As filed with the Securities and Exchange Commission on August 8, 2001
Registration No. 333-61668
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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POST EFFECTIVE AMENDMENT NO. 1
TO
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
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MIRANT MID-ATLANTIC, LLC
(Exact Name of Registrant as Specified in its Charter)
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Delaware 4911 58-2574140
(State or Other (Primary Standard (I.R.S. Employer
Jurisdiction of Industrial Identification No.)
Incorporation or Classification Code
Organization) Number)
1155 Perimeter Center West
Atlanta, Georgia 30338-4780
(678) 579-5000
(Address, Including Zip Code, and Telephone Number, Including Area Code, of
Registrant's Principal Executive Offices)
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Gary J. Kubik
1155 Perimeter Center West
Atlanta, Georgia 30338-4780
(678) 579-5000
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code,
of Agent for Service)
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With a copy to:
John T. W. Mercer, Esq. Sarah M. Ward, Esq.
Troutman Sanders LLP Skadden, Arps, Slate, Meagher & Flom LLP
Bank of America Plaza, Suite 5200 Four Times Square
600 Peachtree Street, N.E. New York, New York 10036
Atlanta, Georgia 30308 (212) 735-3000
(404) 885-3000
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Approximate date of commencement of proposed sale to the public: As soon as
practicable after the effective date of this registration statement.
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance
with General Instruction G, check the following box. [_]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
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CALCULATION OF REGISTRATION FEE
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Proposed
Proposed Maximum
Title of each Class of Amount Maximum Aggregate Amount of
Securities To Be To Be Offering Price Offering Registration
Registered Registered Per Unit Price(1)(2) Fee(1)(2)(3)
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8.625% Exchange Pass
Through Certificates,
Series A............. $ 454,000,000 100% $ 454,000,000 $113,500
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9.125% Exchange Pass
Through Certificates,
Series B............. $ 435,000,000 100% $ 435,000,000 $108,750
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10.060% Exchange Pass
Through Certificates,
Series C............. $ 335,000,000 100% $ 335,000,000 $ 83,750
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Total................. $1,224,000,000 $1,224,000,000 $306,000
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(1) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457 under the Securities Act of 1933, as amended.
(2) The registration fee has been estimated based on the stated principal
amount of the securities to be received by the registrant in exchange for
the securities to be issued hereunder in the exchange offer described
herein.
(3) An aggregate registration fee of $306,000 was paid on May 25, 2001.
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The Registrant hereby amends this registration statement on such date or
dates as may be necessary to delay its effective date until the registrant
shall file a further amendment which specifically states that this
registration statement shall thereafter become effective in accordance with
Section 8(a) of the Securities Act of 1933 or until the registration statement
shall become effective on such date as the Commission, acting pursuant to
Section 8(a), may determine.
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FOR INFORMATION REGARDING CERTAIN DIFFERENCES BETWEEN THIS PROSPECTUS AND OUR
PROSPECTUS DATED JULY 6, 2001, SEE THE EXPLANATORY NOTE ON THE INSIDE FRONT
COVER OF THIS PROSPECTUS.
PROSPECTUS
MIRANT MID-ATLANTIC, LLC
Formerly Known As
Southern Energy Mid-Atlantic, LLC
$1,224,000,000
EXCHANGE OFFER
$454,000,000 Series A Certificates
$435,000,000 Series B Certificates
$335,000,000 Series C Certificates
(Representing Interests in Three Pass Through Trusts)
Interest Payable June 30 and December 30
This Exchange Offer We are offering to exchange new certificates
registered with the Securities and Exchange
Commission for existing certificates that we
previously offered in an offering exempt from the
Security and Exchange Commission's registration
requirements. The terms and conditions of this
exchange offer are summarized below and more fully
described in this prospectus.
Expiration Date 5:00 p.m. (New York City time) on August 15, 2001.
Withdrawal Rights Any time before 5:00 p.m. (New York City time) on
the expiration date.
Integral Multiples Old certificates may only be tendered in integral
multiples of $1,000.
Expenses Paid for by Mirant Mid-Atlantic, LLC.
New Certificates The new certificates will represent the same
fractional undivided interest in three pass through
trusts as the existing certificates they are
replacing. The new certificates will have the same
material financial terms as the existing
certificates, which are summarized below and
described more fully in this prospectus. The new
certificates will not contain terms with respect to
transfer restrictions.
Proceeds We will not receive any proceeds from this exchange
offer.
U.S. Federal Income Tax We believe that the exchange of existing
Consequences certificates will not be a taxable event for U.S.
Federal income tax purposes, but you should see
"Certain U.S. Federal Income Tax Consequences"
starting on page 129 for more information.
Use of Prospectus by Each broker-dealer that receives new certificates
Broker-Dealers for its own account pursuant to this exchange offer
must acknowledge that it will deliver a prospectus
in connection with any resale of such new
certificates. The letter of transmittal to be used
in connection with this exchange offer states that
by so acknowledging and by delivering a prospectus,
a broker-dealer will not be deemed to admit that it
is an "underwriter" within the meaning of the
Securities Act of 1933. This prospectus, as it may
be amended or supplemented from time to time, may be
used by a broker-dealer in connection with resales
of new certificates received in exchange for
existing certificates where such existing
certificates were acquired by such broker-dealer as
a result of market-making activities or other
trading activities. We have agreed that, for a
period of 180 days after the expiration date, we
will make this prospectus available to any broker-
dealer for use in connection with any such resale.
See "Plan of Distribution" starting on page 134 for
more information.
We do not intend to list the certificates on any securities exchange.
Investing in the certificates involves risk. See "Risk Factors" beginning on
page 29.
Principal Interest Final Expected
Certificates Amount Rate Distribution Date
------------ -------------- -------- -----------------
Series A......................... $ 454,000,000 8.625% June 30, 2012
Series B......................... 435,000,000 9.125 June 30, 2017
Series C......................... 335,000,000 10.060 December 30, 2028
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Total.......................... $1,224,000,000
The certificates represent interests in one of three pass through trusts
only and do not represent interests in or obligations of us, Mirant
Corporation or any other affiliate of Mirant Corporation.
We are relying on the position of the SEC staff in certain interpretive
letters to third parties to remove the transfer restrictions on the new
certificates.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these certificates or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.
The date of this prospectus is August 7, 2001.
You should rely only on the information provided in this prospectus. We have
authorized no one to provide you with different information. We are not making
an offer of these securities in any state where the offer is not permitted.
You should not assume that the information in this prospectus is accurate as
of any date other than the date on the front of this document.
TABLE OF CONTENTS
Prospectus Summary........................................................ 1
Forward-Looking Statements................................................ 28
Risk Factors.............................................................. 29
This Exchange Offer....................................................... 39
Ratio of Earnings to Fixed Charges........................................ 48
Use of Proceeds........................................................... 49
Capitalization............................................................ 50
Management's Discussion and Analysis of Financial Condition and Results of
Operations............................................................... 51
About Us and Our Affiliates............................................... 56
Our Business.............................................................. 59
Regulation................................................................ 70
Management................................................................ 76
Relationships with Affiliates and Related Transactions.................... 78
Description of Our Principal Contractual Arrangements with Non-Affiliated
Parties.................................................................. 83
Description of the Certificates........................................... 86
Description of the Lessor Notes........................................... 108
Description of the Leases and Other Lease Documents....................... 115
Certain U.S. Federal Income Tax Consequences.............................. 131
ERISA Considerations...................................................... 134
Plan of Distribution...................................................... 136
Legal Matters............................................................. 137
Independent Public Accountant............................................. 137
Independent Engineer...................................................... 137
Independent Market Expert................................................. 137
Available Information..................................................... 137
Financial Table of Contents............................................... F-1
Glossary of Electric Industry Terms....................................... G-1
Appendix A: Independent Engineer's Report
Appendix B: Independent Market Expert Report
EXPLANATORY NOTE
As described in greater detail in "Relationships with Affiliates and Related
Transactions--Our Arrangements with Mirant Americas Energy Marketing,"
effective August 1, 2001, our relationship with Mirant Americas Energy
Marketing was reconfigured to provide us with payments for our committed
capacity and energy which are not directly linked to spot prices for energy.
You should be aware that the assumptions utilized in the preparation of the R.
W. Beck Independent Engineer's Report attached as Appendix A to this
prospectus do not contemplate this revised structure. While we expect that,
during the term of this new contract, our net operating revenues should be
more stable as a result of this revised structure, we have not requested R. W.
Beck to update or revise the Independent Engineer's Report, nor have we
undertaken to update or revise any forward-looking statements based on that
report as a result of this revised structure.
Prospectus Summary
This summary highlights some of the information contained in this prospectus.
This summary may not contain all the information that is important to you.
Therefore, you should read this summary in conjunction with the more detailed
information appearing elsewhere in this prospectus. We encourage you to read
this prospectus in its entirety. In this prospectus, the words "Mirant Mid-
Atlantic," "we," "our," "ours," and "us" refer to Mirant Mid-Atlantic, LLC.
"Mirant" refers to Mirant Corporation and its direct and indirect subsidiaries
unless the context otherwise requires. In February 2001, Southern Energy, Inc.
changed its name to Mirant Corporation. Accordingly, the names of its
subsidiaries were also changed. You should consider the issues discussed in the
"Risk Factors" section beginning on page 29 when evaluating your investment in
the certificates. Electric industry terms that are used and not otherwise
defined in this prospectus have the meaning given to those terms in the
"Glossary" beginning on page G-1.
Mirant Mid-Atlantic, LLC
We are an indirect wholly-owned subsidiary of Mirant Americas Generation,
Inc., which is an indirect wholly-owned subsidiary of Mirant. We were formed as
a Delaware limited liability company on July 12, 2000 in conjunction with
Mirant's acquisition of 5,154 MW of generating assets and other related assets
from Potomac Electric Power Company, which we will refer to as Pepco.
The mailing address of our principal executive offices is 1155 Perimeter
Center West, Atlanta, Georgia 30338-4780. Our telephone number is (678) 579-
5000.
The Transaction Assets
Mirant Mid-Atlantic Assets
We own, either directly or indirectly through our subsidiaries, the following
assets, which we will refer to as the Mirant Mid-Atlantic assets:
. the 1,907 MW of baseload units and cycling units, fueled by coal, oil
and natural gas at the Chalk Point generating facility, located in
Prince George's County, Maryland;
. the 248 MW of peaking units, fueled by oil at the Morgantown generating
facility, located in Charles County, Maryland;
. the 291 MW of peaking units, fueled by gas and oil at the Dickerson
generating facility, located in Montgomery County, Maryland;
. the Brandywine ash storage facility, the Faulkner ash storage facility
and the Westland ash storage facility;
. the Piney Point oil pipeline; and
. the engineering and maintenance facility, located in suburban Maryland.
The MW totals shown for the generating facilities above and throughout this
prospectus correspond to the maximum capability of facilities in the summer
months.
Leased Facilities
In addition, we lease the following assets, which we will refer to as the
leased facilities:
. the 1,164 MW of baseload units, fueled by coal at the Morgantown
generating facility, located in Charles County, Maryland and related
assets; and
. the 546 MW of baseload units, fueled by coal at the Dickerson generating
facility, located in Montgomery County, Maryland and related assets.
1
Potomac River/Peaker Assets
Two direct wholly-owned subsidiaries of Mirant, Mirant Potomac River, LLC,
and Mirant Peaker, LLC, own or control the following assets, which we will
refer to as the Potomac River/Peaker assets:
. Mirant Potomac River owns the 482 MW Potomac River generating facility,
fueled by coal, located in Alexandria, Virginia; and
. Mirant Peaker owns or controls 516 MW of combustion turbines (including
the rights and obligations with respect to the 84 MW combustion turbine
owned by Southern Maryland Electric Cooperative) fueled by oil and gas,
located at the Chalk Point generating facility in Prince George's
County, Maryland.
Additionally, Mirant Potomac River has entered into a 20-year local area
support agreement with Pepco, pursuant to which Mirant Potomac River will
provide power and ancillary services to Pepco in a Washington, D.C. electric
load pocket.
Transaction Assets
We will refer to the Mirant Mid-Atlantic assets, the leased facilities and
the Potomac River/Peaker assets collectively as the transaction assets.
Operation of the Transaction Assets
We, our subsidiaries and our affiliates Mirant Potomac River and Mirant
Peaker, operate the assets that each of us owns, controls or leases. Another
indirect wholly-owned subsidiary of Mirant, Mirant Mid-Atlantic Services, LLC,
hired Pepco personnel in connection with the acquisition of the transaction
assets from Pepco and provides all operations, maintenance and general
management personnel to us, our subsidiaries and our affiliates. Mirant
Services, LLC, a direct wholly-owned subsidiary of Mirant, provides executive
personnel and administrative services to us, our subsidiaries and our
affiliates. We do not have any employees of our own.
2
Summary of this Exchange Offer
On December 18, 2000, we completed an offering of $454 million principal
amount of Series A certificates, $435 million principal amount of Series B
certificates and $335 million principal amount of Series C certificates that
was exempt from the SEC's registration requirements. In connection with that
offering, we entered into a registration rights agreement with the initial
purchasers of the existing certificates in which we agreed, among other things,
to deliver this prospectus to you and to use our reasonable best efforts to
complete this exchange offer by December 18, 2001.
This Exchange Offer....... We are offering to exchange:
. $1,000 principal amount of Series A certificates
which have been registered under the Securities
Act of 1933, as amended, for each outstanding
$1,000 principal amount of Series A
certificates,
. $1,000 principal amount of Series B certificates
which have been registered under the Securities
Act for each outstanding $1,000 principal amount
of Series B certificates, and
. $1,000 principal amount of Series C certificates
which have been registered under the Securities
Act for each outstanding $1,000 principal amount
of Series C certificates.
The form and terms of the new certificates that we
are offering in this exchange offer are identical
in all material respects to the form and terms of
the existing certificates which were issued on
December 18, 2000 in an offering that was exempt
from the SEC's registration requirements, except
that the new certificates that we are offering in
this exchange offer have been registered under the
Securities Act. The new certificates that we are
offering in this exchange offer will evidence the
same obligations as, and will replace, the existing
certificates and will be issued under the same pass
through trust agreements.
If you wish to exchange an existing certificate,
you must properly tender it in accordance with the
terms described in this prospectus. We will
exchange all existing certificates that are validly
tendered and are not validly withdrawn, subject to
the conditions described under "This Exchange
Offer--Conditions to this Exchange Offer."
As of this date, there are $454 million principal
amount of Series A certificates outstanding, $435
million principal amount of Series B certificates
outstanding and $335 million principal amount of
Series C certificates outstanding. This exchange
offer is not contingent upon any minimum aggregate
principal amount of existing certificates being
tendered for exchange. We will arrange for the pass
through trustee to issue the new certificates on or
promptly after the expiration of this exchange
offer.
Registration Rights
Agreement................ We are making this exchange offer in order to
satisfy our obligation under the registration
rights agreement, entered into on December 18,
2000, to cause our registration statement to become
effective under the Securities Act. You are
entitled to exchange your existing certificates for
new certificates with substantially identical
terms. After this exchange offer is complete, you
will generally no longer be entitled to any
registration rights with respect to your
certificates.
3
Resales of the New
Certificates............. Based on an interpretation by the staff of the SEC
set forth in no-action letters issued to third
parties, we believe that the new 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 are acquiring any new certificate in the
ordinary course of your business;
. you are not participating, do not intend to
participate, and have no arrangement or
understanding with any person to participate, in
the distribution of the new certificates;
. you are not a broker-dealer who purchased
existing certificates for resale pursuant to
Rule 144A or any other available exemption under
the Securities Act; and
. you are not an "affiliate" (as defined in Rule
405 under the Securities Act) of our company.
If our belief is inaccurate and you transfer any
new certificate without delivering a prospectus
meeting the requirements of the Securities Act or
without an exemption from registration of your
certificates from such requirements, you may incur
liability under the Securities Act. We do not
assume or indemnify you against this liability.
Each broker-dealer that receives new certificates
for its own account in exchange for certificates
must acknowledge that it will deliver a prospectus
meeting the requirements of the Securities Act in
connection with any resale of the new certificates.
The letter of transmittal states that, by making
this acknowledgment and by delivering a prospectus,
a broker-dealer will not be deemed to admit that it
is an "underwriter" within the meaning of the
Securities Act. A broker-dealer who acquired
existing certificates for its own account as a
result of market-making or other trading activities
may use this prospectus for an offer to resell,
resale or other transfer of the new certificates.
We have agreed that, for a period of 180 days
following the completion of this exchange offer, we
will make this prospectus and any amendment or
supplement to this prospectus available to any
broker-dealers for use in connection with these
resales. We believe that no registered holder of
the existing certificates is an affiliate (as the
term is defined in Rule 405 of the Securities Act)
of our company.
Accrued Interest on the
New Certificates and
Existing Certificates.... The new certificates will bear interest from the
most recent date to which interest has been paid on
the existing certificates. If your existing
certificates are accepted for exchange, then you
will receive interest on the new certificates and
not on the existing certificates.
Expiration Date........... This exchange offer will expire at 5:00 p.m., New
York City time, August 15, 2001, unless we extend
the expiration date.
4
Conditions to this
Exchange Offer........... Notwithstanding any other provisions of this
exchange offer or any extension of this exchange
offer, we will not be required to accept for
exchange, or to exchange, any existing
certificates. We may terminate this exchange offer,
whether or not we have previously accepted any
existing certificates for exchange, or we may waive
any conditions to or amend this exchange offer, if
we determine in our sole and absolute discretion
that this exchange offer would violate applicable
law or regulation or any applicable interpretation
of the staff of the SEC.
Withdrawal Rights......... You may withdraw the tender of your certificates at
any time prior to 5:00 p.m. New York City time, on
August 15, 2001.
Procedures for Tendering
Original Certificates.... Except as otherwise described in "This Exchange
Offer," you will have validly tendered your
existing certificates pursuant to this exchange
offer if the exchange agent receives at the address
described in this prospectus, prior to the
expiration date:
1) a properly completed and duly executed letter
of transmittal, with any required signature
guarantees, including all documents required by
the letter of transmittal; or
2) if the existing certificates are tendered in
accordance with the book-entry procedures set
forth in this prospectus, the tendering
certificate holder may transmit an agent's
message to the address listed in this
prospectus instead of a letter of transmittal.
In addition, on or prior to the expiration date:
1) the exchange agent must receive the existing
certificates along with the letter of
transmittal; or
2) the exchange agent must receive a timely book-
entry confirmation as described in this
prospectus of a book-entry transfer of the
tendered existing certificates into the
exchange agent's account at The Depository
Trust Company according to the procedure for
book-entry transfer, along with a letter of
transmittal or an agent's message in lieu of
the letter of transmittal; or
3) the holder must comply with the guaranteed
delivery procedures described in this
prospectus.
See "This Exchange Offer--Procedures for Tendering
Existing Certificates--Valid Tender."
Special Procedures for
Beneficial Holders....... If you are a beneficial owner of existing
certificates that are held by or registered in the
name of a broker, dealer, commercial bank, trust
company or other nominee or custodian, we urge you
to contact this entity promptly if you wish to
participate in this exchange offer.
Guaranteed Delivery
Procedures................ If you desire to tender existing certificates into
this exchange offer and:
1) the existing certificates are not immediately
available;
5
2) time will not permit delivery of the existing
certificates and all required documents to the
exchange agent on or prior to the expiration
date; or
3) the procedures for book-entry transfer cannot
be completed on a timely basis;
you may nevertheless tender the existing
certificates, provided that you comply with all of
the guaranteed delivery procedures set forth in
"This Exchange Offer--Guaranteed Delivery
Procedures."
U.S. Federal Income Tax
Consequences............. The exchange of certificates will not constitute a
taxable exchange for United States federal income
tax purposes. For a discussion of other U.S.
federal income tax consequences resulting from the
exchange, acquisition, ownership and disposition of
the new certificates, see "Certain U.S. Federal
Income Tax Consequences."
Use of Proceeds........... We will not receive any proceeds from the issuance
of certificates in this exchange offer. We will pay
all registration expenses incident to this exchange
offer.
Exchange Agent............ State Street Bank and Trust Company is serving as
exchange agent in connection with this exchange
offer.
Background of our Acquisition of the Transaction Assets
On June 7, 2000, Mirant entered into an asset purchase and sale agreement
with Pepco:
. to purchase, acquire the rights to, or lease the transaction assets,
including 5,154 MW of generating facilities, located in Maryland and
Virginia;
. to assume rights and obligations relating to 735 MW of capacity, under
five power purchase agreements;
. to sell power to Pepco to service its customer load for up to four years
under two separate transition power agreements;
. to enter into a local area support agreement in conjunction with the
purchase of the Potomac River generating facility; and
. to provide operations and maintenance services for the Pepco-owned
Buzzard Point and Benning generating facilities for a period of at least
three years.
The cash purchase price under the asset purchase and sale agreement was
$2,650 million, plus a $91 million adjustment for materials and supply
inventory, capital expenditures and the timing of the closing. In addition, an
indirect wholly-owned subsidiary of Mirant, Mirant Americas Energy Marketing,
LP, which was formerly known as Southern Company Energy Marketing L.P., was
assigned obligations pursuant to the power purchase agreements and the
transition power agreements which were estimated on December 19, 2000 to have a
before tax present value of approximately $2,300 million. Mirant assigned its
rights and obligations under the asset purchase and sale agreement to us, our
subsidiaries and our affiliates involved in the acquisition, and Mirant
executed and delivered to Pepco a parent guarantee to support the obligations
of subsidiaries under project agreements. In connection with the closing of the
acquisition, we assigned our rights to acquire the leased facilities to eleven
Delaware limited liability companies, called owner lessors, which acquired the
leased facilities directly from Pepco.
6
We did not assume any of the rights or obligations of the power purchase
agreements or the transition power agreements. Mirant assigned these agreements
to Mirant Americas Energy Marketing and provided a guarantee to Pepco of all
obligations of Mirant Americas Energy Marketing under the power purchase
agreements and the transition power agreements.
The Leveraged Lease Transactions
As a result of the acquisition from Pepco, four owner lessors each own an
undivided interest in baseload units 1, 2 and 3 of the Dickerson generating
facility, and another seven owner lessors each own an undivided interest in
baseload units 1 and 2 of the Morgantown generating facility. We have entered
into long-term leases for each of these undivided interests. These leases were
part of the leveraged lease transactions that raised approximately $1,523
million, which was used by the owner lessors to acquire undivided interests in
the leased facilities and to pay the lease transaction expenses.
The subsidiaries of the institutional investors who hold the membership
interests in the owner lessors are called the owner participants. Equity
funding by the owner participants plus transaction expenses paid by the owner
participants in the lease transactions totaled approximately $299 million. The
issuance and sale of the existing certificates raised the remaining $1,224
million.
The Leveraged Lease Financings
One pass through trust was created for each series of certificates. Each pass
through trust used its share of the proceeds of the offering of the existing
certificates to purchase one of three series of lessor notes issued by each
owner lessor. The lessor notes held in the pass through trusts represent, in
the aggregate, the entire debt portion of the lease transactions. Each trustee
of the pass through trusts will distribute the amount of payments of principal
and interest received by it as holder of the lessor notes to the certificate
holders of the pass through trust for which it is pass through trustee. A
certificate holder has an ownership interest only in the pass through trust
that is the issuer of the certificate held by the certificate holder.
We lease the leased facilities from the owner lessors under eleven separate
facility lease agreements. The terms and conditions of each lease are
substantially similar. At the same time, we lease to each owner lessor a ground
interest in the parcels of land on which the leased facilities are located
pursuant to a facility site lease. Each owner lessor also entered into a
facility site sublease agreement with us, according to which the ground
interests leased by us to each owner lessor is subleased by us from each owner
lessor.
The lessor notes issued by each owner lessor are secured by a lien on and a
first priority security interest in the rights and interests of that owner
lessor under the related lease and that owner lessor's undivided interest in
the Morgantown or Dickerson leased facility and other collateral as set forth
in "Description of Lessor Notes--Security." We refer to this collateral as the
lessor estate. The lessor estate does not include customary excepted payments
and excepted rights reserved to each owner lessor and the owner participant who
holds the membership interest in the owner lessor.
We will pay rent under each lease to the applicable owner lessor. However, as
a result of the assignment of each lease to an indenture trustee, who acts as
trustee under lease indentures corresponding to each undivided interest, we
will make rental payments directly to the indenture trustee. From these rental
payments, the indenture trustee will first make payments of principal, interest
and premiums, if any, due to the pass through trustee on the lessor notes
issued under the lease indentures and held in the pass through trusts and will
pay any remaining balance to the owner lessors for the benefit of the owner
participants. State Street Bank and Trust Company of Connecticut, National
Association is the pass through trustee of each pass through trust and is
indenture trustee under each lease indenture. The pass through trustee will
distribute to the certificate holders of the pass through trust for which it is
pass through trustee payments received on the lessor notes held in that pass
through trust.
7
Lease Transactions Cash Flow Structure
The following diagram illustrates the principal ongoing payment flows in the
lease transactions among us, the owner lessors, the owner participants, the
indenture trustees, the pass through trustees and the certificate holders.
[LEASE TRANSACTION CASH FLOW GRAPHIC]
8
Our Organization
The following chart illustrates our organization, the role of our
subsidiaries and our affiliates and the role of the owner lessors. Intermediate
parent companies of Mirant Americas Energy Marketing, Mirant Americas
Generation and Mirant Mid-Atlantic are not shown.
[ORGANIZATION GRAPHIC APPEARS HERE]
9
Our Competitive Strengths
. We, our subsidiaries and our affiliates have complete managerial and
operational control over the transaction assets, including the leased
facilities. We believe that this will enable us to enhance the financial
and operational performance of the transaction assets.
. The generating facilities represent 5,154 MW, or approximately 10%, of
the installed capacity in the power market covering all or part of the
states of Pennsylvania, New Jersey, Maryland, Delaware, Virginia and the
District of Columbia, a market known as the PJM.
. The generating facilities are well maintained, low cost and
environmentally sound.
. A significant portion of the generating facilities is comprised of low
cost baseload coal units providing increased stability of cash flows.
. The fuel diversity of units at the generating facilities and the mix of
baseload, cycling and peaking units enable us to respond quickly to a
variety of market conditions.
. Our facilities are located near Washington D.C. and can provide
capacity, energy and ancillary services to this load center when prices
are attractive.
. Our risk management and energy marketing affiliate, Mirant Americas
Energy Marketing, is one of the leading electricity and gas marketers in
the United States. Mirant Americas Energy Marketing's experience with a
variety of fuel, energy and related financial products will provide us
with enhanced market knowledge and greater marketing opportunities.
. We will utilize management and personnel who have significant operating
experience with the generating facilities.
Our Strategy
Our strategy is to establish and maintain a leading position in the PJM
wholesale electricity market and focus on serving wholesale customers in the
mid-Atlantic region. We intend to execute this strategy by implementing and
integrating the elements of Mirant's successful strategy for the North American
wholesale electricity market: comprehensive and efficient operations and
maintenance practices and sophisticated risk management with access to multiple
fuel and energy markets.
We will manage our maintenance and capital budgets to focus on achieving high
availability at times of peak prices. Our plant management and operators will
work in conjunction with our marketing affiliate, Mirant Americas Energy
Marketing, to schedule planned outages and facility maintenance when prices are
expected to be low. We intend to maintain an appropriate level of operations,
maintenance and capital expenditures consistent with our priority of high
availability at peak times.
We manage our fuel and energy price risk through Mirant Americas Energy
Marketing which utilizes the liquid trading hubs for electricity, natural gas,
fuel oil and coal in the mid-Atlantic region. Mirant Americas Energy Marketing
sells capacity, ancillary services and energy to other participants in the
wholesale markets including the PJM. Sales may range from short-term hourly
transactions to bilateral sales agreements that extend several years. Effective
August 1, 2001, we entered into an agreement with Mirant Americas Energy
Marketing that provides for us to receive payments for our committed capacity
and energy which are not directly linked to spot prices for energy. This
agreement expires in 2004. Mirant Americas Energy Marketing also procures our
fuel. Many of our units are able to run on multiple fuels, offering us the
flexibility to respond to changes in prices of coal, fuel oil, natural gas and
electricity. Purchases of fuel may range from spot purchases to long-term
agreements.
Mirant Americas Energy Marketing seeks to respond quickly to a variety of
changing market signals. It will bid and schedule our generation portfolio to
maximize the value of the diverse mix of baseload, cycling and peaking units
that we operate.
10
Mirant Corporation
Our indirect parent, Mirant, is a global competitive energy company with
leading energy marketing and risk management expertise. Mirant has extensive
operations in North America, Europe and Asia. With an integrated business
model, Mirant develops, constructs, owns and operates power plants, and sells
wholesale electricity, gas and other energy-related commodity products. Mirant
owns or controls more than 21,600 MW of electric generating capacity around the
world, with approximately 9,000 MW of additional capacity under development. In
North America, Mirant also controls access to approximately 3.0 billion cubic
feet per day of natural gas production, more than 2.9 billion cubic feet per
day of natural gas transportation capacity and approximately 41 billion cubic
feet of natural gas storage.
Mirant uses its risk management capabilities to optimize the value of its
generating and gas assets and offers these risk management services to others.
Mirant also owns electric utilities with generation, transmission and
distribution capabilities and electricity distribution companies. Mirant's
strategy is to expand its business through ownership, leasing or control of
additional natural gas and electricity assets to continue its rapid growth.
Mirant intends to capitalize on opportunities in markets where Mirant's unique
combination of strengths in physical asset management, electricity generation,
management of gas assets and energy marketing and risk management services
allows it to position the company as a leading provider of energy products and
services. According to the McGraw-Hill publication 210 Independent Power
Companies: Profiles of Industry Players and Projects, Mirant was ranked as the
sixth largest independent power producer in July 2000. Mirant's goal is to have
a diversified North American portfolio of owned or controlled generation
exceeding 30,000 MW by 2004.
Mirant was formerly a subsidiary of Southern Company. In October 2000, Mirant
closed an initial public offering of 66.7 million shares, or 19.7%, of its
common stock. On April 2, 2001, Southern Company distributed the remaining
shares of Mirant's common stock to holders of Southern Company's common stock
and Mirant ceased being its subsidiary. In April 2001, Mirant was added to the
S&P 500 index. For more information on the distribution, see Southern Company's
Information Statement filed on Form 8-K with the SEC on March 6, 2001.
11
Summary of Terms of the New Certificates
The form and terms of the new certificates are the same as the form and terms
of the existing certificates except that the new certificates will be
registered under the Securities Act and, therefore, will not bear legends
restricting their transfer and, in general, will not be entitled to
registration under the Securities Act. The new certificates will evidence the
same obligations as the existing certificates and both the existing
certificates and the new certificates are governed by the same pass through
trust agreements.
The certificates are not our direct obligation. Each certificate represents a
fractional undivided interest in one of three pass through trusts formed
pursuant to three separate pass through trust agreements between us and State
Street Bank and Trust Company of Connecticut, National Association, as pass
through trustee under each pass through trust agreement.
The property of the pass through trusts consist of lessor notes. The lessor
notes were issued by the owner lessors in connection with eleven separate
leveraged lease transactions with respect to each owner lessor's undivided
interest in either (i) the Dickerson electric generating baseload units 1, 2
and 3 and related assets or (ii) the Morgantown electric generating baseload
units 1 and 2 and related assets. The lessor notes issued by an owner lessor
are secured by that owner lessor's undivided interest in the leased facilities
and its rights under the related lease and other related financing documents.
The lessor notes issued by each owner lessor were issued in three series.
Each pass through trust purchased one series of the lessor notes issued by each
owner lessor so that all of the lessor notes held in each pass through trust
have an interest rate corresponding to the interest rate, and a final maturity
on or before the final expected distribution date, applicable to the
certificates issued by that pass through trust. Interest paid on the lessor
notes held in each pass through trust will be distributed by each pass through
trust to its certificate holders on June 30 and December 30 of each year,
commencing June 30, 2001. Principal payments on the lessor notes held in each
pass through trust will be distributed by each pass through trust to its
certificate holders on June 30 and December 30 of each year, commencing June
30, 2001.
Although neither the certificates nor the lessor notes are obligations of, or
guaranteed by, us, the amount unconditionally payable by us under our leases of
the leased facilities will be at least sufficient to pay in full when due all
payments of principal of, premium, if any, and interest on the lessor notes.
Our lease obligations will not be obligations of, or guaranteed by, our
indirect parent, Mirant, or any of its other affiliates.
Securities Offered.............. $1,224,000,000 aggregate principal amount of
certificates, Series A, Series B and Series
C.
Lessee.......................... Mirant Mid-Atlantic, LLC.
Ratings......................... Standard & Poor's Ratings Services (a
division of the McGraw-Hill Companies, Inc.),
Moody's Investor Service, Inc. and Fitch,
Inc. have assigned a rating to the
certificates of BBB-, Baa3 and BBB,
respectively.
Pass Through Trusts............. The certificates will be offered by three
pass through trusts. The pass through trusts
were formed pursuant to three separate pass
through trust agreements between us and the
pass through trustee.
