural
gas in each of the market regions is presented in Table 4-3.
TABLE 4-3
NPCC/MAAC DELIVERED NATURAL GAS PRICE (1999 $/MMBtu)(1)
AVERAGE ANNUAL
PRICING AREA 2000 2005 2010 2015 2020 GROWTH RATE
- ---------------------------------------------------------------------------------------------------
PJM East 2.81 2.87 2.99 3.06 3.31 0.82%
PJM West 2.72 2.79 2.91 3.00 3.25 0.89%
PJM Central 2.77 2.83 2.95 3.03 3.28 0.85%
New York-East(2) 2.81 2.87 2.99 3.06 3.31 0.82%
New York-West 2.65 2.73 2.86 2.95 3.20 0.94%
NEPOOL(3) 2.90 2.98 3.07 3.03 3.28 0.62%
Canada 2.51 2.63 2.77 2.82 3.07 1.02%
(1) New units will not incur the LDC charges. Based on the prices set forth in
Table 4-1.
(2) Includes In-City and Long Island transmission areas.
(3) Comprised of Maine, Southeast, and West transmission areas.
4.4.2 FUEL OIL
The fuel oil forecast methodology is described below for No. 2 Fuel Oil and No.
6 Fuel Oil. Prices are developed based on a consensus of crude oil by major
forecasters as presented in Table 4-4.(5) These widely used sources present a
broad perspective on the potential changes in commodity fuel markets. Each
forecast was equally weighted in an effort to arrive at an unbiased consensus
projection of fuel prices.
- -----------------------
(4) EIA, Challenges of Electric Power Industry Restructuring for Fuel
Suppliers, September 1998, p. 65.
(5) The source forecasts are as follows: EIA 1999 Annual Energy Outlook;
Standard & Poor's World Energy Service U.S. Outlook, Fall-Winter 1998-1999;
1999 Baseline Projection, GRI; 1998 Natural Gas Outlook, WEFA.
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- --------------------------------------------------------------------------------
TABLE 4-4
CRUDE OIL PRICE PROJECTION (REAL 1999 $/BBL)
- --------------------------------------------------------------------------------
AVERAGE
ANNUAL
2000 2005 2010 2015 2020 GROWTH RATE
- --------------------------------------------------------------------------------
EIA 14.37 19.81 21.92 22.54 23.38 2.46%
GRI 17.90 17.90 17.90 17.90 NA 0.00%
WEFA 18.80 19.59 20.32 21.11 20.14 0.34%
S&P 14.02 16.92 19.32 20.99 23.50 2.62%
CONSENSUS 16.27 18.55 19.87 20.64 22.34 1.60%
- --------------------------------------------------------------------------------
NO. 2 FUEL OIL
Prices for No. 2 Fuel Oil were derived from EIA data on historical
delivered-to-utility prices for the period 1995 through 1998, on a regional
basis. Each region in the analysis was assigned to a reference terminal. Table
4-5 details the terminal assignment for each of the regions in this analysis.
TABLE 4-5
REFERENCE TERMINAL ASSIGNMENTS FOR
NO. 2 FUEL OIL ANALYSIS
------------------------------------------------
REGION REFERENCE TERMINAL
------------------------------------------------
PJM East Baltimore
PJM West Pittsburgh
PJM Central Average of PJM East and PJM West
New York-East(1) New York
New York-West New York
NEPOOL(2) New York
Canada New York
------------------------------------------------
(1) Includes In-City and Long Island transmission
areas.
(2) Comprised of Maine, Southeast, and West
transmission areas.
This methodology captures both the commodity and transportation components of
delivered costs. Differentials between the delivered cost of No. 2 Fuel Oil and
historical crude oil costs for each month during the historical period were
developed. Projections were developed using the
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- -------------------------------------------------------------------------------
consensus crude oil price forecast and the average differential for each North
American Electric Reliability Council (NERC) region or part of a region showing
different patterns of historical price relationships. The final delivered price
for No. 2 fuel oil in each of the market regions is listed in Table 4-6.
TABLE 4-6
NPCC/MAAC DELIVERED NO. 2 FUEL OIL PRICE (REAL 1999 $/MMBtu)
- --------------------------------------------------------------------------------------
AVERAGE ANNUAL
PRICING AREA 2000 2005 2010 2015 2020 GROWTH RATE
- --------------------------------------------------------------------------------------
PJM East 3.87 4.28 4.57 4.74 4.98 1.27%
PJM West 3.84 4.25 4.54 4.72 4.95 1.30%
PJM Central 3.82 4.24 4.53 4.70 4.93 1.28%
New York-East(1) 4.52 4.96 5.26 5.43 5.68 1.15%
New York-West 4.52 4.96 5.26 5.43 5.68 1.15%
NEPOOL(2) 3.88 4.31 4.61 4.79 5.03 1.31%
Canada 3.88 4.31 4.61 4.79 5.03 1.31%
(1) Includes In-City and Long Island transmission areas.
(2) Comprised of Maine, Southeast, and West transmission areas.
NO. 6 FUEL OIL
Prices for No. 6 Fuel Oil were derived using a similar methodology that was
employed for No. 2 Fuel Oil prices. Because residual oil is so thinly traded,
it is difficult to identify significant regional price premiums. As a result,
commodity prices for all regions were based on 1% sulfur residual oil at New
York Harbor.
The transportation costs for each region are based on an analysis of historic
New York Harbor prices and delivered residual oil at electric generating
stations. Average historical differentials for the period 1995 through 1998
were used with consensus crude oil projections to develop delivered No. 6 Fuel
Oil price projections. The final delivered price for No. 6 Fuel Oil in each of
the market regions is listed in Table 4-7.
Over time, the demand for No. 6 Fuel Oil is projected to decrease, putting
downward pressure on the price of No. 6 Fuel Oil, as compared to the price of
crude oil. The price differential between crude oil and No. 6 Fuel Oil is,
therefore, projected to decline during the forecast period. The ratio between
the price of No. 6 Fuel Oil and the price of crude oil is projected to decline
at a rate of 0.4% per year.
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TABLE 4-7
NPCC/MAAC DELIVERED NO. 6 FUEL OIL PRICE (real 1999 $/MMBtu)
Average Annual
Pricing Area 2000 2005 2010 2015 2020 Growth Rate
- --------------------------------------------------------------------------------
PJM East 2.52 2.73 2.86 2.91 2.99 0.86%
PJM West 2.43 2.64 2.77 2.82 2.90 0.89%
PJM Central 2.41 2.62 2.75 2.80 2.88 0.89%
New York-East(1) 2.97 3.18 3.31 3.36 3.44 1.10%
New York-West 2.97 3.18 3.31 3.36 3.44 1.10%
NEPOOL(2) 2.45 2.66 2.79 2.84 2.92 0.88%
Canada 2.38 2.59 2.72 2.77 2.85 0.91%
- --------------------------------------------------------------------------------
(1) Includes In-City and Long Island transmission areas.
(2) Comprised of Maine, Southeast, and West transmission areas.
4.4.3 COAL
Forecasts for marginal delivered coal prices, Nox and SO(2) allowance prices
were prepared by PHB Hagler Bailly. PHB Hagler Bailly developed a base case
forecast of annual average marginal delivered coal prices for the period 2000
through 2020 on a unit-by-unit basis for electric generators in each region.
In cost-based electric dispatch modeling, the marginal variable cost of
production is expected to determine dispatch order and the wholesale market
price of electricity. For this reason, PHB Hagler Bailly has provided marginal
delivered coal costs. These costs reflect PHB Hagler Bailly's projection of a
particular unit's marginal coal selection and market pricing for that coal, as
well as the cost of transportation for such marginal purchases. If a particular
unit purchases some higher-cost coal under long-term contracts, the unit's
average cost of coal acquisition will be different from its marginal coal
acquisition cost. It is expected that the cost of higher-priced, contract coal
will not be reflected in dispatch pricing or in market prices for electricity.
Delivered coal prices were projected in two components: (1) coal costs at the
mine (on a FOB(6) basis) and (2) transportation costs. Because individual units
within a plant sometimes burn different coals, coal selection and delivered
pricing were developed on a unit-by-unit basis.
Coal selection for individual units reflects differing requirements for
compliance with emissions regulations over time, as well as economics. The use
of scrubbers, requirements to comply with ______________________________
(6) "Free on Board," indicating that the price includes the costs of loading
coal onto a train, truck, or barge.
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- --------------------------------------------------------------------------------
Phase I and/or Phase II of the Clean Air Act Amendments of 1990 (CAAA), and
requirements for compliance with New Source Performance Standards (NSPS) and
State Implementation Plan (SIP) limits were considered, along with the variable
costs of different methods of CAAA compliance. While a unit's historical coal
selection was an important factor in the projections, substitutions of coal
types were projected for several units over time as delivered price economics
(including allowance prices) are expected to change.
FOB mine costs were projected with consideration of productivity increases and
supply and demand economics for different coal types in an integrated market
analysis. The coal price forecast is conservative in that only approximately
one-half of total historical factor productivity improvements are reflected in
projected price decreases. Projected productivity gains and competition in
supply drove projections of real price decreases for some coals. For other
coals, supply limitations were projected to offset productivity gains and to
keep prices flat or minimize price decreases over time. Various quality coals
are expected to be related to other coals in the same supply region based on
energy content and sulfur content (through projected allowance prices).
Projected transportation costs are based on available delivery options at each
plant for the coal types selected for each unit. Transportation modes included
rail, barge, truck, and mine-mouth plant transportation. The cost of rail
transportation in different regions of the country was projected to change
differently over time, and the costs of different transportation modes were
projected separately. Particular units' projected total transportation costs
were calculated as the sum of these separately escalated components.
In addition, potential future changes in transportation options were considered.
In some cases, for example, PHB Hagler Bailly projected the addition of rail or
vessel receiving capability. Potential future rail regulatory relief was also
projected for some plants without access to competitive transportation options.
Regional specific coal discussion are provided in greater detail in Appendix A.