12
Principal Amount................ 100% of the principal amount of each series
of certificates is as follows:
Principal
Certificate Amount
----------- --------------
Series A............... $ 454,000,000
Series B............... 435,000,000
Series C............... 335,000,000
--------------
Total................ $1,224,000,000
Interest........................ Interest will accrue on the principal amount
of the lessor notes at the applicable annual
rate as set forth below. Interest will be
payable on the lessor notes, and
distributions will be made under the
certificates, semiannually in arrears on June
30 and December 30 of each year, commencing
on June 30, 2001.
Certificate Annual Interest Rate
----------- --------------------
Series A......... 8.625%
Series B......... 9.125
Series C......... 10.060
Payment Dates...................
Principal payments will be made on the lessor
notes and the resulting distributions will be
made on the certificates according to the
amortization schedule on pages 87-88.
Average Life....................
Certificates within a series will be paid-off
over varying periods of time, but the initial
average life of each series of certificates,
calculated from December 18, 2000, will be as
follows:
Certificate Average Life
----------- ------------
Series A................. 6.2 years
Series B................. 13.0 years
Series C................. 20.0 years
Ranking of Our Lease Payment Our lease payment obligations will be our
Obligations.................... senior unsecured obligations and will rank
equally in right of payment with all of our
other existing and future senior unsecured
obligations. These payment obligations will
not be guaranteed by Mirant or any of its
affiliates, but Mirant has issued a guarantee
for the benefit of the owner lessors in the
amount described under "--Credit Support,"
below.
Pass Through Trust Property..... The property of each pass through trust
consists solely of the applicable lessor
notes issued on a nonrecourse basis by each
of the owner lessors in separate lease
transactions. Each owner lessor issued three
series of lessor notes, with notes of each
series having an interest rate corresponding
to the interest rate applicable to the
corresponding series of lessor notes of each
other owner lessor. Each pass through trust
purchased one series of the lessor notes
issued by each owner lessor so that all the
lessor notes held in each pass through trust
have an
13
interest rate corresponding to the interest
rate, and a final maturity on or before the
final expected distribution date, applicable
to the certificates issued by the pass
through trust.
Lessor Notes Collateral......... The lessor notes issued by each owner lessor
are secured by:
. the facility lease to which the owner
lessor is a party, including the owner
lessor's right to receive rental payments
under its lease;
. the owner lessor's undivided interest;
. the owner lessor's interest in any
components and improvements in connection
with its undivided interest;
. the facility site lease to which the owner
lessor is a party;
. the facility site sublease to which the
owner lessor is a party and the ground
interest subject to the facility site
sublease;
. the fixtures on the leased facility land
relating to the owner lessor's undivided
interest;
. the facility deed relating to the owner
lessor's undivided interest;
. the bill of sale relating to the owner
lessor's undivided interest;
. the participation agreement to which the
owner lessor is a party, which contains
covenants, representations and warranties,
indemnification terms and other provisions
related to the acquisition, ownership and
lease of the leased facilities;
. the shared facilities agreement regarding
the Dickerson facilities or the shared
facilities agreement regarding the
Morgantown facilities. These agreements,
between us and the owner lessors, relate
to the use of equipment and facilities by
us and the owner lessors after the
termination of any lease;
. the credit support described under "--
Credit Support," below;
. the ownership and operation agreement
regarding the Dickerson facilities or the
ownership and operation agreement
regarding the Morgantown facilities. These
agreements, between us and the owner
lessors, provide for the appointment of an
operator for any facility upon the
expiration or termination of a facility
lease; and
. each other operative document (as defined
under "Description of the Certificates" in
this prospectus) to which the owner lessor
is a party (other than the tax indemnity
agreement).
For further discussion regarding the
collateral for the lessor notes, see
"Description of the Lessor Notes--Security."
14
No Cross Collateralization of
Lessor Notes or Cross Default
Provisions..................... Each lessor note issued in a lease
transaction will not be cross collateralized
with, or generally cross-defaulted to, the
lessor notes issued under the other lease
transactions. Thus, an event of default under
one lease may not necessarily trigger an
event of default under the other leases.
However, the covenants under each set of
operative documents are identical (except
that there are certain leased facility
specific covenants, such as maintenance and
insurance, which relate to the applicable
leased facility).
Optional Redemption............. Upon an optional refinancing of any series of
lessor notes, we may request the owner
lessors of a particular leased facility to
redeem that series of lessor notes (and
consequently cause the pass through trusts to
redeem the related series of certificates) at
a redemption price equal to:
. 100% of the principal amount of the lessor
notes being redeemed, plus
. accrued interest on the lessor notes being
redeemed, plus
. a make-whole premium in an amount equal to
the discounted present value (calculated
based on the rates of comparable treasury
securities plus 50 basis points) of the
applicable lessor note less the principal
amount and accrued interest of that lessor
note.
We have agreed not to request that any lessor
notes be refinanced unless all lessor notes
in a particular series are being redeemed. In
addition, we will not request an optional
refinancing of any lessor notes prior to
December 19, 2007 without the consent of the
applicable owner participants.
In addition, with our consent, each owner
lessor may, at its option, redeem all or a
portion of the lessor notes issued by it on
any date at a redemption price equal to 100%
of the principal amount of the lessor notes
being redeemed, plus accrued interest on the
lessor notes being redeemed, plus a make-
whole premium in an amount equal to the
discounted present value (calculated based on
the rates of comparable treasury securities
plus 50 basis points) of the applicable
lessor note less the principal amount and
accrued interest of that lessor note.
Mandatory Redemption With
Premium........................ At any time on or after December 19, 2007, if
we elect to terminate the applicable leases
because the related leased facility is:
. economically or technologically obsolete
for reasons other than the reasons in item
(3) below under "Mandatory Redemption
Without Premium," below, or
. surplus to our needs or no longer useful
in our trade or business,
15
then, all lessor notes outstanding under the
lease indentures relating to that facility
will be redeemed, in whole but not in part,
at a redemption price equal to:
. 100% of the principal amount of the lessor
notes being redeemed, plus
. accrued interest on the lessor notes being
redeemed, plus
. a make-whole premium in an amount equal to
the discounted present value (calculated
based on the rates of comparable treasury
securities plus 50 basis points) of the
applicable lessor note less the principal
amount and accrued interest of that lessor
note.
Mandatory Redemption Without
Premium........................ Upon receipt by an indenture trustee of
proceeds in connection with any of the
circumstances described below, all lessor
notes outstanding under the related lease
indenture will be redeemed, in whole but not
in part, at a redemption price equal to 100%
of the principal amount of the lessor notes
being redeemed plus accrued interest, but
without any premium:
(1) any owner participant or owner lessor is
then subject to any public utility
regulation that renders it materially
burdensome to participate in the lease
transactions, which we refer to as a
regulatory event of loss, unless either
. we purchase the membership interest in
the applicable owner lessor and waive
the regulatory event of loss, and the
lease between us and that owner lessor
remains in effect, or
. we assume the related lessor notes;
(2) any event of loss, other than a
regulatory event of loss, occurs with
respect to a leased facility, unless we
elect to rebuild or replace the affected
leased facility, and the event of loss
results in the termination of the related
leases;
(3) we elect to terminate the leases with
respect to one of the leased facilities
following a good faith determination that
such leased facility is economically or
technologically obsolete as a result of:
. a change in law, regulation or tariff
of general application, or
. the imposition by the Federal Energy
Regulatory Commission, or any other
governmental authority, of any
conditions or requirements (including
requiring significant capital
improvements to the affected leased
facility) upon the initial issuance,
continued effectiveness, or renewal of
any license or permit required for the
operation or ownership of such leased
facility; or
16
(4) we exercise our option to terminate one
or more of the leases with respect to a
leased facility (except in circumstances
in which we assume the applicable lessor
notes) if:
. a change in law causes it to become
illegal for us to continue a lease or
to make payments under a lease and the
other operative documents related to
that lease, and the transactions
contemplated by those operative
documents cannot be restructured to
comply with the change in law; or
. one or more events not deliberately
caused by us or any of our affiliates,
wholly or partially for the purposes
of exercising this termination option,
occurs that gives rise to indemnity
obligations under the operative
documents, such obligations can be
avoided if that lease is terminated
and the related owner lessor sells its
interest leased thereunder to us, and
the present value of such avoided
payments would exceed 2.5% of the
original purchase price of such
interest.
Covenants....................... Documents related to our lease of the leased
facilities include covenants that limit,
among other things, our ability to incur
indebtedness, to make restricted payments, to
sell, transfer or otherwise dispose of
assets, to merge or consolidate, to change
our legal form, to create liens, or to
assign, transfer or sublease our interest in
the leased facilities. See "Description of
the Certificates--Covenants" and "Description
of the Leases and Other Lease Documents."
Documents related to our lease of the leased
facilities also include covenants that limit,
among other things, the ability of Mirant
Chalk Point, Mirant Potomac River and Mirant
Peaker, which we refer to collectively as
designated subsidiaries, to incur
indebtedness, to sell, transfer or otherwise
dispose of assets, to merge or consolidate,
or to create liens. We have the right, but
not the obligation, to designate any other
wholly-owned subsidiary as a designated
subsidiary and a subsidiary so designated
shall be and remain thereafter a designated
subsidiary.
Change of Control............... It is an event of default under the leases if
Mirant's direct or indirect beneficial
ownership in us is reduced to less than 50%,
unless Moody's and S&P confirm that the then
existing ratings for the certificates will
not be lowered as a result of the reduction.
Credit Support.................. Uncollateralized, irrevocable, unconditional
stand-by letters of credit or surety bonds
provided by a bank or surety rated at least A
by S&P and A2 by Moody's, or guarantees by
any of our affiliates rated at least BBB- by
S&P and Baa3 by Moody's, in either case for
the benefit of the owner lessors and
17
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. Currently,
Mirant has issued a guarantee for the benefit
of the owner lessors to fulfill our
obligations to provide this credit support.
Governing Law................... The certificates, the pass through trust
agreements, the lease indentures and the
lessor notes will be governed by the laws of
the State of New York.
Book-Entry, Delivery and Form... Certificates will be issuable in
denominations of $100,000 or any integral
multiple of $1,000 in excess of that amount.
Each series of certificates sold to qualified
institutional buyers in reliance on Rule 144A
is represented by restricted global
certificates in registered form, without
interest coupons, and has been deposited with
the pass through trustee as custodian for,
and registered in the name of DTC or Cede &
Co., its nominee, in each case for credit to
an account of a direct or indirect
participant of DTC. See "Description of the
Certificate--Book-Entry; Delivery and Form."
Indenture and Pass Through
Trustee........................ State Street Bank and Trust Company of
Connecticut, National Association acts as
pass through trustee, paying agent and
registrar for the certificates to be issued
by each pass through trust. State Street Bank
and Trust Company of Connecticut, National
Association also acts as the indenture
trustee for the lessor notes.
Risk Factors.................... Your investment in the certificates involves
risks, including, without limitation, risks
related to the uncertainties associated with
the competitive market in which we operate,
environmental liabilities, risks related to
the structure of the lease transactions and
the operation of the generating facilities.
See "Risk Factors."
18
Selected Financial Information
(in millions)
For the Period from
For the Three July 12, 2000
Months Ended (Inception) Through
March 31, 2001 December 31, 2000
-------------- -------------------
Income Statement Data:
Operating Revenues.......................... $ 281 $ 40
------ -------
Operating Expenses:
Cost of fuel, electricity and other
products................................. 127 14
Labor..................................... 20 3
Depreciation and amortization............. 18 2
Rental.................................... 24 3
Maintenance............................... 7 --
Selling, general and administrative....... 6 6
Other..................................... 14 4
------ -------
Operating income............................ 65 8
Other income (expense):
Interest income........................... 6 1
Interest expense.......................... (2) --
Financing Fees............................ (1) (4)
------ -------
Net income.................................. $ 68 $ 5
====== =======
Statement of Cash Flows Data:
Cash flow from operating activities......... $ 99 $ 2
Cash flow from investing activities......... (109) (1,142)
Cash flow from financing activities......... -- 1,162
Noncash investing and financing activity.... 108 1,602
Other Operating Data:
EBITDA (1).................................. $ 83 $ 10
Ratio of earnings to fixed charges (2)...... 4.1x 2.5x
As of As of
March 31, 2001 December 31, 2000
-------------- -------------------
Balance Sheet Data:
Cash and cash equivalents................... $ 12 $ 22
Property, plant, and equipment, net......... 1,035 1,030
Total assets................................ 3,058 2,936
Payables to related parties................. 101 186
Members' equity............................. 2,872 2,694
- --------
(1) EBITDA represents our operating income plus depreciation and amortization.
EBITDA, as defined, is presented because it is widely accepted financial
indicator used by some investors and analysts to analyze and compare
companies on the basis of operating performance. EBITDA, as defined, is not
intended to represent cash flows for the period, nor is it presented as an
alternative to operating income or as an indicator of operating
performance. It should not be considered in isolation or as a substitute
for a measure of performance prepared in accordance with generally accepted
accounting principles (GAAP) in the United States and is not indicative of
operating income or cash flow from operations as determined under GAAP. Our
method of computation may or may not be comparable to other similarly
titled measures by other companies.
(2) The term "fixed charges" means the sum of the following: (a) interest
expensed and capitalized, (b) amortized premiums, discounts and capitalized
expenses related to indebtedness and (c) an estimate of imputed interest
within rental expense. The term "earnings" means pretax income from
continuing operations, plus (a) fixed charges and (b) amortization of
capitalized interest, minus interest capitalized.
19
Summary of the Independent Engineer's Report
Prior to the acquisition of the transaction assets from Pepco, our
independent engineer, R.W. Beck, Inc., prepared a report dated December 7,
2000, and amended April 26, 2001, a copy of which is set forth in its entirety
as Appendix A to this prospectus. Following is a summary of the conclusions
reached by the independent engineer in its report. The independent engineer's
conclusions are subject to the assumptions and qualifications set forth in the
independent engineer's report, and you should read this summary in conjunction
with the full text of the independent engineer's report.
Our independent accountant has neither examined nor compiled the accompanying
prospective financial information and, accordingly, does not express an opinion
or any other form of assurance with respect thereto.
As described in greater detail in "Relationships with Affiliates and Related
Transactions--Our Arrangements with Mirant Americas Energy Marketing,"
effective August 1, 2001, our relationship with Mirant Americas Energy
Marketing was reconfigured to provide us with payments for our committed
capacity and energy which are not directly linked to spot prices for energy.
You should be aware that the assumptions utilized in the preparation of the R.
W. Beck Independent Engineer's Report attached as Appendix A to this prospectus
do not contemplate this revised structure. While we expect that, during the
term of this new contract, our net operating revenues should be more stable as
a result of this revised structure, we have not requested R. W. Beck to update
or revise the Independent Engineer's Report, nor have we undertaken to update
or revise any forward-looking statements based on that report as a result of
this revised structure, including the discussions in this summary.
The independent engineer has expressed the following opinions:
. The sites for the generating facilities are suitable for the generating
facilities' continued operation.
. The generating facilities have been designed and constructed with good
engineering practices and generally accepted industry practices, and the
technologies in use at the generating facilities are sound, proven
conventional methods of electric generation. If operated and maintained
as proposed by Mirant Mid-Atlantic, the generating facilities should be
capable of meeting the currently applicable environmental permit
requirements. Furthermore, all off-site requirements of the generating
facilities have been adequately provided for, including fuel supply,
water supply, ash and waste-water disposal and electrical
interconnections.
. The generating facilities should have a useful life extending beyond the
term of the certificates.
. The environmental site assessments of the sites for the generating
facilities were conducted in a manner consistent with industry
standards, using comparable industry protocols for similar studies with
which the independent engineer is familiar.
. The major permits and approvals required to operate the generating
facilities have been obtained and are currently valid or are in the
process of being renewed, and the independent engineer is not aware of
any technical circumstances that would prevent the renewal of any
permit.
. By combining the demonstrated experience of the existing Pepco personnel
and programs and the experience of the Mirant operating subsidiaries,
Mirant Mid-Atlantic should have sufficient capability to operate the
generating facilities effectively. The operating programs and procedures
which are currently in place are consistent with generally accepted
practices in the industry, and the generating facilities have
incorporated organizational structures that are comparable to other
generating facilities using similar technologies.
. Based on the operating history, a review of the operations and
maintenance practices and procedures, and general observations of the
plants, the generating facilities should be capable of achieving the
20
projected annual average net capacities, annual availability factors,
and net heat rates assumed in the projected operating results.
. The generating facilities appear to be operating in material compliance
with applicable environmental permits, approvals, consent orders, laws,
rules and regulations.
. Mirant Mid-Atlantic's estimate of the costs of operating and maintaining
the generating facilities, including provision for capital expenditures
and major maintenance, is within the range of the costs of similar
plants with which the independent engineer is familiar.
. For the base case projected operating results, the projected revenues
from the sale of electricity are adequate to pay annual operating and
maintenance expenses (including capital expenditures and major
maintenance), fuel expenses, and other operating expenses. Such revenues
provide an annual coverage on the certificates of at least 3.16 times
the annual fixed charge requirement (including rent) in each year during
the term of the certificates, and a weighted average coverage of 5.62
times the annual fixed charge requirement (including rent) over the term
of the certificates.
Several sensitivity analyses on the base case assumptions set forth in the
projected operating results were performed, including analyses based on: (a)
market prices, energy sales and fuel prices that are consistent with the low
fuel prices case prepared by the independent market expert; (b) market prices,
energy sales and fuel prices that are consistent with the capacity overbuild
case prepared by the independent market expert; (c) a 5% decrease in the
availability of the generating facilities; (d) a 5% increase in the heat rates
of the generating facilities; and (e) a 10% increase in the non-fuel operating
expenses of the generating facilities.
Set forth below is a table showing the projected fixed charge coverage
ratios (the ratios of projected net operating cash flows to the annual fixed
charge requirement (including 100% of rent)) in various scenarios addressed by
the independent engineer. The cash flows referred to in the preceding sentence
include those of the generating facilities acquired by Mirant Potomac River
and Mirant Peaker. The table sets forth the minimum fixed charge coverage
ratio in any year during the term of the certificates and the weighted average
coverage ratio over the term of the certificates.
Minimum
Fixed Charge Weighted Average
Coverage Ratio Coverage Ratio
-------------- ----------------
Base case............... 3.16x 5.62x
Low fuel prices case.... 3.00x 5.09x
Capacity overbuild
case................... 2.08x 5.20x
Decreased availability
case................... 2.94x 5.23x
Increased heat rate
case................... 2.97x 5.34x
Increased operating and
maintenance case....... 2.98x 5.34x
21
Summary of the Independent Market Expert Report
PA Consulting Services Inc. (PA), formerly PHB Hagler Bailly, Inc., our
independent market expert, has prepared an independent market expert report
dated April 10, 2001, a copy of which is attached as Appendix B to this
prospectus.
In the preparation of the independent market expert report, which we refer to
as the "power market report," and the opinion contained in the power market
report, the independent market expert has 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 expert 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 predominant. Nevertheless, in both types of markets, new
generating capacity will be developed based on the revenue streams determined
through competition. The type of market that exists in a given region will
determine the composition of the revenue streams and will affect the mix and
timing of new generating units. However, 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.
Many of the vertically integrated utilities are divesting their generation
assets, and the 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 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.
22
Forecasting Methodology
The following is PA's description of its forecasting methodology.
PA employs its proprietary market valuation process, MVPSM, to estimate the
value of electric generation units based upon the level of energy prices and
their volatility. MVPSM 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 MVPSM 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. MVPSM 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.
MVPSM uses a real options approach to value electric generating capacity,
thereby capturing 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).
However, unlike most option analyses, 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. A unit may also have constraints
placed upon its operation that limit its ability to capture margins when the
spread is positive (price is greater than variable cost) or to avoid losses
when the spread is negative (variable cost is greater than price). Hence, the
second step of MVPSM focuses on the ability of a generation unit to capture
margins, given its cost structure and constraints on operation.
PA'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
. compensation for capacity, which represents the additional margin
necessary to keep an economic amount of capacity in the market.
PA uses a detailed chronological production-costing model to simulate energy
price formation in the market area of interest. From the energy price analysis,
PA 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 PA'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.
23
Key Assumptions
In developing its capacity and energy market price forecasts for the PJM
market, the independent market expert 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
expert report, as well as the input assumptions used in its volatility
analyses. The following discussion describes some key assumptions used by the
independent market expert in arriving at its forecasts of capacity and energy
prices.
Demand. PJM peak demand is forecasted to grow at an average annual growth
rate of approximately 1.45% from 2001 through 2020.
Fuel prices. 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-Central region where the assets
that are owned or leased by Mirant Mid-Atlantic are located. PA also has
modeled near-term fuel prices (gas and oil) based on recent actual spot prices
and futures prices through December 2003, trending back to the long-term
consensus view by 2005. Table 1 displays the price projection for gas in PJM-
Central for this analysis.
Table 1
PJM-Central Delivered Fuel Prices (real 2000 $/MMBtu)/1/
Fuel 2001/2/ 2005 2010 2015 2020
---- ------- ---- ---- ---- ----
Natural Gas.................................... 5.55 2.92 3.07 3.15 3.22
Fuel Oil No. 2................................. 7.14 4.56 4.65 4.85 5.02
Fuel Oil No. 6................................. 4.63 2.98 3.03 3.16 3.27
- --------
1. The prices shown represent the prices for existing units. New units are
assumed not to pay local distribution company, or LDC, charges of
$0.05/MMBtu to $0.10/MMBtu.
2. The 2001 delivered price is based on average daily New York Mercantile
Exchange, or NYMEX, closing prices from September 13, 2000 to December 12,
2000.
Capacity additions. Based on assessments of the status of announced plants,
PA has estimated operational capacity additions of 5,730 MW in PJM 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,
20,940 MW of new capacity is added in PJM from 2004 through 2020, and 6,431 MW
is retired.
Results
Using the assumptions presented in its report, PA developed a Base Case for
each region that reflects PA's 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. The Base Case and three sensitivity cases are
described below:
. The Base Case incorporates the actual spot and futures gas and oil
prices through December 2003. Prices then decrease linearly to the
consensus forecast price in year 2005.
. The Low Fuel Case evaluates the effects of lower gas and oil prices
represented as a $0.50/MMBtu reduction in the 2001 gas and oil prices
with escalation remaining unchanged (coal prices are not changed).
. The High Fuel Case evaluates the effects of higher gas and oil prices
throughout the study period. Gas and oil prices are held at the 2001
NYMEX value throughout the study period.
24
. The Overbuild Case evaluates an over-exuberance of merchant plant
development in the regions reviewed. 4,160 MW of additional merchant
plant capacity is added in the Overbuild Case in 2004.
The all-in market price combines the energy price with the price received by
generators for other relevant generation services and energy products in the
PJM market. The all-in price reflects PA's estimate of the total market price
that generators will recover in PJM-Central. The all-in price results of the
study are summarized in Figure 1.
[Graph appears here]
Figure 1
PJM-Central Estimated All-In Price Forecasts(1) ($/MWh)
Year Base Case High Fuel Low Fuel Overbuild
- ---- ---------- --------- -------- ---------
2001 37.47 37.21 35.68 37.47
2002 33.64 35.46 32.56 33.64
2003 34.05 36.79 32.73 34.05
2004 31.89 37.01 30.94 29.77
2005 30.95 37.64 30.18 27.06
2006 31.63 40.06 30.27 27.63
2007 31.53 40.24 30.17 28.61
2008 31.58 40.69 30.29 30.08
2009 31.83 41.69 30.20 30.78
2010 32.18 42.83 30.34 31.09
2011 31.89 43.54 30.12 31.38
2012 31.70 43.71 30.12 31.06
2013 31.76 43.74 30.06 31.14
2014 31.69 44.45 29.93 31.12
2015 31.70 45.08 29.90 31.19
2016 31.67 45.18 29.91 31.18
2017 31.76 45.53 29.99 31.32
2018 31.85 45.66 29.97 31.49
2019 31.90 45.51 30.04 31.42
2020 32.12 46.15 30.24 31.53
- ------------
(1) Results are expressed in real 2000 dollars.
The dispatch curve for 2001 is shown in Figure 2. This curve orders
generation plants based upon short run variable cost (fuel and O&M). The
relative rankings of the plants that are owned or leased by Mirant Mid-Atlantic
are included on the graph.
25
Figure 2
PJM Dispatch Curve for 2001
[FIGURE 2 CHART APPEARS HERE]
Cumulative Capacity (MW)
Peak Demand = 51,267 MW With Reserve 18% = 60,495 MW
A Chalk Pt 1 J Chalk Pt CT 6 R Morgantown 2
B Chalk Pt 2 K Chalk Pt SMCT S Morgantown CT 1-2
C Chalk Pt 3 L Dickerson 1 T Morgantown CT 3-6
D Chalk Pt 4 M Dickerson 2 U Potomac River 1
E Chalk Pt CT 1 N Dickerson 3 V Potomac River 2
F Chalk Pt CT 2 O Dickerson CT 1 W Potomac River 3
G Chalk Pt CT 3 P Dickerson CT 2-3 X Potomac River 4
H Chalk Pt CT 4 Q Morgantown 1 Y Potomac River 5
I Chalk Pt CT 5
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 Mirant Mid-Atlantic
portfolio, offer decreased risk, as they portray fuel and unit diversity.
26
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) that have 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.
27
FORWARD-LOOKING STATEMENTS
Some of the statements under "Prospectus Summary," "Risk Factors,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "About Us and Our Affiliates," "Our Business" and elsewhere in
this prospectus include forward-looking statements in addition to historical
information. These statements involve known and unknown risks and relate to
future events, our future financial performance or our projected business
results. In some cases, you can identify forward-looking statements by
terminology such as "may," "will," "should," "expects," "plans,"
"anticipates," "believes," "estimates," "predicts," "potential" or "continue"
or the negative of these terms or other comparable terminology.
Forward-looking statements are only statements of intent, belief or
expectations. Actual events or results may differ materially from any forward-
looking statement as a result of various factors. These factors include:
. legislative and regulatory initiatives regarding deregulation,
regulation and restructuring of the electric utility industry;
. the extent and timing of the entry of additional competition in the
markets of our subsidiaries and affiliates;
. our pursuit of potential business strategies, including acquisitions or
dispositions of assets or internal restructuring;
. state, federal and other rate regulations in the United States;
. changes in or application of environmental and other laws and
regulations to which we and our subsidiaries and affiliates are subject;
. political, legal and economic conditions and developments in the United
States;
. financial market conditions and the results of our financing efforts;
. changes in market conditions, commodity prices and interest rates;
. weather and other natural phenomena;
. our ability to complete the development or acquisition of current and
future projects; and
. other factors, including the risks outlined under "Risk Factors"
beginning on page 29.
Although we believe that the expectations reflected in the forward-looking
statements are reasonable, we cannot guarantee future results, events, levels
of activity, performance or achievements. We have no obligation and do not
undertake any duty to update or revise any forward-looking statement after the
date of this prospectus or, in the case of the Independent Engineer's Report
and the Independent Market Expert Report attached as appendices to this
prospectus, after the dates of such reports, whether as a result of new
information, future events or otherwise.
As described in greater detail in "Relationships with Affiliates and Related
Transactions--Our Arrangements with Mirant Americas Energy Marketing,"
effective August 1, 2001, our relationship with Mirant Americas Energy
Marketing was reconfigured to provide us with payments for our committed
capacity and energy which are not directly linked to spot prices for energy.
You should be aware that the assumptions utilized in the preparation of the
R.W. Beck Independent Engineer's Report attached as Appendix A to this
prospectus do not contemplate this revised structure. We have not requested
R.W. Beck to update or revise the Independent Engineer's Report, nor have we
undertaken to update or revise any forward-looking statements based on that
report as a result of this revised structure.
28
RISK FACTORS
You should carefully consider the risks described below as well as other
information contained in this prospectus in evaluating an investment in the
new certificates and your participation in this exchange offer. The risks
described in this section are those that we consider to be the most
significant to our offering. If any of these events occur, our business,
financial condition or results of operations could be materially harmed and
you may lose all or part of your investment.
Risks Related To Our Business
Our revenues and results of operations depend in part on market and
competitive forces that are beyond our control.
Effective August 1, 2001, we entered into an agreement with Mirant Americas
Energy Marketing that provides for us to receive payments for our committed
capacity and energy which are not directly linked to spot prices for energy.
This agreement expires in 2004. However, Mirant Americas Energy Marketing has
the option to reduce the committed capacity and energy purchased each year,
and after December 31, 2002, may reduce the committed capacity and energy
purchased to zero. To the extent that our committed capacity and energy is not
sold under our agreement with Mirant Americas Energy Marketing, we will sell
capacity, energy and ancillary services from the generating facilities into
the PJM spot market or other competitive power markets or on a bilateral
contract basis, including through our power sales agreement with Mirant
Americas Energy Marketing. See "Relationships with Affiliates and Related
Transactions--Our Arrangements with Mirant Americas Energy Marketing." The
market for wholesale electric energy and energy services in the PJM market is
largely deregulated. We are not guaranteed any rate of return on our capital
investments through mandated rates. To the extent that our committed capacity
and energy is not sold under our agreement with Mirant Americas Energy
Marketing, 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. Among the
factors that will influence these prices, all of which are beyond our control,
are:
. prevailing market prices for fuel oil, coal and natural gas;
. the extent of additional supplies of electric energy and energy services
from our current competitors or new market entrants, including the
development of new generating facilities that may be able to produce
electricity at a lower cost than our generating facilities;
. the extended operation of nuclear generating plants in the PJM market
beyond their presently expected dates of decommissioning;
. prevailing regulations that affect the PJM market and other competitive
markets and regulations governing the independent system operators that
oversee these markets, including any price limitations and other
mechanisms to address some of the volatility or illiquidity in these
markets;
. weather conditions; and
. changes in the rate of growth in electricity usage as a result of such
factors as regional economic conditions and implementation of
conservation programs.
In addition, the independent system operators that oversee these markets may
impose price limitations and other mechanisms to address some of the
volatility in these markets. All of these factors could have an adverse impact
on our revenues and results of operations.
Changes in commodity prices may increase the cost of producing power and
decrease the amount we receive from selling power, resulting in financial
performance below our expectations.
Our generation business is subject to changes in power prices and fuel costs
that may impact our financial results and financial position by increasing the
cost of producing power and decreasing the amount we receive from the sale of
power. In addition, actual power prices and fuel costs may differ from those
assumed in the financial projections. As a result, our financial results may
not meet our expectations.
29
We are responsible for price risk management activities conducted by Mirant
Americas Energy Marketing for our facilities.
Mirant Americas Energy Marketing engages in price risk management activities
related to our sales of electricity and purchases of fuel and we receive the
revenues and incur the costs from these activities. Mirant Americas Energy
Marketing may use forward contracts and derivative financial instruments, such
as futures contracts and options, to manage market risks and exposure to
fluctuating electricity, coal and natural gas prices, and we bear the gains
and losses from these activities. Effective August 1, 2001, however, we
entered into an agreement with Mirant Americas Energy Marketing that provides
for us to receive payments for committed capacity and energy which are not
directly linked to spot prices for energy. This agreement expires in 2004.
However, Mirant Americas Energy Marketing has the option to reduce the
committed capacity and energy purchased each year, and after December 31,
2002, may reduce the committed capacity and energy purchased to zero. We
cannot assure you that these strategies will be successful in managing our
pricing risks, or that they will not result in net losses to us as a result of
future volatility in electricity and fuel markets.
Commodity price variability results from many factors, including:
. weather;
. illiquid markets;
. transmission or transportation inefficiencies;
. availability of competitively priced alternative energy sources;
. demand for energy commodities;
. natural gas, crude oil and coal production;
. natural disasters, wars, embargoes and other catastrophic events; and
. federal, state and foreign energy and environmental regulation and
legislation.
Furthermore, the risk management procedures we have in place may not always
be followed or may not always operate as planned. As a result of these and
other factors, we cannot predict with precision the impact that these risk
management decisions may have on our businesses, operating results or
financial position.
The transaction assets have not been operated historically on a competitive
basis and we have only a limited history of owning or operating the
transaction assets.
Substantially all of our business consists of operating the Mirant Mid-
Atlantic assets and the leased facilities. Although these assets had a
significant operating history prior to the time of their acquisition by us and
the owner lessors, they had all been operated as an integrated part of a
regulated utility and not on a competitive basis. Therefore, prior to their
recent acquisition by us and the owner lessors, the energy generated by these
assets had been sold by Pepco based upon rates set by regulatory authorities
rather than market prices. In addition, we have only a limited history of
owning or operating the transaction assets. As a result, we cannot assure you:
. that we will be successful in operating these assets in a competitive
environment in which energy rates will be set by market forces, or
. that these assets will perform as expected or that the revenues
generated by them will support the costs of operating them, the capital
expenditures needed to maintain them, our obligation to make rental
payments under the leases or our ability to pay the principal amount of
and interest on our indebtedness.
In addition, the only historical financial data available about us is for
the period beginning July 12, 2000, when we were formed, and the operating
results reflected in this historical financial data only date back to December
19, 2000, when the transaction assets were acquired from Pepco.
Operation of the generating facilities involves risks that could negatively
affect our ability to make lease payments to the owner lessors, which, in
turn, could negatively affect the pass through trustee's ability to make
payments due under the certificates.