4.5 DEMAND AND ENERGY FORECASTS
Annual demand and energy forecast values are based on the following sources:
- - NPCC - April 1, 1999 NPCC Load, Capacity, Energy, Fuels, and Transmission
Report
- - New York Power Pool - Report of the Member Electric Systems of the New
York Power Pool Load and Capacity Data, 1999
- - PJM/MAAC - 1999 MAAC Regional Reliability Council, EIA-411
- MAAC Annual Electric Control and Planning Area Report, 1999
- ------------------------------ PHB Hagler Bailly ------------------------------
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- -------------------------------------------------------------------------------
A synthetic hourly load shape based on five years of actual hourly data (1992
through 1996) was developed by HESI to represent the native load requirements
for each of the pricing areas. The annual demand and energy forecast values
were applied to the native hourly load requirements to develop the forecasted
hourly loads for each year of the analysis.
For New York and PJM, peak load and energy forecasts were taken from the
sources cited above for each member utility. These forecasts were extended to
2020 based on a five-year compound average growth rate from 2003 to 2008.
For New England, the peak load and energy forecasts from the sources cited above
were used to produce forecasts for the utilities in the three New England
transmission areas. The proportion of total New England load was determined for
each utility using utility-specific weather normalized 1997 load data from the
synthetic load shapes supplied by HESI, with a coincidence factor calculated to
allow for variation in the timings of the utility peak loads. Utility specific
forecasts were then produced by applying these proportions of the EIA-411
forecast for New England out to 2008. Beyond 2008, a five-year compound average
growth rate was used to grow each of the utilities' peak loads and energies
based on the last six years of EIA-411 data.
The annual coincident peak demand and energy growth rates for NPCC/MAAC and the
regional pricing areas for select years from 2000 and 2020 are displayed in
Table 4-8.
TABLE 4-8
REGIONAL PEAK DEMAND AND ENERGY GROWTH
AVERAGE
ANNUAL
GROWTH
REGION CATEGORY 2000 2005 2010 2015 2020 RATE
PJM Peak Demand (MW) 49,503 53,618 57,997 62,831 68,130 1.61%
Energy (GWh) 258,859 280,506 303,392 328,324 355,305 1.60%
- --------------------------------------------------------------------------------------------
New York Peak Demand 28,185 29,710 30,962 32,298 33,706 0.90%
Energy 155,960 165,260 173,248 181,990 191,174 1.02%
- --------------------------------------------------------------------------------------------
New England Peak Demand (MW) 22,855 25,180 27,720 30,513 33,585 1.94%
Energy (GWh) 120,570 134,996 150,038 166,624 185,045 2.16%
- --------------------------------------------------------------------------------------------
4.6 ELECTRICITY IMPORTS
Imports and exports between transmission areas are determined by the model
using inputs for transfer capabilities, wheeling rates, and line losses. The
wheeling rates between pricing areas in NPCC/MAAC are assumed to be $3/MWh.
Wheeling rates within the territories of the PJM-ISO,
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- --------------------------------------------------------------------------------
the NY-ISO, and the NE-ISO are set to $0/MWh. Line losses between all pricing
areas are assumed to be 2%. The inputs for transfer capability are shown in
Appendix B.
4.7 EXISTING GENERATION UNITS
4.7.1 FOSSIL UNITS
The characteristics for the REMA facilities were provided by Stone & Webster
Management Consultants, Inc. (S&W). Each of the remaining existing fossil
generating units in the model is characterized using the following parameters:
- -- summer and winter net capability
- -- average heat-rate curve
- -- operating characteristics
- minimum capacity
- ramp rate
- minimum uptime
- minimum downtime
- -- forced outage rate
- -- scheduled maintenance rate
- -- variable operation maintenance (VO&M) cost
- -- emission costs
- -- start fuel
SUMMER AND WINTER CAPABILITIES
Summer and winter capability values were obtained from the following sources.
- -- PJM/MAAC -- 1999 MAAC Regional Reliability Council, EIA-411 Report
- -- NPCC -- April 1, 1999 NPCC Load, Capacity, Energy, Fuels, and Transmission
Report
- -- New York Power Pool -- Report of the Member Electric Systems of the New York
Power Pool, Load and Capacity Data, 1999
HEAT-RATE CURVES FOR FOSSIL UNITS
Full load heat-rate values are based on those reported in the EIA Form EIA-860.
This form contains data, including full-load heat-rates, for existing electric
generating plants and for new plants scheduled for initial commercial operation
within ten years of the filing of the report. Full
- --------------------------------PHB Hagler Bailly-------------------------------
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- --------------------------------------------------------------------------------
load heat-rate values were established according to the 1995 Form EIA-860.(7)
This is the most recent year the report was published. PHB Hagler Bailly then
made adjustments to the heat-rate curves reported in Form EIA-860 based on
generic assumptions by unit type.
OPERATING CHARACTERISTICS
Generating unit operating characteristics (i.e., minimum capacity, ramp rate,
minimum uptime, and minimum downtime) were estimated by PHB Hagler Bailly based
on typical characteristics by unit type.
SCHEDULED AND FORCED OUTAGE RATES
The scheduled maintenance outage rates and equivalent forced outage rates for
all fossil units were estimated by PHB Hagler Bailly based on historical data
for comparable units contained in the GADS database.(8)
VARIABLE OPERATION AND MAINTENANCE COSTS
Each generating unit's variable operation and maintenance cost is represented
by PHB Hagler Bailly's default values. The values used are as follows: $4/MWh
for scrubbed steam-coal units, $3/MWh for other steam-coal units, $2/MWh for
steam-gas and oil units, $2/MWh for combined cycle units, and $5MWh for peaking
units (includes combustion turbine units, internal combustion units, and jet
engines).
SULFUR DIOXIDE EMISSION COSTS
Title IV of the Clean Air Act awarded tradable sulfur dioxide (SO(2)) emission
allowances to certain "grandfathered" plants in existence. Each allowance gives
the plant owner the right to emit one ton of SO(2) for one year. Congress'
intent was to reduce the total number of tons of SO(2) emissions by awarding
emission allowances for less SO(2) than a plant had emitted in previous years.
These allowances were awarded in two phases: one beginning in 1995, the other in
2000.
In this study, PHB Hagler Bailly assumes that the SO(2) emission costs a
generating unit incurs in any future year are determined by the number of tons
of SO(2) it emits, after installation of cost-effective control technologies,
multiplied by the price of allowances in that year. This resulting cost was
added to the variable cost of each generating unit and included in the
development of the energy price forecast. Any capital expenditures incurred for
abatement
- ------------------------------
(7) EIA Form EIA-860, 1995.
(8) North American Electricity Reliability Counsel, Generating Availability
Data System (GADS), Equipment Availability Report (1994-1998).
- ------------------------------ PHB Hagler Bailly -------------------------------
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- -------------------------------------------------------------------------------
equipment were included in the generating unit's fixed costs and were included
in the capacity market simulation.
PHB Hagler Bailly developed a price forecast for SO(2) allowances, as shown in
Table 4-9. Starting with a 1999 value of $200 per ton, PHB Hagler Bailly
projects the price of SO(2) emission allowances to increase at a real rate of
6.65% per year between 2000 and 2010, reflecting a market discount consistent
with the expected rate of return required to justify holding "banked" SO(2)
allowances. By 2010 the real cost of allowances is projected to plateau at $406
per ton (in 1999 dollars), a level determined by the equivalent cost of
releasing allowances by installing flue gas desulfurization equipment at
existing plants.(9)
TABLE 4-9
SO(2) Cost Curves (real 1999 $/ton)
YEAR SO(2)
----------- ----
1999 $200
2000 $213
2001 $227
2002 $243
2003 $259
2004 $276
2005 $294
2006 $314
2007 $335
2008 $357
2009 $381
2010 $406
2011 $406
2012 - 2018 $406
DEVELOPMENT OF NOx CONTROL COSTS AND EMISSION RATES
The development of NOx control costs and the creation of a NOx forward-price
forecast for this report was conducted by Stratus Consulting. This NOx
forward-price forecast is the determination of emission control costs to derive
baseline boiler emission rates for NOx emissions accounted for both market
effects and the costs to control emissions. The market component was integrated
into this analysis by first calculating an expected value of NOx allowances
from the NOx forward curve. This value was $4,000/ton. The next step was to
apply Stratus' NOx control cost database(10)
- -----------
(9) This assumes a continuation of current regulations under the 1990 Clean
Air Act Amendments. Proposals are under consideration by the Environmental
Protection Agency (EPA) (e.g., controls on fine particulates) that could change
these regulations.
(10) The costs of NOx controls are calculated using algorithms adapted from the
EPA's Integrated Air Pollution Control System (IAPCS), data from other EPA
publications, reports published by the Electric Power Research Institute (EPRI),
conference proceedings, and published magazine articles. The NOx control
technologies considered are Low Excess Air (LEA), Overfire Air (OFA), Low-NOx
Burners (LNB), Low-NOx Burners with Overfire Air/Tangential (LNB/OFA-T),
Selective Non-catalytic Reduction (SNCR), and Selective Catalytic Reduction
(SCR). Most of the combustion modification technologies (OFA, LNB, LNB/OFA-T)
can be combined with the post-combustion technologies (SNCR, SCR) to provide
greater NOx reductions at lower overall cost. In addition, OFA and LNB (LNB+OFA)
can be combined. Capital and O&M costs for each control technology are
calculated separately and are added together for the combined technologies.
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- -------------------------------------------------------------------------------
to determine the extent to which NOx controls are installed and the emissions
rate. This part of the analysis followed a two-step process:
1. calculate the capital costs and incremental variable costs which have an
impact of less than $4,000/ton
2. determine the boiler emission rate associated with the level of technology
selected in step 1
Application of this logic assumes that plants will purchase allowances when
their marginal cost (not their average cost) of abatement exceeds the expected
price of emission allowances. PHB Hagler Bailly assumed that NOx emission costs
were equal to the tons of NOx emitted after installation of applicable control
technologies, multiplied by the price of allowances represented by the NOx
forward-price forecast. This resulting cost was added to the variable cost of
each generating unit and included in the development of the energy price
forecast. Any capital expenditures incurred were included in the generating
unit's fixed costs and in the capacity market simulation.
The price forecast for NOx allowances has been developed through a simulation
of NOx market dynamics using existing market data applied to the Regional
Economic Model for Air Quality (REMAQ). The regulatory backdrop to development
of the NOx forward forecast is air quality regulations on tropospheric ozone.