The operation of the generating facilities included in the transaction
assets involves various operating risks, including:
. the output and efficiency levels at which those generating facilities
perform,
30
. interruptions in fuel supply,
. disruptions in the delivery of electricity,
. breakdown or failure of equipment (whether due to age or otherwise) or
processes,
. violation of permit requirements,
. shortages of equipment or spare parts,
. labor disputes,
. operator error,
. curtailment of operations due to transmission constraints,
. restrictions on emissions, and
. catastrophic events such as fires, explosions, floods, earthquakes or
other similar occurrences affecting power generating facilities.
We have a limited history of owning, leasing and operating our facilities.
Although most of our facilities had a significant operating history at the
time we acquired them, we have a limited history of owning, leasing and
operating these acquired facilities and operational issues may arise as a
result of our lack of familiarity with issues specific to a particular
facility or component thereof or change in operating characteristics resulting
from regulation. A decrease or elimination of revenues generated by our
facilities or an increase in the costs of operating our facilities could
decrease or eliminate funds available to us to make payments on the Notes or
our other obligations.
Changes in technology may significantly impact our business by making our
power plants less competitive.
A basic premise of our business is that generating power at central power
plants achieves economies of scale and produces electricity at a low price.
There are other technologies that can produce electricity, most notably fuel
cells, microturbines, windmills and photovoltaic (solar) cells. It is possible
that advances will reduce the cost of alternate methods of electric production
to a level that is equal to or below that of most central station electric
production. If this happens, the value of our power plants may be
significantly impaired.
We may not be able to successfully implement our business plan.
We are relying on Mirant Americas Energy Marketing to purchase our output in
order to supply Mirant Americas Energy Marketing's obligations under the Pepco
transition power agreements and to purchase any other available output for
resale to third parties through a combination of spot sales and bilateral
contracts. Effective August 1, 2001, we entered into an agreement with Mirant
Americas Energy Marketing that provides for us to receive payments for our
committed capacity and energy which are not directly linked to spot prices for
energy. This agreement expires in 2004. To the extent that our committed
capacity and energy is not sold under our agreement with Mirant Americas
Energy Marketing, 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 short periods of time. We
cannot assure you that Mirant Americas Energy Marketing will be successful in
marketing our output in accordance with our business plan.
Moreover, even a successful implementation of our business plan may produce
results which are less favorable than indicated by the projected operating
results. The projected operating results assume that we will sell the energy
generated by the generating facilities in the spot market. However, during the
term of the Energy and Capacity Sales Agreement with Mirant Americas Energy
Marketing, which expires in 2004, payment for our committed energy will be
made at prices not linked to spot prices. This mix of spot and bilateral term
contracts may result in sales of energy by us at prices lower than those
projected to be available in spot markets.
31
Mirant controls us and its interests may come into conflict with yours.
We are an indirect wholly-owned subsidiary of Mirant. Mirant has the power
to control us. In circumstances involving a conflict of interest between
Mirant as our indirect equity owner, on the one hand, and the certificate
holders as our indirect creditors, on the other hand, Mirant may exercise its
power to control us in a manner that would benefit Mirant to the detriment of
the certificate holders. Although Mirant does not own or lease any generating
units located within the PJM market, other than the generating facilities
described in this prospectus, it is possible that in the future Mirant or its
subsidiaries may undertake projects that compete with the generating
facilities.
In addition, if the credit rating of any of our parents, including Mirant,
is reduced, the rating on the certificates may be correspondingly reduced,
which may make it more difficult to sell the certificates or to sell them at
prices which you consider favorable.
If Mirant Americas Energy Marketing does not renew agreements to purchase or
market our power and provide us services that are required for our operations,
or if Mirant Mid-Atlantic Services or Mirant Services does not renew
agreements to provide us personnel and administrative services, we may not be
able to replace those services on as favorable terms.
Mirant Americas Energy Marketing's contracts with us to purchase capacity,
energy and ancillary services from our generating facilities are scheduled to
expire in 2004 and the contracts to provide fuel, fuel transportation and
other services are scheduled to expire at the end of 2001; however, after
December 31, 2002, Mirant Americas Energy Marketing may reduce the committed
capacity and energy purchased to zero. Mirant Americas Energy Marketing is not
obligated to renew these contracts. Additionally, our contracts with Mirant
Mid-Atlantic Services and Mirant Services to provide personnel and
administrative services are scheduled to expire at the end of 2001. Neither
Mirant Mid-Atlantic Services nor Mirant Services is obligated to renew their
contracts with us. The contracts with Mirant Americas Energy Marketing, Mirant
Mid-Atlantic Services and Mirant Services 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.
Our future access to capital could be limited, limiting our ability to fund
future capital and other requirements.
We will need to make substantial expenditures in the future to, among other
things, maintain the performance of our generating facilities and comply with
environmental laws and regulations. Our direct and indirect parent companies
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 additional indebtedness, including working
capital indebtedness in the future. The documents related to our lease of the
leased facilities limit our ability to issue securities and to incur
indebtedness. We may not be successful in obtaining sufficient additional
capital in the future to enable us to fund all of our future capital and other
requirements.
We are exposed to credit risk from third parties under contracts and in market
transactions.
The financial performance of our generating facilities that have power
supply agreements is dependent on the continued performance by customers of
their obligations under these agreements and, in particular, on the credit
quality of the facilities' customers. Our operations are exposed to the risk
that counterparties that owe money as a result of market transactions will not
perform their obligations. A facility's financial results may be materially
adversely affected if any one customer fails to fulfill its contractual
obligations and we are unable to find other customers to produce the same
level of profitability. As a result of the failure of a major customer to meet
its contractual obligations, we may be unable to repay obligations under our
debt agreements.
Risks Related to Our Industry
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, which requires continuous compliance with
conditions established by our operating permits. To comply with these legal
requirements, we must spend significant sums on environmental monitoring,
pollution control equipment and
32
emission fees. We may also be exposed to compliance risks from new projects,
as well as from plants we have acquired. Although we have budgeted for
significant expenditures to comply with these requirements, we may incur
significant additional costs if actual expenditures are greater than budgeted
amounts. If we fail to comply with these requirements, we could be subject to
civil or criminal liability and the imposition of liens or fines with the
trend toward stricter standards, greater regulation and more extensive
permitting requirements, we expect our environmental expenditures to be
substantial in the future. The scope and extent of new environmental
regulations, including their effect on our operations, is unclear; however,
our business, operations and financial conditions could be adversely affected
by this trend.
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
generating facilities or the sale of electricity to third parties could be
prevented or become subject to additional costs.
Except for environmental liability relating to an oil release from the Piney
Point oil pipeline which occurred in April 2000, and for which Pepco has
agreed to indemnify Mirant and its subsidiaries, including us, we are
generally responsible for all on-site liabilities associated with the
environmental condition of our generating facilities, regardless of when such
liabilities arose and whether they are known or unknown. For further
information on the Piney Point oil pipeline, see discussion of the Piney Point
oil pipeline in "Our Business--Other Assets, Rights and Obligations--The Piney
Point Oil Pipeline."
Our business is subject to complex government regulations and changes in these
regulations or in their implementation may affect the rates we are able to
charge, the costs of operating our facilities or our ability to operate our
facilities, any of which may negatively impact our results of operations.
All of our generation operations are exempt wholesale generators that sell
electricity exclusively into the wholesale markets. Generally, our exempt
wholesale generators are subject to regulation by the FERC regarding rate
matters and state public utility commissions regarding non-rate matters. The
majority of our generation from exempt wholesale generators is sold at market
prices under market rate authority exercised by the FERC, although the FERC
has the authority to impose "cost of service" rate regulation if it determines
that market pricing is not in the public interest. The FERC and the ISOs also
may impose pricing caps on bids to provide wholesale energy that may affect
our revenues. Any reduction by the FERC of the rates we may receive for our
generation activities may adversely affect our results of operations.
To conduct our business, we must obtain licenses, permits and approvals for
our plants. We cannot assure you that we will be able to obtain and comply
with all necessary licenses, permits and approvals. If we cannot comply with
all applicable regulations, our business, results of operations and financial
condition could be adversely affected.
The energy industry is rapidly changing and we may not be successful in
responding to these changes.
We may not be able to respond in a timely or effective manner to the many
changes in the energy industry. These changes may include reduced regulation
of the electric utility industry in some markets, increased regulation of the
electric utility industry in other markers and increasing competition in most
markets. To the extent competitive pressures increase and the pricing and sale
of electricity assumes more characteristics of a commodity business, the
profitability of our business may come under increasing downward pressure.
Industry deregulation may not only continue to fuel the current trend toward
consolidation in the utility industry, but may also encourage the separation
of vertically integrated utilities into independent generation, transmission
and distribution businesses. As a result, additional significant competitors
could become active in our industry and we may not be able to maintain our
revenues and earnings in this competitive marketplace or to acquire or develop
new assets to pursue our growth strategy.
We are not subject to the Public Utility Holding Company Act (PUHCA), and we
believe that as long as our and our affiliates' domestic power plants qualify
as either exempt wholesale generators or as qualifying facilities under the
Public Utility Regulatory Policies Act of 1978, as amended (PURPA), and we and
our affiliates do not otherwise acquire public utility assets or securities of
public utility companies, we will be subject to PUHCA.
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The United States Congress is considering legislation that would repeal
PURPA entirely, or at least eliminate the obligation of utilities to purchase
power from qualifying facilities. Various bills have also proposed repeal of
PUHCA. In the event of a PUHCA repeal, competition form independent power
generators and from utilities with generation, transmission and distribution
assets would likely increase. Repeal of PURPA or PUHCA may or may not be part
of comprehensive legislation to restructure the electric utility industry,
allow retail competition and deregulate most electric rates. We cannot predict
the effect of this type of legislation, although we anticipate that any
legislation would result in increased competition. If we were unable to
compete in an increasingly competitive environment, our business and results
of operation may suffer.
The FERC has issued power and gas transmission initiatives that require
electric and gas transmission services be offered on a common carrier basis
and not be bundled with commodity sales. Although these initiatives are
designed to encourage wholesale market transactions for electricity and gas,
there is the potential that fair and equal access to transmission systems will
not be available, and we cannot predict the timing of industry changes as a
result of these initiatives or the adequacy of transmission additions in
specific markets.
We cannot predict whether the federal government or state legislatures will
adopt legislation relating to the deregulation of the energy industry.
Furthermore, due to the current energy crisis in California, some states have
either discontinued or delayed implementation of initiatives involving retail
deregulation. In California and elsewhere there has been recent increased
support for a return to some form of regulation as well as changes in other
laws.
The introduction of new laws or other future regulatory developments may
have a material adverse effect on our business, results of operations or
financial condition.
Risks Relating to this Exchange Offer
Projections of our future performance may not match actual results.
The projected operating results contained in the independent engineer's
report in Appendix A to this prospectus are based on assumptions and forecasts
of our revenue, generating capacity and associated costs. The assumptions made
with respect to future market price for energy are based upon a market
analysis prepared by the independent market expert. This market forecast
served as a basis for the revenue assumptions incorporated in the projected
operating results. The independent engineer's report contains a discussion of
the principal assumptions and considerations utilized in preparing the
projected operating results, which you should review carefully.
As described in greater detail in "Relationships with Affiliates and Related
Transactions--Our Arrangements with Mirant Americas Energy Marketing,"
effective August 1, 2001, our relationship with Mirant Americas Energy
Marketing was reconfigured to provide us with payments for our committed
capacity and energy which are not directly linked to spot prices for energy.
You should be aware that the assumptions utilized in the preparation of the R.
W. Beck Independent Engineer's Report attached as Appendix A to this
prospectus do not contemplate this revised structure. While we expect that,
during the term of this new contract, our net operating revenues should be
more stable as a result of this revised structure, we have not requested R. W.
Beck to update or revise the Independent Engineer's Report, nor have we
undertaken to update or revise any forward-looking statements based on that
report as a result of this revised structure.
The projected operating results have been prepared on the basis of
assumptions as of the respective dates of the reports that we and the persons
who have provided them believe to be reasonable. However, we do not intend to
provide the certificate holders with any revised or updated projected
operating results or analyses of the differences between the projected
operating results and actual operating results.
Our independent auditors, Arthur Andersen LLP, have not examined, reviewed
or compiled the projected operating and financial results and, accordingly, do
not express an opinion or any other form of assurance with
34
respect to them. The report of Arthur Andersen LLP included in this prospectus
relates to our historical financial information. It does not extend to our
projected financial data and should not be read to do so.
The projected operating results are not necessarily indicative of our future
performance and neither we, the independent market expert, the independent
engineer nor any other person assumes any responsibility for their accuracy.
Therefore, no representation is made or intended, nor should any be inferred,
with respect to the likely existence of any particular future set of facts or
circumstances.
If actual results are less favorable than those shown or if the assumptions
used in formulating the base case and the sensitivities included in the
projected operating results prove to be incorrect, our ability to pay our
operating expenses, make rent payments under the leases and pay our other
obligations may be materially and adversely affected.
Certain bankruptcy law considerations could limit claims against us or the
owner lessors.
With Respect to the Leases
The certificates are not our direct obligations. Payments of principal and
interest on the certificates depend upon our lease payments to the owner
lessors. If we were to become a debtor in a liquidation or reorganization case
under the federal Bankruptcy Code, we, as debtor, or a bankruptcy trustee
appointed for us, could reject the leases as "executory" contracts under
Bankruptcy Code Section 365. 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.
Under Maryland law, however, it is likely that the leases will be viewed as
leases of real, rather than personal property. To the extent the leases are
considered leases of real property, Bankruptcy Code Section 502(b)(6) would
limit the owner lessors' claims against us for damages resulting from such
rejection or other termination of the leases, whether occurring before or
after the commencement of our bankruptcy case, to the greater of (a) one
year's rent under the leases or (b) 15% of the remaining rent due under the
leases (not to exceed three years' rent). The sum of the liquidation proceeds
from the sale of the leased facilities, plus the amount of the owner lessors'
damage claims, as limited by Section 502(b)(6), may be insufficient to cover
all amounts due on the lessor notes. Section 502(b)(6) would not limit the
owner lessors' claims against us, however, if the bankruptcy court were to
hold that the leases are financing arrangements rather than true leases.
Regardless of how a bankruptcy court characterizes the leases, the amount of
recovery on any claims against us and the amount of time that would pass
between the commencement of our bankruptcy case and the receipt of such
recovery cannot be predicted with any degree of certainty.
Furthermore, in a bankruptcy case, we could elect to cure defaults under the
leases and to assume or assign the leases. If we were to assign the leases,
the ultimate source of payments under the leases, and thus on the
certificates, would be an entity other than us. While the assignee would have
to demonstrate its ability to perform under the assumed leases to the
bankruptcy court, there can be no definitive assurances that the assignee
would satisfy our obligations under the leases.
With Respect to the Lessor Notes
If any of the owner lessors were to become a debtor in a case under the
Bankruptcy Code, the right to exercise virtually all remedies against that
owner lessor would be stayed. The bankruptcy court could permit the owner
lessor to use or dispose of payments made to it by us under the leases for
purposes other than making payments on the lessor notes and could reduce the
amount of, and modify the time for making, payments due under the lessor
notes, subject to procedural and substantive safeguards for the benefit of the
lease indenture trustee as holder of a security interest in the related lease
and undivided interest. In such event, payments on the lessor notes could be
reduced or delayed, reducing or delaying payments due under the certificates.
Furthermore, if the court were to hold that the leases are executory contracts
or true leases of real property rather than a financing arrangement, an owner
lessor would have the right to reject its lease under Bankruptcy Code Section
35
365. Such rejection could terminate our obligation to make any further
payments to the owner lessor in respect of the applicable leased facility,
unless the related lease was deemed to be a true lease of real property and we
elected to remain in possession. If we terminated our obligation to make lease
payments to an owner lessor, such owner lessor may stop making payments due
under its lessor notes, which would result in funds being unavailable for
payments due under the certificates. In addition, the amount of recovery on
any claims against an owner lessor and the amount of time that would pass
between commencement of the owner lessor's bankruptcy case and the receipt of
such recovery cannot be predicted with any degree of certainty.
Upon foreclosure on the leased facilities, the actual values of the leased
facilities may be less than their appraised values.
The purchase price of the leased facilities acquired by the owner lessors
was determined based on independent appraisals. The appraisals are not,
however, intended to be representations as to the future market value of the
leased facilities. In general, appraisals represent the analysis and opinion
of qualified appraisers and are not guarantees of present or future value. One
appraiser may reach a different conclusion than another appraiser would reach
appraising the same property. Moreover, appraisals seek to establish the
amount a typically motivated buyer would pay a typically motivated seller and,
in certain cases, may have taken into consideration the purchase price to be
paid by the owner lessors. Such amounts could be significantly higher than the
amount that would be obtained from the sale of the leased facilities under
distress in a liquidation sale. None of us, the owner lessors, or the
indenture trustees makes any warranty or representation that the leased
facilities could be sold at their appraised values. The value of the leased
facilities upon the exercise of remedies which results in foreclosure on the
leased facilities will depend on market and economic conditions, the
availability of buyers, the condition of the leased facilities and other
factors. Accordingly, there can be no assurance that the proceeds realized
upon any such exercise with respect to the lessor notes would equal the
ratable portion of the appraised value of the leased facilities or be
sufficient to satisfy in full payments due on the lessor notes. In the event
of foreclosure on the leased facilities, it may be necessary to sell the
undivided interests rather than a complete leased facility, which may reduce
the amount that could be realized.
It may be difficult to realize the value of the collateral pledged to secure
the lessor notes and the proceeds received from a sale of the collateral may
be insufficient to repay the lessor notes secured by that collateral.
The lessor notes issued by each owner lessor will be secured by collateral,
including an assignment of that owner lessor's rights and interests in its
respective undivided interest, the participation agreement to which the owner
lessor is a party, the facility site lease and our leases for the leased
facilities. If a default occurs with respect to the lessor notes, there can be
no assurance that an exercise of remedies, including foreclosure on the
related collateral, would provide sufficient funds to repay all amounts due on
the lessor notes and, accordingly, the certificates.
If the indenture trustee exercises its right to foreclose on a particular
undivided interest, transferring required government approvals to, or
obtaining new approvals by, a purchaser or new operator of the leased facility
may require governmental proceedings with consequential delays.
In addition, the leases and the other operative documents do not contain
cross-collateralization provisions. Accordingly, each indenture trustee's
security interests in each owner lessor's undivided interest and the
collateral pertaining to each undivided interest are separate and secure
separate amounts. If each indenture trustee exercises its right to foreclose
on and sell the collateral, the proceeds from the sale of each undivided
interest and the collateral pertaining to the undivided interest would be
separately applied against the amount secured by that particular undivided
interest and could not be used to satisfy any deficiency in the proceeds from
the sale of the other undivided interests and the collateral pertaining to the
other undivided interests. Any excess of sale proceeds would be remitted to
the applicable owner lessor. As a result, if the amount of sale proceeds from
the
36
foreclosure of the collateral related to a particular undivided interest is
less than the amount required to pay all amounts payable on the lessor notes
secured by that collateral, the holders of certificates would suffer a
permanent loss, even though aggregate sale proceeds from the foreclosure of
the collateral related to all undivided interests were equal to or greater
than all principal, premium, if any, and interest due on the certificates.
Our insurance coverage for the leased facilities may not be adequate to cover
potential liabilities and losses.
We are required by the lease documents to have insurance for the leased
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 the
leased 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.
There is no existing market for the certificates, and we cannot assure you
that an active trading market will develop or continue.
Following completion of this exchange offer, the certificates will be freely
tradable by most holders. See "This Exchange Offer--Resales of the New
Certificates." We do not intend to apply for listing of the certificates on
any securities exchange or on the Nasdaq National Market. There can be no
assurance as to the liquidity of any market that may develop for the
certificates, the ability of the certificate holders to sell their
certificates or the price at which the certificate holders will be able to
sell their certificates. Future trading prices of certificates will depend on
many factors including, among other things, prevailing interest rates, our
operating results and the market for similar securities.
Credit Suisse First Boston Corporation, Banc of America Securities LLC,
Chase Securities Inc. and UBS Warburg LLC, the initial purchasers in the
offering of the existing certificates, have informed us that they intend to
make a market in the certificates. However, they are not obligated to do so
and they may terminate any market-making activity at any time without notice
to holders of certificates. In addition, this market-making activity will be
subject to the limits imposed by federal securities law. If a market for the
certificates does not develop, holders may be unable to resell the
certificates for an extended period of time, if at all. Consequently, a holder
of a certificate may not be able to liquidate its investment readily, and the
certificates may not be readily accepted as collateral for loans.
We are also obligated, following the effectiveness of a registration
statement, to maintain our status as a reporting company under the Securities
Exchange Act of 1934, as amended (unless the SEC will not accept the filing of
the applicable reports), even though the SEC rules and regulations may not
require us to maintain that status. If we cease to maintain that status, the
interest rate on the lessor notes will be increased by 0.50% per annum for the
duration of such cessation (unless the SEC will not accept the filing of the
applicable reports). If the SEC will not accept the filing of the applicable
reports, it might become more difficult to sell the certificates or to sell
them at prices which you consider favorable.
Ratings assigned to the certificates are not investment recommendations and do
not assure market value.
S&P, Moody's and Fitch have assigned a rating to the certificates of BBB-,
Baa3 and BBB, respectively. A rating is not a recommendation to purchase, hold
or sell certificates because a rating does not address market price or
suitability for a particular investor. There can be no assurance that a rating
will remain in effect for any given period of time or that a rating will not
be lowered or withdrawn entirely by a rating agency if, in its judgment,
circumstances in the future so warrant. The rating of the certificates is
based primarily on our default risk under the leases.
37
The inability of Mirant Potomac River, Mirant Peaker, Mirant or Mirant Chalk
Point to make payments or distributions to us could have a material adverse
effect on our ability to make full and timely payments under the leases.
The purchase of the Potomac River/Peaker assets by Mirant Potomac River and
Mirant Peaker was funded by loans from us and a capital contribution from
Mirant. These loans from us are evidenced by notes, which we refer to as the
Mirant Potomac River and Mirant Peaker notes. Under a capital contribution
agreement, Mirant will cause Mirant Potomac River and Mirant Peaker to
distribute to Mirant available cash after each company has made its payments
under its note to us. Mirant will contribute or cause these amounts to be
contributed to us, and these amounts will be available to make payments under
the lease.
The obligations of Mirant Potomac River and Mirant Peaker to make payments
to us under the notes and the obligation of Mirant to make distributions to us
under the capital contribution agreement are all unsecured general
obligations. As the sole member of Mirant Chalk Point, we will be entitled to
all distributions made by Mirant Chalk Point, but any claims of creditors of
Mirant Chalk Point will be superior to our rights to distributions from Mirant
Chalk Point. The inability of Mirant Potomac River, Mirant Peaker, Mirant or
Mirant Chalk Point to make payments or distributions to us could have a
material adverse effect on our ability to make full and timely payments under
the leases and the other operative documents, and thus could have a material
adverse effect on the ability of the pass through trustee to make payments due
under the certificates.
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THIS EXCHANGE OFFER
Purpose and Terms of this Exchange Offer
The existing certificates were originally sold on December 18, 2000 in an
offering that was exempt from the registration requirements of the Securities
Act. As of the date of this prospectus, $454 million aggregate principal
amount of Series A certificates, $435 million aggregate principal amount of
Series B certificates and $335 million aggregate principal amount of Series C
certificates are outstanding. In connection with the sale of the existing
certificates, we entered into a registration rights agreement in which we
agreed to file with the SEC a registration statement with respect to the
exchange of existing certificates for new certificates and to use our best
efforts to cause the registration statement to become effective by November 9,
2001. Under the registration rights agreement, we also agreed to pay
additional interest at a rate of 0.50% per annum on the existing certificates
if we failed to consummate this exchange offer on or prior to December 18,
2001 for so long as that failure continued. The additional interest would be
payable on the existing certificates on the regular interest payment date. We
filed a copy of the registration rights agreement as an exhibit to the
registration statement of which this prospectus is a part. This exchange offer
satisfies our contractual obligations under the registration rights agreement.
In addition, there are circumstances where we are required to file a shelf
registration statement for resales of the existing certificates.
We are offering, upon the terms and subject to the conditions set forth in
this prospectus and in the accompanying letter of transmittal, to exchange up
to $454 million aggregate principal amount of outstanding Series A
certificates for $454 million aggregate principal amount of Series A
certificates which have been registered under the Securities Act, up to $435
million aggregate principal amount of outstanding Series B certificates for
$435 million aggregate principal amount of Series B certificates which have
been registered under the Securities Act and up to $335 million aggregate
principal amount of outstanding Series C certificates for $335 million
aggregate principal amount of Series C certificates which have been registered
under the Securities Act. We will accept for exchange existing certificates
that you properly tender prior to the expiration date and do not withdraw in
accordance with the procedures described below. You may tender your existing
certificates in whole or in part in integral multiples of $1,000 principal
amount.
This exchange offer is not conditioned upon the tender for exchange of any
minimum aggregate principal amount of existing certificates. We reserve the
right in our sole discretion to purchase or make offers for any existing
certificates that remain outstanding after the expiration date or, as detailed
under the caption "--Conditions to this Exchange Offer," to terminate this
exchange offer and, to the extent permitted by applicable law, purchase
existing certificates in the open market, in privately negotiated transactions
or otherwise. The terms of any of these purchases or offers could differ from
the terms of this exchange offer. There will be no fixed record date for
determining the registered holders of the existing certificates entitled to
participate in this exchange offer.
Only a registered holder of the existing certificates (or the holder's legal
representative or attorney-in-fact) may participate in this exchange offer.
Holders of existing certificates do not have any appraisal or dissenters'
rights in connection with this exchange offer. Existing certificates which are
not tendered in, or are tendered but not accepted in connection with, this
exchange offer will remain outstanding. We intend to conduct this exchange
offer in accordance with the provisions of the registration rights agreement
and the applicable requirements of the Securities Act and SEC rules and
regulations.
If we do not accept any existing certificates that you tender for exchange
because of an invalid tender, the occurrence of other events set forth in this
prospectus or otherwise, we will return the unaccepted existing certificates
to you, without expense, after the expiration date.
If you tender existing certificates in connection with this exchange offer,
you will not be required to pay brokerage commissions or fees or, subject to
the instructions in the letter of transmittal, transfer taxes with respect
39
to the exchange of existing certificates in connection with this exchange
offer. We will pay all charges and expenses, other than certain applicable
taxes described below, in connection with this exchange offer. See "--Fees and
Expenses."
Each broker-dealer that receives new certificates for its own account in
exchange for existing certificates, where such existing certificates were
acquired by such broker-dealer as a result of market-making activities or
other trading activities, must acknowledge that it will deliver a prospectus
in connection with any resale of the new certificates. See "Plan of
Distribution."
Unless the context requires otherwise, the term "holder" with respect to
this exchange offer means any person in whose name the existing certificates
are registered on the pass through trustee's books or any other person who has
obtained a properly completed bond power from the registered holder, or any
participant in The Depository Trust Company whose name appears on a security
position listing as a holder of existing certificates. For purposes of this
exchange offer, a participant includes beneficial interests in the existing
certificates held by direct or indirect participants and existing certificates
held in definitive form.
We make no recommendation to you as to whether you should tender or refrain
from tendering all or any portion of your existing certificates into this
exchange offer. In addition, no one has been authorized to make this
recommendation. You must make your own decision whether to tender into this
exchange offer and, if so, the aggregate amount of existing certificates to
tender after reading this prospectus and the letter of transmittal and
consulting with your advisors, if any, based on your financial position and
requirements.
Expiration Date, Extension and Amendments
The term "expiration date" means 5:00 p.m., New York City time, on August
15, 2001 unless we extend this exchange offer, in which case the term
"expiration date" shall mean the latest date and time to which we extend this
exchange offer.
We expressly reserve the right, at any time or from time to time, so long as
applicable law allows,
(1) to delay our acceptance of existing certificates for exchange;
(2) to terminate or amend this exchange offer if, in the opinion of our
counsel, completing this exchange offer would violate any applicable law,
rule or regulation or any SEC staff interpretation; and
(3) to extend the expiration date and retain all existing certificates
tendered into this exchange offer, subject, however, to your right to
withdraw your tendered existing certificates as described under "--
Withdrawal Rights."
If this exchange offer is amended in a manner that we think constitutes a
material change, or if we waive any material condition of this exchange offer,
we will promptly disclose the amendment by means of a prospectus supplement
that will be distributed to the registered holders of the existing
certificates, and we will extend this exchange offer to the extent required by
Rule 14e-1 under the Exchange Act.
We will promptly follow any delay in acceptance, termination, extension or
amendment by oral or written notice of the event to the exchange agent
followed promptly by oral or written notice to the registered holders. Should
we choose to delay, extend, amend or terminate this exchange offer, we will
have no obligation to publish, advertise or otherwise communicate this
announcement to the public, other than by making a timely release to an
appropriate news agency.
Procedures for Tendering the Existing Certificates
Upon the terms and the conditions of this exchange offer, we will exchange,
and we will arrange for the pass through trusts to issue to the exchange
agent, new certificates for existing certificates that have been validly
tendered, and not validly withdrawn, promptly after the expiration date. The
tender by a holder of any existing
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certificates and our acceptance of that holder's existing certificates will
constitute a binding agreement between us and that holder subject to the terms
and conditions set forth in this prospectus and the accompanying letter of
transmittal.
Valid Tender
Upon the terms and conditions of this exchange offer, we will deliver new
certificates in exchange for existing certificates that have been validly
tendered and accepted for exchange pursuant to this exchange offer. Except as
set forth below, you will have validly tendered your existing certificates
pursuant to this exchange offer if the exchange agent receives, prior to the
expiration date, at the address listed under the caption "--Exchange Agent":
(1) a properly completed and duly executed letter of transmittal, with
any required signature guarantees, including all documents required by the
letter of transmittal; or
(2) if the existing certificates are tendered in accordance with the
book-entry procedures set forth below, the tendering certificate holder may
transmit an agent's message (described below) instead of a letter of
transmittal.
In addition, on or prior to the expiration date:
(1) the exchange agent must receive the existing certificates along with
the letter of transmittal; or
(2) the exchange agent must receive a timely book-entry confirmation
(described below) of a book-entry transfer of the tendered existing
certificates into the exchange agent's account at The Depository Trust
Company according to the procedure for book-entry transfer described below,
along with a letter of transmittal or an agent's message in lieu of the
letter of transmittal; or
(3) the holder must comply with the guaranteed delivery procedures
described below.
Accordingly, we may not make delivery of new certificates to all tendering
holders at the same time since the time of delivery will depend upon when the
exchange agent receives the existing certificates, book-entry confirmations
with respect to existing certificates and the other required documents.
The term "book-entry confirmation" means a timely confirmation of a book-
entry transfer of existing certificates into the exchange agent's account at
The Depository Trust Company. The term "agent's message" means a message,
transmitted by The Depository Trust Company to and received by the exchange
agent and forming a part of a book-entry confirmation, which states that The
Depository Trust Company has received an express acknowledgment from the
tendering participant stating that the participant has received and agrees to
be bound by the letter of transmittal and that we may enforce the letter of
transmittal against the participant.
If you tender less than all of your existing certificates, you should fill
in the amount of existing certificates you are tendering in the appropriate
box on the letter of transmittal or, in the case of a book-entry transfer, so
indicate in an agent's message if you have not delivered a letter of
transmittal. The entire amount of existing certificates delivered to the
exchange agent will be deemed to have been tendered unless otherwise
indicated.
If any letter of transmittal, endorsement, bond power, power of attorney or
any other document required by the letter of transmittal is signed by a
trustee, executor, administrator, guardian, attorney-in-fact, officer of a
corporation or other person acting in a fiduciary or representative capacity,
that person should so indicate when signing, and, unless waived by us, you
must submit evidence satisfactory to us, in our sole discretion, of that
person's authority to so act.
If you are a beneficial owner of existing certificates that are held by or
registered in the name of a broker, dealer, commercial bank, trust company or
other nominee or custodian, we urge you to contact this entity promptly if you
wish to participate in this exchange offer.
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The method of delivery of the existing certificates, the letter of
transmittal and all other required documents is at your option and at your
sole risk, and delivery will be deemed made only when actually received by the
exchange agent. Instead of delivery by mail, we recommend that you use an
overnight or hand delivery service. In all cases, you should allow sufficient
time to assure timely delivery and you should obtain proper insurance. Do not
send any letter of transmittal or existing certificates to Mirant Mid-
Atlantic. You may request your broker, dealer, commercial bank, trust company
or nominee to effect these transactions for you.
Book-Entry Transfer
Holders who are participants in The Depository Trust Company tendering by
book-entry transfer must execute the exchange through the Automated Tender
Offer Program of The Depository Trust Company on or prior to the expiration
date. The Depository Trust Company will verify this acceptance and execute a
book-entry transfer of the tendered existing certificates into the exchange
agent's account at The Depository Trust Company. The Depository Trust Company
will then send to the exchange agent a book-entry confirmation including an
agent's message confirming that The Depository Trust Company has received an
express acknowledgment from the holder that the holder has received and agrees
to be bound by the letter of transmittal and that the exchange agent and we
may enforce the letter of transmittal against such holder. The book-entry
confirmation must be received by the exchange agent in order for the exchange
to be effective.