In 1973, EPA promulgated a one-hour standard of 0.125 ppm. Since the one-hour
standard has been instituted, most of the eastern seaboard from Washington, DC,
to Boston has been in non-attainment. In 1997, EPA instituted a new eight-hour
standard of 0.85 ppm. This is significantly more stringent than the 1973
one-hour standard and encompasses non-attainment over a broader landmass --
approximately 75% of the area east of the Mississippi River. The implications
of the new standard on NOx emissions from power plants are significant.
NOx emissions have been recognized as the primary contributor to ozone
formation. This represents a significant change from the previous twenty-five
years of regulatory policy, which focused on the reductions of volatile organic
compounds (VOCs) produced primarily by vehicles and industrial processes. Thus,
attainment of the ozone standard will primarily be met by reductions in NOx
emissions and the utility sector will be a major source of these reductions.
Because of the persistence of the ozone non-attainment problem and the
recognition of NOx emissions as the primary precursor pollutant, the EPA has
recently proposed the State Implementation Plan (SIP) Call. The SIP Call seeks
a 70% reduction in NOx emissions from large NOx point sources (i.e., power
plants and industrial boilers) over twenty-two states starting in 2003. Despite
these large proposed reductions in NOx emissions, modeling of ozone
concentrations suggests that approximately 30% of the area east of the
Mississippi River will be in non-attainment of the eight-hour ozone standard.
In order to avoid strict federal penalties for ozone non-attainment, states
will need to obtain further reductions in NOx emissions. This will result in a
continuous reduction in the number of allowances that are available, which will
maintain price pressure on the cost of NOx allowances beyond 2018.
- ------------------------------ PHB Hagler Bailly ------------------------------
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ASSUMPTIONS -- 4-14
- -------------------------------------------------------------------------------
The forecast for NOx emissions begins at the 1999 market price for summer(11)
NOx allowances, which was approximately $3,400/ton (see Table 4-10). The price
remains constant through 2002. From 2003 to 2018, Stratus forecast the price of
NOx allowances by applying its proprietary general equilibrium model of the NOx
market, REMAQ. This model has most recently been applied by the EPA to evaluate
the costs of the SIP Call. In addition, the model has been applied for numerous
analyses by states, industry groups, and utilities and has been used to develop
many peer-reviewed publications. Application of REMAQ provides a price of
$4,700/ton for the first summer of SIP Call regulations (2003). The price of
NOx allowances drops to $4,475/ton in 2004 and remains below this level
through 2018. The SO(2) and NOx price curves for the study period 2000-2018 are
illustrated in Figure 4-1.
TABLE 4-10
NOx COST CURVES (REAL 1999 $/TON)
YEAR NO(x)
---- ------
1999 $3,400
2000 $3,400
2001 $3,400
2002 $3,400
2003 $4,700
2004 $4,475
2005 $4,300
2006 $4,160
2007 $4,200
2008 $4,200
2009 $4,200
2010 $4,200
2011 $4,200
2012-2018 $4,280
- ----------
(11) The summer NO(x) market is defined as May 1 through September 30.
- -------------------------------PHB Hagler Bailly-----------------------------
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- --------------------------------------------------------------------------------
FIGURE 4-1
SO(2) AND NO(X) COST CURVES
[PERFORMANCE GRAPH]
4.7.2 HYDROELECTRIC UNITS
The hydroelectric plants are consolidated by utility and categorized as peaking
or baseload. Similar to the thermal units, the maximum capacity for each unit
was taken from the sources cited above for summer and winter capabilities.
Monthly energy patterns were developed from the 1993-1998 EIA Forms 759, which
contain monthly generation and (for pumped storage units) net in flows.
4.7.3 NUCLEAR UNITS
PHB Hagler Bailly evaluated the operation of nuclear plants in the regions
covered by this study on the basis of operating experience and going-forward
costs to determine which plants would remain in service.
To conduct the operating experience assessment, PHB Hagler Bailly utilized two
proprietary PHB Hagler Bailly databases of nuclear power information: the
Nuclear Power Experience (NPE), and the Operating Plant Evaluation Code (OPEC).
NPE is a database of all safety-related events that have occurred in the United
States. OPEC is a database that tracks the performance of
- -------------------------------PHB Hagler Bailly--------------------------------
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ASSUMPTIONS -- 4-16
- --------------------------------------------------------------------------------
all United States nuclear units (400 MW or larger), containing approximately
130,000 event records that document over 1,500 unit-years of experience. The
operating experience assessment was used to then evaluate the probable shutdown
dates of the nuclear units in question.
To evaluate shutdown dates, several major issues were considered. The most
important issue was plant competitiveness. Many nuclear stations are viewed as
expensive because of the high capital costs for original construction, however,
these costs are treated as sunk costs and are not considered in determination
of the competitiveness of a station. Sunk capital costs for original
construction will not determine a unit's competitive position in the future.
The competitiveness of each unit can be evaluated with two essential variables,
level of production and costs. Because nuclear units are typically base loaded
and reserve shutdown hours are very low, PHB Hagler Bailly uses capacity factor
to measure production. Going-forward costs include three components: operations
and maintenance (O&M), capital addition costs, and fuel costs. The capital
addition costs do not include the original investment in the plant and only
include modifications made to the plant each year. These costs are very
difficult to track due to the reporting methods. In recent years, the number of
modifications to nuclear power stations has decreased and these costs are
relatively low compared to O&M costs. Thus, PHB Hagler Bailly did not consider
capital costs in this analysis. Fuel costs are also relatively low and have
been predictable and stable over the past decade. Given the greater importance
of many of the other major variables, PHB Hagler Bailly did not consider fuel
costs as an important factor and did not evaluate them in the analysis.
In addition to the competitiveness of the station, there are a number of other
issues that might affect a shutdown date. Politics of the region plays an
important part in the premature shutdown of units. Equipment failures and poor
overall performance can also cause a utility to shut down a unit before its
license expires. As the units age, the amount of investment required to
continue operating the unit becomes an important factor. Issues such as
locations that assist in voltage regulation, restrictions due to transmission,
and restrictions due to environmental regulation must also be considered. PHB
Hagler Bailly specifically addressed each of the following for each of the
units analyzed:
- -- SIZE OF UNIT. Larger units provide more benefit to the utility when the unit
is operating and represent a larger investment loss by the utility if the
unit is shut down.
- -- AGE OF UNIT. Nuclear power plants are licensed for forty years. PHB Hagler
Bailly has conducted studies showing that generating power stations begin to
require life extension costs between thirty and forty years. Thus, the older
a station gets, the more it is expected to spend and the less competitive it
becomes.
- -- NUMBER OF UNITS OPERATED BY UTILITY. If a utility has more than one unit, it
has more corporate overhead costs associated with the nuclear power
generation allocated to more than one station. In addition, the utility is
more likely to be committed to operating its nuclear power generation.
- ------------------------------ PHB Hagler Bailly ------------------------------
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- --------------------------------------------------------------------------------
- -- PERFORMANCE. Typically the poorer performing units (units that are shut down
for extended periods of time or have many forced outages) are viewed as
noncompetitive. Even if the unit is able to overcome the existing difficulty
causing the shutdown, the perception that the unit is uneconomic is difficult
to overcome.
Historical performance as well as recent trends in forced outage rates at each
unit were reviewed. Future forced outage rates were forecast for each year, and
each unit's scheduled outages during the year were also considered. From this
information, and noting that outages are becoming shorter as the industry
improves outage planning, the duration of outages for each unit was forecast.
For refueling outages, sources included refueling outage schedules, published
every six months in Nuclear News for all UNITED STATES. units.
In addition to the operating experience assessment, PHB Hagler Bailly estimated
the annual going-forward costs (fixed O&M, property taxes, and annualized
incremental capital costs) associated with each unit. For this assessment,
Table 4-11 summarizes the nuclear units projected to retire before their
forty-year operating lives are completed:
TABLE 4-11
NPCC/MAAC NUCLEAR UNIT RETIREMENTS
UNIT CAPACITY RETIREMENT DATE
- -----------------------------------------------------------
NEPOOL
Millstone 2 871 12/31/06
Millstone 3 1,140 12/31/17
Pilgrim 1 670 12/31/07
Vermont Yankee 1 500 12/31/07
NYPP
Indian Point 2 931 12/31/04
Indian Point 3 970 12/31/04
GINNA 485 12/31/04
Nine Mile 1 619 12/31/06
J A Fitzpatrick 820 12/31/07
PJM
Oyster Creek 619 12/31/06
Three Mile 786 12/31/10
- ------------------------------ PHB Hagler Bailly ------------------------------
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4.8 CAPACITY MARKET SIMULATION MODEL INPUT ASSUMPTIONS
4.8.1 EXISTING UNITS GOING-FORWARD COSTS
PHB Hagler Bailly developed projections of Fixed Operation & Maintenance (FO&M)
costs for steam generating units. FO&M costs are intended to include all
forward (non-sunk) costs of operating and maintaining plants, except those
variable costs, such as fuel costs, which are included in the dispatch cost.
Total O&M expenses, excluding fuel expenses, rents, and allowances were
obtained from the OPRI(12) Database of FERC Form 1 data. Internal estimates of
Variable Operation & Maintenance (VO&M) costs (see Section 4.7.1) were used in
conjunction with the data to net the variable portion out of total O&M
expenses, generating a value for FO&M for each plant.
Estimates of pension and benefit expenses, based on the number of full-time
employees at each station, were also obtained from FERC Form 1 data and added
to the FO&M estimate for each plant.
FO&M estimates were developed for broad prime mover, fuel type, and size
categories. For example, coal steam plants were grouped together, as were all
oil and gas-fired steam plants. Plants in each of these groups were further
grouped by size categories. Plants in each resulting grouping were then ranked
according to FO&M value.
To account for an expected reduction in FO&M costs over time in a deregulated
environment, the cost for the plant at the 25th percentile in each grouping
(lower percentiles indicating lower costs) was taken as an appropriate value
for the 50th percentile of plants in the same grouping for 2005. Estimates of
annual incremental capital expenditures were based on a ten-year national
average of capital additions to utility steam generating plants. These
estimates were added to the FO&M cost figures to develop a total annual
going-forward cost. After 2005, FO&M costs were assumed to decrease at a
constant real rate of 3% per year, equivalent to the average rate of worker
productivity improvement in the UNITED STATES industrial sector over the past
several decades.
Property tax data for each unit was derived by applying an estimated mill levy
rate to an assumed market value.
4.8.2 CAPACITY ADDITIONS THROUGH 2002
A critical step in simulating the regional capacity market is to ascertain the
number and timing of capacity additions for the near term (2000 to 2002). To
this end, PHB Hagler Bailly worked toward the following goals: determining the
number and status of greenfield power plants that are currently under
development in the regions, determining the average length of time required
- ----------
(12) OPRI is a division of Resource Data International, Inc.
- ------------------------------ PHB Hagler Bailly -------------------------------
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- -------------------------------------------------------------------------------
to construct and operate a new power plant in the regions, and determining the
costs associated with constructing and operating a power plant in the regions.
In order to collect and analyze sufficient data to meet these goals, PHB Hagler
Bailly completed a number of separate tasks. PHB Hagler Bailly performed a
literature search in an effort to identify articles referring to planned power
plant development in the regions. Also, PHB Hagler Bailly's experts analyzed PHB
Hagler Bailly's IPP Database to determine the number of plants currently under
development and/or construction in the regions and also the average length of
time required to bring a plant on-line following the announcement of a new
project.
As a result of PHB Hagler Bailly's analysis and investigation, a baseline
on-line scenario was developed which reflects PHB Hagler Bailly's estimate of
the plants that realistically will be constructed in the target region through
the year 2002. These are summarized in Table 4-12.
TABLE 4-12
NPCC/MAAC BASE CASE CAPACITY ADDITIONS
- --------------------------------------------------------------------------------
CAPACITY UNIT FUEL
DEVELOPER (MW) TYPE TYPE BASE CASE
- --------------------------------------------------------------------------------
NEPOOL
Berkshire Power (Agawam) 270 CC NG 4/1/2000
Polsky (Androscoggin) 150 CT NG 1/1/2000
EMI/Calpine (Tiverton) 265 CC NG 4/1/2000
EMI/Calpine (Rumford) 265 CC NG 1/1/2000
Duke Energy (Maine Independence) 520 CC NG 4/1/2000
PG&E Generating (Millennium) 360 CC NG 6/1/2000
Power Dev. Corp/El Paso Energy (Milford) 544 CC NG 1/1/2001
Calpine (Westbrook) 540 CC NG 4/1/2001
PG&E Generating (Lake Road) 792 CC NG 4/1/2001
American National Power (Blackstone) 550 CC NG 6/1/2001
PJM
AES (Red Oak) 816 CC NG 6/1/2002
Columbia (Liberty) 520 CC NG 1/1/2002
Southern Union (Archbald expansion) 47 CC NG 12/1/2000
Williams (Hazelton expansion) 190 CC NG 6/1/2001
PG&E (Mantua Creek) 800 CC NG 6/1/2002
AES (Warrior Run) 180 Coal Coal 3/1/2000
AES (Ironwood) 705 CC NG 6/1/2001
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4.8.3 CAPACITY ADDITIONS POST 2002
The validity of capacity additions post 2002 is assessed based on a discounted
cash flow (DCF) approach that provides a "Go" or a "No Go" decision for each
increment of generic new capacity.
The DCF framework captures the net present value of the various cash flow
streams: revenues, including compensation for capacity and energy; and
expenses, including fixed and variable O&M, fuel, property taxes, and principal
and interest expenses for the new capacity additions. The analysis merges
assumptions concerning the general economy, capital markets, tax structures,
fixed costs, and depreciation with the operating projections for the potential
new capacity in order to capture the gross cash flow from the unit's projected
operation.
GENERIC PLANT CHARACTERISTICS
The starting point for the DCF calculation is the generic unit-specific
operating parameters for new combined cycle and combustion turbine units. The
generic parameters and assumptions assumed in the model are displayed in Table
4-13. Capital costs are assumed to decrease at 1% per annum (real 1999 $).
Table 4-14 indicates the assumed schedule and effect of technology improvement
on new unit heat-rates.
- --------------------------------------------------------------------------------
TABLE 4-13
NEW CC AND CT GENERATING CHARACTERISTICS (REAL 1999 $)
- --------------------------------------------------------------------------------
NEW YORK
(IN CITY AND LONG ISLAND) NEPOOL, NY, AND MAAC
- --------------------------------------------------------------------------------
COMBUSTION COMBINED COMBUSTION COMBINED
TURBINE CYCLE TURBINE CYCLE
- --------------------------------------------------------------------------------
Capital Cost ($/kW)...... $ 390 $ 700 $ 345 $ 575
Fixed O&M ($/kW-year).... $7.15 $13.65 $6.00 $11.50
Variable O&M ($/MWh)..... $5.00 $ 2.00 $5.00 $ 2.00
Size (MW)................ 345 520 345 520
- --------------------------------------------------------------------------------
TABLE 4-14
FULL LOAD HEAT-RATE IMPROVEMENT (BTU/KWH)
- --------------------------------------------------------------------------------
1999-2003 2004-2008 2009-2013 2014-2018 2019+
- --------------------------------------------------------------------------------
Combined Cycle.. 6,700 6,566 6,435 6,306 6,180
- --------------------------------------------------------------------------------
Combustion..... 10,400(W) 10,192(W) 9,988(W) 9,788(W) 9,593(W)
Turbine........ 10,700(S) 10,487(S) 10,427(S) 10,070(S) 9871(S)
- --------------------------------------------------------------------------------
- -------------------------------PHB Hagler Bailly--------------------------------
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ASSUMPTIONS -- 4-21
- --------------------------------------------------------------------------------
OTHER EXPENSES
Information on fixed costs, depreciation and taxes is also developed and
incorporated within the DCF analysis to determine the economic viability of the
new unit additions. Environmental costs and overhaul expenses are not included,
due to expectations that such expenses would be minimal in early years of
operation.
- -- Property taxes are assumed to be 1% to 2% of the initial capital costs
- -- Depreciation of the initial all-in cost of the new additions is based on a
standard twenty-year Modified Accelerated Cost Recovery System (MACRS)
(150 DB) with mid-year convention
ECONOMIC AND FINANCIAL ASSUMPTIONS
- -- Minimum internal rate of return (IRR) is assumed to be 13.5%
- -- Financing assumptions are assumed to be 60% debt, 40% equity for combined
cycle units, and 50% debt, 50% equity for combustion turbine units
- -- Debt interest rate is assumed to be 9.1%. Debt terms and project lives are
twenty years with mortgage-style amortization for combined cycle units and
fifteen years for combustion turbine units
- ------------------------------ PHB Hagler Bailly -----------------------------
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CHAPTER 5
MARKET PRICE FORECASTS
5.1 INTRODUCTION
Using the assumptions presented in Chapter 4, PHB Hagler Bailly developed a
"Base Case." This Base Case reflects the results of the MVP(SM) analysis
outlined in Chapter 3. It should be recognized that this Base Case will vary to
the extent the input assumptions change, and such assumptions should be
reviewed with the same rigor as the resulting forecast.
The market price forecast is composed of two price streams: those associated
with the system marginal cost of producing in the energy market, and the
additional compensation for capacity that must be present in the market (above
and beyond the system marginal cost) to ensure that adequate generation
capacity is available.(1) This capacity compensation is developed on an average
across the region and will apply to each individual unit depending on its unit
characteristics. The REMA facilities also have potential additional revenues
available through transitional capacity contracts. These revenues are not
included in this analysis.
The energy price forecast presents the marginal cost of generating electricity
in the PJM electricity market. The additional compensation for capacity needed
to maintain a minimum amount of capacity in the market is factored into the
all-in market price forecast. Thus, the all-in price is a good representation of
the average price needed in the marketplace to maintain equilibrium. It should
be noted that the amount of compensation for capacity needed in the market is
directly related to the energy price level and the ability of the marginal unit
to recover its fixed costs. As energy prices rise and fall, compensation for
capacity will also adjust to ensure that the total going-forward costs of the
marginal unit are met. As a result of this dynamic equilibrium, the revenues,
which form the all-in market price, should be sufficient to support the minimum
amount of capacity needed by the system.
Compensation for capacity may take many forms. Payments could be in the form of
a capacity price arising from a capacity market, a regulated payment fee,
bilateral contracts, payments by the ISO for ancillary services, or in the form
of prices above the marginal cost of the price-setting plant. Ultimately, the
compensation for capacity will reflect what customers are willing to pay for
reliability.
- --------------
(1) If additional compensation for capacity were not present in the market,
then a substantial portion of the generating capacity necessary to meet peak
demand, let alone necessary to maintain an economic level of reserves, would
exit the market as these plants would not be able to meet their going-forward
costs. Such a forecast is nonsensical; therefore the energy price generated by
the model should not be considered without factoring in the value of the assets
needed to maintain reliability in the market.
- ------------------------------ PHB Hagler Bailly -------------------------------
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The PJM wholesale electric market requires Load Serving Entities (LSEs) to
directly contract for capacity through the Capacity Credit Market. Similarly,
the New York market is developing an installed capacity market. While these
mechanisms provide a revenue stream to generators for installed capacity;
generators can earn additional revenues by offering services to the ancillary
service markets or through bilateral contracts with wholesale customers.
Additional revenues can also be extracted from the energy market in the form of
prices above the marginal cost of the price-setting plant. The ability of
generators to capture such additional payments will depend largely on the
flexibility of their operating characteristics, their location within the
system, and the continued development and modification of these market
mechanisms.
In each year the value of the additional compensation for capacity captured
through these market mechanisms' is assumed to be capped at the annual carrying
cost of a new combustion turbine. If the additional compensation for capacity
were higher than the carrying cost of a new unit, then the new unit would be
constructed to displace other higher cost units in the system.
In addition to the Base Case, PHB Hagler Bailly developed two sensitivities to
the portfolio as outlined below:
- - "Low Fuel Price Case" which tests the sensitivity of the market price
forecasts to lower gas and oil prices represented as a $0.50/MMBtu
reduction in the 1999 gas and oil forecast with escalation remaining
unchanged (coal prices are not changed)
- - "Overbuild Case" which tests the sensitivity of the market price forecasts
to an exuberance of merchant plant development as well as continued
operation of all nuclear plants. In this scenario, an additional 12,447 MW
of merchant capacity comes online by 2003 in PJM and NPCC in addition to
the 8,147 MW of confirmed new merchant capacity that is reflected in the
Base Case
These sensitivities have been developed to portray the impact of changes in
critical assumptions, and do not necessarily present a "worst" case scenario.