The exchange agent will make a request to establish an account with respect
to the existing certificates at The Depository Trust Company for purposes of
this exchange offer within two business days after the date of this prospectus
unless the exchange agent already has established an account with The
Depository Trust Company suitable for this exchange offer.
Any financial institution that is a participant in The Depository Trust
Company's book-entry transfer facility system may make a book-entry delivery
of the existing certificates by causing The Depository Trust Company to
transfer these existing certificates into the exchange agent's account at The
Depository Trust Company in accordance with The Depository Trust Company's
procedures for transfers.
If the tender is not made through the Automated Tender Offer Program, you
must deliver the existing certificates and the applicable letter of
transmittal, or a facsimile of the letter of transmittal, properly completed
and duly executed, with any required signature guarantees, or an agent's
message in lieu of a letter of transmittal, and any other required documents
to the exchange agent at its address listed under the caption "--Exchange
Agent" prior to the expiration date, or you must comply with the guaranteed
delivery procedures set forth below in order for the tender to be effective.
Delivery of documents to The Depository Trust Company does not constitute
delivery to the exchange agent and book-entry transfer to The Depository Trust
Company in accordance with its procedures does not constitute delivery of the
book-entry confirmation to the exchange agent.
Signature Guarantees
Signature guarantees on a letter of transmittal or a notice of withdrawal,
as the case may be, are only required if:
(1) existing certificates are registered in a name other than that of the
person submitting a letter of transmittal or a notice of withdrawal; or
(2) a registered holder completes the section entitled "Special Issuance
Instructions" or "Special Delivery Instructions" in the letter of
transmittal. See "Instructions" in the letter of transmittal.
In the case of (1) or (2) above, you must duly endorse the existing
certificates or they must be accompanied by a properly executed bond power,
with the endorsement or signature on the bond power and on the letter of
transmittal or the notice of withdrawal, as the case may be, guaranteed by a
firm or other entity identified in
42
Rule 17Ad-15 under the Exchange Act as an "eligible guarantor institution"
that is a member of a medallion guarantee program, unless these existing
certificates are surrendered on behalf of that eligible guarantor institution.
An "eligible guarantor institution" includes the following:
. a bank;
. a broker, dealer, municipal securities broker or dealer or government
securities broker or dealer;
. a credit union;
. a national securities exchange, registered securities association or
clearing agency; or
. a savings association.
Guaranteed Delivery
If you desire to tender existing certificates into this exchange offer and:
(1) the existing certificates are not immediately available;
(2) time will not permit delivery of the existing certificates and all
required documents to the exchange agent on or prior to the expiration
date; or
(3) the procedures for book-entry transfer cannot be completed on a
timely basis;
you may nevertheless tender the existing certificates, provided that you
comply with all of the following guaranteed delivery procedures:
(1) tender is made by or through an eligible guarantor institution;
(2) prior to the expiration date, the exchange agent receives from the
eligible guarantor institution a properly completed and duly executed
Notice of Guaranteed Delivery, substantially in the form accompanying the
letter of transmittal. This eligible guarantor institution may deliver the
Notice of Guaranteed Delivery by hand or by facsimile or deliver it by mail
to the exchange agent and must include a guarantee by this eligible
guarantor institution in the form in the Notice of Guaranteed Delivery; and
(3) within three New York Stock Exchange trading days after the date of
execution of the Notice of Guaranteed Delivery, the exchange agent must
receive:
. the existing certificates, or book-entry confirmation, representing
all tendered existing certificates, in proper form for transfer;
. a properly completed and duly executed letter of transmittal or
facsimile of the letter of transmittal or, in the case of a book-
entry transfer, an agent's message in lieu of the letter of
transmittal, with any required signature guarantees; and
. any other documents required by the letter of transmittal.
Determination of Validity
. We have the right, in our sole discretion, to determine all questions as
to the form of documents, validity, eligibility, including time of
receipt, and acceptance for exchange of any tendered existing
certificates. Our determination will be final and binding on all
parties.
. We reserve the absolute right, in our sole and absolute discretion, to
reject any and all tenders of existing certificates that we determine
are not in proper form.
. We reserve the absolute right, in our sole and absolute discretion, to
refuse to accept for exchange a tender of existing certificates if our
counsel advises us that the tender is unlawful.
. We also reserve the absolute right, so long as applicable law allows, to
waive any of the conditions of this exchange offer or any defect or
irregularity in any tender of existing certificates of any particular
holder whether or not similar defects or irregularities are waived in
the case of other holders.
43
. Our interpretation of the terms and conditions of this exchange offer,
including the letter of transmittal and the instructions relating to it,
will be final and binding on all parties.
. We will not consider the tender of existing certificates to have been
validly made until all defects or irregularities with respect to the
tender have been cured or waived.
. We, our affiliates, the exchange agent, and any other person will not be
under any duty to give any notification of any defects or irregularities
in tenders and will not incur any liability for failure to give this
notification.
Acceptance for Exchange for the New Certificates
For each existing certificate accepted for exchange, the holder of the
existing certificate will receive a new certificate having a principal amount
equal to that of the surrendered existing certificate. The new certificates
will bear interest from the most recent date to which interest has been paid
on the existing certificates. Accordingly, registered holders of new
certificates on the relevant record date for the first interest payment date
following the completion of this exchange offer will receive interest accruing
from the most recent date to which interest has been paid. Existing
certificates accepted for exchange will cease to accrue interest from and
after the date of completion of this exchange offer. Holders of existing
certificates whose existing certificates are accepted for exchange will not
receive any payment for accrued interest on the existing certificates
otherwise payable on any interest payment date the record date for which
occurs on or after completion of this exchange offer and will be deemed to
have waived their rights to receive the accrued interest on the existing
certificates.
Upon satisfaction or waiver of all of the conditions of this exchange offer,
we will accept, promptly after the expiration date, all existing certificates
properly tendered and will arrange for the pass through trusts to issue the
new certificates promptly after acceptance of the existing certificates. See
"--Conditions to this Exchange Offer." Subject to the terms and conditions of
this exchange offer, we will be deemed to have accepted for exchange, and
exchanged, existing certificates validly tendered and not withdrawn as, if and
when we give oral or written notice to the exchange agent, with any oral
notice promptly confirmed in writing by us, of our acceptance of these
existing certificates for exchange in this exchange offer. The exchange agent
will act as our agent for the purpose of receiving tenders of existing
certificates, letters of transmittal and related documents, and as agent for
tendering holders for the purpose of receiving existing certificates, letters
of transmittal and related documents and transmitting new certificates to
holders who validly tendered existing certificates. The exchange agent will
make the exchange promptly after the expiration date. If for any reason
whatsoever:
. the acceptance for exchange or the exchange of any existing certificates
tendered in this exchange offer is delayed, whether before or after our
acceptance for exchange of existing certificates;
. we extend this exchange offer; or
. we are unable to accept for exchange or exchange existing certificates
tendered in this exchange offer;
then, without prejudice to our rights set forth in this prospectus, the
exchange agent may, nevertheless, on our behalf and subject to Rule 14e-1(c)
under the Exchange Act, retain tendered existing certificates and these
existing certificates may not be withdrawn unless tendering holders are
entitled to withdrawal rights as described under "--Withdrawal Rights."
Interest
For each existing certificate that we accept for exchange, the existing
certificate holder will receive a new certificate having a principal amount
and final distribution date equal to that of the surrendered existing
certificate. Interest on the new certificates will accrue from December 18,
2000, the original issue date of the existing certificates or from the last
interest payment date on which interest was paid on the existing certificates
tendered for exchange. June 30, 2001 is the first scheduled interest
distribution date.
44
Resales of the New Certificates
Based on interpretations by the staff of the SEC set forth in no-action
letters issued to third parties, we believe that the new certificates may be
offered for resale, resold and otherwise transferred by you without compliance
with the registration and prospectus delivery requirements of the Securities
Act provided that:
. you acquire any new certificate in the ordinary course of your business;
. you are not participating, do not intend to participate, and have no
arrangement or understanding with any person to participate, in the
distribution of the new certificates;
. you are not a broker-dealer who purchased existing certificates directly
from us for resale pursuant to Rule 144A or any other available
exemption under the Securities Act; and
. you are not an "affiliate" (as defined in Rule 405 under the Securities
Act) of our company.
If our belief is inaccurate and you transfer any new certificate without
delivering a prospectus meeting the requirements of the Securities Act or
without an exemption from registration of your certificates from these
requirements, you may incur liability under the Securities Act. We do not
assume any liability or indemnify you against any liability under the
Securities Act.
Each broker-dealer that is issued new certificates for its own account in
exchange for existing certificates must acknowledge that it will deliver a
prospectus meeting the requirements of the Securities Act in connection with
any resale of the new certificates. A broker-dealer that acquired existing
certificates for its own account as a result of market-making or other trading
activities may use this prospectus for an offer to resell, resale or other
retransfer of the new certificates.
Withdrawal Rights
Except as otherwise provided in this prospectus, you may withdraw your
tender of existing certificates at any time prior to the expiration date.
In order for a withdrawal to be effective, you must deliver a written,
telegraphic or facsimile transmission of a notice of withdrawal to the
exchange agent at any of its addresses listed under the caption "--Exchange
Agent" prior to the expiration date.
Each notice of withdrawal must specify:
(1) the name of the person who tendered the existing certificates to be
withdrawn;
(2) the aggregate principal amount of existing certificates to be
withdrawn; and
(3) if certificates for existing certificates have been tendered, the
name of the registered holder of the existing certificates as set forth on
the existing certificates, if different from that of the person who
tendered these existing certificates.
If you have delivered, or otherwise identified to the exchange agent,
certificates for existing certificates, the notice of withdrawal must specify
the serial numbers on the particular certificates for the existing
certificates to be withdrawn and the signature on the notice of withdrawal
must be guaranteed by an eligible guarantor institution, except in the case of
existing certificates tendered for the account of an eligible guarantor
institution.
If you have tendered existing certificates in accordance with the procedures
for book-entry transfer listed in "--Procedures for Tendering the Existing
Certificates--Book-Entry Transfer," the notice of withdrawal must specify the
name and number of the account at The Depository Trust Company to be credited
with the withdrawal of existing certificates and must otherwise comply with
the procedures of The Depository Trust Company.
You may not rescind a withdrawal of your tender of existing certificates.
We will not consider existing certificates properly withdrawn to be validly
tendered for purposes of this exchange offer. However, you may retender
existing certificates at any subsequent time prior to the expiration date by
following any of the procedures described above in "--Procedures for Tendering
Existing Certificates."
45
We, in our sole discretion, will determine all questions as to the validity,
form and eligibility, including time of receipt, of any withdrawal notices.
Our determination will be final and binding on all parties. We, our
affiliates, the exchange agent and any other person have no duty to give any
notification of any defects or irregularities in any notice of withdrawal and
will not incur any liability for failure to give any such notification.
We will return to the holder any existing certificates that have been
tendered but which are withdrawn promptly after the withdrawal.
Conditions to this Exchange Offer
Notwithstanding any other provisions of this exchange offer or any extension
of this exchange offer, we will not be required to accept for exchange, or to
exchange, any existing certificates. We may terminate this exchange offer,
whether or not we have previously accepted any existing certificates for
exchange, or we may waive any conditions to or amend this exchange offer, if
we determine in our sole and absolute discretion that this exchange offer
would violate applicable law or regulation or any applicable interpretation of
the staff of the SEC.
Exchange Agent
We have appointed State Street Bank and Trust Company as exchange agent for
this exchange offer. You should direct all deliveries of the letters of
transmittal and any other required documents, questions, requests for
assistance and requests for additional copies of this prospectus or of the
letters of transmittal to the exchange agent as follows:
State Street Bank and Trust Company
2 Avenue de Lafayette
Corporate Trust, 5th Floor
Boston, Massachusetts 02111-1724
Attention: Ralph Jones
Telephone No.: (617) 662-1548
Facsimile No.: (617) 662-1452
or:
State Street Bank and Trust Company
Corporate Trust
P.O. Box 778
Boston, Massachusetts 02102-0778
Attention: Ralph Jones
Telephone No.: (617) 662-1548
Facsimile No.: (617) 662-1452
Delivery to other than the above addresses or facsimile number will not
constitute a valid delivery.
Fees and Expenses
We will bear the expenses of soliciting tenders of the existing
certificates. We will make the initial solicitation by mail; however, we may
decide to make additional solicitations personally or by telephone or other
means through our officers, agents, directors or employees.
We have not retained any dealer-manager or similar agent in connection with
this exchange offer and we will not make any payments to brokers, dealers or
others soliciting acceptances of this exchange offer. We have agreed to pay
the exchange agent and pass through trustee reasonable and customary fees for
its services and will reimburse it for its reasonable out-of-pocket expenses
in connection with this exchange offer. We will also pay brokerage houses and
other custodians, nominees and fiduciaries the reasonable out-of-pocket
expenses they incur in forwarding copies of this prospectus and related
documents to the beneficial owners of existing certificates, and in handling
or tendering certificates for their customers.
46
Transfer Taxes
Holders who tender their existing certificates will not be obligated to pay
any transfer taxes in connection with the exchange, except that if:
. you want us to deliver new certificates to any person other than the
registered holder of the existing certificates tendered;
. you want the pass through trusts to issue the new certificates in the
name of any person other than the registered holder of the existing
certificates tendered; or
. a transfer tax is imposed for any reason other than the exchange of
existing certificates in connection with this exchange offer
then you will be liable for the amount of any transfer tax, whether imposed on
the registered holder or any other person. If you do not submit satisfactory
evidence of payment of such transfer tax or exemption from such transfer tax
with the letter of transmittal, the amount of this transfer tax will be billed
directly to the tendering holder.
Consequences of Exchanging or Failing to Exchange Existing Certificates
Holders of existing certificates who do not exchange their existing
certificates for new certificates in this exchange offer will continue to be
subject to the provisions of the pass through trust agreements regarding
transfer and exchange of the existing certificates and the restrictions on
transfer of the existing certificates set forth on the legend on the existing
certificates. In general, the existing certificates may not be offered or
sold, unless registered under the Securities Act, except under an exemption
from, or in a transaction not subject to, the registration requirements of the
Securities Act and applicable state securities laws.
Based on interpretations by the staff of the SEC, as detailed in no-action
letters issued to third parties, we believe that new certificates issued in
this exchange offer in exchange for existing certificates may be offered for
resale, resold or otherwise transferred by you (unless you are an "affiliate"
of our company within the meaning of Rule 405 under the Securities Act)
without compliance with the registration and prospectus delivery provisions of
the Securities Act, provided that the new certificates are acquired in the
ordinary course of your business, you have no arrangement or understanding
with any person to participate in the distribution of these new certificates
and you are not a broker-dealer who purchased existing certificates directly
from us for resale pursuant to Rule 144A or any other available exemption
under the Securities Act. However, we do not intend to request the SEC to
consider, and the SEC has not considered, this exchange offer in the context
of a no-action letter and we cannot guarantee that the staff of the SEC would
make a similar determination with respect to this exchange offer.
Each holder must acknowledge that it is not engaged in, and does not intend
to engage in, a distribution of new certificates and has no arrangement or
understanding to participate in a distribution of new certificates. If any
holder is an affiliate of our company, is engaged in or intends to engage in
or has any arrangement or understanding with respect to the distribution of
the new certificates to be acquired pursuant to this exchange offer, the
holder:
. cannot rely on the applicable interpretations of the staff of the SEC,
and
. must comply with the registration and prospectus delivery requirements
of the Securities Act.
Each broker-dealer that receives new certificates for its own account in
exchange for existing certificates, where such existing certificates were
acquired by such broker-dealer as a result of market making activities or
other trading activities, must acknowledge that it will deliver a prospectus
in connection with any resale of the new certificates. See "Plan of
Distribution."
In addition, to comply with state securities laws, the new certificates may
not be offered or sold in any state unless they have been registered or
qualified for sale in the state or an exemption from registration or
qualification is available and is complied with. The offer and sale of the new
certificates to "qualified institutional buyers" (as defined under Rule 144A
of the Securities Act) is generally exempt from registration or qualification
under the state securities laws. We currently do not intend to register or
qualify the sale of the new certificates in any state where an exemption from
registration or qualification is required and not available.
47
RATIO OF EARNINGS TO FIXED CHARGES
For the three months ended March 31, 2001 and for the period from July 12,
2000 (inception) through December 31, 2000, the ratio of our earnings to fixed
charges was 4.1 and 2.5, respectively. Due to our July 12, 2000 inception date
and because we began operations on December 19, 2000, we cannot calculate a
ratio of earnings to fixed charges for any prior periods. For the purposes of
calculating the ratio of earnings available to cover fixed charges:
. earnings consist of income from continuing operations less fixed charges
excluding capitalized interest, and
. fixed charges consist of interest on borrowings (whether expensed or
capitalized), related amortization and the interest component of rent
expense.
48
USE OF PROCEEDS
Neither we nor the pass through trusts will receive any cash proceeds from
the issuance of the new certificates offered in this exchange offer. In
consideration for issuing the new certificates as contemplated in this
prospectus, the pass through trusts will receive in exchange existing
certificates in like principal amount.
The existing certificates surrendered in exchange for new certificates will
be retired and canceled and cannot be reissued. Accordingly, issuance of the
new certificates will not result in a change in our lease rental obligations.
The existing certificates were issued and sold in order to provide the debt
portion of the lease transactions we entered into with respect to the leased
facilities. The pass through trusts used the $1,224 million of proceeds from
the sale of the existing certificates to purchase $1,224 million of lessor
notes issued by the owner lessors. The owner lessors used approximately $973
million of the proceeds from the sale of the lessor notes, together with
approximately $227 million of equity contributed to the owner lessors by the
owner participants, to purchase their undivided interests in the Morgantown
leased facility from Pepco. Similarly, the owner lessors used approximately
$251 million of the proceeds from the sale of the lessor notes, together with
approximately $49 million of equity contributed to the owner lessors by the
owner participants, to purchase their undivided interests in the Dickerson
leased facility from Pepco. In addition, the owner participants directly or
through the owner lessors, paid $22.5 million of the transaction expenses
associated with the lease transactions. We paid for transaction expenses
totaling approximately $8.5 million associated with the lease transactions.
49
CAPITALIZATION
The following table sets forth our consolidated capitalization as of March
31, 2001 and December 31, 2000. Please note that members' equity does not
include the Mirant Potomac River and Mirant Peaker equity investments, which
have aggregate capitalization values of approximately $437 million and
$405 million at March 31, 2001 and December 31, 2000, respectively. You should
read the information in this table together with our consolidated financial
statements and the related notes and with "Selected Financial Information" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" included elsewhere in this prospectus.
As of As of
March 31, 2001 December 31, 2000
-------------- -----------------
(in millions) (in millions)
Debt.................................... $ 75 $ 75
Members' equity......................... 2,872 2,694
------ ------
Total debt and members' equity........ $2,947 $2,769
====== ======
Our leases of the leased facilities are accounted for as operating leases
and are not reflected in our balance sheet; however, if they were treated as
direct financing capital leases, they would have a value of $1,500 million. As
of March 31, 2001, our future minimum rent obligations under the leases are
(rounded to millions) $196 million for the nine months ended December 31,
2001, $170 million for 2002, $151 million for 2003, $122 million for 2004,
$116 million for 2005 and a total of $2,351 million for the remaining terms of
the leases.
50
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion in conjunction with "Risk Factors,"
"Selected Financial Information" and our consolidated financial statements and
the related notes included elsewhere in this prospectus.
Overview
We are an indirect wholly-owned subsidiary of Mirant that was formed, along
with our subsidiaries, in conjunction with the acquisition of the transaction
assets from Pepco which occurred on December 19, 2000. Prior to the
acquisition of these assets from Pepco, we had no operating history.
As a part of the acquisition, we or our subsidiaries acquired directly from
Pepco the peaking units at the Dickerson and Morgantown generating facilities,
the Chalk Point generating facility (except for the combustion turbines and
the Southern Maryland Electric Cooperative combustion turbine), three ash
storage facilities, the Piney Point oil pipeline and the production service
center. The owner lessors acquired undivided interests in the baseload units
at the Dickerson and Morgantown generating facilities directly from Pepco, and
we lease the Dickerson and Morgantown baseload units from the owner lessors.
Our subsidiary Mirant D.C. O&M, LLC, which we will refer to as Mirant D.C.
Operator, provides operations and maintenance services to the Buzzard Point
and Benning generating stations in Washington, D.C. that Pepco continues to
own.
Mirant Potomac River and Mirant Peaker, direct subsidiaries of Mirant, were
also recently formed in conjunction with the acquisition of the transaction
assets from Pepco. Mirant Potomac River and Mirant Peaker acquired the Potomac
River generating facility and the Chalk Point combustion turbines (including
the rights and obligations with respect to the Southern Maryland Electric
Cooperative combustion turbine), respectively, directly from Pepco. These
purchases by Mirant Potomac River and Mirant Peaker were funded by loans from
us evidenced by notes and a capital contribution from Mirant. Under the
capital contribution agreement, Mirant will cause, unless prohibited by law,
Mirant Potomac River and Mirant Peaker to make distributions to Mirant, at
least once per quarter, of all cash available after taking into account
projected cash requirements, including mandatory debt service, prepayments
permitted under the Mirant Potomac River and the Mirant Peaker notes, and
maintenance reserves, as reasonably determined by Mirant. Mirant will
contribute or cause these amounts to be contributed to us. We estimate that
payments to us in respect of the Potomac River/Peaker assets will contribute
12% of our net revenues on average during the term of the certificates.
Over the life of the certificates, we expect the majority of our revenues to
be derived from sales of capacity, energy and ancillary services from the
generating facilities owned or leased by us into the PJM spot and forward
markets, with the balance of our revenues derived from sales to other
competitive power markets or from bilateral contracts. The market for
wholesale electric energy and energy services in the PJM market is largely
deregulated. To the extent that we have not sold our energy and capacity under
fixed price agreements, our revenues and results of operations will depend, in
part, upon prevailing market prices for energy, capacity and ancillary
services in the PJM market and other competitive markets.
We have entered into a power sales agreement and a separate services and
risk management agreement with Mirant Americas Energy Marketing, both of which
are described in greater detail in "Relationships with Affiliates and Related
Transactions--Our Arrangements with Mirant Americas Energy Marketing." The
services and risk management agreement expires on December 31, 2001, but may
be renewed annually. Effective August 1, 2001, we modified the power sales
arrangement by entering into an Energy and Capacity Sales Agreement with
Mirant Americas Energy Marketing which effectively restructured our power
sales arrangements with Mirant Americas Energy Marketing. The Energy and
Capacity Sales Agreement expires in June 2004; however, Mirant Americas Energy
Marketing has the option to extend it through December 2004.
As described in greater detail in "Relationships with Affiliates and Related
Transactions--Our Arrangements with Mirant Americas Energy Marketing," the
Energy and Capacity Sales Agreement was entered into to provide us with
payments for our committed capacity and energy at prices that are not directly
linked to
51
spot market prices. You should be aware that the assumptions utilized in the
preparation of the R.W. Beck Independent Engineer's Report attached as
Appendix A to this prospectus do not contemplate this revised structure. While
we expect that, during the term of this new contract, our net operating
revenues should be more stable as a result of this revised structure, we have
not requested R.W. Beck to update or revise the Independent Engineer's Report,
nor have we undertaken to update or revise any forward-looking statements
based on that report as a result of this revised structure.
As part of our services and risk management agreement with Mirant Americas
Energy Marketing, Mirant Americas Energy Marketing procures fuel and emissions
credits necessary for the operation of the generating facilities owned or
leased by us, the cost of which is charged to us based upon actual costs
incurred by Mirant Americas Energy Marketing. Mirant Americas Energy Marketing
also procures or advises us to procure business interruption insurance, the
costs of which are charged to us. Our expenses are primarily derived from the
ongoing maintenance and operations of the generating facilities owned or
leased by us, capital expenditures needed to ensure their continued safe and
environmentally compliant operation and our obligation to make rental payments
under the leases.
Results of Operations
Neither Mirant Potomac River, Mirant Peaker, we, nor any of our subsidiaries
have any operating history prior to December 19, 2000. Prior to the
acquisition of the transaction assets from Pepco, the transaction assets were
fully integrated with Pepco's utility operations and all results of operations
were consolidated into Pepco's financial statements. Due to the regulated
nature of Pepco's utility operations and the differences inherent in the
manner in which we expect to operate the generating facilities, historical
financial results prior to December 19, 2000 would not be meaningful or
indicative of our ability to operate the transaction assets or to generate
revenues. As a result, this Management's Discussion and Analysis of Financial
Condition and Results of Operations reflects the operations of Mirant Mid-
Atlantic beginning December 19, 2000 and excludes a discussion of, or
comparison with, prior periods.
For the Three Months Ended March 31, 2001
Revenues
Operating revenues for the period were approximately $281 million. Revenues
primarily consisted of $195 million of energy revenues, $64 million of
capacity revenues and $22 million of other revenues.
Operating Expenses
Operating expenses of $216 million consisted of expenses for facility
operations, maintenance and labor. Operations expenses included fuel,
electricity and other product purchases of $127 million, of which $43 million
was for coal, $34 million was for oil, $6 million was for natural gas and $44
million was for power. Labor expenses totaled $20 million and maintenance
expenses totaled $7 million.
Rental Expenses
Operating lease expense (also referred to as rental fees) related to the
leased generating facilities totaled $24 million.
Depreciation and Amortization
Depreciation and amortization expenses were $18 million. Depreciation
expenses amounted to $9 million, primarily related to the generating
facilities, which are being depreciated over an average of approximately
32 years. Amortization expense amounted to $9 million and related primarily to
amortization of goodwill.
52
Selling, General and Administrative Expenses
Selling, general and administrative expenses for the period totaled $6
million, and consist primarily of costs for insurance, outside legal and other
contract services, information technology, telephone and office administration
as well as the service fee from Mirant Americas Energy Marketing under the
terms of the Services and Risk Management Agreement.
Other Income and Expense
Other income included $6 million of interest income from related parties and
an investment account, interest expense of $2 million related to a $75 million
note payable to a related party and financing fees of $1 million.
For the Period from July 12, 2000 (Inception) through December 31, 2000
Revenues
Operating revenues for the period were approximately $40 million. Revenues
primarily consisted of $39 million of energy revenues and $1 million of other
revenues.
Operating Expenses
Operating expenses of $32 million consisted of expenses for facility
operations, maintenance and labor. Operations expenses included fuel,
electricity and other product purchases of $14 million, of which $9 million
was for coal, $4 million was for oil and $1 million was for power. Labor
expenses totaled $3 million.
Rental Expenses
Operating lease expense (also referred to as rental fees) related to the
leased generating facilities totaled $3 million.
Depreciation and Amortization
Depreciation and amortization expenses were $2 million. Depreciation
expenses amounted to $1 million, primarily related to the generating
facilities, which are being depreciated over an average of approximately 32
years. Amortization expense amounted to $1 million and related primarily to
amortization of goodwill.
Selling, General and Administrative Expenses
Selling, general and administrative expenses for the period totaled $6
million, including $5 million in non-recurring charges. The remaining $1
million included costs for insurance, outside legal and other contract
services, information technology, telephone and office administration as well
as the service fee from Mirant Americas Energy Marketing under the terms of
the Services and Risk Management Agreement.
Other Income and Expense
Other income included $1 million of interest income from related parties and
an investment account. Financing fees of approximately $4 million were
recognized related to the cancellation of a $1.5 billion bank commitment
letter in December 2000.
Liquidity and Capital Resources
Cash flows provided through operations are expected to be sufficient to
cover our ongoing expenses and capital expenditures. In addition to these cash
flows, we have a dedicated working capital facility in the amount of $150
million from our indirect parent, Mirant Americas Generation. As of March 31,
2001 and December 31,
53
2000, $75 million was outstanding under the facility. Further, should the need
arise, we have the ability to incur additional debt as described in the lease
documents (see "Description of the Certificates--Covenants").
We are required to make semi-annual rental payments under the leases. As of
March 31, 2001, the future rent obligations associated with the leases are
(rounded to millions) $196 million for the nine months ended December 31,
2001, $170 million in 2002, $151 million in 2003, $122 million in 2004, $116
million in 2005 and a total of $2,351 million for the remaining terms of the
leases. A substantial amount of the projected cash flows will be used to
service these payment obligations in addition to ongoing operating expenses
and other expenses.
We have budgeted expenditures for environmental compliance, capital
improvements and repairs in connection with the ongoing maintenance and
operations of the generating facilities. For the period from 2001 through
2010, capital expenditures are expected to total approximately $654 million,
including approximately $280 million for expenditures associated with
environmental compliance.
We expect our cash and financing needs over the next several years to be met
through a combination of cash flows from operations and debt financings.
Operating cash flows along with drawings under the dedicated working capital
facility from our indirect parent, Mirant Americas Generation, are expected to
provide sufficient liquidity for new investments, working capital and capital
expenditure needs for the next 12 months.
Seasonality
Our revenues are expected to be seasonal and affected by unusual weather
conditions. Short-term prices for capacity, energy and ancillary services in
the PJM market are particularly impacted by weather conditions. Peak demand
for electricity typically occurs during the summer months, caused by the
increased use of air-conditioning. Cooler than normal temperatures during
months that are normally warm may lead to reduced use of air-conditioners,
which would reduce short-term demand for capacity, energy and ancillary
services and lead to a reduction in wholesale prices. However, as described in
greater detail in "Relationships with Affiliates and Related Transactions--Our
Arrangements with Mirant Americas Energy Marketing," effective August 1, 2001,
our relationship with Mirant Americas Energy Marketing was reconfigured to
provide us with payments for our committed capacity and energy which are not
directly linked to spot prices for energy.
New Accounting Standard
In July 2000, the FASB issued SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Tangible Assets." SFAS 141 establishes that
all business combinations will be accounted for using the purchase method; use
of the pooling-of-interests method is no longer allowable. The provisions of
SFAS 141 are effective for all business combinations initiated after June 30,
2001 and all business combinations accounted for using the purchase method for
which the date of acquisition is July 1, 2001 or later. SFAS 142 addresses
financial accounting and reporting for acquired goodwill and other intangible
assets and, generally, adopts a non-amortization and periodic impairment
analysis approach to goodwill and indefinitely-lived intangibles. FASB
Statement 142 is effective for Mirant Mid-Atlantic's 2002 fiscal year. The
Company is currently assessing the financial statement impact of both
statements but has not yet determined the final impact at this time.
Quantitative and Qualitative Disclosures about Market Risk
Market risk is the potential loss that we may incur as a result of changes
in the fair value of a particular instrument or commodity. All financial and
commodities-related instruments, including derivatives, are subject to market
risk. Through various hedging mechanisms, primarily contractual arrangements
with Mirant Americas Energy Marketing, we attempt to mitigate some of the
impact of changes in energy prices and fuel costs on our results of
operations.
We engage in commodity-related marketing and price risk management
activities, through Mirant Americas Energy Marketing, in order to hedge market
risk and exposure to electricity and to natural gas, coal and other fuels
utilized by our generation assets. These financial instruments primarily
include forwards, futures and swaps. Prior to January 1, 2001, when we adopted
Statement of Financial Accounting Standards No. 133, the gains and
54
losses related to these derivatives were recognized in the same period as the
settlement of underlying physical transactions. These realized gains and
losses are included in operating revenues and operating expenses in the
accompanying consolidated statement of income for the period from July 12,
2000 (inception) through December 31, 2000. Subsequent to the adoption of SFAS
No. 133 on January 1, 2001, these derivative instruments are recorded in the
consolidated balance sheet as either assets or liabilities measured at fair
value, and changes in the fair value are recognized currently in earnings,
unless specific hedge accounting criteria are met. If the criteria for hedge
accounting are met, changes in the fair value are recognized in other
comprehensive income until such time as the underlying physical transaction is
settled and the gains and losses related to these derivatives are recognized
in earnings. Contractual commitments expose us to both market risk and credit
risk.
We maintain clear policies for undertaking risk-mitigating actions that may
become necessary when measured risks temporarily exceed limits as a result of
market conditions. To the extent an open position exists, fluctuating
commodity prices can impact financial results and financial position, either
favorably or unfavorably. As a result, we cannot predict with precision the
impact that our risk management decisions may have on our businesses,
operating results or financial position. Mirant Americas Energy Marketing
manages price market risk for us through formal oversight groups, which
include senior management, mechanisms that independently verify transactions
and measure risk and the use of a value-at-risk methodology on a daily basis.
We bear all gains and losses of the price market risk activities conducted by
Mirant Americas Energy Marketing on our behalf. Effective August 1, 2001,
however, we entered into an agreement with Mirant Americas Energy Marketing
that provides for us to receive payments for committed capacity and energy
which are not directly linked to spot prices for energy. This agreement
expires in 2004. However, Mirant Americas Energy Marketing has the option to
reduce the committed capacity and energy purchased each year, and after
December 31, 2002, may reduce the committed capacity and energy purchased to
zero.
Mirant Mid-Atlantic employs a systematic approach to the evaluation and
management of risk associated with its marketing and risk management-related
commodity contracts, including Value-at-Risk ("VaR"). VaR is defined as the
maximum loss that is not expected to be exceeded with a given degree of
confidence and over a specified holding period.