Section 5.2 describes the current market conditions in PJM. Sections 5.3 and 5.4
present analyses of the market price forecasts for the Base Case and sensitivity
cases, respectively. Energy price forecasts were derived for the PJM East,
Central, and West markets and an all-in market price forecast is provided
utilizing the methodology outlined in Chapter 3 (assuming 100% load factor).
5.2 PJM MARKET CONDITIONS
The REMA facilities, located in the PJM-East, PJM-Central, and PJM-West pricing
areas, participate in the PJM wholesale electricity market, which covers the
entire MAAC transmission region.
- ------------------------------ PHB Hagler Bailly -------------------------------
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- --------------------------------------------------------------------------------
Figure 5-1 illustrates the load and resource balance for PJM through the end of
the study period. Peak demand growth in the PJM market is forecast to grow at an
average of approximately 1.6% per year from 2000 through the end of the study
period. A required system-wide reserve margin of 18% is assumed through 2001.
Subsequent to 2001, the system-wide reserve margin is assumed to be 15% as PHB
Hagler Bailly believes the market will mature and the required reserve margins
will be lowered.
The existing capacity in PJM is initially sufficient to meet the system reserve
requirement.
FIGURE 5-1
PJM LOAD AND RESOURCE BALANCE
[PERFORMANCE GRAPH]
Source: MAAC EIA 411, 1999 and 1999 MAAC Annual Electric Control and Planning
Area Report.
(1) The system reserve margin is assumed to be 18% through 2001. From 2002
through the end of the study period the reserve margin is lowered to 15%.
- ------------------------------ PHB Hagler Bailly -------------------------------
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- -------------------------------------------------------------------------------
The transmission transfer capability between PJM and the surrounding
transmission areas is defined in Appendix B. While PJM shares numerous
interconnections with surrounding regional markets, transfer capability can be
limited under certain operating conditions, reducing total import capabilities
into the PJM system.
The relative mix of installed capacity and energy generation between gas/oil,
coal, hydro, and nuclear assets in PJM is illustrated in Figures 5-2 and 5-3.
As illustrated, the PJM market relies primarily on coal-fired and nuclear
baseload generating facilities for the bulk of the electricity produced in the
system. This mix results in coal units setting the marginal price in a
significant number of hours.
[PJM CAPACITY AND ENERGY PIE CHARTS]
Figure 5-2 Figure 5-3
PJM Capacity PJM Energy
Other 5% Other 1%
Nuclear 22% Nuclear 38%
Hydro 4% Hydro 2%
Coal 32% Coal 45%
Gas/Oil 37% Gas/Oil 14%
Source: MAAC EIA 411, 1999.
5.3 BASE CASE ANALYSIS
The market price forecast is developed based on the marginal energy costs and
the going-forward costs of the marginal unit on the supply curve, as outlined
in Chapter 3.
The marginal energy price forecast presents the marginal cost of generating
electricity in the competitive market. The additional compensation for
capacity, or implied capacity price, needed to maintain a minimum amount of
capacity in the market is factored in to the all-in market price forecast. The
all-in price includes revenues needed by the "average" market participants,
above the system marginal cost of operating the last unit called on the
dispatch curve. Therefore, it represents a price that generators will expect to
receive for combined electricity and energy products in the PJM market in the
long run. To the extent there are boom and bust cycles, these
- ------------------------------ PHB Hagler Bailly -----------------------------
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- --------------------------------------------------------------------------------
revenues will vary, as demonstrated in the Overbuild Case. It should be noted
that the amount of compensation for capacity needed in the market is directly
related to the energy price level and the ability of the marginal unit to
recover its fixed costs. As energy prices rise and fall, compensation for
capacity will also adjust in an opposite direction, based on our methodology,
to ensure that the total going-forward costs of the marginal unit are met.
The Base Case implied capacity price for the entire PJM market is represented
in Table 5-1. The energy and all-in price forecasts for the PJM-East,
PJM-Central, and PJM-West pricing areas for the period 2000 through 2020 are
presented in Tables 5-2, 5-3, and 5-4 and graphically represented in Figures
5-4, 5-5, and 5-6.
TABLE 5-1
PJM BASE CASE IMPLIED CAPACITY PRICE FORECAST(1)
IMPLIED CAPACITY PRICE FORECAST ($/KW-yr)
2000 60.00 2007 47.60 2014 50.40
2001 59.60 2008 46.70 2015 50.40
2002 52.60 2009 45.40 2016 49.60
2003 52.60 2010 46.20 2017 49.50
2004 52.70 2011 48.20 2018 49.70
2005 44.80 2012 50.00 2019 49.80
2006 45.40 2013 49.30 2020 49.80
- -----------
(1) Results are expressed in real 1999 dollars.
TABLE 5-2
PJM-EAST BASE CASE ENERGY AND ALL-IN PRICE FORECAST(1)
ENERGY PRICE FORECAST ($/MWh) ALL-IN PRICE FORECAST ($/MWh)
2000 24.30 2007 24.50 2014 24.50 2000 31.20 2007 29.90 2014 30.30
2001 24.80 2008 24.60 2015 24.50 2001 31.60 2008 30.00 2015 30.30
2002 24.50 2009 25.00 2016 25.00 2002 30.50 2009 30.20 2016 30.60
2003 25.00 2010 25.00 2017 25.40 2003 31.00 2010 30.30 2017 31.10
2004 25.00 2011 24.80 2018 25.80 2004 31.00 2011 30.30 2018 31.40
2005 24.90 2012 24.60 2019 26.00 2005 30.00 2012 30.30 2019 31.60
2006 24.70 2013 24.60 2020 26.10 2006 29.90 2013 30.20 2020 31.80
- -----------
(1) Results are expressed in real 1999 dollars.
- ------------------------------ PHB Hagler Bailly -------------------------------
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- --------------------------------------------------------------------------------
TABLE 5-3
PJM-CENTRAL BASE CASE ENERGY AND ALL-IN PRICE FORECAST(1)
ENERGY PRICE FORECAST ($/MWh) ALL-IN PRICE FORECAST ($/MWh)
2000 23.90 2000 30.70
2001 24.30 2001 31.10
2002 24.10 2002 30.10
2003 24.60 2003 30.60
2004 24.60 2004 30.70
2005 24.50 2005 29.60
2006 24.40 2006 29.50
2007 24.20 2007 29.60
2008 24.50 2008 29.80
2009 24.80 2009 30.00
2010 24.80 2010 30.10
2011 24.80 2011 30.30
2012 24.50 2012 30.20
2013 24.50 2013 30.20
2014 24.50 2014 30.30
2015 24.50 2015 30.20
2016 24.90 2016 30.50
2017 25.20 2017 30.80
2018 25.50 2018 31.10
2019 25.70 2019 31.40
2020 25.90 2020 31.60
- -------
(1) Results are expressed in real 1999 dollars.
TABLE 5-4
PJM-WEST BASE CASE ENERGY AND ALL-IN PRICE FORECAST(1)
ENERGY PRICE FORECAST ($/MWh) ALL-IN PRICE FORECAST ($/MWh)
2000 23.41 2000 30.27
2001 23.88 2001 30.68
2002 23.62 2002 29.62
2003 24.15 2003 30.16
2004 24.22 2004 30.24
2005 24.08 2005 29.19
2006 23.93 2006 29.11
2007 23.74 2007 29.18
2008 24.01 2008 29.34
2009 24.39 2009 29.58
2010 24.41 2010 29.68
2011 24.33 2011 29.84
2012 24.10 2012 29.81
2013 24.14 2013 29.76
2014 24.10 2014 29.86
2015 24.04 2015 29.79
2016 24.44 2016 30.10
2017 24.76 2017 30.41
2018 25.08 2018 30.75
2019 25.28 2019 30.97
2020 25.49 2020 31.17
- -------
(1) Results are expressed in real 1999 dollars.
A significant drop in the implied capacity price occurs in 2005 due to the
assumed retirement of some nuclear units. New combined cycle plants (CCs)
assumed to enter into the market in this period have net going-forward costs
that are significantly lower than those of the retiring units. Capacity prices
also decline overall during this period due to the assumption that generating
technology and management will become more efficient, decreasing overall
going-forward costs. The new CCs assumed to enter the market beginning in 2000
contribute to a fairly stable energy price and in turn, all-in price.
Appendix C presents a dispatch curve for the REMA facilities.
- --------------------------------PHB Hagler Bailly-------------------------------
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- -------------------------------------------------------------------------------
FIGURE 5-4
PJM-EAST ENERGY AND ALL-IN PRICES (REAL 1999 $)
[PERFORMANCE GRAPH TO COME]
[PLOT POINTS TO COME]
FIGURE 5-5
PJM-CENTRAL ENERGY AND ALL-IN PRICES (REAL 1999 $)
[PERFORMANCE GRAPH TO COME]
[PLOT POINTS TO COME]
- ------------------------------ PHB Hagler Bailly ------------------------------
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FIGURE 5-6
PJM-WEST ENERGY AND ALL-IN PRICES (REAL 1999 $)
[PERFORMANCE GRAPH TO COME]
[PLOT POINTS TO COME]
5.4 SENSITIVITY CASES
Two sensitivity cases were developed to assess the impact of major assumption
changes on the Base Case market price forecast. The first sensitivity case
examined the effect of lower natural gas and oil prices. Since fuel oil and
natural gas are the marginal fuels in several of the transmission or pricing
areas, the energy price forecast is driven in large part by the forecast price
of these fuels. In order to test the sensitivity of the Base Case energy price
forecast to changes in the natural gas and fuel oil forecasts the Low Fuel
Price Case was developed. This case assumed that natural gas and fuel oil
prices would start at a level $0.50/MMBtu lower than the Base Case, but that
they would escalate at the same rate as projected for the Base Case. No change
was made to the forecast prices of coal.