Mirant Mid-Atlantic uses a 95% confidence interval and holding periods that
vary by commodity and tenor to evaluate its VaR exposure. Based on a 95%
confidence interval and employing a one-day holding period for all positions,
Mirant Mid-Atlantic's portfolio of positions had a VaR of $4 million at March
31, 2001. During the three months ended March 31, 2001 and the period from
July 12, 2000 (inception) through December 31, 2000 the actual daily change in
fair value did not exceed the corresponding daily VaR calculation. Mirant
Mid-Atlantic also utilizes additional risk control mechanisms such as
commodity position limits and stress testing of the total portfolio and its
components.
55
ABOUT US AND OUR AFFILIATES
Mirant Mid-Atlantic and its Subsidiaries
We are a Delaware limited liability company and an indirect wholly-owned
subsidiary of Mirant. We were formed on July 12, 2000 to acquire, own, lease
and operate a portion of the transaction assets. Specifically, we own the
Dickerson and Morgantown generating facilities, except the leased facilities,
which we lease from the owner lessors, and we own the engineering and
maintenance facility. We operate both the Dickerson and Morgantown generating
facilities, including the leased facilities.
The mailing address of our principal executive offices is 1155 Perimeter
Center West, Atlanta, Georgia 30338-4780. Our telephone number is (678) 579-
5000.
Our subsidiaries, each of which is a Delaware limited liability company,
are:
. Mirant Chalk Point, which was formed on August 2, 2000 to acquire, own
and operate the multi-fuel electric generating facility commonly
referred to as the Chalk Point station, including all baseload and
cycling units, but excluding the peaking units;
. Mirant D.C. Operator, which was formed on August 2, 2000 to enter into
an agreement with Pepco to operate and maintain two oil-fired peaking
facilities owned by Pepco, the Buzzard Point and Benning generating
stations;
. Mirant Piney Point, which was formed on August 2, 2000 to own and
operate the Piney Point oil pipeline which serves the Chalk Point and
Morgantown generating facilities; and
. Mirant Ash Management, which was formed on August 24, 2000 to own and
operate the Westland, Brandywine and Faulkner ash storage facilities.
Mirant Potomac River and Mirant Peaker
. Mirant Potomac River is a Delaware limited liability company that was
formed on August 2, 2000 to acquire, own and operate the coal-fired
generating facility commonly referred to as the Potomac River generating
facility. Mirant Potomac River is a direct wholly-owned subsidiary of
Mirant.
. Mirant Peaker is a Delaware limited liability company that was formed on
August 25, 2000 to acquire and own the six combustion turbine units at
the Chalk Point generating facility and to acquire the rights and
obligations with respect to the Southern Maryland Electric Cooperative
combustion turbine, which is located at the Chalk Point generating
facility. Mirant Peaker is a direct wholly-owned subsidiary of Mirant.
The purchases of the Potomac River generating facility and the Chalk Point
combustion turbines (including the rights and obligations with respect to the
Southern Maryland Electric Cooperative combustion turbine) by Mirant Potomac
River and Mirant Peaker, respectively, were funded by capital contributions
from Mirant and loans from us evidenced by notes. Under the capital
contribution agreement, Mirant will cause, unless prohibited by law, Mirant
Potomac River and Mirant Peaker to make distributions to Mirant, at least once
per quarter, of all cash available after taking into account projected cash
requirements, including mandatory debt service, prepayments permitted under
the Mirant Potomac River and the Mirant Peaker notes, and maintenance
reserves, as reasonably determined by Mirant. Mirant will contribute or cause
these amounts to be contributed to us.
Neither Mirant Potomac River, Mirant Peaker, we, nor any of our subsidiaries
owned any assets or engaged in any business prior to the acquisition of the
transaction assets from Pepco.
Mirant Corporation
Our indirect parent, Mirant, is a global competitive energy company with
leading energy marketing and risk-management expertise. Mirant has extensive
operations in North America, Europe and Asia. With an integrated business
model, Mirant develops, constructs, owns and operates power plants, and sells
wholesale electricity, gas and other energy-related commodity products. Mirant
owns or controls more than 21,600 MW of electric
56
generating capacity around the world, with approximately another 9,000 MW
under development. Mirant considers a project to be under development when it
has contracted to purchase machinery for the project, it owns or controls the
project site and it is in the permitting process. These projects may or may
not have received all of the necessary permits and approvals to begin
construction. Mirant cannot provide assurance that these projects or pending
acquisitions will be completed. In North America, Mirant also controls access
to approximately 3.0 billion cubic feet per day of natural gas production,
more than 2.9 billion cubic feet per day of natural gas transportation and
approximately 41 billion cubic feet of natural gas storage.
Mirant owns and controls power generation and natural gas assets and energy
marketing operations in North America and generation, transmission and
distribution operations in South America and the Caribbean. Mirant owns and
leases power plants in North America with a total generation capacity of over
12,900 MW, and it controls over 2,500 MW of additional generating capacity
through management contracts. Mirant continually reviews acquisition
opportunities and is currently in discussions with a number of parties about
potential acquisitions, including potential acquisitions in the United States
that may be deemed material to Mirant's business. Through Mirant Americas
Energy Marketing, Mirant's wholly owned indirect subsidiary, Mirant markets
and trades energy and energy-linked commodities, including electricity,
natural gas, coal, oil, pulp and paper, weather derivatives and emission
allowances. In the Caribbean and South America, Mirant has ownership interests
in electric utilities, power plants and transmission facilities. These assets
are located in the Bahamas, Jamaica, Trinidad and Tobago, Brazil and Chile.
In Europe, Mirant owns a 49% economic interest and a 50% voting interest in
WPD Holdings UK, which distributes electricity to approximately 1.4 million
end-users in southwest England and approximately 1 million end-users in South
Wales. With the completion of its acquisition of an additional 18.8%, Mirant
now owns a 44.8% interest in Bewag, an electric utility serving over 2 million
customers in Berlin, Germany. Mirant's European marketing and risk management
business began trading power in the Nordic energy markets in 1999. Mirant
began trading power in Germany, The Netherlands and Switzerland in 2000 and
has begun natural gas trading in the UK on the International Petroleum
Exchange in 2001. Mirant's other target markets for energy marketing and
trading include Austria, Italy and central Europe.
In the Asia-Pacific region, Mirant has interests in approximately 3,100 MW
of generation capacity in the Philippines and China, with ownership interest
in another 250 MW under construction in the Philippines and 60 MW under
construction in China. Most of Mirant's revenues in the Asia-Pacific region
are derived from contracts with government entities or regional power boards
and are predominantly linked to the U.S. dollar to mitigate foreign currency
exchange risks. Mirant's other target markets are Korea, Singapore and Japan.
Mirant was formerly a wholly-owned subsidiary of Southern Company. In
October 2000, Mirant closed an initial public offering of 66.7 million shares,
or 19.7%, of its common stock. On April 2, 2001, Southern Company distributed
the remaining shares of Mirant's common stock to holders of Southern Company's
common stock and Mirant ceased being its subsidiary. In April 2001, Mirant was
added to the S&P 500 index. For more information on the distribution, see
Southern Company's Information Statement filed on Form 8-K with the SEC on
March 6, 2001.
Obligations under the leases are not obligations of, or guaranteed by,
Southern Company, Mirant or any of their respective affiliates, other than any
credit support provided by Mirant as described under "Description of the
Certificates--Covenants--Credit Support."
Mirant Americas Generation, Inc.
Mirant Americas Generation, our indirect parent, is an indirect wholly-owned
subsidiary of Mirant that was formed on May 12, 1999 for the purpose of
financing, acquiring, owning, operating and maintaining the bulk of Mirant's
North American generating assets. The remainder of Mirant's North American
assets are held by separate subsidiaries of Mirant. Mirant Americas Generation
currently owns or controls approximately 12,500 MW of electricity generation
capacity, which includes 236 MW under construction, all of which is located in
the United States.
57
Mirant Americas Energy Marketing
Mirant Americas Energy Marketing is an indirect wholly-owned subsidiary of
Mirant. It engages in the marketing and risk management of energy and energy-
linked commodities, including electricity, natural gas, oil, coal and
emissions allowances in North America. Mirant Americas Energy Marketing is a
leading energy marketer in North America. Mirant Americas Energy Marketing was
ranked by Power Markets Weekly as the sixth largest North American power
marketer for year 2000 and by Gas Daily as the tenth largest North American
gas marketer for year 2000. Mirant Americas Energy Marketing is one of only
five companies to be included in the top 10 of both of these rankings.
Mirant Americas Energy Marketing procures fuel for and markets electricity
generated by us and Mirant's North American facilities that are not committed
under long-term contracts. In addition, Mirant Americas Energy Marketing
provides marketing of these and other energy-linked commodities to third
parties. Mirant Americas Energy Marketing employees are located primarily in
Atlanta, with a staff divided between marketing, asset optimization,
logistics, risk control, information technology and other support functions.
In 2000, Mirant Americas Energy Marketing marketed an average of 6.9 billion
cubic feet of natural gas per day and sold 203 million MWh of electricity.
Mirant Americas Energy Marketing owns two seats on and is a member of the New
York Mercantile Exchange and is a FERC licensed national energy wholesaler.
Mirant Americas Energy Marketing's strategy is to be the marketer and risk
manager for affiliates and third parties, including Mirant's North American
generating assets, gas production from BP Amoco p.l.c., Pan-Alberta Gas Supply
Ltd. and Canadian West Gas Supply and other third-party assets. Mirant
Americas Energy Marketing's primary responsibilities are asset optimization
and the management and coordination of the flow of energy commodities. We
believe that Mirant Americas Energy Marketing's energy marketing and risk
management expertise and risk controls will add value to our assets. Over the
next decade, we expect Mirant Americas Energy Marketing to take advantage of
the expected deregulation of the energy business to build upon its position as
a leading energy marketer in North America through its marketing and risk
management expertise, risk controls and information systems.
Mirant Americas Energy Marketing has created a comprehensive control and
risk management organization to manage and mitigate market price risk, credit
risk and operational risk. Key processes executed by this organization include
order entry and transaction verification, control of structured transactions.,
internal and external counterparty credit evaluation, value at risk limits,
stress tests, close monitoring of all positions and value at risk and
independent daily marked-to-market portfolio evaluation.
Mirant Americas Development, Inc.
Mirant Americas Development, Inc. ("Mirant Development") is an indirect
wholly-owned subsidiary of Mirant. Mirant Development will manage development
and construction risks for its affiliates, including us. Mirant Development
will bring facilities under construction to commercial operation, supported by
certain completion assurances by Mirant. Mirant Development will enter into
development agreements with its affiliates to, among other things, provide
capital to develop new projects. We plan to enter into a development agreement
with Mirant Development under which Mirant Development will manage an
expansion of the Dickerson facility.
58
OUR BUSINESS
Industry Overview
In the United States, in response to increasing customer demand for access
to low cost electricity and enhanced services, significant aspects of the
electric industry are currently being restructured. New regulatory initiatives
to increase competition in the domestic power generation industry have been
adopted or are being considered at the federal level and by many states.
The Federal Energy Regulatory Commission issued Order 636 in 1992 and Order
888 in 1996 to increase competition by easing entry into natural gas and
electricity markets. These orders require owners and operators of natural gas
and power transmission systems, respectively, to make transmission service
available on a nondiscriminatory basis to energy suppliers such as us.
In order to better ensure competitive access to the transmission network on
a nondiscriminatory basis, the Federal Energy Regulatory Commission issued
Order 2000 in December 1999. Order 2000 encourages electric utilities with
power transmission assets to voluntarily form regional transmission
organizations to provide regional management and control of transmission
assets independent of control by firms that sell electricity. Among other
things, these regional organizations will have:
. exclusive authority to initiate rate changes for the transmission system
under each regional organization's control,
. exclusive operational control over a broad transmission region, and
. ultimate responsibility for transmission planning and expansion.
These regional transmission organizations are also expected to facilitate
coordination between regions. In the event the response of transmission-owning
utilities to Order 2000 is deemed inadequate, the Federal Energy Regulatory
Commission has announced that it will reexamine this voluntary approach, but
there can be no assurance that such action will be taken.
Orders 636, 888 and 2000 are expected to facilitate access for non-utility
power generators, such as us, who are not owners of transmission assets.
However, the impact of these orders on our business and operations depends on
the effect of these orders on the transmission operations in the PJM market.
Continued uncertainty over transmission pricing may discourage utilities from
investing in needed transmission and cause a reduction in market
opportunities, imposition of wholesale price regulation, or both. We believe
there is a strong trend in the United States toward competitive electric power
and natural gas markets, but that our business will continue to be affected by
regional and local price regulation in the near term.
Due to changing regulatory environments and market dynamics in the United
States, numerous utilities have divested generating assets. This process has
led to industry consolidation and an increase in competition among the
dominant players in the marketplace. This deregulation has provided a
significant degree of liquidity in various wholesale power markets throughout
the United States. However, this consolidation and the continued entry of new
competitors may lead to potentially lower energy prices and profits.
The PJM Market and PJM Independent System Operator
All of the generating facilities acquired from Pepco in December 2000 are
located within the PJM market. The PJM independent system operator operates
the largest centrally dispatched control area in the United States and covers
all or part of the states of Pennsylvania, New Jersey, Maryland, Delaware,
Virginia and the District of Columbia.
Utilities in a number of regions voluntarily established power pools that
attempt to capture the benefits associated with being part of a larger
generation and transmission system, including improved reliability through
coordinated maintenance planning and shared operating reserves, as well as the
blending of load profiles and generating resources. The PJM Power Pool was the
first centrally dispatched power pool in the United States
59
and is one of the largest power pools in the world, with over 220,000 gigawatt
hours of annual electricity sales. For a detailed discussion of power pools,
please see the independent market expert report in Appendix B of this
prospectus.
In response to 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 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.
The PJM independent system operator was certified as an independent system
operator by the Federal Energy Regulatory Commission on November 25, 1997, and
it began operating on April 1, 1998. The stated objectives of this independent
system operator 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 independent system operator manages the PJM
Open Access Transmission Tariff (the first power pool open access tariff
approved by the Federal Energy Regulatory Commission), which provides
comparative pricing and access to the transmission system. PJM also operates
the PJM Interchange Energy Market, which is the region's spot market (power
exchange, or PX) for wholesale electricity. PJM also provides ancillary
services for its transmission customers and performs transmission planning for
the region.
Strategy
Our strategy is to establish and maintain a leading position in the PJM
wholesale electricity market and focus on serving wholesale customers in the
mid-Atlantic region. We will execute this strategy by implementing and
integrating the elements of Mirant's successful strategy for the North
American wholesale electricity market: comprehensive and efficient operations
and maintenance practices and sophisticated risk management with access to
multiple fuel and energy markets.
We intend to manage our maintenance and capital budgets to focus on
achieving high availability at times of peak prices. Our plant management and
operators will work in conjunction with our marketing affiliate, Mirant
Americas Energy Marketing, to schedule planned outages and facility
maintenance when prices are expected to be low. We intend to maintain an
appropriate level of operations, maintenance and capital expenditures
consistent with our priority of high availability at peak times.
We will manage our fuel and energy price risk through Mirant Americas Energy
Marketing, which will utilize the liquid trading hubs for electricity, natural
gas, fuel oil and coal in the mid-Atlantic region. Mirant Americas Energy
Marketing will sell capacity, ancillary services and energy to other
participants in the wholesale markets including the PJM independent system
operator. Sales may range from short-term hourly transactions to bilateral
sales agreements that extend several years. Effective August 1, 2001, however,
we entered into an agreement with Mirant Americas Energy Marketing that
provides for us to receive payments for our committed capacity and energy
which are not directly linked to spot prices for energy. This agreement
expires in 2004. Mirant Americas Energy Marketing will also procure our fuel.
Many of our units are able to run on multiple fuels, offering us the
flexibility to respond to changes in prices of coal, fuel oil, natural gas and
electricity. Purchases of fuel may range from spot purchases to long-term
agreements.
Mirant Americas Energy Marketing will seek to respond quickly to a variety
of changing market signals. It will bid and schedule our generation portfolio
to maximize the value of the diverse mix of baseload, cycling and peaking
units that we operate.
Competitive Strengths
We believe that we have a number of competitive advantages with regard to
our operation of the Mirant Mid-Atlantic assets and our lease of the leased
facilities and Mirant's overall North American strategy. Mirant
60
and we seek to enhance the financial and operational performance of our
businesses and assets. We believe that our strengths, and those of our
affiliates, are in design, engineering, finance, construction management and
fuel procurement. We will utilize management and operations personnel who have
significant operating experience with our generating facilities. We believe
that operations, maintenance, marketing and risk management services provided
by our affiliates will enable us to maintain a competitive advantage essential
to executing our strategy in the PJM market. The complete managerial and
operational control over the transaction assets by us, our subsidiaries and
affiliates will enable us to enhance the financial and operational performance
of the transaction assets.
Significant Presence in a Strategic Location
The generating facilities represent 5,154 MW, or approximately 10%, of the
installed capacity in the PJM market. The PJM market is a mature, large and
growing market. These characteristics facilitate a liquid electricity market
which in turn creates wholesale market opportunities for Mirant Americas
Energy Marketing. In addition, all of the generating facilities are located
near Washington, D.C. and can provide capacity, energy and ancillary services
to this load center when prices are attractive. The PJM independent system
operator also affords access to surrounding systems which are also relatively
well developed markets including the East Central Area Reliability Council,
the New York Power Pool, and the Virginia-Carolina region of the Southeast
Electric Reliability Council. For a detailed discussion of reliability
councils, please see the independent market expert report in Appendix B of
this prospectus.
Low Cost Producer
In order to remain competitive in the deregulated marketplace, it is
important to have low cost, reliable and flexible units. The generating
facilities are well maintained and environmentally sound and include a
considerable amount of low cost coal-fired baseload capacity. The heat rates
of the baseload units in the generating facilities are among the most
efficient in the PJM market. We believe that opportunities may exist to
enhance the performance of the generating facilities by combining the
knowledge of the employees who have operated the transaction assets in the
past with the operating experience of our management team.
Stable Baseload Cashflow Profile
While the generating facilities represent a diverse portfolio across the
entire dispatch curve, 80% of the projected cumulative cash available for
fixed charges over the life of the certificates is anticipated to be derived
from baseload assets. The predominance of cash flow from these units provides
increased stability to our revenues and will allow us to cover our lease
obligations in a variety of pricing environments. We believe that the baseload
coal units will retain and improve their competitiveness over time and support
the continuing strength of our portfolio. In addition, as described in greater
detail in "Relationships with Affiliates and Related Transactions--Our
Arrangements with Mirant Americas Energy Marketing," effective August 1, 2001,
our relationship with Mirant Americas Energy Marketing was reconfigured to
provide us with payments for our committed capacity and energy which are not
directly linked to spot prices for energy.
Dispatch and Fuel Diversity and Flexibility
We believe that the fuel diversity of the generating facilities and the mix
of baseload, intermediate and peaking units enables them to operate profitably
in a variety of market conditions. The portfolio of the generating facilities
comprises 30 units consisting of approximately 52% baseload, 27% intermediate,
and 21% peaking generating capacity. We believe that the proximity of the
generating facilities to load centers, the flexibility associated with the
dispatch diversity and fuel switching capability, and the marketing services
offered through our affiliation with Mirant Americas Energy Marketing will
enable us to increase our revenues and manage our exposure to market risks.
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Energy Trading and Marketing and Fuel Procurement through Mirant Americas
Energy Marketing
Our energy marketing affiliate, Mirant Americas Energy Marketing, is one of
the leading electricity and gas marketers in the United States. Through
various operational agreements, Mirant Americas Energy Marketing will provide
the generating facilities with fuel and emissions credits and will purchase
the power, capacity and ancillary services produced by the generating
facilities. Mirant Americas Energy Marketing's experience in fuel and energy
trading and marketing will provide us with enhanced market knowledge and
greater marketing opportunities over the life of the certificates.
The Acquisition of the Transaction Assets
Background
As part of the acquisition, we, Mirant Potomac River, Mirant Peaker, our
subsidiaries and the owner lessors:
. purchased, acquired the rights to, or leased 5,154 MW of generating
facilities located in Maryland and Virginia, three ash storage
facilities, the Piney Point oil pipeline and the engineering and
maintenance facility,
. agreed to provide power and ancillary services to Pepco in a Washington,
D.C. electric load pocket pursuant to a 20-year local area support
agreement, and
. agreed to provide operations and maintenance services for two power
plants in Washington, D.C. that Pepco continues to own.
The transaction assets consist primarily of four generating stations:
. the 837 MW Dickerson station, fueled by coal, oil and natural gas in
Montgomery County, Maryland;
. the 1,412 MW Morgantown station, fueled by coal and oil in Charles
County, Maryland;
. the 2,423 MW Chalk Point station, fueled by coal, oil and natural gas in
Prince George's County, Maryland (including the rights and obligations
with respect to the Southern Maryland Electric Cooperative combustion
turbine); and
. the 482 MW Potomac River station, fueled by coal in Alexandria,
Virginia.
We own, directly or indirectly through our subsidiaries, all of the
transaction assets, except the leased facilities and the Potomac River/Peaker
assets. We lease the baseload units at the Dickerson and Morgantown generating
facilities pursuant to the leveraged lease transactions. Through our
subsidiary, Mirant Chalk Point, we own the Chalk Point station, except the
combustion turbines.
Mirant Peaker, a direct, wholly-owned subsidiary of Mirant, acquired the six
Chalk Point combustion turbines and the rights and obligations with respect to
the 84 MW Southern Maryland Electric Cooperative combustion turbine located at
the Chalk Point station. The facility and capacity credit agreement for the
Southern Maryland Electric Cooperative combustion turbine was assigned to
Mirant Peaker. Under the agreement, Mirant Peaker receives all output from the
combustion turbine and pays all costs associated with its operation as well as
a fixed monthly capacity charge. The facility and capacity credit agreement
expires on November 30, 2015, unless terminated earlier as permitted under the
agreement. Of the 2,423 MW and 516 MW of aggregate and combustion turbine
capacity, respectively, at the Chalk Point generating facility, 84 MW is
represented by the Southern Maryland Electric Cooperative combustion turbine.
Mirant Potomac River, a direct, wholly-owned subsidiary of Mirant, owns the
Potomac River station and leases the site where the Potomac River station is
located from Pepco under a 99-year lease agreement. Under certain load and
system conditions, local generation support from the Potomac River station is
necessary for the PJM independent system operator to maintain system
reliability. Mirant Potomac River and Pepco have entered into the local area
support agreement, requiring Mirant Potomac River to follow the generation
unit commitment procedures and dispatch orders of the PJM independent system
operator or, in order to maintain local reliability, of Pepco, including
requests for ancillary services.
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Mirant Potomac River and Mirant Peaker are obligated to make payments to us
in connection with our approximate $223 million loan to them. Additionally,
Mirant, as the owner of all ownership interests in Mirant Potomac River and
Mirant Peaker, entered into a capital contribution agreement pursuant to which
Mirant will cause, unless prohibited by law, Mirant Potomac River and Mirant
Peaker to make distributions to Mirant, at least once per quarter, of all cash
available after taking into account projected cash requirements, including
mandatory debt service, prepayments permitted under the Mirant Potomac River
and the Mirant Peaker notes to us, and maintenance reserves, as reasonably
determined by Mirant. Mirant will contribute or cause these amounts to be
contributed to us. The combination of Mirant Potomac River and Mirant Peaker's
loan obligations and Mirant's capital contribution agreement is intended to
make available to us the cash flows from Mirant Potomac River and Mirant
Peaker.
Financing of the Acquisition
The leased facilities were acquired by the owner lessors for a purchase
price of $1,500 million through the leveraged lease financing.
We loaned a total of approximately $223 million of the proceeds of an equity
contribution that we received from Mirant Americas Generation to Mirant
Potomac River and Mirant Peaker to fund part of their acquisitions of the
Potomac River station, the Chalk Point combustion turbines and the rights and
obligations with respect to the Southern Maryland Electric Cooperative
combustion turbine. The remainder of the purchases by Mirant Potomac River and
Mirant Peaker were funded through an equity contribution from Mirant.
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The Generating Facilities
The table below lists and briefly describes the generating facilities
acquired from Pepco and owned or leased by us, our subsidiaries and our
affiliates.
Facility/Location Capacity(1) Dispatch Type Primary Fuel
- ----------------- ----------- ------------- ------------
Generating Facilities Owned by
Us or Our Subsidiary(2)
Chalk Point generating
facility..................... 1,907 Baseload/Cycling Coal/No. 6 Oil/Gas
. Excluding combustion
turbines and rights to
Southern Maryland Electric
Cooperative combustion
turbine
. Prince George's County,
Maryland
Morgantown generating
facility..................... 248 Peaking No. 2 Oil
. Excluding baseload units 1
& 2
. Charles County, Maryland
Dickerson generating
facility..................... 291 Peaking No. 2 Oil/Gas
. Excluding baseload units 1,
2 & 3
. Montgomery County, Maryland
Generating Facilities Leased
by Us Under the Leveraged
Leases
Morgantown generating
facility..................... 1,164 Baseload Coal
. Units 1 & 2
. Charles County, Maryland
Dickerson generating
facility..................... 546 Baseload Coal
. Units 1, 2 & 3
. Montgomery County, Maryland
Generating Facility Owned by
Mirant Potomac River
Potomac River generating
facility..................... 482 Baseload/Cycling Coal
. Alexandria, Virginia
Generating Facilities Owned or
Controlled by Mirant Peaker
Chalk Point combustion
turbines...................... 516 Peaking No. 2 Oil/Gas
. Including the rights and
obligations with respect to
the 84 MW Southern Maryland
Electric Cooperative
combustion turbine
. Prince George's County,
Maryland
Total......................... 5,154
- --------
(1) Summer-rated net capacity in MW.
(2) Mirant Chalk Point owns the baseload and cycling units located at the
Chalk Point generating facility.
A detailed technical review of all of the generating facilities has been
prepared by the independent engineer and is attached as Appendix A of this
prospectus.
The Morgantown Generating Facility
The Morgantown generating facility is an approximately 1,412 MW net summer
capacity coal/oil-fired generating facility located on the Potomac River near
Newburg in Charles County, Maryland. The 620-acre site is approximately 50
miles south of Washington, D.C., with good site access from Route 301.
The Morgantown generating facility combines cost-competitive and dual-fuel
(coal/oil) baseload units with substantial peaking capacity through six oil-
fired combustion turbines. The generating facility's low heat rate is
competitive, and its dual-fuel capability provides operational and fuel
contracting flexibility.
64
The following table sets forth a description of the Morgantown generating
facility:
Net Annual Net Net Equivalent
In Service Capacity Primary Heat Rate Capacity Availability
Unit Unit Type Date (mw) Fuel (btu/kwh)(1) Factor (%) Factor (%)
- ---- --------- ---------- -------- ------- ------------- ---------- ------------
Baseload 1 (Leased)..... Steam 1970 582 Coal(2) 8,945 79 82
Baseload 2 (Leased)..... Steam 1971 582 Coal(2) 8,973 66 70
Peaking/Black Start 1-
6...................... Combustion Turbine 1970-1973 248 #2 Oil 14,243-18,076 2 80
- --------
Note: 1999 Data
(1) Average annual heat rate.
(2) Secondary Fuel #6 Oil.
The Dickerson Generating Facility
The Dickerson generating facility is an approximately 837 MW net summer
capacity generating facility located on the Potomac River, south of the
Monocracy River in Montgomery County, near Dickerson, Maryland. The generating
facility is located on a 1,000-acre site, excluding the approximately 300 acre
Westland ash storage facility. The Dickerson generating facility has potential
expansion opportunities based on the generating facility's multi-fuel
capability, which includes coal, oil and natural gas, good transmission access
and its large site.
The following table sets forth a description of the Dickerson generating
facility:
Net Annual Net Net Equivalent
In Service Capacity Primary Heat Rate Capacity Availability
Unit Unit Type Date (mw) Fuel (btu/kwh)(1) Factor (%) Factor (%)
- ---- --------- ---------- -------- ---------- ------------- ---------- ------------
Baseload 1 (Leased)..... Steam 1959 182 Coal 9,701 78 86
Baseload 2 (Leased)..... Steam 1960 182 Coal 9,728 68 74
Baseload 3 (Leased)..... Steam 1962 182 Coal 9,584 66 75
Peaking/Black Start 1-
3...................... Combustion Turbine 1967-1993(2) 291 #2 Oil/Gas 13,378-19,735 6 77
- --------
Note: 1999 Data
(1) Average annual heat rate.
(2) The combustion turbines were installed in 1967, 1992 and 1993.
Projected Gross Operating Margin of the Leased Facilities
Based on the projected operating results, the contribution to the gross
operating margin (revenue less fuel cost, the cost of emissions allowances and
variable operating and maintenance cost) by the leased facilities over the
term of the certificates was calculated by the independent engineer. Based
upon the electricity revenue and fuel costs for the leased facilities
estimated by the independent market expert, the cost of emissions allowances
estimated by the independent engineer, the variable operating and maintenance
costs of the leased facilities as estimated by us, and the various other
assumptions used in the projected operating results as described in the
independent engineer's report, the leased facilities are estimated by the
independent engineer to provide approximately 47% of the projected gross
operating margin of the generating facilities over the term of the
certificates, or an average of approximately $410 million per year over the
term of the certificates.
The opinions, calculations and estimates in the independent engineer's
report, which is attached as Appendix A, are based on certain assumptions made
by the independent engineer with respect to conditions which may exist or
events which may occur in the future. These assumptions are dependent upon
future events, and actual conditions may differ from those assumed. Investors
are responsible for performing their own review and analysis of the
independent engineer's report. In addition, as described in greater detail in
"Relationships with Affiliates and Related Transactions--Our Arrangements with
Mirant Americas Energy Marketing," effective August 1, 2001, our relationship
with Mirant Americas Energy Marketing was reconfigured to provide us with
payments for our committed capacity and energy which are not directly linked
to spot prices for energy. You should be aware that the assumptions utilized
in the preparation of the independent engineer's report do not contemplate
this revised structure. While we expect that, during the term of this new
contract, our net operating revenues should be more stable as a result of this
revised structure, we have not requested R. W. Beck to update or revise the
independent engineer's report, nor have we undertaken to update or revise any
forward-looking statements based on that report as a result of this revised
structure.
65
The Chalk Point Generating Facility
The Chalk Point generating facility is an approximately 2,423 MW (including
the rights and obligations with respect to the 84 MW Southern Maryland
Electric Cooperative combustion turbine) net summer capacity multi-fuel
generating facility located on the Patuxent River in Prince George's County,
Maryland. The generating facility is approximately 45 miles from Washington,
D.C. and is located on a 1,160-acre site.
The Chalk Point generating facility is the largest of the generating
facilities included in the transaction assets, providing baseload, mid-range
and peaking facilities in combination with substantial fuel flexibility.
The Chalk Point generating facility has high fuel reliability and
flexibility due to multiple fuel transportation options, including train,
pipeline and truck, and multiple fuel types, including coal, oil and natural
gas. Additionally, the large, 1,160-acre site and the existing transmission
infrastructure make the station well-suited for expansion.
The following table sets forth a description of the Chalk Point generating
facility:
Net Annual Net Net Equivalent
In Service Capacity Primary Heat Rate Capacity Availability
Unit Unit Type Date (mw) Fuel (btu/kwh)(1) Factor (%) Factor (%)
- ---- --------- ---------- -------- ---------- ------------- ---------- ------------
Baseload Units 1-2...... Steam 1964-1965 683 Coal 9,451-9,481 78 85
Cycling Units 3-4....... Steam 1975-1981 1,224 #6 Oil/Gas 11,215-11,811 26 87
Peaking/Black Start 1-
7(2)................... Combustion Turbine 1967-1991(3) 516 #2 Oil/Gas 12,600-28,665 5 87
- --------
Note: 1999 Data
(1) Average annual heat rate.
(2) Includes rights and obligations with respect to the 84 MW Southern
Maryland Electric Cooperative combustion turbine.
(3) The combustion turbines were installed in 1967, 1974, 1990 and 1991.
The Potomac River Generating Facility
The Potomac River generating facility is an approximately 482 MW net summer
capacity, coal-fired generating facility, located on the Potomac River in
Alexandria, Virginia. The generating facility is located on a 25-acre site
near Washington, D.C. The generating facility is efficiently operated with
high equivalent availability factors, moderate heat rate efficiency and
transmission access to both the PJM grid and to Virginia Electric Power
Company.
The Potomac River generating facility's proximity to Washington, D.C.
provides it with an excellent opportunity to serve load centers located
nearby. Opportunities for expansion of the facility are limited, however, by
the size of the site and operating restrictions on rail and truck
transportation.
The following table sets forth a description of the Potomac River generating
facility:
Net Annual Net Net Equivalent
In Service Capacity Primary Heat Rate Capacity Availability
Unit Unit Type Date (mw) Fuel (btu/kwh)(1) Factor (%) Factor (%)
- ---- --------- ---------- -------- ------- ------------- ---------- ------------
Cycling Units 1-2....... Steam 1949-1950 176 Coal 12,791-13,297 44 85
Baseload Units 3-5...... Steam 1954-1957 306 Coal 10,111-10,241 76 94
- --------
Note: 1999 Data
(1) Average annual heat rate.
Other Assets, Rights and Obligations
The Piney Point Oil Pipeline
Our subsidiary, Mirant Piney Point, owns the Piney Point oil pipeline, which
is approximately 51.5 miles long and serves the Chalk Point and Morgantown
generating facilities.
66
The Ash Storage Sites
Our subsidiary, Mirant Ash Management, owns three off-site ash storage
facilities, the Westland, Brandywine and Faulkner ash storage facilities. The
Westland ash storage facility is a 300-acre site adjacent to the Dickerson
generating facility. The Faulkner ash storage facility is a 276-acre site 10
miles from the Morgantown generating facility. The Brandywine ash storage
facility is a 232-acre site 16 miles from the Chalk Point generating facility
and 30 miles from the Potomac River generating facility.
Engineering and Maintenance Facility
We own the 145,000 square foot engineering and maintenance facility in
Maryland, located nine miles from Washington, D.C. This facility is the
primary location for all generating engineering and maintenance services,
which provides support for major equipment maintenance for the generating
facilities, including unit planned outages, major component overhauls and
repairs and forced outage support.
The D.C. Operations and Maintenance Agreement
Our subsidiary, Mirant D.C. Operator, entered into an agreement with Pepco
to operate and maintain two other Pepco power plants, the 256 MW Buzzard Point
generating station and the 550 MW Benning generating station. See "Description
of Our Principal Contractual Agreements with Non-Affiliated Parties" for a
further description of the operations and maintenance agreement for the
Buzzard Point and Benning generating stations.
Competition
To the extent our committed capacity and energy is not currently sold under
contract, we compete in the PJM market on the basis of price, operating
characteristics of our generating facilities and the availability of our
generating facilities to supply capacity, energy and ancillary services to the
market when needed. We compete in the PJM market with a number of other major
power generators. A number of additional generating facilities are being
developed in the PJM market and these facilities will increase competition in
the PJM market over time. Additional generating facilities are also being
planned for the PJM market and could be developed in the future.
Intercompany Power Sales and Services Agreements
Mirant Americas Energy Marketing--Power Sales Agreements
We have entered into a power sales agreement with Mirant Americas Energy
Marketing to supply all capacity, ancillary services and energy requirements
to meet Mirant Americas Energy Marketing's obligations under the Pepco
transition power agreements which are not met by deliveries under the Pepco
power purchase agreements or deliveries from Mirant Chalk Point, Mirant
Potomac River and Mirant Peaker, each of which has an agreement to sell all
output from its respective generating facilities to Mirant Americas Energy
Marketing. Effective August 1, 2001, we entered into an Energy and Capacity
Sales Agreement with Mirant Americas Energy Marketing pursuant to which Mirant
Americas Energy Marketing pays us a fixed capacity payment for committed
capacity, and a specified energy charge per MWh for committed energy
delivered. This energy charge is not adjusted for fuel cost. We will also sell
to Mirant Americas Energy Marketing any additional capacity, ancillary
services and energy to the extent these products are available after supplying
our obligations to Mirant Americas Energy Marketing under the Energy Capacity
and Sales Agreement as described in greater detail in "Relationships with
Affiliates and Related Transactions--Our Arrangements with Mirant Americas
Energy Marketing." Our price for the sale of such products to Mirant Americas
Energy Marketing will be the market price Mirant Americas Energy Marketing
obtains from the resale of such products or services to third parties,
including power pools.
Mirant Americas Energy Marketing--Services and Risk Management Agreements
We have entered into a services and risk management agreement with Mirant
Americas Energy Marketing, and Mirant Chalk Point, Mirant Peaker and Mirant
Potomac River have also entered into such an agreement with
67
Mirant Americas Energy Marketing on substantially similar terms. Under these
services and risk management agreements, Mirant Americas Energy Marketing
dispatches each of our generating facilities and provides fuel, procures
emissions credits and enters into marketing arrangements, hedges and other
transactions for our benefit. We bear the gains and losses arising from such
transactions. We, Mirant Chalk Point, Mirant Peaker and Mirant Potomac River
each pay an annual fee to Mirant Americas Energy Marketing for its estimated
cost of providing these services. Once the net revenues (revenues less the fee
paid to Mirant Americas Energy Marketing) received by us together with the net
revenues received by Mirant Chalk Point, Mirant Peaker and Mirant Potomac
River reach a specified level, Mirant Americas Energy Marketing is entitled to
a specified percentage of the aggregate net revenues in excess of such amount.
Such percentage of net revenues payable to Mirant Americas Energy Marketing
will only be paid by us to Mirant Americas Energy Marketing to the extent such
amount may be paid by us as a restricted payment under the participation
agreements and is subordinated to our obligations.
Mirant Mid-Atlantic Services--Management and Personnel Services Agreements
Mirant Mid-Atlantic Services, an indirect wholly-owned subsidiary of Mirant,
acting as an independent contractor, has hired Pepco personnel to provide
operation, maintenance and general management services and advice to us,
Mirant Chalk Point, Mirant Potomac River, Mirant Peaker and Mirant D.C.
Operator. Each company utilizing such personnel pays a fee to Mirant Mid-
Atlantic Services equal to Mirant Mid-Atlantic Services' costs of providing
such personnel services.
Mirant Services--Administrative Services Agreements
Mirant Services, a direct wholly-owned subsidiary of Mirant, acting as an
independent contractor, provides executive personnel and administrative
services to us, Mirant Chalk Point, Mirant Potomac River, Mirant Peaker and
Mirant D.C. Operator. Each company utilizing such services pays a fee to
Mirant Services equal to Mirant Services' costs of providing such services.
Mirant MD Ash Management--Ash Disposal and Storage Services Agreements
Mirant MD Ash Management, acting as an independent contractor, provides
services, personnel and resources to load, transport, unload and store ash
produced by each of the generating stations. Each generating station utilizing
such services pays a fee to Mirant MD Ash Management equal to Mirant MD Ash
Management's costs of providing such services.
Mirant Piney Point--Oil Delivery Services Agreements
Mirant Piney Point, acting as an independent contractor, provides services,
personnel and resources to deliver oil to the Morgantown and Chalk Point
generating facilities. We and Mirant Chalk Point each pay a fee to Mirant
Piney Point equal to Mirant Piney Point's cost of providing these services to
the Morgantown generating facility and the Chalk Point generating facility,
respectively.
Mirant Peaker/Mirant Chalk Point--Common Facilities Agreement
Mirant Chalk Point provides personnel, services and resources for and access
to the common facilities shared by Mirant Chalk Point and Mirant Peaker at the
Chalk Point station. Mirant Peaker pays a fee to Mirant Chalk Point equal to
Mirant Chalk Point's costs of providing such services in connection with the
operation and maintenance of the combustion turbines at the Chalk Point
generating facility.
See the "Relationships with Affiliates and Related Transactions" section for
a more complete description of all of our intercompany services agreements.
Employees
We do not have any employees of our own. Mirant Mid-Atlantic Services hired
approximately 950 Pepco personnel and provides all operations, maintenance and
general management personnel to us, Mirant Chalk Point,
68
Mirant Potomac River, Mirant Peaker and Mirant D.C. Operator. All of the
transaction assets are staffed by a combination of union and nonunion
employees. All union employees are covered by a collective bargaining
agreement with the International Brotherhood of Electrical Workers, Local
1900. The collective bargaining agreement expires on May 31, 2003, with annual
automatic renewals unless either party delivers two month's prior written
notice. However, the agreement is subject to reopening for wages and benefits
in 2002.
Legal Proceedings
We may experience routine litigation from time to time in the normal course
of our business, none of which is expected to have a material adverse effect
on our financial condition or results of operations.
In January 2001, the U.S. Environmental Protection Agency, Region 3 issued a
request for information to Mirant Mid-Atlantic concerning the air permitting
implications of past repair and maintenance activities at its Potomac River
plant in Virginia and Chalk Point, Dickerson and Morgantown plants in
Maryland. We are in the process of responding fully to this request.
On August 2, 2001, Potomac Electric Power Company ("Pepco") filed a civil
action against Mirant in the U.S. District Court for the District of Columbia
(Case No. 1:01CV01674), alleging that Mirant breached the Asset Purchase and
Sale Agreement ("APSA") between Pepco and Mirant's predecessor (Southern
Energy, Inc.) governing Mirant's purchase of most of Pepco's electric
generation assets. Specifically, Pepco alleges that Mirant's withholding of
$11.7 million from a post-closing payment for fuel inventory is in breach of
the APSA. Due to the early stages of this litigation and the uncertainties
inherent in the litigation process, we cannot predict the outcome of this
proceeding at this time.
69
REGULATION
Energy Regulatory Matters
General
Our ownership, lease and operation of the Mirant Mid-Atlantic assets and the
leased assets are subject to numerous federal, state and local statutes and
regulations. These statutes and regulations, among other things, govern, to a
certain extent, the rates that we may charge for the output of the generating
facilities owned or leased by us and establish, in certain instances, the
operating standards for such generating facilities.
Federal Regulation
Federal Power Act. Under the Federal Power Act, the Federal Energy Regulatory
Commission possesses exclusive rate-making jurisdiction over wholesale sales of
energy, capacity, ancillary services and transmission services in interstate
commerce. The Federal Energy Regulatory Commission regulates the owners of
generating facilities used for the wholesale sale of energy and transmission in
interstate commerce as "public utilities" under the Federal Power Act.
On December 12, 2000 the Federal Energy Regulatory Commission approved the
transfer of those assets over which it had jurisdiction from Pepco to us,
Mirant Chalk Point, Mirant Potomac River and Mirant Peaker, as applicable. In
this order, the Federal Energy Regulatory Commission authorized us to enter
into the leveraged lease transactions for the purpose of financing the leased
facilities and granted a disclaimer of jurisdiction over each of the owner
participants and the owner lessors (and the trustees involved in the leveraged
lease transactions) as public utilities under Section 201 of the Federal Power
Act.
All public utilities subject to the Federal Energy Regulatory Commission's
jurisdiction are required to obtain the Federal Energy Regulatory Commission's
acceptance of their rate schedules in connection with the wholesale sale of
energy. On November 21, 2000, the Federal Energy Regulatory Commission accepted
for filing the proposed market rate tariffs filed by us, Mirant Chalk Point,
Mirant Potomac River and Mirant Peaker, thereby authorizing each of us, Mirant
Chalk Point, Mirant Potomac River and Mirant Peaker to make wholesale sales of
energy, capacity and ancillary services at market-based rates, subject to
various standard regulatory conditions, to willing purchasers in wholesale
markets.
Public Utility Holding Company Act. The Public Utility Holding Company Act
provides that any corporation, partnership or other entity or organized group
that owns, controls or holds power to vote 10% or more of the outstanding
voting securities of a "public utility company" or a company that is a "holding
company" of a public utility company is subject to regulation under the Public
Utility Holding Company Act, unless an exemption is established or an order is
issued by the Securities and Exchange Commission declaring it not to be a
holding company. Registered holding companies under the Public Utility Holding
Company Act are required to limit their utility operations to a single
integrated utility system and to divest any other operations not functionally
related to the operation of the utility system. In addition, a public utility
company that is a subsidiary of a registered holding company under the Public
Utility Holding Company Act is subject to financial and organizational
regulation, including approval by the Securities and Exchange Commission of
certain of its financing transactions. However, as explained below, neither we,
Mirant Chalk Point, Mirant Potomac River or Mirant Peaker are subject to
regulation under the Public Utility Holding Company Act.
Under the Energy Policy Act, a company engaged exclusively in the business of
owning and/or operating a facility used for the generation of energy for sale
at wholesale may be exempted from the Public Utility Holding Company Act
regulation as an "exempt wholesale generator." On December 11, 2000, we and
each of Mirant Chalk Point, Mirant Potomac River and Mirant Peaker filed
applications for exempt wholesale generator status with the Federal Energy
Regulatory Commission, which applications were effective upon filing. The owner
lessors filed applications for exempt wholesale generator status with the
Federal Energy Regulatory Commission
70
on December 15, 2000. Such applications were also effective upon filing. As
exempt wholesale generators, we, Mirant Chalk Point, Mirant Potomac River,
Mirant Peaker and the owner lessors are precluded from making any direct sales
to retail customers, or we will risk losing our exempt status and becoming
"electric utility companies" as that term is defined in the Public Utility
Holding Company Act. In addition, any retail sales in Maryland, Virginia or
elsewhere will be effectuated via wholesale sales from us to a wholesale
purchaser, which may then make retail sales in accordance with the state law in
the relevant jurisdictions. In that circumstance, the wholesale purchaser may
become subject to state regulation with regard to such retail sales.
Lease Transaction Filings and Approvals. As explained above, we and the
appropriate financial participants in the lease transactions received all
Federal Energy Regulatory Commission approvals required for the consummation of
the lease transactions.
In the event that the indenture trustees exercise certain remedies under
their respective indentures and the collateral becomes the property of an
indenture trustee, additional federal and state approvals may be required from
the SEC, the Federal Energy Regulatory Commission or the State of Maryland (and
other state or federal agencies with respect to permits and other like
entitlements) before the exercise of such remedies may be consummated. The
likelihood of obtaining such approvals, or any associated terms and conditions,
will depend on the law then in effect and on the particular facts and
circumstances presented by such proposed transfer.
State Regulation
Neither we nor Mirant Chalk Point, Mirant Potomac River or Mirant Peaker are
subject to rate regulation by the Public Service Commission of the District of
Columbia, the Maryland Public Service Commission or the Virginia State
Corporation Commission with respect to wholesale sales of energy, capacity or
ancillary services.
We, Mirant Chalk Point, Mirant Potomac River and Mirant Peaker received all
other state approvals required for the acquisition of the transaction assets,
including the issuance of a certificate of convenience and public necessity by
the Virginia State Corporation Commission. On November 15, 2000 and November
22, 2000, the Public Service Commission of the District of Columbia and the
Maryland Public Service Commission, respectively determined that the generating
facilities in their respective jurisdictions are "eligible facilities" as
defined in the Energy Policy Act, which determinations were required for filing
applications for exempt wholesale generator status with the Federal Energy
Regulatory Commission.
Environmental Regulatory Matters
General
Our operations are subject to a number of federal, state and local
environmental regulations relating to the safety and health of personnel, the
public and the environment. Key areas covered by these regulations include:
. standards and limitations on the release of air and water pollutants to
the environment;
. matters related to hazardous and toxic materials;
. limits on noise emissions;
. safety and health standards;
. practices and procedures applicable to the operation of our assets; and
. protection of endangered and threatened species.
Compliance with these regulations require significant expenditures. Failure
to comply with any of these regulations also could have material adverse
effects on operation of the transaction assets including the imposition of
criminal or civil liability or fines by regulatory agencies or liability to
private parties. In addition, pursuant to the asset purchase and sale agreement
with Pepco, we, our subsidiaries and our affiliates, Mirant Potomac River and
Mirant Peaker, will indemnify Pepco against all environmental liabilities
associated with the
71
past operation of the transaction assets, except for fines and penalties.
Also, we, our subsidiaries and our affiliates will not indemnify Pepco against
any environmental liability relating to the disposal or release of hazardous
substances by Pepco prior to the closing of the acquisition at any off-site
location or any environmental liability related to the release of fuel oil
from the Piney Point oil pipeline prior to the closing. Additionally, under
the asset purchase and sale agreement, we, our subsidiaries and our affiliates
will be responsible for future compliance with applicable environmental laws
affecting the respective assets acquired or leased by each of us.
It is likely that environmental regulations affecting our operations will
become more stringent in the future, and that it will cost more for us to
comply with potential future regulations. We cannot assure you that future
compliance with these regulations will not adversely affect our operations or
financial condition. In the meantime, we will monitor potential regulatory
developments that may impact our operations and may participate in any
rulemakings applicable to our operations.
Air Emissions
In order to reduce acid rain and ground level ozone, or smog, the federal
Clean Air Act and related state laws require significant reductions in sulfur
dioxide (SO\\2\\) and nitrogen oxides (NOx) emissions that result from burning
fossil fuels at power plants. The primary permit that regulates generating
facilities' air emissions is the Clean Air Act Title V Operating Permit. The
Title V Operating Permit applications for the Dickerson, Morgantown, and the
Chalk Point generating facilities were submitted in December 1996. By letter
in January 1997, the Maryland Department of the Environment deemed the
applications complete. The Maryland Department of the Environment has not yet
issued the final permits for these generating facilities; however, preliminary
draft Title V permits have been issued for the Dickerson and Morgantown
plants. The Maryland Department of the Environment indicated in its January
1997 letter that the plants can continue operation subject to the permits
currently in effect.
The Title V application for the Potomac River generating facility was
submitted to the Virginia Department of Environmental Quality and deemed
complete on March 4, 1998. On March 29, 2001, the preliminary draft Title V
permit was issued for the generating facility.
The current permits for these generating facilities contain specific
emission limits and monitoring requirements as well as other conditions that
must be complied with during the operation of the plants. The generating
facilities are also subject to limits set forth in consent agreements that
Pepco negotiated with the relevant state environmental agencies. The consent
agreements cover requirements associated with:
. the generating facilities' compliance with Reasonably Available Control
Technology standards (Title I of the Clean Air Act requires these
additional standards in areas not in attainment of the National Ambient
Air Quality Standards);
. Maryland's NOx Budget Rule (this Title I requirement establishes NOx
emission allowance budgets for each of the coal-fired units);
. Opacity or Visible Emission standards; and
. compliance with other SO\\2\\ and opacity requirements.
Based on the information available to us, each of the generating facilities
is currently in compliance with applicable emission limits defined in their
respective permits or in the negotiated consent agreements.
On January 17, 2001, Mirant received a request for information from the U.S.
Environmental Protection Agency, pursuant to its authority under the Clean Air
Act, requiring Mirant to provide records and information relevant to the
repair and maintenance history of Potomac River, Chalk Point, Dickerson and
Morgantown power plants. Mirant is in the process of responding to the request
for information. The request for information is an information gathering tool
and is not an allegation that the generating stations are in violation of the
law. However, the Environmental Protection Agency is currently engaged in a
national regulatory enforcement initiative against the coal-fired electric
utility industry pursuant to the New Source Review and New Source
72
Performance Standard provisions of Title I of the Clean Air Act and its
related regulations. The Environmental Protection Agency has targeted
activities widely understood in the utility industry to be routine maintenance
and repair activities, which are exempt from the permitting requirements of
the law. Depending on the outcome of the Environmental Protection Agency's
enforcement initiative, the potential cost of compliance could be significant.
Sulfur Dioxide (SO\\2\\). SO\\2\\ emissions are regulated under Title IV of
the Clean Air Act, which established the national Acid Rain Program to address
emissions of acid rain precursors, SO\\2\\ and NOx. The Acid Rain Program
mandates substantial reductions in SO\\2\\ emissions to meet a national cap
for such emissions. Phase I of the Acid Rain Program set a national annual
emissions cap for certain affected facilities beginning in 1995, and Phase II
of this program set a national annual emissions cap for the remaining affected
facilities beginning in 2000. Methods for achieving reductions in SO\\2\\
emissions include addition of emission controls, allowance purchases, fuel
switching and unit retirements. Each of the coal-fired units at the generating
facilities is subject to these requirements, whereby each coal-fired unit is
allocated a certain number of allowances that may be banked or sold under this
program, such that a generating facility could acquire the additional SO\\2\\
allowance it needs to operate, or sell excess allowances to third parties. As
part of the asset purchase and sale agreement, Pepco transferred to us, Mirant
Chalk Point and Mirant Potomac River all of the SO\\2\\ allowances allocated
to the respective coal-fired units that each of us own or lease. We anticipate
that there will be a need to buy SO\\2\\ allowances in order to comply with
the requirements of the Acid Rain Program. A summary of the anticipated need
for SO\\2\\ allowances can be found in the independent engineer's report,
attached hereto as Appendix A.
Nitrogen Oxides (NOx). Several Clean Air Act programs require reduction of
NOx emissions from certain coal-fired electric utility boilers, including
those operated at our generating facilities. These programs include: the
Reasonably Available Control Technology requirements, Title IV of the Clean
Air Act, which established the Acid Rain Program, and Title I of the Clean Air
Act. Compliance with the Reasonably Available Control Technology requirements
for NOx has been achieved in the past through a system-wide averaging. A
consent agreement with the Virginia Department of Environmental Quality
requires that the Reasonably Available Control Technology averaging plan not
result in any greater emissions during the ozone season than would have
occurred with unit-by-unit Reasonably Available Control Technology controls.
If necessary, interstate or intrastate allowance trading may be used to comply
with this requirement.
The Acid Rain Program imposes additional requirements on the generating
facilities. Chalk Point units 1 and 2 and Morgantown units 1 and 2 became
subject to the requirements of the Acid Rain Program beginning in 1995.
Potomac River units 1 through 5 can defer complying with lower emissions
limits until 2008. Dickerson units 1 through 3 became subject to the
requirements of the Program beginning in 2000. A summary of the Acid Rain
Program requirements and the compliance plan for these units can be found in
the independent engineer's report, attached hereto as Appendix A. According to
the information available, the generating facilities are in compliance with
all Acid Rain Program requirements.
Under Title I of the Clean Air Act, NOx emission budgets were established in
2000, with further reductions expected in 2003. Each of the coal-fired units
at the generating facilities has been allocated NOx emission allowances. We
anticipate that there will be an initial need to buy NOx allowances in order
to comply with the Title I requirements. A summary of the anticipated initial
need for NOx allowances can be found in the independent engineer's report,
attached hereto as Appendix A.
Particulates and Opacity. The Environmental Protection Agency issued
standards in July 1997 which could significantly increase the areas in the
country that are not in attainment with the standard for airborne
particulates. In a related rulemaking, the Environmental Protection Agency
also issued regulations requiring reduction in emissions that affect haze on a
regional scale. Federal law requires states to submit what are known as
revised state implementation plans that address both particulate matter
emissions and regional haze at the same
73
time. For areas that fail to attain the particulate matter standards, state
implementation plan revisions that address particulate matter and regional
haze should be submitted to the Environmental Protection Agency by
approximately 2007 and 2008 and should also establish an appropriate
compliance period (e.g., 10 years) to meet the new standards. Both the
regional haze rule and the particulate matter standard may have a material
adverse effect on the transaction assets.
The Dickerson generating facility is currently operating under a consent
order issued by the Maryland Department of the Environment which requires the
coal-fired units to meet visible emissions standards by July 2003.
Mercury. In December 2000, the Environmental Protection Agency determined
that mercury emissions for coal and oil-fired power plants should be
regulated. The proposed rule is scheduled for 2003 with the final rule
scheduled for 2004. Compliance could be required by approximately 2007, and
may result in additional costs to the generating facilities. Currently, given
the uncertain status of these possible requirements, we cannot determine if
they will have a material adverse effect on the transaction assets.
Carbon Dioxide (CO\\2\\). In 1993, President Clinton committed the United
States to limit CO\\2\\ and other greenhouse gas emissions to their 1990
levels by the year 2000. It became apparent that this goal was unlikely to be
met by most industrialized nations, and the Kyoto Protocol was formulated to
expedite a global climate treaty. If adopted by the participating nations, the
Kyoto Protocol or any climate treaty will have significant economic
consequences for the utility industry as a whole, and particularly for coal-
fired generating facilities. The United States has signed the Kyoto Protocol
which, if ratified, would require the United States to significantly reduce
its greenhouse gas emissions between 2008 and 2012. If the treaty is ratified,
the EPA would then initiate a rulemaking process. In March 2001, President
Bush officially pronounced his opposition to the Kyoto Protocol. The cost of
meeting any future CO\\2\\ requirements could be significant. Currently, any
reductions in greenhouse gas emissions are based on voluntary reduction
measures.
Hazardous Material and Wastes
The Environmental Protection Agency has indicated that within the next few
years it plans to promulgate new national regulations governing coal ash
management, which would be enforceable at the state level. Such regulations
are anticipated to require increased groundwater monitoring and/or
installation of an impermeable lining system, when warranted by site-specific
conditions. Our three ash disposal sites currently have groundwater monitoring
in place, and funds have been budgeted to install liner systems as new ash
disposal "cells" are created. Thus, we do not expect the Environmental
Protection Agency's new coal ash management regulations to have a significant
cost impact on the transaction assets.
Our facilities are also subject to several waste management laws and
regulations in the United States. The Resource Conservation and Recovery Act
sets forth very comprehensive requirements for handling of solid and hazardous
wastes. The generation of electricity produces non-hazardous and hazardous
materials, and we incur substantial costs to store and dispose of waste
materials from our facilities. Recently, the Environmental Protection Agency
indicated that it may intensify regulation of fossil fuel combustion
materials, including types of coal ash, under the Resource Conservation and
Recovery Act. If the Environmental Protection Agency implements its initial
proposals on this issue, we may be required to change our current waste
management practices and expend significant resources on the increased waste
management requirements caused by the Environmental Protection Agency's change
in policy.
Water Issues
The transaction assets, including the ash disposal sites, have been designed
and are operated to meet strict water and wastewater compliance standards,
which have been established through the National Pollutant Discharge
Elimination System program permits. In general, these permits have established
limitations on temperature, pH, residual chlorine or other oxidants, certain
metals, such as, iron and copper, suspended solids, oil and grease,
biochemical oxygen demand and fecal coliform, depending on specific effluent
sources. With respect to temperature limits, the Dickerson and Chalk Point
generating facilities have been granted thermal variances, which are
authorized when a facility has demonstrated that its thermal discharge has not
caused
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appreciable harm to the aquatic community in the receiving water body.
Historically, the variances have been renewed and we expect such renewals in
the future. The current permit for the Potomac River generating facility
requires the facility to show that its thermal discharge is in compliance with
water quality standards. Based on historical information, we believe that the
facility will successfully meet the appropriate standards or obtain a thermal
variance.
A number of groundwater protection measures at the transaction assets have
been implemented, which include:
. a lined coal pile at the Morgantown facility;
. clay-lined active dry ash disposal sites; and
. an extensive network of groundwater monitoring wells, designed to
monitor potential sources of contamination.
Regulatory developments that may affect intake and discharge of cooling
water at our facilities include regulation of intake structures and
development of total maximum daily loads. We do not know at this point what
impact, if any, these developments may have on the transaction assets. With
respect to existing cooling water intake structures, the Environmental
Protection Agency is currently required to propose regulations for existing
facilities by February 28, 2002 and to promulgate final regulations by August
28, 2003. The Environmental Protection Agency has proposed a new rule that
would impose more stringent standards on the cooling water intakes for new
plants.
Water Appropriation
The transaction assets withdraw water from surface water and/or groundwater
sources for a variety of uses, such as providing cooling and drinking water.
The State of Maryland regulates the appropriation of water through a water
appropriation permitting program. Historically, these permits have been
renewed without problems or controversy. The transaction assets have all
necessary water appropriation permits in place and are operating within their
withdrawal limits.
Environmental Site Assessments
Other than visual observations of the sites, we have not conducted any
independent investigation of environmental conditions at the sites of the
transaction assets, but have relied exclusively on Phase I of Environmental
Site Assessments conducted in 1999 by Pepco's environmental consultants.
Currently unknown environmental conditions at any of the transaction assets
may have a material adverse effect on the transaction assets or our ability to
pay the rent under the leases. Our decision to acquire the transaction assets
without further environmental investigation increases the risk of such unknown
conditions. A summary of the specific findings made in the Phase I assessments
can be found in the independent engineer's report, attached hereto as Appendix
A.
75
MANAGEMENT
We are a limited liability company. Ninety-nine percent of our interests are
owned by Mirant Mid-Atlantic Investments, Inc., and 1% of our interests are
owned by Mirant Mid-Atlantic Management, Inc. Our affairs are managed by
Mirant Mid-Atlantic Management, which is managed by a board of directors
consisting of Gary J. Morsches, John L. O'Neal and Michael L. Smith. Both
Mirant Mid-Atlantic Investments and Mirant Mid-Atlantic Management are direct
wholly-owned subsidiaries of Mirant Americas Generation, which is an indirect
wholly-owned subsidiary of Mirant. The officers listed below have been
appointed by Mirant Mid-Atlantic Management.
Name Age Position
---- --- --------
Gary J. Morsches............. 41 Chief Executive Officer
John L. O'Neal............... 33 President
Gary J. Kubik................ 39 Vice President, Chief Financial Officer and
Treasurer
Richard J. Koch.............. 51 Vice President and Chief Operating Officer
Michael L. Smith............. 41 Vice President
Paul M. Lansdell............. 36 Vice President and Controller
Michelle H. Ancosky.......... 30 Secretary
Elizabeth B. Chandler........ 37 Assistant Secretary
Sonnet Edmonds............... 32 Assistant Secretary
Below are the principal past occupations and business activities of our
officers in addition to their positions described above.
Gary J. Morsches has served as our Chief Executive Officer since November 8,
2000. Mr. Morsches also serves as Senior Vice President and Chief Executive
Officer of the East Region of Mirant Americas Group, which positions he has
held since September 2000. Prior to this, Mr. Morsches served as the President
of Mirant Americas Energy Marketing since October 1999. From October 1998 to
October 1999, Mr. Morsches was the Senior Vice President and Chief Operating
Officer of Mirant Americas Energy Marketing. Prior to this, Mr. Morsches
served as Mirant Americas Energy Marketing's Vice President of Trading, which
position he held from 1997, when he joined Mirant Americas Energy Marketing,
until October 1998. Prior to joining Mirant Americas Energy Marketing, Mr.
Morsches served in various commercial roles with Sostram Corporation, Enron,
Access Energy and Diamond Shamrock Refinery & Marketing Company.
John L. O'Neal has served as our President since July 12, 2000. Previously,
Mr. O'Neal served as the Director of Asset Management and Cash Trading for
Mirant Americas Energy Marketing's Western Region from 1999 to July 2000. Mr.
O'Neal traded short-term and forward power throughout Mirant Americas Energy
Marketing's Western Region from August 1997 to 1999. Prior to joining Mirant
Americas Energy Marketing in 1997, Mr. O'Neal served as Assistant to the
President and Chief Executive Officer and the Assistant to the Chief Financial
Officer of Mirant since 1995.
Gary J. Kubik has served as our Vice President, Chief Financial Officer and
Treasurer since July 12, 2000. Mr. Kubik also serves as Vice President and
Chief Financial Officer of the East Region of Mirant's Americas Group, which
positions he has held since October 2000. Prior to this, he served as
Executive Director of Finance for Mirant, a position he held since 1998. He
served as Mirant's Director of Corporate Finance from 1997 to 1998, Project
Director from 1996 to 1997 and Project Finance Manager from 1993 to 1996.
Prior to joining Mirant, Mr. Kubik served in various roles at GE Capital and
Westpac Banking Corporation.
Richard J. (Dick) Koch has served as our Vice President and Chief Operating
Officer since November 8, 2000. Since March 1997, Mr. Koch was the business
unit manager for Mobile Energy Services Company, L.L.C., a partially owned
indirect subsidiary of Southern Company. From 1992 to March 1997, he served as
General Manager for Power Generation at Savannah Electric, also a subsidiary
of Southern Company. Prior to that, Mr. Koch, who joined Southern Company in
1972, held a variety of positions with various Southern Company subsidiaries.
76
Michael L. Smith has served as our Vice President since November 8, 2000.
Mr. Smith also serves as Senior Vice President and Chief Financial Officer of
Mirant's Americas Group, which positions he has held since September 2000 and
June 2000, respectively. Prior to these positions, Mr. Smith served as the
Chief Financial Officer for Mirant Americas Energy Marketing from September
1997 through May 2000. From 1996 through 1997, Mr. Smith was Manager of
Planning and Evaluation for Vastar Resources, Inc., and from 1994 through 1995
Mr. Smith was Vastar Resources' Manager of Business Analysis.
Paul M. Lansdell has served as our Vice President and Controller since
November 8, 2000. From April to October 2000, Mr. Lansdell served as Treasurer
of Western Power Distribution, a subsidiary of Mirant, in Bristol, England.
From April 1999 through March 2000, Mr. Lansdell, who joined Western Power
Distribution in March 1993, served as Assistant to the Chief Executive
Officer. From December 1997 through March 1999, Mr. Lansdell served as
Financial Controller of Western Power Distribution's supply business.
Michelle H. Ancosky has served as our Secretary since November 8, 2000. Ms.
Ancosky also serves as Corporate Governance Analyst in Mirant's Corporate
Legal Group, which position she has held since she joined Mirant in September
2000. From October 1999 through September 2000, Ms. Ancosky was the Corporate
Secretary of Georgia Tech Foundation, Inc. From February 1995 through mid-
September 1999, Ms. Ancosky was Director of Corporate Records (formerly Senior
Analyst) at Magellan Health Services, Inc., where she also served as the
Secretary or Assistant Secretary of several of its subsidiaries.
Elizabeth B. Chandler has served as our Assistant Secretary since November
8, 2000. Ms. Chandler currently serves as a Vice President in Mirant's
Corporate Legal Group and is the Secretary of Mirant. Before joining Mirant in
February 2000, Ms. Chandler was a partner with the law firm of Troutman
Sanders LLP since 1996. Ms. Chandler joined Troutman Sanders LLP in 1988.
Sonnet Edmonds has served as our Assistant Secretary since July 12, 2000.
Ms. Edmonds also serves as Assistant General Counsel in Mirant's Americas
Legal Group. Prior to joining Mirant in 1998, Ms. Edmonds was associated with
the Kansas City law firm of Polsinelli, White, Vardeman & Shalton since May
1997. Prior to that, she was an associate with Brickfield, Burchette & Ritts,
a Washington, D.C. law firm, since 1993.