The second sensitivity case, the Overbuild Case, examined the effect of
exuberance in merchant plant development. This case assumed that in addition
to the merchant plants identified for the Base case (see Section 4.8.2)
several additional merchant plants would come on-line in the near term
(2001-2003). Nuclear plant retirements were pushed out to license expiration,
and it was assumed that no economic retirements would occur until after 2007.
This assumption could be interpreted as the ability of all generators to seek
recovery of out-of-the-market costs from other sources (e.g., stranded cost
recovery). Table 5-5 displays the incremental merchant plant development
assumed for the Overbuild Case.
- ------------------------------ PHB Hagler Bailly ------------------------------
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- --------------------------------------------------------------------------------
TABLE 5-5
OVERBUILD CASE INCREMENTAL MERCHANT PLANT ASSUMPTIONS
------------------------------------------------------------
CAPACITY (MW) ADDITIONS
-----------------------------------
TRANSMISSION AREA 2001 2002 2003 TOTAL
------------------------------------------------------------
NEPOOL 0 3,050 665 3,715
NYPOOL 0 1,117 2,420 3,537
PJM 0 2,095 3,100 5,195
TOTAL 0 6,262 6,185 12,447
Table 5-6 presents the implied capacity price forecasts for the Low Fuel Price
and Overbuild Cases. Tables 5-7, 5-8, and 5-9 display the estimated energy and
all-in price forecasts for the sensitivities for the PJM-East, PJM-Central, and
PJM-West pricing areas. Figures 5-7, 5-8, and 5-9 graphically compare the all-in
results for the sensitivities to the Base Case.
TABLE 5-6
PJM SENSITIVITY CASES IMPLIED CAPACITY PRICE FORECASTS(1)
- --------------------------------------------------------------------------------
LOW FUEL ($/kW-yr) OVERBUILD ($/kW-yr)
- --------------------------------------------------------------------------------
2000 60.00 2007 45.30 2014 50.60 2000 59.00 2007 41.40 2014 49.60
2001 59.60 2008 45.80 2015 49.90 2001 59.10 2008 44.90 2015 49.60
2002 52.60 2009 44.90 2016 48.60 2002 47.20 2009 44.90 2016 49.70
2003 52.70 2010 44.60 2017 48.60 2003 47.00 2010 43.70 2017 49.80
2004 52.70 2011 45.70 2018 47.80 2004 46.70 2011 45.30 2018 49.80
2005 44.90 2012 48.40 2019 48.70 2005 40.10 2012 50.00 2019 49.90
2006 45.00 2013 48.50 2020 49.00 2006 41.40 2013 49.60 2020 49.80
- ----------
(1) Results are expressed in real 1999 dollars.
The implied capacity price in the Low Fuel Price Case is slightly higher than
in the Base Case in the initial years. However, as gas units become the
marginal unit in more hours in the model, the implied capacity price becomes
less than the Base Case.
The implied capacity price in the Overbuild Case reaches equilibrium in 2012
(approaches the Base Case). This is based on the overbuild shown in Table 5-5.
A more dramatic or prolonged overbuild would have a bigger impact on prices and
the time it takes to reach equilibrium.
- ------------------------------ PHB Hagler Bailly -------------------------------
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TABLE 5-7
PJM-EAST AVERAGE ANNUAL ENERGY & ALL-IN-PRICE FORECASTS(1)
LOW FUEL OVERBUILD
---------------------- -----------------------
ENERGY ALL-IN ENERGY ALL-IN
PRICE PRICE PRICE PRICE
FORECAST FORECAST FORECAST FORECAST
YEAR ($/MWh) ($/MWh) ($/MWh) ($/MWh)
2000 22.50 29.30 24.30 31.10
2001 22.70 29.50 24.80 31.60
2002 22.30 28.30 23.60 29.00
2003 22.60 28.60 22.30 27.70
2004 22.30 28.30 22.70 28.00
2005 22.00 27.10 23.10 27.60
2006 21.80 27.00 23.50 28.20
2007 21.60 26.80 23.80 28.50
2008 21.80 27.00 24.40 29.50
2009 21.80 26.90 24.70 29.80
2010 21.80 26.90 25.00 30.00
2011 21.70 26.90 24.90 30.00
2012 21.20 26.70 24.50 30.20
2013 21.30 26.80 24.60 30.20
2014 21.00 26.80 24.90 30.50
2015 21.10 26.80 24.70 30.40
2016 21.40 26.90 25.30 30.90
2017 21.70 27.30 25.60 31.30
2018 22.10 27.50 26.00 31.70
2019 22.10 27.70 26.10 31.80
2020 22.10 27.70 26.40 32.10
- ---------
(1) Results are expressed in real 1999 dollars.
- ------------------------------PHB Hagler Bailly --------------------------------
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- -------------------------------------------------------------------------------
TABLE 5-8
PJM-CENTRAL AVERAGE ANNUAL ENERGY & ALL-IN PRICE FORECASTS(1)
LOW FUEL OVERBUILD
------------------------- ------------------------
ENERGY ALL-IN ENERGY ALL-IN
PRICE PRICE PRICE PRICE
FORECAST FORECAST FORECAST FORECAST
YEAR ($/MWh) ($/MWh) ($/MWh) ($/MWh)
2000 22.00 28.90 23.90 30.60
2001 22.30 29.10 24.30 31.10
2002 21.90 27.90 23.10 28.50
2003 22.30 28.30 21.90 27.30
2004 22.00 28.00 22.30 27.60
2005 21.70 26.90 22.70 27.20
2006 21.60 26.80 23.10 27.80
2007 21.50 26.70 23.40 28.10
2008 21.70 27.00 24.00 29.10
2009 21.70 26.90 24.30 29.40
2010 21.80 26.90 24.60 29.60
2011 21.70 27.00 24.50 29.60
2012 21.30 26.80 24.10 29.80
2013 21.30 26.90 24.20 29.90
2014 21.10 26.90 24.40 30.10
2015 21.10 26.80 24.40 30.00
2016 21.40 27.00 24.90 30.50
2017 21.60 27.10 25.10 30.80
2018 21.90 27.30 25.60 31.20
2019 22.00 27.50 25.60 31.30
2020 22.00 27.60 26.00 31.70
(1) Results are expressed in real 1999 dollars.
- ------------------------------ PHB Hagler Bailly -------------------------------
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- -----------------------------------------------------------------------------
TABLE 5-9
PJM-WEST AVERAGE ANNUAL ENERGY & ALL-IN PRICE FORECASTS(1)
LOW FUEL OVERBUILD
------------------ ------------------
ENERGY ALL-IN ENERGY ALL-IN
PRICE PRICE PRICE PRICE
FORECAST FORECAST FORECAST FORECAST
YEAR ($/MWh) ($/MWh) ($/MWh) ($/MWh)
- ---- -------- -------- -------- --------
2000 21.70 28.50 23.40 30.20
2001 21.90 28.70 23.90 30.60
2002 21.50 27.50 22.70 28.10
2003 21.90 27.90 21.40 26.80
2004 21.60 27.70 21.80 27.10
2005 21.40 26.50 22.20 26.70
2006 21.30 26.40 22.60 27.30
2007 21.20 26.30 22.80 27.50
2008 21.40 26.60 23.40 28.50
2009 21.40 26.50 23.70 28.80
2010 21.50 26.60 24.00 29.00
2011 21.40 26.60 24.00 29.10
2012 21.00 26.50 23.60 29.30
2013 21.00 26.60 23.80 29.40
2014 20.80 26.60 24.00 29.60
2015 20.80 26.50 23.90 29.50
2016 21.10 26.70 24.40 30.00
2017 21.30 26.90 24.60 30.30
2018 21.60 27.10 25.10 30.70
2019 21.70 27.20 25.10 30.70
2020 21.70 27.30 25.40 31.10
- ------------
(1) Results are expressed in real 1999 dollars.
- ------------------------------ PHB Hagler Bailly ----------------------------
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FIGURE 5-7
PJM-EAST ESTIMATED ALL-IN PRICE FORECAST
[PERFORMANCE GRAPH]
FIGURE 5-8
PJM-CENTRAL ESTIMATED ALL-IN PRICE FORECAST
[PERFORMANCE GRAPH]
- ------------------------------ PHB Hagler Bailly -------------------------------
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- --------------------------------------------------------------------------------
FIGURE 5-9
PJM-WEST ESTIMATED ALL-IN PRICE FORECAST
[PERFORMANCE GRAPH]
As the figures above demonstrate, the Low Fuel Price Case causes a significant
decline in the all-in price throughout the study period. However, this decline
is mitigated in part by the fact that coal is the marginal fuel in many hours.
The Overbuild Case causes the all-in price to fall in the initial years of the
study period and then approaches the Base Case as the model reaches
equilibrium. The unit specific revenues reported in the pro forma include the
effects of the volatility analysis as outlined in Chapter 3.
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APPENDIX A
METHODOLOGY FOR COAL PRICE FORECASTING
The following details the methodology used for projecting pricing for Central
Appalachian, Northern Appalachian and Pittsburgh seam, and other coals used in
the NPCC/MAAC region.
Central Appalachia. Fieldston Hagler Bailly (Fieldston)(1) projects the
use of 1.2-pound and 1.5-pound Central Appalachian coals(2) in MAAC and
NPCC-United States, during the forecast period. Both coal types are associated
with energy contents of 12,500 Btu per pound, and are both priced on a FOB
railcar basis.
Fieldston projects the real price of 1.2-pound coal from this region to remain
flat through 2005, and then decline steadily in real terms at a low rate through
2014. The flat price projection in the near- to mid-term is the result of
depletion effects offsetting expected productivity gains. However, productivity
gains are projected eventually to dominate, leading to a mild downward trend in
real prices (less than 1% per year) after 2005.
Similarly, the price of 1.5-pound Central Appalachian coal is projected to
remain flat through 2005 and to decline slightly thereafter. The rate of
decline from 2005 to 2010 is projected to be somewhat greater than the rate for
the 1.2-pound coal (somewhat less than 2% per year in real terms), reflecting
the increasing value of sulfur allowances. After 2010, Fieldston projects that
these two coals will remain linked through the sulfur allowance price, which is
projected to remain flat at 2010 levels (in real terms). This linkage results
in a projected real rate of price decline that is slightly larger than the rate
for the 1.2-pound coal, but still less than 1% per year.