John L. O'Neal, Richard J. Koch and Paul M. Lansdell are the only three of
our officers that will work full-time for us. The rest of our officers will
work part-time for us and will also work for affiliates of ours. We
acknowledge that the attention of the officers who do not work full time for
us may, from time to time, be required for our affiliates rather than for us.
If this occurs, we intend to shift their responsibilities to other members of
our management team, or to authorize others to act, and to take other action
to avoid a material adverse effect on our business. These officers may perform
services for our affiliates on projects that may compete with us. See "Risk
Factors--Mirant controls us and its interests may come into conflict with
yours" and "Relationships with Affiliates and Related Transactions."
Compensation
We are a recently formed limited liability company. Mirant Services, a
direct subsidiary of Mirant, directly pays the salaries of our officers listed
above. A portion of those salaries are effectively paid by us through an
administrative services agreement with Mirant Services, described in
"Relationships with Affiliates and Related Transactions--Intercompany Services
Agreements--Mirant Services--Administrative Services Agreements." For the
calendar year 2000, the aggregate amount of base compensation allocated to us
and paid by us to all officers as a group, on an annual basis for services to
us in all capacities, was $624,626.
All members of our management are eligible to participate in employee
benefit plans and arrangements sponsored by Mirant for its similarly situated
employees. This includes 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.
77
RELATIONSHIPS WITH AFFILIATES AND RELATED TRANSACTIONS
The following is a summary of the intercompany relationships and related
transactions regarding us, Mirant Potomac River, Mirant Peaker, Mirant, Mirant
Mid-Atlantic Services, Mirant Americas Generation, Mirant Services and Mirant
Americas Energy Marketing.
Our Relationship with Mirant
Ninety-nine percent of our membership interests are owned by Mirant Mid-
Atlantic Investments and 1% of our interests are owned by Mirant Mid-Atlantic
Management, which are both direct wholly-owned subsidiaries of Mirant Americas
Generation. Mirant Americas Generation is a direct wholly-owned subsidiary of
Mirant Americas, Inc., which is a direct wholly-owned subsidiary of Mirant.
We have been organized and operated as a legal entity separate and apart
from Mirant and any other affiliates of Mirant. Therefore, the transaction
assets are not generally available to satisfy the obligations of Mirant or any
other affiliates of Mirant. However, our unrestricted cash or other assets
which are available for distribution may, subject to applicable law and the
terms of financing arrangements of these parties, be advanced, loaned, paid as
dividends or otherwise distributed or contributed to Mirant or any of its
affiliates. Mirant is not obligated to make any payments under the
certificates or lessor notes and are not obligated to guarantee our lease
obligations, other than any credit support provided by Mirant as described
under "Description of the Certificates--Covenants--Credit Support."
Intercompany Financing Agreements
We have entered into the following intercompany loans and agreements in
connection with the lease financing.
Mirant Potomac River Note
We loaned $152 million to Mirant Potomac River to fund its purchase of the
Potomac River station. In return, we received a note from Mirant Potomac River
to be paid in full on December 30, 2028. Mirant Potomac River is obligated to
pay interest at the rate of 10% per annum, due and payable semiannually, in
arrears, on the thirtieth day of June and December of each calendar year
beginning June 30, 2001. Mirant Potomac River may prepay not more than $5
million of the principal amount of the note each year on a cumulative basis.
Mirant Peaker Note
We loaned $71 million to Mirant Peaker to fund Mirant Peaker's purchase of
the Chalk Point combustion turbines (including the rights and obligations with
respect to the Southern Maryland Electric Cooperative combustion turbine). In
return, we received a note from Mirant Peaker to be paid in full on December
30, 2028. Mirant Peaker is obligated to pay interest at the rate of 10% per
annum, due and payable semiannually, in arrears, on the thirtieth day of June
and December of each calendar year beginning June 30, 2001. Mirant Peaker may
prepay not more than $3 million of the principal amount of the note each year
on a cumulative basis.
Mirant--Capital Contribution Agreement
In connection with the lease transactions, Mirant entered into a capital
contribution agreement with us and is obligated to contribute to us all cash
distributions Mirant receives from Mirant Potomac River and Mirant Peaker.
Mirant will not be permitted to transfer any of its membership interest in
Mirant Potomac River or Mirant Peaker other than through a capital
contribution to us or to one of our wholly-owned subsidiaries. Mirant will be
obligated to cause Mirant Potomac River and Mirant Peaker, unless prohibited
by law, to distribute to Mirant, at least once per quarter, all cash available
after taking into account projected cash requirements, including mandatory
debt service, prepayments permitted under the Mirant Potomac River and the
Mirant Peaker notes, and maintenance reserves, as reasonably determined by
Mirant. Mirant will contribute or cause these amounts to
78
be contributed to us. In addition, Mirant will not permit Mirant Potomac River
or Mirant Peaker to incur indebtedness, assume liens, consolidate, merge, sell
assets, or engage in certain activities except as provided in the
participation agreements.
Mirant Americas Generation--Working Capital Facility
Mirant Americas Generation will make available up to $150 million for our
working capital requirements. In return, we gave Mirant Americas Generation a
demand note for the repayment of all sums advanced by Mirant Americas
Generation. We will pay interest at a rate per annum equal to Mirant Americas
Generation's total cost of borrowed funds from time to time calculated by
Mirant Americas Generation. Interest calculated under the note shall be due
and payable semiannually, in arrears, on the first day of January and July of
each calendar year beginning July 1, 2001. We may also prepay the note in
whole or in part, without penalty. As of March 31, 2001, $75 million was
outstanding under the note.
Intercompany Services Agreements
Mirant Mid-Atlantic Services--Management and Personnel Services Agreements
Mirant Mid-Atlantic Services, an indirect wholly-owned subsidiary of Mirant,
acting as an independent contractor, hired Pepco personnel to provide
operation, maintenance and general management services and advice to us,
Mirant Chalk Point, Mirant Potomac River, Mirant Peaker and Mirant D.C.
Operator. Each company utilizing such personnel pays a fee to Mirant Mid-
Atlantic Services equal to Mirant Mid-Atlantic Services' costs of providing
such services. Mirant Mid-Atlantic Services' agreements with us and with each
of Mirant Chalk Point, Mirant Peaker, Mirant Potomac River and Mirant D.C.
Operator expire on December 31, 2001, but automatically renew for successive
one year terms unless either party to an agreement notifies the other party,
at least 30 days prior to the expiration date, that such agreement will not be
renewed.
Mirant Services--Administrative Services Agreements
Mirant Services, a direct wholly-owned subsidiary of Mirant, acting as an
independent contractor, provides the following services to us, Mirant Chalk
Point, Mirant Potomac River, Mirant Peaker and Mirant D.C. Operator: contract
administrative services and advice; bookkeeping, accounting and auditing
services and advice; finance and treasury services and advice; tax advice and
assistance and insurance and bonding advice and assistance. Our executives are
employed by Mirant Services. Each company utilizing such services pays a fee
to Mirant Services equal to Mirant Services' cost of providing such services.
Mirant Services' agreements with us and with each of Mirant Chalk Point,
Mirant Peaker, Mirant Potomac River and Mirant D.C. Operator expire on
December 31, 2001, but automatically renew for successive one year terms
unless either party to an agreement notifies the other party, at least 30 days
prior to the expiration date, that such agreement will not be renewed.
Mirant MD Ash Management--Ash Disposal and Storage Services Agreements
Mirant MD Ash Management, acting as an independent contractor, provides
services, personnel and resources to load, transport, unload and store ash
produced by each of the generating stations. Each generating station utilizing
such services pays a fee to Mirant MD Ash Management equal to Mirant MD Ash
Management's cost of providing such services. Each of these agreements will
expire on December 31, 2001, but will automatically renew for successive one
year terms unless either party to an agreement notifies the other party to
such agreement, at least 30 days prior to the expiration date, that the
agreement will not be renewed.
Mirant Piney Point--Oil Delivery Services Agreements
Mirant Piney Point, acting as an independent contractor, provides services,
personnel and resources to deliver oil to the Morgantown and Chalk Point
generating facilities. We and Chalk Point each pay a fee to Mirant Piney Point
equal to Mirant Piney Point's cost of providing these services to the
Morgantown generating facility and the Chalk Point generating facility,
respectively. Each of these agreements will expire on December 31, 2001, but
will automatically renew for successive one year terms unless either party to
an agreement notifies the other party to such agreement, at least 30 days
prior to the expiration date, that the agreement will not be renewed.
79
Mirant Peaker/Mirant Chalk Point--Common Facilities Agreement
Mirant Chalk Point provides personnel, services and resources for and access
to the common facilities to be shared by Mirant Chalk Point and Mirant Peaker
at the Chalk Point generating facility. Mirant Peaker pays a fee to Mirant
Chalk Point equal to Mirant Chalk Point's costs of providing such services in
connection with the operation and maintenance of the combustion turbine at the
Chalk Point generating facility. This common facilities agreement will expire
on December 31, 2001, but will automatically renew for successive one year
terms unless either party to the agreement notifies the other party to the
agreement, at least 30 days prior to the expiration date, that the agreement
will not be renewed.
Our Arrangements with Mirant Americas Energy Marketing
Power Sales Agreements
We and Mirant Chalk Point, Mirant Potomac River and Mirant Peaker have each
entered into a master power sales agreement with Mirant Americas Energy
Marketing (the Master Power Sales Agreements). In March of 2001, we and Mirant
Chalk Point, Mirant Potomac River and Mirant Peaker also entered into
confirmations to our respective Master Power Sales Agreements (the March
Confirmations) under which we each agreed to supply all capacity, ancillary
services and energy requirements to meet Mirant Americas Energy Marketing's
obligations under the Pepco transition power agreements which are not met by
deliveries under the Pepco power purchase agreements. Our agreement to supply
Mirant Americas Energy Marketing's obligations under the transition power
agreements also includes supplying power to Mirant Americas Energy Marketing
to enable it to meet the load requirements for any retail customer served by a
supplier supplied by Mirant Americas Energy Marketing, which customer was
previously supplied by Pepco and whose load would be included within the load
supplied by the Pepco transition power agreement if such customer had remained
a customer of Pepco. Effective as of August 1, 2001, we, Mirant Chalk Point,
Mirant Potomac River and Mirant Peaker each entered into Energy and Capacity
Sales Agreements with Mirant Americas Energy Marketing which substitute and
terminate the March Confirmation and are described below.
Mirant Americas Energy Marketing has agreed to assume Mirant's obligation to
enter into the Pepco transition power agreements to supply Pepco the energy
and capacity needed to service Pepco's default service load. In return, Mirant
Americas Energy Marketing will receive from Pepco payments for capacity,
ancillary services and energy to its default customers. The Pepco transition
power agreement for the Washington, D.C. load expires in December 2004, while
the Pepco transition power agreement for the Maryland load expires June 30,
2004. During the term of the Pepco transition power agreements, Mirant
Americas Energy Marketing is required to supply Pepco's full requirements for
capacity, ancillary services and energy. In the first contract year, Pepco
will purchase 100% of its energy requirements from Mirant Americas Energy
Marketing. In the second contract year, Pepco is required to purchase 75% of
its energy requirements from Mirant Americas Energy Marketing and has an
option to purchase the remaining 25% of its requirements from Mirant Americas
Energy Marketing. During the third and fourth contract years, Pepco has no
obligation to purchase power from Mirant Americas Energy Marketing under the
transition power agreements. However, Pepco has the option to purchase up to
100% (in 25% blocks) of its energy requirements from Mirant Americas Energy
Marketing, with the restriction that the amount purchased cannot exceed the
percentage of Pepco's energy requirement purchased in the prior year.
Mirant Americas Energy Marketing's obligation to pay us and Mirant Chalk
Point, Mirant Potomac River or Mirant Peaker under the Master Power Sales
Agreements and the Energy and Capacity Sales Agreements market price is not
affected by the price in Mirant Americas Energy Marketing's transition power
agreements with Pepco. In addition, Mirant Americas Energy Marketing has an
agreement with Mirant to recover or receive the amount by which the market
price of supply exceeds the contract price under the Pepco transition power
agreements (Makewhole Obligation).
Mirant Americas Energy Marketing entered into a back-to-back arrangement
with Pepco whereby Mirant Americas Energy Marketing acquired Pepco's
contractual entitlements and assumed Pepco's obligations under certain power
purchase agreements, with Pepco acting as an intermediary between Mirant
Americas Energy
80
Marketing and the counterparties to the power purchase agreements. The power
purchase agreements subject to the back-to-back arrangement include:
. an agreement with Ohio Edison Company and Pennsylvania Power Company for
450 MW,
. an agreement with Panda-Brandywine for approximately 230 MW, and
. an agreement with Northeast Maryland Waste Disposal Authority for
approximately 50 MW.
We supply capacity, ancillary services and energy to Mirant Americas Energy
Marketing either from our own generating facilities or through power purchases
arranged by Mirant Americas Energy Marketing on our behalf. Such power
purchases will not include power purchased under the power purchase agreements
assumed by Mirant Americas Energy Marketing. Effective August 1, 2001, we,
Mirant Chalk Point, Mirant Potomac River and Mirant Peaker each entered into
Energy and Capacity Sales Agreements (ECSAs) with Mirant Americas Energy
Marketing. Each ECSA has an initial term which expires in June of 2004, and
includes an option for Mirant Americas Energy Marketing to extend the initial
term through December 31, 2004. Under the terms of the ECSA:
. Mirant Americas Energy Marketing pays the seller a fixed capacity
payment ranging from $10,400 per MW-month to $12,120 per MW-month over
the term of the contract for committed capacity (initially all of the
capacity from the units owned or leased by us, Mirant Chalk Point,
Mirant Potomac River and Mirant Peaker). If the availability of the
committed capacity calculated on a twelve month rolling average is 75%
or greater, we will be entitled to the full capacity payment. If
availability is below 75%, our capacity payment will be reduced at the
rate of 1 1/3% of the capacity payment for each 1% reduction in
availability.
. Mirant Americas Energy Marketing pays the seller a specified energy
charge for committed energy delivered of $16.50 per MWh in year 1 of the
ECSAs; $17.15 per MWh in year 2 of the ECSAs; $17.75 per MWh in year 3
of the ECSAs; $18.80 per MWh in year 4 of the ECSAs; and $18.80 per MWh
in extension periods. These energy charges are not adjusted for fuel
costs.
. Mirant Americas Energy Marketing has the option to reduce the committed
capacity and energy purchased each year; however, Mirant Americas Energy
Marketing does not have the unilateral right to increase committed
capacity in any subsequent year. After December 31, 2002, Mirant
Americas Energy Marketing may reduce the committed capacity and energy
purchased to zero. If Mirant Americas Energy Marketing elects to reduce
committed capacity, it will purchase all energy and other products
associated with the released capacity at market prices.
. We agree to supply other products which are necessary to meet Mirant
Americas Energy Marketing's obligations under the Pepco transition power
agreements which are not met by deliveries under the Pepco power
purchase agreements. We are paid for these other products at market
prices.
The ECSAs were designed in order to provide us with payments for our
committed capacity and energy which are not directly linked to spot market
prices for energy, which can be volatile. During periods where energy prices
paid under the ECSAs are above the prices received by Mirant Americas Energy
Marketing from Pepco under the transition power agreements or market prices,
Mirant will be responsible for paying the difference to Mirant Americas Energy
Marketing under the Makewhole Obligation.
We will sell Mirant Americas Energy Marketing additional capacity, ancillary
services and energy to the extent such products are available after supplying
our obligations to Mirant Americas Energy Marketing under the ECSA. Our price
for such sales will be the actual price Mirant Americas Energy Marketing
obtains from the resale of such products to third parties, including power
pools.
Services and Risk Management Agreements
We have entered into a services and risk management agreement with Mirant
Americas Energy Marketing, and Mirant Chalk Point, Mirant Peaker and Mirant
Potomac River have also entered into such an agreement with
81
Mirant Americas Energy Marketing on substantially similar terms. Because these
services and risk management agreements are substantially similar, we will
describe the terms and conditions of only one of these agreements. Our
services and risk management agreement provides that:
. Mirant Americas Energy Marketing is responsible for all dispatching or
bidding of our generating facilities.
. Mirant Americas Energy Marketing provides fuel, including fuel oil, gas
and coal, for our generating facilities at Mirant Americas Energy
Marketing's cost. Fuel costs are calculated as Mirant Americas Energy
Marketing's actual cost for transportation, inventory and related costs,
as adjusted for any gains or losses on fuel hedges and trading
activities.
. Mirant Americas Energy Marketing procures all emissions credits
necessary for the operation of our generating facilities, and sells
excess credits. Mirant Americas Energy Marketing charges Mirant Americas
Energy Marketing's actual cost of acquiring the credits and remits the
proceeds of any emission credit sales to us, as adjusted for any gains
or losses on emission hedges and trading activities.
. Mirant Americas Energy Marketing procures or advises us to procure
business interruption insurance and forced outage insurance. The costs
of such insurance are charged to us. Any proceeds from such insurance
will be included within the gross revenues for purposes of calculating
our net revenues for the year and any bonus payable to Mirant Americas
Energy Marketing.
. Mirant Americas Energy Marketing enters into financial products
(including, but not limited to, swaps, contracts for differences,
options and weather derivatives) purchased for us. The costs, including
without limitation, third party broker costs, transaction fees and
revenues related to such financial products, are charged to or paid to
us.
. Mirant Americas Energy Marketing enters into forward sales, hedges and
other transactions for our benefit. The costs of such transactions,
including without limitation, purchased power costs, transmission costs,
third party broker costs, transaction fees and incremental credit costs,
and gains or losses related to such activities, are charged to or paid
to us.
We, Mirant Chalk Point, Mirant Peaker and Mirant Potomac River each pay an
annual service fee to Mirant Americas Energy Marketing for providing these
services. The service fee payable for the first term of the agreement
(December 18, 2000 through December 31, 2001) is approximately $7.5 million.
In addition, once our net revenues together with the net revenues received by
Mirant Chalk Point, Mirant Peaker and Mirant Potomac River reach a specified
level, Mirant Americas Energy Marketing is entitled to 50% of the aggregate
net revenues in excess of such amount. The specified amount of aggregate net
revenues used to calculate Mirant Americas Energy Marketing's bonus will be
established by Mirant Americas Energy Marketing and us on an annual basis. For
2001, Mirant Americas Energy Marketing is entitled to 50% of the Mirant Chalk
Point, Mirant Peaker, Mirant Potomac River and our aggregate net revenues in
excess of $896 million. Amounts of net revenues due Mirant Americas Energy
Marketing under this agreement are only payable to the extent that we could at
the time make a restricted payment and are fully subordinated to the payments
due under the facility leases and all other non-disputed obligations then due
and payable. This agreement may be terminated by us without further payment
upon the exercise of remedies following the occurrence of a lease event of
default (as defined under "Description of the Leases and Other Lease
Documents--Defaults--Lease Events of Default."
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DESCRIPTION OF OUR PRINCIPAL CONTRACTUAL ARRANGEMENTS WITH
NON-AFFILIATED PARTIES
Asset Purchase and Sale Agreement
Mirant and Pepco entered into the asset purchase and sale agreement for the
purchase and sale of the transaction assets and for other transactions. Mirant
assigned its rights to acquire the transaction assets to us, Mirant Chalk
Point, Mirant Peaker, Mirant Potomac River, Mirant D.C. Operator, Mirant PJM
Management, Mirant Piney Point and Mirant Ash Management. Prior to closing the
lease transactions, we assigned to the owner lessors the right to acquire the
leased facilities. For purposes of describing the asset purchase and sale
agreement, we refer to the owner lessors, Mirant Chalk Point, Mirant Peaker,
Mirant Potomac River, Mirant D.C. Operator, Mirant Mid-Atlantic Services,
Mirant Piney Point, Mirant Ash Management and us as the purchasers.
Assumed Obligations
The asset purchase and sale agreement provides that we and our affiliates
assumed Pepco's liabilities with respect to the transaction assets, except, in
each case, liabilities retained by Pepco. Our assumed liabilities include any
environmental liability arising out of or in connection with the transaction
assets prior to, on or after closing, except for liabilities specifically
retained by Pepco.
Retained Assets and Liabilities
Pursuant to the asset purchase and sale agreement, Pepco retained ownership
of various assets, including: (i) the transmission and distribution assets;
(ii) all mainframe computer systems and software, copyrights or other
proprietary information not primarily relating to the power generation
operations of the generating facilities; and (iii) all master station voltage
control equipment including the master station voltage control cabinets
located at the generating facilities. We refer to these assets as the retained
assets. Pepco will also retain various liabilities, including: (i) all
liabilities and obligations associated with the retained assets; (ii) any
environmental liability arising out of the disposal or release of hazardous
substances at any off-site location prior to the closing date; (iii) any
environmental liability arising out of the disposal or release of hazardous
substances from the retained assets after the closing date; and (iv) any
environmental liability associated with the release of fuel oil from the Piney
Point oil pipeline in April 2000. We refer to these liabilities as the
retained liabilities.
Indemnification
Pepco is obligated to indemnify the purchasers from any liability or loss
incurred related to: (i) any breach by Pepco of any covenant or agreement;
(ii) the retained liabilities; or (iii) any breach by Pepco of any agreement
related to the purchase from Pepco of the transaction assets. The purchasers
will be obligated to indemnify Pepco from any liability or loss incurred
related to: (i) any breach by purchasers of any covenant or agreement; (ii)
the obligations assumed by the purchasers; (iii) any of the purchasers'
obligations under any assumed contract, warranty or permit; (iv) any transfer,
sales or excise tax obligation imposed on Pepco arising from the sale or
transfer of the transaction assets; or (v) any breach by the purchasers of any
ancillary agreement. Neither Pepco nor the purchasers will be responsible to
the other party for any indemnifiable loss, unless the aggregate amount of
Pepco's or the purchasers' indemnifiable losses exceeds $5 million.
Interconnection Agreements
We, Mirant Chalk Point and Mirant Potomac River, each of which we refer to
as a generator, entered into an interconnection agreement with Pepco. Because
these interconnection agreements differ only with respect to the description
of the generating facilities at which the generator will need interconnection
service, we will describe the terms and conditions of only one of these
agreements. The term of each interconnection agreement is December 19, 2000
through the earlier of the permanent cessation by the generator of the power
generation function of the generating facilities or the permanent cessation of
the interconnection functions of the transmission system owned by Pepco.
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Interconnection Services
Pepco will permit the generating facilities to continue to be interconnected
to its transmission system at the generating facilities' point of
interconnection and will provide interconnection service at such point of
interconnection. Pepco's interconnection service provided to the generator
will be such services as are necessary to connect the generating facilities to
the transmission system for parallel operation of the generating facilities
and to enable the generator to transmit the energy and ancillary services
produced by the generating facilities to the transmission system and receive
energy service and ancillary services, including blackstart power, from the
generator's supplier. Pepco will permit the generator to interconnect the
generating facilities so long as the generator continues to operate the
generating facilities in accordance with the requirements of the PJM
interconnected power pool and good utility practice.
Reasonable Costs and Maintenance
The generator will be responsible for all reasonable costs incurred by Pepco
to provide the generator with interconnection service and to maintain the
interconnection facilities pursuant to the interconnection agreement. The
generator will be required to maintain its generating facilities in a safe and
efficient manner and as required by the PJM independent system operator
requirements and good utility practice. However, the generator will not be
required to modernize, expand or upgrade the generating facilities unless the
failure to modernize would be likely to have a material adverse effect on the
operation of the interconnection facilities or the transmission system.
Mirant D.C. Operator Operation and Maintenance Agreement for Buzzard Point and
Benning Facilities
Pepco and Mirant D.C. Operator have entered into an operation and
maintenance agreement under which Mirant D.C. Operator operates and maintains
various Pepco-owned generating facilities. Pepco retained ownership of two
generating facilities located in the District of Columbia: the Buzzard Point
station and the Benning station.
Term, Renewal and Termination
The term of the operation and maintenance agreement commenced on December
19, 2000 and will expire on December 31, 2003. The agreement will
automatically renew for terms of three years unless either party delivers a
written notice not to renew the operation and maintenance agreement at least
one year prior to its expiration. If Pepco terminates the operation and
maintenance agreement after the initial term, Pepco will pay Mirant D.C.
Operator a termination fee of $250,000.
Fee
For each year of the initial term of the operation and maintenance
agreement, Pepco will pay Mirant D.C. Operator a fee of $500,000. This fee
does not include bonuses Mirant D.C. Operator may earn through its
performance. The fee during any renewal term will be determined by mutual
agreement of the parties. Mirant D.C. Operator will also be entitled to
reimbursement of costs incurred that are consistent with the approved
operating budget and the approved capital budget.
Potomac River Site Lease Agreement
Pepco and Mirant Potomac River have entered into a site lease agreement for
the site on which the Potomac River station is located. Pepco leases the site
to Mirant Potomac River, and Mirant Potomac River operates and maintains the
site at its sole cost and expense, including, but not limited to, utility
payments and insurance coverage. Mirant Potomac River also has the right to
mortgage its interest in the site. The site consists of the land on which the
Potomac River station sits and adjoins a parcel of land owned by Pepco upon
which various transmission and distribution facilities owned by Pepco are
located. The site and the parcel containing the transmission and distribution
facilities are part of the same overall recorded land parcel.
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Term, Termination and Rent
The term of the Potomac River site lease began on December 19, 2000 and will
expire ninety-nine years thereafter. For each year of the Potomac River site
lease, Mirant Potomac River will pay Pepco an annual rent of one dollar. On
the due date of the rent, Mirant Potomac River will pay Pepco the rent and any
applicable real estate taxes related to the site.
Assignment
Mirant Potomac River may not assign the Potomac River site lease or sublet
the site without the prior written consent of Pepco. However, Mirant Potomac
River will not need Pepco's prior consent to assign or sublet the site to an
affiliate of Mirant Potomac River in connection with the transfer of the
Potomac River station to such affiliate.
Potomac River Station Local Area Support Agreement
Pepco and Mirant Potomac River have entered into an agreement, called a
local area support agreement, pursuant to which Mirant Potomac River will
provide Pepco with power and ancillary services from the Potomac River
generating facility to a Washington, D.C. electric load pocket for a term of
twenty years and in accordance with good utility practice. Under the terms and
conditions of the local area support agreement, Mirant Potomac River will make
the Potomac River generating facility available in order to maintain the local
area reliability of Pepco. Mirant Potomac River will be liable for damages for
failure to meet its obligations under the local area support agreement.
Mirant Potomac River is obligated to promptly notify Pepco of any condition
reasonably likely to cause Mirant Potomac River to fail to provide energy or
ancillary services. Mirant Potomac River must also follow certain guidelines
prior to the retirement or indefinite removal from service of the Potomac
River station. Pepco has no obligation under the local area support agreement
to compensate Mirant Potomac River for such local area support except if Pepco
requires Mirant Potomac River to generate electricity when the PJM independent
system operator has not. In this case, Pepco must pay Mirant Potomac River the
amount the PJM independent system operator would have paid Mirant Potomac
River if the PJM independent system operator had ordered such operation. The
maintenance of the Potomac River generating facility must be scheduled in
accordance with the reliability needs of PJM, and the Potomac River generating
facility may only be retired or indefinitely removed from service upon five
years notice and only then after consideration of the necessary resources
needed to replace the generating facility.
Assignment
Upon ten days' prior written notice to Mirant Potomac River, Pepco may
assign the local area support agreement to (i) an affiliated entity that owns
all or part of Pepco's transmission system or (ii) an independent system
operator or independent transmission company whose control over all or part of
Pepco's transmission system has been approved by the Federal Energy Regulatory
Commission. Mirant Potomac River may assign, transfer or pledge its rights or
interest in the local area support agreement for purposes relating to the
financing or refinancing of the Potomac River generating facility. Mirant
Potomac River will be unable to sell, lease or otherwise transfer the Potomac
River generating facility without Pepco's prior written consent which will not
be unreasonably withheld.
Fuel and Fuel Transportation Contracts
Pepco's fuel supply and fuel transportation contracts were assigned to
Mirant Americas Energy Marketing. These include contracts for supply of coal,
fuel oil and natural gas; for rail transportation of coal; for pipeline
delivery of natural gas; and for terminal handling, storage and delivery (by
pipeline or barge) of fuel oil. These agreements cover fuel utilized by the
Morgantown, Dickerson, Chalk Point and Potomac River generating facilities, as
well as the Benning Road and Buzzard Point generating facilities where our
subsidiary provides operations and maintenance services.
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DESCRIPTION OF THE CERTIFICATES
The existing certificates in aggregate principal amount of $1,224,000,000
were issued pursuant to three separate pass through trust agreements between
us and the pass through trustees. The new certificates will be issued under
the pass through trust agreements in the same aggregate principal amount and
will be identical in all material respects to the existing certificates.
The statements under this caption are a summary only and do not purport to
be complete. This summary makes use of terms defined in and is qualified in
its entirety by reference to all of the provisions of the certificates, the
participation agreements, the leases, the facility site leases, the facility
site subleases, the lease indentures, the lessor notes and the pass through
trust agreements in respect of each of the lease transactions, collectively
referred to below as the operative documents. As used in this section, the
term "certificate" refers to both existing certificates and new certificates.
Except as otherwise indicated, the following summaries relate to each of the
three pass through trust agreements, the pass through trusts formed by the
pass through trust agreements and the certificates to be issued by each pass
through trust.
General
The existing certificates were, and the new certificates will be, issued in
fully registered form without coupons. Each new certificate will represent a
fractional undivided interest in the pass through trust created by the pass
through trust agreement pursuant to which each certificate will be issued.
The property of each pass through trust consists solely of:
. the lessor notes held in the related pass through trust;
. all monies at any time paid on the related lessor notes;
. all monies due and to become due under the related lessor notes;
. funds from time to time deposited with the pass through trustee in
accounts relating to such pass through trust; and
. proceeds from the sale by the pass through trustee of a lessor note.
Each certificate corresponds to a pro rata share of the outstanding
principal amount of the lessor notes held in the related pass through trust
and is issuable in minimum denominations of $100,000 or integral multiples of
$1,000 in excess thereof. No person acquiring a beneficial interest in the
certificates (we will refer to each person as a certificate owner) will be
entitled to receive a definitive certificate representing such person's
interest in the certificates, except as set forth below under "Book-Entry;
Delivery and Form." Unless and until definitive certificates (as defined
below) are issued under the limited circumstances described herein, all
references to actions by registered certificate holders shall refer to actions
taken by DTC upon instructions from DTC participants (as defined below), and
all references to distributions, notices, reports and statements to
certificate holders shall refer, as the case may be, to distributions,
notices, reports and statements to DTC or its nominee, Cede & Co., as the
registered holder of the certificates, or to DTC participants for distribution
to certificate owners in accordance with DTC procedures. See "Book-Entry;
Delivery and Form."
The certificates represent interests in the respective pass through trusts
and do not represent an interest in or obligation of Mirant Mid-Atlantic, the
pass through trustees or the owner lessors, or any of their affiliates. The
pass through trustee shall make distributions to the certificate holders
solely from the property of the related pass through trust. By accepting a
certificate, a certificate holder agrees that it will look only to the income
and proceeds of the property of the related pass through trust insofar as that
income and those proceeds are available for distribution. The certificates
will be subject to prepayment when and to the extent that the related Lessor
Notes are redeemed, prepaid or purchased. See "The Lessor Notes--Redemption of
Lessor Notes" and "The Lessor Notes--Owner Lessor's Right to Purchase the
Lessor Notes."
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Same-Day Settlement and Payment
All payments made by us under the leases to the indenture trustee (as
assignee of the owner lessors) and subsequently to the pass through trustee
will be in immediately available funds and will be passed through to DTC in
immediately available funds.
Payments and Distributions
Scheduled payments of principal and interest on the lessor notes are herein
referred to as scheduled payments, and each June 30 and December 30 of each
year, commencing June 30, 2001, are herein referred to as regular distribution
dates. Each certificate holder is entitled to receive a pro rata share of any
distribution in respect of scheduled payments of principal and interest made
on the related class of lessor notes. All scheduled payments of principal and
interest on the lessor notes held in each pass through trust received by the
pass through trustee will be distributed by the pass through trustee to
certificate holders on the date such receipt is confirmed.
Interest. Payments of interest on the unpaid principal amount of the lessor
notes held in the pass through trusts are scheduled to be received by the pass
through trustee on each June 30 and December 30 of each year, commencing June
30, 2001, at the applicable annual rate for such pass through trust indicated
on the cover page of this prospectus, until the final distribution date for
such pass through trust. Interest will be passed through to certificate
holders of each of the pass through trusts at the applicable annual rate,
calculated on the basis of a 360-day year of twelve 30-day months.