Northern Appalachia and Pittsburgh Seam. Fieldston projects the use of
mid-sulfur and higher-sulfur coals in MAAC and NPCC-U.S. during the forecast
period. For modeling purposes, 2.4-pound, 3.2-pound, and 6-pound coal types of
different energy contents were identified. These coal types are priced on a FOB
basis, as delivered to trucks or railcars, depending upon the particular type.
Relative prices were determined based on sulfur levels, and prices were
adjusted to reflect differences in energy content.
- --------
(1) Fieldston Hagler Bailly is a wholly owned subsidiary of PHB Hagler Bailly,
Inc.
(2) The terms "1.2 pound" and "1.5 pound" coal refer to a particular coal's
sulfur content. For example, a coal with a sulfur content corresponding to 1.2
pounds of sulfur dioxide for each MMBtu of energy content is called a
"1.2-pound" coal.
- ------------------------------ PHB Hagler Bailly -------------------------------
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- --------------------------------------------------------------------------------
Fieldston expects that productivity gains will drive down prices in mid-sulfur
coals, overwhelming any depletion effects. Prices for these coals are projected
to decline at a rate of 2% per year in real terms.
Very high sulfur coals primarily serve generating units that are equipped with
scrubbers that remove SO(2) from emission streams. These units obtain very
little benefit from lower sulfur coals and typically seek to minimize cost with
the use of cheap, very high sulfur coals. The analysis projects the price of
6-pound coals to decline at slightly more than 2% per year in real terms,
maintaining a relatively fixed differential to 2.5-pound Northern Appalachian
coals.
The prices for higher-sulfur coals, identified for modeling purposes as those
with a sulfur content of 3.2 pounds per MMBtu, are projected to decline at a
faster rate than those for mid-sulfur coals. As CAAA Phase II takes effect in
2000, and afterward, it is expected that prices for higher-sulfur coals will
trend downward toward those for very high sulfur, 6-pound coals. Increasingly,
three- to four-pound coals are expected to serve the scrubber market as well,
causing their sulfur-related price premium to decline in value, approximately
equilibrating the price of these coals with the price of 6-pound coals by 2010.
The projected result is a relatively steep average price decline for 3.2-pound
coals through 2010 -- greater than 3% per year in real terms. Higher production
cost sources of these coals may cease production due to this relatively large
rate of decline.
Other. Several other coal types are projected in the NPCC/MAAC region.
These include coal from the Powder River Basin (PRB), imports from Colombia,
waste coals (both bituminous and anthracite), and petroleum coke (a non-coal
solid fuel).
The FOB mine price of PRB coal is projected to increase slightly in real terms
to 2000, and then to decline gradually throughout the forecast period. A
near-term price increase is expected due to increasing demand as new,
lower-cost reserves begin to be exploited. Productivity gains are projected to
more than counterbalance growing demand after 2000, resulting in a real price
decrease trend of approximately 1% per year.
The prices for imported coal, waste coals, and petroleum coke are expected to
remain flat in real terms during the forecast period. This projection reflects
the view that inflation-related costs will cause nominal pricing to rise, but
underlying productivity gains will not generate real price decreases like the
ones projected for other coals.
Transportation costs. All transportation costs were estimated using several
publicly available data sources that provide information on electric utility
delivered fuel costs and commercial publications providing spot coal market
pricing. Transportation cost estimates were developed for plant locations for
particular coal types, based on spot coal purchases, to reflect marginal
delivered pricing. Transportation costs for coal types not historically used at
a particular location were based on industry experience and economic analysis.
Projected escalation rates for coal transportation rates are provided below.
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METHODOLOGY FOR COAL PRICE FORECASTING -- A-3
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Rail. Rail escalation rates were projected in real dollar terms and
differentiated according to origin region.
Coal movements originating in Central Appalachia are projected to remain flat
in real terms during to forecast period, as inflation-related cost increases
are passed on to shippers. General improvements in productivity are not
projected to result in lower rail rates in this region because low-density
utilization results in higher railroad costs. Rail lines used to gather coal
from various mines are used by carriers at a very low rate, as measured by the
number of tons of coal shipped over a mile of track during the course of a
year. Operating costs for low-density gathering lines are therefore spread
over a small number of shipments, eliminating the possibility that productivity
gains could drive reductions in rail rates.
Some coal movements originating in Northern Appalachia are projected to remain
flat in real terms, and some are projected to decrease as a result of regulatory
activity during the forecast period. For generating units receiving coal over
low-density rail routes, no rate decreases are likely for the same reason cited
for Central Appalachian gathering lines. Some generating units, however,
receive coal shipped over relatively high-density lines, and currently pay rates
far in excess of variable costs. It is expected that several such plants will
experience greater access to the rate regulatory process than has been the case
in the past, and will see substantial cost reductions as rates are lowered, by
2005. After achieving a lower rate level, rates for these units are projected
to remain flat in real terms for the remainder of the forecast period,
reflecting a return to inflation-related cost increases at the new level.
PRB coal is projected to reach a small number of plants in New York by rail and
vessel, via the Great Lakes. Western rail rates are expected to decline in
real terms. With continued competition between the Burlington Northern Santa Fe
and the Union Pacific, and the construction of the proposed Dakota, Minnesota,
and Eastern, rates are projected to decline at 2.5% per year in real terms
through 2010. Thereafter, Fieldston projects decreases to continue at a slower
rate of 1% per year.
Vessel and barge. Vessel and barge rates are projected to decline during
the forecast period, and average, at a rate of 1% per year in real terms,
reflecting improved productivity in competitive markets.
Truck. Truck rates are projected to decline slowly during the forecast
period, at a rate of 0.1% per year in real terms, to reflect small capital
improvements in an industry that is already very competitive.
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APPENDIX B
TRANSFER CAPABILITY
The transmission system is the transportation mechanism that moves power from
where it is generated to where it is to be used. There are a number of
technical factors that limit the amount of power between utilities, control
areas or large regions. While facility ratings are one key element, voltage
levels or instability are other considerations that need to be considered in
establishing transfer capabilities. In addition, transfers that involve two
utilities or control areas will have an impact on the transfer capabilities of
neighboring utilities because a portion of that transfer will flow on
neighboring utilities' lines. In order to quantify transmission capabilities
between NERC regions and major subregions, seasonal analyses are performed that
include current operating parameters, load patterns and scheduled transfers to
determine regional import and export capabilities.
The transfer capabilities that are shown are non-simultaneous, meaning that for
any given transfer at an identified limit, the other transfer limitations shown
in the tables are unlikely to be attainable at the same time. Concurrent
exports or imports for any particular region may not be technically feasible at
the total of the capabilities listed. These values represent the ability of the
transmission networks to accommodate the transfer electricity from one area to
another area for a single load and generation pattern. Therefore, the actual
patterns of demands and generation can result in changes in transfer
capabilities on both an hourly and daily basis. These transfer capabilities
have been considered as representative of the level of interchange that could
occur between the various transmission areas.
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TRANSFER CAPABILITY -- B-2
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TABLE B-1
TRANSFER CAPABILITY
WINTER SUMMER
CAPABILITY CAPABILITY
FROM TO (MW) (MW)
---- -- ---------- ----------
ECAR Ontario Hydro 2,230 1,680
ECAR PJM-Central 494 494
ECAR PJM-West 2,000 2,000
Hydro Quebec NEPOOL-SE 525 1,800
Hydro Quebec Nova Scotia -- New Brunswick 1,050 1,050
Hydro Quebec NYPP-West 1,200 1,200
Hydro Quebec Ontario Hydro 1,391 1,391
NEPOOL-Maine NEPOOL-West 1,200 1,200
NEPOOL-Maine Nova Scotia -- New Brunswick 55 55
NEPOOL-SE Hydro Quebec 1,670 1,370
NEPOOL-SE NEPOOL-West 3,600 3,600
NEPOOL-SE NYPP-East 122 191
NEPOOL-West NEPOOL-Maine 1,450 1,450
NEPOOL-West NEPOOL-SE 3,600 3,600
NEPOOL-West NYPP-East 510 802
NEPOOL-West NYPP-In-City 334 525
NEPOOL-West NYPP-Long Island 84 132
Nova Scotia -- New Brunswick Hydro Quebec 400 400
Nova Scotia -- New Brunswick NEPOOL-Maine 700 700
NYPP-East NYPP-In-City 4,441 4,441
NYPP-East NEPOOL-SE 200 154
NYPP-East NEPOOL-West 925 811
NYPP-East NYPP-Long Island 1,390 1,390
NYPP-East NYPP-West 5,339 5,339
NYPP-East PJM-East 1,784 1,784
NYPP-In-City NEPOOL-West 575 443
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TRANSFER CAPABILITY -- B-3
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TABLE B-1 (CONT.)
TRANSFER CAPABILITY
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WINTER SUMMER
CAPABILITY CAPABILITY
FROM TO (MW) (MW)
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NYPP-In-City NYPP-East 4,441 4,441
NYPP-In-City PJM-East 2,750 2,750
NYPP-Long Island NEPOOL-West 150 116
NYPP-Long Island NYPP-East 1,306 1,306
NYPP-West Hydro Quebec 1,500 1,500
NYPP-West NYPP-East 5,261 5,261
NYPP-West Ontario Hydro 1,850 1,850
NYPP-West PJM-West 725 725
Ontario Hydro ECAR 2,370 1,830
Ontario Hydro Hydro Quebec 309 309
Ontario Hydro NYPP-West 1,850 1,850
PJM-Central ECAR 400 400
PJM-Central PJM-East 8,673 8,673
PJM-Central PJM-West 5,254 5,254
PJM-Central SERC 1,700 1,700
PJM-East NYPP-East 735 735
PJM-East NYPP-In-City 766 766
PJM-East PJM-Central 6,971 6,971
PJM-West ECAR 2,600 2,600
PJM-West NYPP-West 725 725
PJM-West PJM-Central 5,146 5,146
SERC PJM-Central 1,700 1,700
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APPENDIX C
DISPATCH CURVES
The dispatch curves below represent our projections of the annual average
marginal dispatch cost of the REMA assets for the years 2000 and 2010 as
compared to the other generators in the market. These curves portray the
diversity of the REMA portfolio.
PJM BASE CASE DISPATCH CURVE 2000
[PERFORMANCE GRAPH]
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DISPATCH CURVES -- C-2
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PJM BASE CASE DISPATCH CURVE 2010
[PERFORMANCE GRAPH]
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GLOSSARY
RELEVANT TERMS DEFINITIONS
ANCILLARY SERVICES. Those services that are necessary to support the
transmission of capacity and energy from resources to loads, while maintaining
the reliable operation of the transmission provider's transmission system in
accordance with good utility practice.
AVAILABLE TRANSFER CAPABILITY. The amount of energy above "base case"
conditions that can be transferred reliably from one area to another over all
transmission facilities without violating any pre- or post-contingency criteria
for the facilities in a Control Area under specified system conditions.
DIVESTITURE. Occurs when a corporation separates a portion of its business and
assets, such as power plants, transmission facilities, or distribution system,
from the existing company. This can occur through a sale, spin-off, or other
transfer line of business. Divestiture can occur voluntarily as a business
decision driven by the market or by government mandate that a utility sell
certain assets to diminish perceived market power.
BILATERAL TRANSACTION. An agreement between two entities (one or both being
members of the ISO) for the sale and delivery of a service.
BUS. The point at which transmission lines connect to a substation.
ENERGY IMBALANCE SERVICE. Used to supply energy for mismatch between scheduled
delivery and actual loads that have occurred over an hour.
FIRM POINT-TO-POINT TRANSMISSION SERVICE. Transmission service that is
reserved and/or scheduled between specified points of receipt and delivery.
FORCED OUTAGE. The failure of equipment (transmission lines or generators) due
to unplanned events.
INDEPENDENT SYSTEM OPERATOR (ISO). Generally, an ISO is a voluntarily formed
entity that ensures comparable and non-discriminatory access by power suppliers
to regional electric transmission systems. As currently envisioned, ISOs would
be governed in a manner that renders them "independent" of the commercial
interests of power suppliers who also may be owners of transmission facilities
in the region. The ISO assumes operational control of the use of transmission
facilities, administers a system wide transmission tariff applicable to all
market participants, and maintains short-term system reliability.
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GLOSSARY -- 2
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LOAD. Energy demand.
LOAD SERVING ENTITY (LSE). An entity, including a load aggregator or power
marketer, serving end-users within a Control Area, that has been granted the
authority or has an obligation pursuant to state or local law, regulation or
franchise to sell electric energy to end-users located within the Control Area
or the duly designated agent of such an entity.
LOCATIONAL MARGINAL PRICE (LMP). The marginal cost of supplying the next
increment of electric energy at a specific location bus on the electric power
network taking into account both generation marginal cost and the physical
aspects of the transmission system (PJM).
LOCATIONAL-BASED MARGINAL PRICE (LBMP). The marginal cost of supplying the next
increment of electric energy at a specific location bus on the electric power
network taking into account both generation marginal cost and the physical
aspects of the transmission system (NY-ISO).
MULTISYM. A product developed by Henwood Energy Services, Inc.
NETWORK INTEGRATION TRANSMISSION SERVICE. Allows a transmission customer to
integrate, plan, economically dispatch and regulate its network resources to
serve its network load in a manner comparable to that in which the transmission
provider utilizes its transmission system to serve its native load customers.
Network integration transmission service also may be used by the transmission
customer to deliver non-firm energy purchases to its network load without
additional charge.
NEW YORK IN-CITY. Generators located in the City of New York.
OPEN ACCESS SAME-TIME INFORMATION SYSTEM. (1) The computer system that is used
by transmission providers to exchange transmission service and ancillary service
information with transmission customers. The OASIS requirements and standard of
conduct were initially defined in FERC Order 889. (2) A computerized information
system, developed as an Internet application, that allows LDCs to provide and
obtain information needed to schedule transmission services.
OPEN TRANSMISSION ACCESS (OPEN ACCESS). Enables all participants in the
wholesale market equal access to transmission service, as long as capacity is
available, with the objective of creating a more competitive wholesale power
market. The Energy Policy Act of 1992 gave FERC the authority to order utilities
to provide transmission access to third parties in the wholesale electricity
market.
PANCAKING TRANSMISSION RATES. These result when power crosses more than one
transmission system and is subject to two or more tariffs.
POINT-TO-POINT TRANSMISSION SERVICE. The reservation and transmission of
capacity and energy on either firm or non-firm basis from the point(s) of
receipt to the point(s) of delivery.
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GLOSSARY -- 3
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POWER POOL. Two or more interconnected electric systems planned and operated
to supply power in the most reliable and economical manner for their combined
load requirements and maintenance programs.
REGULATION. The capability of a specific generating unit with appropriate
telecommunications, control and response capability to increase or decrease its
output in response to a regulating control signal.
RELIABILITY. The degree to which electric power is made available to those
who need it in sufficient quantity and quality to be dependable and safe. The
degree of reliability may be measured by the frequency, duration, and magnitude
of adverse effects on consumer services.
TEN-MINUTE SPINNING RESERVE. Refers to the kWs of generating capacity of an
electric generator that is synchronized to the system, unloaded during all or
part of the hour, and capable of providing contingency protection by loading to
supply energy immediately on demand, increasing the energy over no more than 10
minutes to the full amount of generating capacity designated.
TEN-MINUTE NON-SPINNING RESERVE. Refers to the kWs of generating capacity that
are not synchronized to the system and capable of providing contingency
protection by loading to supply energy within ten minutes to the full amount of
generating capacity designated.
THIRTY-MINUTE OPERATING RESERVE. Refers to the kWs of generating capacity
that are capable of providing contingency protection by loading to supply
energy within 30 minutes of demand at an output equal to the full amount of
generating capacity designated.
TIGHT POWER POOL. A centrally dispatched power pool formed by a group of
utilities that dedicate their generating and transmission resources for
economic dispatch. Usually in tight power pools costs and revenues are divided
among the members after the fact and no one pool member is responsible for the
procurement of individual power supply.
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GLOSSARY -- 4
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ACRONYMS DEFINITIONS
AEP American Electric Power Company
AGC Automatic Generation Control
APS Allegheny Power System
ATC Available Transfer Capability
Btu British Thermal Units
CAAA Clean Air Act Amendments of 1990
CA-ISO California Independent System Operator
CC Combined Cycle Combustion Turbine
CT Simple Cycle Combustion Turbine
CTC Competitive Transition Charges
DCF Discounted Cash Flow
ECAR East Central Area Reliability Coordination Agreement
EIA Energy Information Administration
EMO East Missouri Subregion
EPA Environmental Protection Agency
EPRI Electric Power Research Institute
FCITC First Contingency Incremental Transfer Capabilities
FERC Federal Energy Regulatory Commission
FOB Free on Board
FO&M Fixed Operation & Maintenance
FRCC Florida Reliability Coordinating Council
FTRs Fixed Transmission Rights
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GLOSSARY -- 5
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GADS Generating Availability Data System
GRI Gas Research Institute
HESI Henwood Energy Services, Inc.
IAPCS Integrated Air Pollution Control System
IRR Internal Rate of Return
ISO Independent System Operator
kW Kilowatts
kWh Kilowatt Hours
LAN Local Area Network
LBMP Locational-Based Marginal Pricing
LDC Local Distribution Company
LEA Low Excess Air
LMP Locational Marginal Price
LNB Low-NOx Burners
LNB/OFA-T Low-NOx Burners with Overfire Air/Tangential
LOLP Loss of Load Probability
LSE Load Serving Entity
MAAC Mid-Atlantic Area Council
MACRS Modified Accelerated Cost Recovery System
MISO Midwest Independent System Operator
MMBtu Million British Thermal Units
MW Megawatts
MWh Megawatt Hours
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GLOSSARY -- 6
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MVP Market Valuation Process
NEPOOL New England Power Pool
NERC North American Electric Reliability Council
NO(x) Nitrogen Oxide
NPCC Northeast Power Coordinating Council
NPE Nuclear Power Experience
NSPS New Source Performance Standards
NY-ISO New York Independent System Operator
NYMEX New York Mercantile Exchange
NYPP New York Power Pool
OASIS Open Access Same-Time Information System
OFA Overfire Air
O&M Operation and Maintenance
OPEC Operating Plant Evaluation Code
PJM Pennsylvania-New Jersey-Maryland Interconnection LLC
PPA Power Purchase Agreement
PUC Public Utility Commission
PRB Powder River Basin
REMAQ Regional Economic Model for Air Quality
RMR CONTRACTS Reliability Must-Run contracts
RTO Regional Transmission Organization
SCIL South Central Illinois Subregion
SCR Selective Catalytic Reduction
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GLOSSARY -- 7
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SERC Southeastern Electric Reliability Council
SIC Synchronous Interconnect Committee
SIGE Southern Indiana Gas & Electric
SIP State Implementation Plan
SNCR Selective Non-Catalytic Reduction
SO(2) Sulfur Dioxide
SPP Southwest Power Pool
S&P Standard and Poor's
TCC Transmission Congestion Contracts
TRA Tennessee Regulatory Authority
TRANSCO Transmission Company
TVA Tennessee Valley Authority
TWh Terrawatt Hours
VACAR Virginia - Carolinas Region
VOCs Volatile Organic Compounds
VO&M Variable Operation & Maintenance
WEFA The WEFA Group
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$727,850,000
RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
OFFER TO EXCHANGE
$210,000,000 $297,850,000 $220,000,000
8.554% SERIES A EXCHANGE PASS 9.237% SERIES B EXCHANGE PASS 9.681% SERIES C EXCHANGE PASS
THROUGH CERTIFICATES DUE 2005 THROUGH CERTIFICATES DUE 2017 THROUGH CERTIFICATES DUE 2026
FOR ALL OUTSTANDING FOR ALL OUTSTANDING FOR ALL OUTSTANDING
8.554% SERIES A PASS 9.237% SERIES B PASS 9.681% SERIES A PASS
THROUGH CERTIFICATES DUE 2005 THROUGH CERTIFICATES DUE 2017 THROUGH CERTIFICATES DUE 2026
---------------------
PROSPECTUS
---------------------
Until May 15, 2001, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus.
February 12, 2001
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