Principal. Scheduled principal payments on the lessor notes and the
resulting distributions on the certificates are as follows (rounded to the
first decimal place):
Debt Amortization Schedule
Percentage of Percentage of Percentage of
Initial Balance Initial Balance Initial Balance
Regular Distribution of Series A of Series B of Series C
Dates Certificates Certificates Certificates
-------------------- --------------- --------------- ---------------
June 30, 2001........... 6.2 10.5 2.6
December 30, 2001....... 0.2 0.0 0.0
June 30, 2002........... 14.9 0.0 0.0
December 30, 2002....... 0.2 0.0 0.0
June 30, 2003........... 11.6 0.0 0.0
December 30, 2003....... 0.2 0.0 0.0
June 30, 2004........... 5.2 0.0 0.0
December 30, 2004....... 0.2 0.0 0.0
June 30, 2005........... 4.6 0.0 0.0
December 30, 2005....... 0.2 0.0 0.0
June 30, 2006........... 2.7 0.0 0.0
December 30, 2006....... 0.2 0.0 0.0
June 30, 2007........... 4.5 0.0 0.0
December 30, 2007....... 0.2 0.0 0.0
June 30, 2008........... 7.0 0.0 0.0
December 30, 2008....... 0.1 0.0 0.0
June 30, 2009........... 7.2 0.0 0.0
December 30, 2009....... 0.1 0.0 0.0
June 30, 2010........... 13.1 0.0 0.0
December 30, 2010....... 0.1 0.0 0.0
June 30, 2011........... 12.9 0.0 0.0
December 30, 2011....... 0.0 0.0 0.0
June 30, 2012........... 8.5 5.4 0.0
December 30, 2012....... 0.0 0.0
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Percentage of Percentage of Percentage of
Initial Balance Initial Balance Initial Balance
Regular Distribution of Series A of Series B of Series C
Dates Certificates Certificates Certificates
-------------------- --------------- --------------- ---------------
June 30, 2013........... 17.2 0.0
December 30, 2013....... 0.0 0.0
June 30, 2014........... 16.7 0.0
December 30, 2014....... 0.0 0.0
June 30, 2015........... 12.5 0.0
December 30, 2015....... 0.0 0.0
June 30, 2016........... 13.2 0.0
December 30, 2016....... 0.0 0.0
June 30, 2017........... 24.4 0.0
December 30, 2017....... 0.0
June 30, 2018........... 18.8
December 30, 2018....... 0.0
June 30, 2019........... 30.1
December 30, 2019....... 0.0
June 30, 2020........... 25.2
December 30, 2020....... 0.0
June 30, 2021........... 2.1
December 30, 2021....... 0.1
June 30, 2022........... 0.1
December 30, 2022....... 0.0
June 30, 2023........... 0.0
December 30, 2023....... 0.0
June 30, 2024........... 0.0
December 30, 2024....... 0.0
June 30, 2025........... 0.0
December 30, 2025....... 0.0
June 30, 2026........... 0.0
December 30, 2026....... 0.0
June 30, 2027........... 0.0
December 30, 2027....... 18.1
June 30, 2028........... 0.0
December 30, 2028....... 3.0
General. Certificate holders of record will receive all scheduled payments
on each regular distribution date if the pass through trustee receives the
scheduled payments due on such date as provided in the pass through trust
agreements. The record date for each such distribution of scheduled payments
will be the fifteenth day preceding such regular distribution date, subject to
certain exceptions. If a scheduled payment is not received by the pass through
trustee on a regular distribution date but is received within five days
thereafter, it will be distributed on the date received to those certificate
holders of record. If it is received after such five-day period, it will be
treated as a special payment (as defined below) and distributed as described
below.
The pass through trust agreements require that the related pass through
trustee establish and maintain with itself, for the pass through trusts and
for the benefit of the certificate holders, one or more non-interest bearing
accounts, which we refer to as the certificate account, for the deposit of
payments representing scheduled payments on the lessor notes held in the
related pass through trust. The pass through trust agreements also require
that the related pass through trustee establish and maintain with itself, for
each pass through trust and for the benefit of the certificate holders, one or
more accounts, which we refer to as the special payments account, for the
deposit of payments representing special payments. Pursuant to the terms of
the pass through trust agreements, the related pass through trustee is
required to deposit immediately any scheduled payments received
88
by it in the certificate account and to deposit immediately any special
payments so received by it in the special payments account. All amounts so
deposited will be distributed by the pass through trustee on a regular
distribution date or a special distribution date (as defined below), as
appropriate. Each certificate holder will receive its proportionate share
(based on the aggregate fractional undivided interest that the certificate
holder holds) of the aggregate amount in the certificate account or special
payments account, as applicable.
In addition to scheduled payments with respect to principal, the lessor
notes (and consequently the certificates) are subject to prepayment under
certain circumstances. See "--Redemption of Lessor Notes." Payments of
principal, premium, if any, and interest received by the pass through trustee
on account of a prepayment, if any, of the lessor notes held in the related
pass through trust, and payments received by the pass through trustee
following a default in respect of the lessor notes held in the related pass
through trust (including, but not limited to, the proceeds received on account
of the sale of such lessor notes by the pass through trustee), which we refer
to as special payments, will be distributed on the 30th day of a month, unless
such special payment is with respect to the prepayment of lessor notes, in
which case such distribution shall be the date the prepayment is scheduled to
occur under the terms of the lease indenture, which we refer to as a special
distribution date, so long as payment is received by the pass through trustee
on such scheduled prepayment date as provided in the pass through trust
agreements. The pass through trustee will mail notice of each special payment
to the certificate holders of record and certificate owners, which notice
shall set forth (i) the special distribution date and record date therefor;
(ii) the amount of the special payment per $1,000 of face amount of
certificates and the extent to which it constitutes principal, premium, if
any, and interest; (iii) the reason for the special payment; and (iv) if the
special distribution date is the same as a regular distribution date, the
total amount to be received on such date per $1,000 of face amount of
certificates. The record date for each distribution (other than the final
distribution) of a special payment on a special distribution date for each
pass through trust will be the fifteenth day preceding such special
distribution date. See "--Redemption of Lessor Notes" and "--Events of Default
and Certain Rights Upon an Event of Default."
Distributions by the pass through trustee from the certificate account or
the special payments account of the related pass through trust on a regular
distribution date or a special distribution date will be made:
(a) by wire transfer in immediately available funds to an account
maintained by such certificate holder with a bank if:
. DTC is the certificate holder of record;
. a certificate holder holds certificates in an aggregate amount
greater than $10 million; or
. any certificate holder that holds certificates in an aggregate
amount greater than $1 million requests that such distributions be
made by wire transfer.
or,
(b) if none of the above apply, by check mailed to each certificate
holder of record on the applicable record date at its address appearing in
the register maintained for the related pass through trust.
The final distribution for each pass through trust, however, will be made
only upon presentation and surrender of the certificates at the office or
agency of the pass through trustee specified in the notice given by the pass
through trustee of such final distribution. The pass through trustee will mail
such notice of the final distribution (at maturity, redemption or otherwise)
to the certificate holders of record no earlier than 60 days and no later than
20 days preceding such final distribution, specifying, among other things, the
date set for such final distribution and the amount of such distribution. See
"Termination of the Pass Through Trusts."
If any regular distribution date or special distribution date is not a
business day, distributions scheduled to be made on that regular distribution
date or special distribution date may be made on the next succeeding business
day without any additional interest accruing during the intervening period.
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Reports to Certificate Holders
On each regular distribution date and special distribution date, if any, the
pass through trustee will include with each distribution of a scheduled
payment or special payment, if any, to certificate holders of record and, upon
request, to persons who acquire a beneficial interest in certificates (that
is, certificate owners) of the related pass through trust a statement, giving
effect to such distribution to be made on such regular distribution date or
special distribution date, as the case may be, setting forth the following
information (per $1,000 face amount certificate, as to (a) and (b) below):
(a) the amount of such distribution allocable to principal and the amount
allocable to premium, if any; and
(b) the amount of such distribution allocable to interest.
In addition, within a reasonable period of time after the end of each
calendar year but not later than the latest date permitted by law, the pass
through trustee will furnish to each person who at any time during the year
was a certificate holder of record and, upon request, each certificate owner
at any time during the preceding calendar year a statement specifying the sum
of the amounts determined pursuant to clauses (a) and (b) above with respect
to the related pass through trust for the applicable calendar year or, in the
event such person was a certificate holder of record or certificate owner
during a portion of such calendar year, for the applicable portion of such
calendar year, and such other items as are readily available to the pass
through trustee and which a certificate holder or certificate owner shall
reasonably request as necessary for the purpose of such certificate holder's
or certificate owner's preparation of its federal income tax returns. Reports
and related items shall be prepared on the basis of information supplied to
the pass through trustee by the DTC participants and the certificate owners.
At such time, if any, as the certificates are issued in the form of
definitive certificates, the pass through trustee will prepare and deliver the
information described above to each certificate holder of record as the name
and period of record ownership of such certificate holder appears on the
records of the registrar of the certificates.
As long as any certificates remain outstanding, we will furnish to the pass
through trustee unaudited quarterly and audited annual financial statements,
with the accompanying footnotes and audit report. Unaudited quarterly
financial statements will be furnished to the pass through trustee within 60
days following the end of each of our first three fiscal quarters during each
fiscal year and audited annual financial statements will be furnished to the
pass through trustee within 120 days following the end of our fiscal year. The
pass through trustee will furnish all such information directly to certificate
holders and, upon request, certificate owners. We will also furnish to
certificate holders, certificate owners and prospective investors upon request
any information required to be delivered pursuant to Rule 144A(d)(4) under the
Securities Act so long as we are not a reporting company under the Exchange
Act.
In addition, following the effectiveness of the registration statement
relating to this exchange of new certificates for existing certificates,
whether or not required by the rules and regulations of the SEC, we will
maintain our status as a reporting company under the Exchange Act, and file
copies of all such information and reports with the SEC for public
availability (unless the SEC will not accept such filings) within the time
periods specified in the SEC's rules and regulations and make such information
available to securities analysts and prospective investors upon request. If we
fail to maintain our status as a reporting company, the interest rate on the
lessor notes (and, correspondingly, the certificates) will be increased by
0.50% on an annual basis for the duration of such failure. There will be no
such increase in the interest rate if the SEC does not accept the filing of
the applicable reports.
Voting of Lessor Notes
The pass through trustee of each pass through trust, as holder of the lessor
notes in such pass through trust, has the right under certain circumstances
under the lease indentures to vote and give consents and waivers in
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respect of the lessor notes held in such pass through trust. Each pass through
trust agreement sets forth the circumstances in which the pass through trustee
shall direct any action or cast any vote as the holder of the lessor notes at
its own discretion and the circumstances in which the pass through trustee
shall seek instructions from the certificate holders. The principal amount of
the lessor notes held in the pass through trust directing any action or being
voted for or against any proposal will be in proportion to the principal
amount of certificates held by the certificate holders taking the
corresponding position.
Covenants
We are subject to the following covenants contained in the participation
agreements. The definitions of some of the capitalized terms used in the
section "Covenants" are defined under the heading "Definitions" immediately
following this section.
Sale of Assets. Except in connection with a merger, consolidation or the
sale of all or substantially all of our properties or assets on the terms
described under the caption "Merger, consolidation or sale of substantially
all assets" below, we will not, and will not permit any of the designated
subsidiaries to, sell, lease, transfer, convey or otherwise dispose of any
assets (including by way of the issue or sale by us of equity interests in any
of our subsidiaries) other than the following permitted asset sales:
. transfers of assets (including equity or debt interests in any of our
subsidiaries, but excluding our interest in either facility site and any
leasehold interest in assets subject to the leases) among us and any of
the designated subsidiaries (other than transfers of assets from Mirant
Chalk Point to Mirant Peaker or Mirant Potomac River, unless Mirant
Peaker or Mirant Potomac River, as applicable, is, at that time, a
wholly-owned subsidiary of us);
. sales of inventory (including, but not limited to, fuel), products or
obsolete items and other similar dispositions and sales of energy,
capacity and ancillary services in the ordinary course of business;
. sales of assets required to be made pursuant to any change in law,
regulation or any imposition by the Federal Energy Regulatory Commission
or any other governmental entity having or claiming jurisdiction over
us, our affiliates or our assets;
. sales or dispositions of equity or debt interests in subsidiaries other
than the designated subsidiaries;
. a restricted payment that is made in cash or cash equivalent investments
that is permitted by the participation agreements;
. aggregate sales or other aggregate dispositions of assets (other than
our ownership interest in either facility site and any leasehold
interest in the assets subject to the leases) that, in the aggregate,
are not in excess of 15% of the consolidated book value of us and the
designated subsidiaries;
. sales or other dispositions of assets (other than (a) our ownership
interest in either facility site, (b) any leasehold interest in the
assets subject to the leases and (c) equity in Mirant Chalk Point,
Mirant Potomac River and Mirant Peaker, each a designated subsidiary so
long as a subsidiary of Mirant or Mirant Mid-Atlantic) if the proceeds
of that sale or disposition are: invested by us in any Permitted
Business, used by us or the designated subsidiaries to repay existing
Indebtedness (other than Subordinated Indebtedness), or retained by us
in a segregated asset sale account;
. sales or other dispositions of assets (other than (a) our ownership
interest in either facility site, (b) any leasehold interest in the
assets subject to the leases and (c) equity in any designated
subsidiary) certified by us as no longer useful in our business or that
of one of the designated subsidiaries, as long as the disposal of the
asset will not have a material adverse effect on us and the designated
subsidiaries, taken as a whole; and
. any other sale or disposition of assets (other than (a) our ownership
interest in either facility site and (b) any leasehold interest in
assets subject to the leases) so long as, after giving effect to that
sale or disposition, both S&P and Moody's confirms its respective rating
of the certificates in effect immediately prior to that sale or
disposition; provided, that, if either of those ratings is below
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investment grade, we will not be permitted to consummate that sale or
disposition unless: (i) the Fixed Charge Coverage Ratio for the most
recently ended period of four full fiscal quarters is at least 2.5 to
1.0 and (ii) the projected Fixed Charge Coverage Ratio for each of the
following two periods of four full fiscal quarters is at least 2.5 to
1.0. Prior to making any sale or disposition in accordance with this
paragraph, we will deliver to the pass through trustees, each owner
lessor and each owner participant (the institutional investor which
holds the membership interests in the owner lessors) a copy of the
letters from S&P and Moody's confirming their respective ratings of the
certificates and an officer's certificate certifying as to the matters
in clauses (i) and (ii) of this paragraph.
Assignments of our leasehold interests in either leased facility and
subleases permitted by the terms of the leases are not considered sales or
dispositions of assets for the purposes of this covenant. See "Description of
the Leases and Other Lease Documents--Sublease and Assignment."
Merger, Consolidation or Sale of Substantially All Assets. Except in
connection with a permitted asset sale on the terms described under the caption
"--Sale of Assets," we will not, and will not permit any of the designated
subsidiaries to, directly or indirectly, consolidate or merge with or into, any
other person, or sell, assign, convey, lease, transfer or otherwise dispose of
all or substantially all of our or its properties or assets to any person or
persons in one or a series of transactions, unless immediately after giving
effect to the transaction each of the following conditions is satisfied:
. no significant lease default (as defined in "Description of Capital
Leases--Owner Lessor's Right to Cure") or a lease event of default has
occurred and is continuing;
. the surviving entity, if other than us or any of the designated
subsidiaries, or the transferee, will (i) be organized under the laws of
the United States, any state thereof or the District of Columbia,
(ii) expressly assume, under an agreement reasonably satisfactory to the
applicable owner participants and the indenture trustee, all of our, or
the designated subsidiary's, as applicable, obligations under the
operative documents and (iii) be a corporation, limited liability
company or limited partnership;
. we provide to each of the pass through trustees, the indenture trustee,
the owner lessors and the owner participants a customary officers'
certificate and customary legal opinions addressing various matters in
connection with the merger or sale; and
. we, the surviving entity, or the transferee, as applicable, after giving
effect to such consolidation, merger or sale of all or substantially all
of our assets, has a credit rating of at least BBB-, from S&P and Baa3
from Moody's and, prior to the consummation of any such transaction, we
will have provided an officer's certificate to such effect or a copy of
the letters from S&P and Moody's confirming such ratings.
. if the surviving entity has any Indebtedness (after giving effect to the
consolidation or merger), we, or the designated subsidiary, as
applicable, would be permitted to incur that Indebtedness in accordance
with the provisions described under the caption "--Limitations on
Incurrence of Indebtedness" or "--Limitations on Incurrences of
Indebtedness by Designated Subsidiaries," as applicable;
In addition, so long as no significant lease default or lease event of
default has occurred and is continuing, any designated subsidiary may merge
into us or into another designated subsidiary.
Restriction on Liens. We will not, nor will we permit any of the designated
subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or
become effective any liens on our or any of the designated subsidiaries'
properties or assets, except for the following permitted encumbrances:
(1) liens and encumbrances identified as exceptions to each of the title
policies issued in connection with the leveraged lease transactions;
(2) any lien arising solely by order of any court, tribunal or other
governmental authority (or by an agreement of similar effect) so long as
such lien is being contested in good faith and is appropriately bonded or
reserved against, and any appropriate legal proceedings that may have been
initiated for the review of
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such order have not been finally terminated or the period within which
those proceedings may be initiated has not expired;
(3) construction materialmen's, mechanics', workers', repairmen's,
employees' or other like liens arising in the ordinary course of business
for amounts either not overdue for a period of not more than 30 days or
being contested in good faith by appropriate proceedings (and in respect of
which adequate cash reserves have been set aside) so long as those
proceedings do not involve a material risk of the sale, forfeiture or loss
of either leased facility;
(4) the interests of us, the designated subsidiaries, the owner
participants, the owner lessors, the owner managers, the indenture trustees
and the pass through trustees under any of the applicable operative
documents;
(5) liens caused by the owner lessors, the owner participants and the
indenture trustees that such parties are responsible for removing;
(6) the interests of each owner lessor in the applicable leased facility
and facility sites and our interests and those of each owner lessor in the
ownership and operation agreement;
(7) our reversionary interests in either leased facility or facility
site;
(8) liens for taxes, water, sewage, license, permit or inspection fees
either not yet due and payable or being contested in good faith by
appropriate proceedings (and in respect of which adequate cash reserves
have been set aside) so long as those proceedings could not reasonably be
expected to result in a material adverse effect on us and the designated
subsidiaries, taken as a whole;
(9) applicable zoning and building regulations and ordinances from time
to time in effect which do not affect the use or operation of the leased
facilities except to an insignificant extent;
(10) the interest of a sublessee in the applicable undivided interests or
leased facilities under a permitted sublease;
(11) liens, easements, encumbrances, restrictions, defects or
irregularity of title that in the aggregate are not substantial in amount
and do not materially detract from the value of the applicable undivided
interests, leased facilities or facility sites and do not materially impair
the use of the leased facilities or facility sites in the ordinary course
of business;
(12) liens created or expressly permitted by any operative document for
the sole purpose of paying all amounts due and owing under the operative
documents;
(13) liens in existence on the closing date as set forth on a schedule to
the participation agreements;
(14) liens by us to any of the designated subsidiaries or by one of the
designated subsidiaries to us or any of our other designated subsidiaries;
(15) liens arising by reason of security for payment of workers'
compensation or other insurance;
(16) liens in favor of suppliers incurred in the ordinary course of
business for sums that are not yet delinquent or are being contested in
good faith by appropriate proceedings that suspend the collection of those
sums;
(17) liens arising by operation of law pursuant to any license issued by
the Federal Energy Regulatory Commission required for our operation, or any
designated subsidiary's operation, of electric generation facilities;
(18) liens to secure permitted indebtedness or designated subsidiary
permitted indebtedness, described below under the caption "--Limitations on
Incurrence of Indebtedness" or "--Limitations on Incurrence of Indebtedness
by Designated Subsidiaries", as applicable, other than Subordinated
Indebtedness, so long as the liens will not secure Indebtedness in an
amount in excess of $100 million;
(19) liens to secure our hedging obligations or the hedging obligations
of one of the designated subsidiaries, but only to the extent (a) the
hedging obligations are entered into in the ordinary course of business and
not for speculative purposes to protect us or the designated subsidiary
from interest rate
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fluctuations and (b) the notional principal amount of the hedging
obligations does not exceed the principal amount of Indebtedness to which
the hedging obligations relate;
(20) liens described in any of the sub-paragraphs above and renewed or
extended upon the renewal or extension or refinancing or replacement of the
Indebtedness secured thereby, provided that (A) there is no increase in the
principal amount of the Indebtedness secured thereby over the principal,
capital or nominal amount thereof outstanding immediately prior to such
refinancing; (B) such liens attach solely to that property, (C) at the time
of the extension, renewal or refunding of that Indebtedness and after
giving effect thereto and to the application of the proceeds thereof, no
significant lease default or lease event of default would exist, and (D)
such liens do not cover assets that are, as a whole, more valuable than the
assets covered by liens that secured the refinanced Indebtedness;
(21) liens securing designated subsidiary permitted indebtedness incurred
in connection with the financing of accounts receivable or the financing of
inventory;
(22) liens securing Indebtedness incurred for the purposes of financing
capital expenditures required by law and, in our case, liens securing
Indebtedness incurred for the purposes of financing required improvements;
(23) liens on the property of any person existing at the time that person
is merged into or consolidated with us or one of the designated
subsidiaries and not incurred in contemplation with that merger or
consolidation;
(24) liens (x) outstanding on or over any asset acquired after December
19, 2000, (y) in existence at the date of such acquisition and (z) where we
or one of the designated subsidiaries, as applicable, does not take any
step to increase the principal amount secured thereby from that so secured
and outstanding at the time of such acquisition (other than in the case of
liens for a fluctuating balance facility, by way of utilization of that
facility within the limits applicable thereto at the time of acquisition)
so long as such liens were not incurred, extended or renewed in
contemplation of that acquisition or purchase; provided, that (A) such lien
attaches solely to the assets acquired or purchased and (B) if the
Indebtedness secured by such lien is assumed by us or a designated
subsidiary, then and in such event, that Indebtedness is incurred in
accordance with the provisions described under the caption "--Limitations
on Incurrence of Indebtedness" or "--Limitations on Incurrence of
Indebtedness by Designated Subsidiaries," as applicable.
The liens described in paragraphs (1) through (24) above are, collectively,
permitted liens.
Maintenance of Existence and Properties. Except in connection with a merger,
consolidation or the sale of all or substantially all of our properties or
assets on the terms described under the caption "--Merger, Consolidation or
Sale of Substantially All Assets" above, we will, and will cause each
designated subsidiary to, (i) do or cause to be done all things necessary to
preserve, renew, and keep in full force and effect our, or the designated
subsidiaries', legal existence (ii) do or cause to be done all things
reasonably necessary to preserve, renew and keep in full force and effect the
rights, governmental approvals, and franchises material to the conduct of our,
or our designated subsidiaries', business, (iii) keep and maintain all
property material to the conduct of our, and our designated subsidiaries',
business in good working order, and condition, force majeure excepted and (iv)
operate and maintain our, and our designated subsidiaries', property and
assets (other than the leased facilities, which are to be maintained in
accordance with the provisions of the leases) in good condition, repair and
working order and in any event in all material respects (a) in compliance with
all requirements of law, including environmental laws, unless noncompliance
could not reasonably be expected to result in a material adverse effect on us
and the designated subsidiaries, taken as a whole, subject to force majeure,
and (b) in accordance with Prudent Industry Practice.
Maintenance of Tax Status. We will not, and will cause each designated
subsidiary not to, voluntarily take any action to cause us or any of the
designated subsidiaries to be subject to taxation as a separate entity for
federal income tax purposes.
Insurance. We will comply with the terms and conditions regarding the
maintenance of insurance set forth in each lease. We will maintain or cause to
be maintained, and will cause each designated subsidiary to maintain,
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with financially sound and reputable insurers, insurance against such
liabilities, casualties, risks, contingencies and in such types and amounts as
is maintained by persons engaged in similar businesses as us and the
designated subsidiaries.
Limitation on Activities. We will not, and we will not permit any of our
subsidiaries to, engage in any business other than a Permitted Business.
Credit Support. We will:
. maintain for the benefit of each owner lessor (or its permitted assign),
Qualifying Credit Support, with an available amount equal to, for the
related lease, the greater of (1) the periodic lease rent scheduled to
be paid under that lease in the following six months and (2) 50% of the
periodic lease rent scheduled to be paid under that lease in the
following twelve months;
. extend or replace any Qualifying Credit Support at least 30 days before
its expiration date if that Qualifying Credit Support expires before the
expiration date of the applicable leases;
. within 60 days of receiving knowledge that a Qualifying Credit Support
Issuer no longer meets the criteria in the definition of Qualifying
Credit Support Issuer set forth below, replace the Qualifying Credit
Support provided by that Qualifying Credit Support Issuer with
Qualifying Credit Support from another Qualifying Credit Support Issuer;
and
. within 90 days after a Qualifying Credit Support is drawn upon by the
related indenture trustee to pay scheduled rent, reinstate the
availability under the drawn Qualifying Credit Support or provide new
Qualifying Credit Support in the required amount.
Limitations on Incurrence of Indebtedness. We will not create, incur, assume
or permit to exist, or permit any of our subsidiaries (other than designated
subsidiaries, which are subject to the provisions described under the caption
"--Limitation on Incurrence of Indebtedness by Designated Subsidiaries") to
create, incur, assume or permit to exist, any Indebtedness (as defined below)
other than the following (which we refer to as permitted indebtedness):
(a) Indebtedness in existence on December 19, 2000 and set forth on a
schedule to each participation agreement;
(b) Indebtedness, if, after giving effect to the incurrence of that
Indebtedness:
(i) each of Moody's and S&P confirms the then current rating of the
certificates; provided, that, if either of those ratings is below
investment grade, we will not be permitted to incur the Indebtedness
unless: (i) the Fixed Charge Coverage Ratio for the most recently ended
period of four full fiscal quarters is at least 2.5 to 1.0 and (ii) the
projected Fixed Charge Coverage Ratio for each of the following two
periods of four full fiscal quarters is at least 2.5 to 1.0;
(ii) no significant lease default or lease event of default has
occurred and is continuing, unless the application of the proceeds of
the incurred Indebtedness cures the significant lease default or lease
event of default;
(iii) prior to incurring the Indebtedness, we deliver an officer's
certificate to each pass through trustee, each owner participant and
each owner lessor certifying as to the matters in clauses (i) and
(ii) above; and
(iv) a copy of the ratings letters from S&P and Moody's confirming
their respective ratings of the certificates is delivered (prior to the
incurrence of such Indebtedness) to each pass through trustee and the
applicable owner participant.
(c) Indebtedness incurred for working capital purposes;
(d) Indebtedness in respect of letters of credit, surety bonds or
performance bonds or guarantees issued in the ordinary course of business;
(e) Subordinated Indebtedness;
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(f) Indebtedness in an aggregate principal amount not to exceed $100
million including the aggregate value at risk under unhedged transactions
referred to under the definition of "Power Market Business" (escalated
annually based upon the consumer price index) less the aggregate principal
amount of Indebtedness incurred pursuant to clause (c) under the caption
"--Limitation on Incurrence of Indebtedness by Designated Subsidiaries;"
(g) Indebtedness represented by interest rate swaps, caps or collar
agreements, or other hedging arrangements entered into to protect against
fluctuations in interest rates or the exchange of nominal interest
obligations in the ordinary course of business and not for speculative
purposes;
(h) Indebtedness secured by a pre-existing lien on any assets that we
acquire, so long as that Indebtedness is recourse only to those acquired
assets and to neither other assets nor to our general credit;
(i) in the case of any subsidiary (other than designated subsidiaries),
any Non-Recourse Indebtedness;
(j) Intercompany Loans;
(k) Indebtedness incurred to finance capital expenditures made to comply
with law or to finance required improvements (as defined below) under any
Lease;
(l) Indebtedness incurred in exchange for, or the net proceeds of which
are used to refund, refinance or replace Indebtedness permitted to be
incurred pursuant to clauses (a) and (h) above, provided, that the average
life of the refinancing Indebtedness shall not be shorter than the
remaining average life of the Indebtedness refinanced and the principal
amount of the refinancing Indebtedness shall not exceed the principal
amount of the Indebtedness refinanced plus a reasonable premium in
connection with the refinancing; and
(m) Indebtedness guaranteed by (a) Mirant or (b) one or more of our
direct or indirect parents, provided that each of those parents has a
senior, unsecured, long-term credit rating from S&P of BBB or higher and
from Moody's of Baa2 or higher.
Limitations on Incurrence of Indebtedness by Designated Subsidiaries. We
will not permit any of the designated subsidiaries to create, incur, assume or
permit to exist, any Indebtedness other than the following (which we refer to
as designated subsidiary permitted indebtedness):
(a) Indebtedness of any designated subsidiary in existence on December
19, 2000 and set forth on a schedule to each participation agreement;
(b) Indebtedness incurred by any designated subsidiary to finance capital
expenditures made to comply with law;
(c) Indebtedness incurred by the designated subsidiaries, taken as a
whole, in an aggregate principal amount not to exceed $100,000,000,
including the aggregate value at risk under various unhedged transactions
of us and our subsidiaries, and with respect to any individual designated
subsidiary, in an aggregate principal amount not to exceed $50,000,000 (in
each case, escalated annually based upon the consumer price index) in each
case, less the aggregate principal amount of Indebtedness incurred pursuant
to paragraph (f) under the caption "--Limitations on Incurrence of
Indebtedness";
(d) Indebtedness in respect of letters of credit, surety bonds or
performance bonds or guarantees issued in the ordinary course of business;
(e) Intercompany Loans;
(f) Indebtedness secured by a pre-existing lien on any assets acquired by
a designated subsidiary, so long as that Indebtedness is recourse only to
those acquired assets and to neither other assets nor to the general credit
of the applicable designated subsidiary; and
(g) Indebtedness, if, after giving effect to the incurrence of that
Indebtedness:
(i) each of Moody's and S&P confirms the then current rating of the
certificates provided, that, if either of those ratings is below
investment grade, the applicable designated subsidiary will not be
permitted to incur the Indebtedness unless: (i) the Fixed Charge
Coverage Ratio for the most recently
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ended period of four full fiscal quarters is at least 2.5 to 1.0 and
(ii) the projected Fixed Charge Coverage Ratio for each of the
following two periods of four full fiscal quarters is at least 2.5 to
1.0;
(ii) no significant lease default or lease event of default has
occurred and is continuing, unless the application of the proceeds of
the incurred Indebtedness cures the significant lease default or lease
event of default;
(iii) prior to incurring the Indebtedness, we deliver an officer's
certificate to each pass through trustee, each owner participant and
each owner lessor certifying as to the matters in clauses (i) and
(ii) above; and
(iv) a copy of the ratings letters from S&P and Moody's confirming
their respective ratings of the certificates is delivered (prior to the
incurrence of such Indebtedness) to each pass through trustee and the
applicable owner participant.
Limitations on Restricted Payments. We will not take any of the following
actions, which we refer to as restricted payments:
. make distributions in respect of the equity interests in us (in cash,
property, securities or obligations other than additional equity
interests of the same type);
. make any other payments or distributions on account of payments of
interest, set apart money for a sinking or analogous fund for, or
purchase, redeem, retire or otherwise acquire any portion of, any equity
interest in us or of any warrants, options or other rights to acquire
any such equity interest (or make payments to any person such as phantom
stock payments, where the amount of the payment is calculated with
reference to our fair market or equity value); or
. make any payment on or with respect to, the purchase, redemption,
defeasance or other acquisition or retirement for value of any
Subordinated Indebtedness;
unless, at the time of the restricted payment, each of the following
conditions is satisfied:
. the Fixed Charge Coverage Ratio for the most recently ended four full
fiscal quarters, or such shorter period (of not less than one full
fiscal quarter) commencing on December 19, 2000 and ending on the last
day of the most recent fiscal quarter for which internal financial
statements are available equals at least:
(1) 1.7 to 1.0; or
(2) 1.6 to 1.0, if, as of the last day of the most recently completed
fiscal quarter, we and the designated subsidiaries are parties to
Power Purchase Agreements covering, in the aggregate, at least 25%
of the projected Total Consolidated Operating Revenue for the
consecutive period of eight full fiscal quarters following that
date; or
(3) 1.45 to 1.0 if, as of the last day of the most recently completed
fiscal quarter, we and the designated subsidiaries are parties to
Power Purchase Agreements covering, in the aggregate, at least 50%
of the projected Total Consolidated Operating Revenue for the
consecutive period of eight full fiscal quarters following that
date; or
(4) 1.3 to 1.0 if, as of the last day of the most recently completed
fiscal quarter, we and the designated subsidiaries are parties to
Power Purchase Agreements covering, in the aggregate, at least 75%
of the projected Total Consolidated Operating Revenue for the
consecutive period of eight full fiscal quarters following that
date; or
(5) 1.2 to 1.0, if, as of the last day of the most recently completed
fiscal quarter, we and the designated subsidiaries are parties to
Power Purchase Agreements covering, in the aggregate, at least 100%
of the Projected Total Consolidated Operating Revenue for the
consecutive period of eight full fiscal quarters following that
date; and
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. the projected Fixed Charge Coverage Ratio (determined on a pro forma
basis after giving effect to the restricted payments) for each of the
two following periods of four fiscal quarters commencing with the fiscal
quarter in which the restricted payment is proposed to be made equals at
least:
(1) 1.7 to 1.0; or
(2) 1.6 to 1.0, if, as of the last day of the most recently completed
fiscal quarter, we and our designated subsidiaries are parties to
Power Purchase Agreements covering, in the aggregate, at least 25%
of the projected Total Consolidated Operating Revenue for the
consecutive period of eight full fiscal quarters following that
date; or
(3) 1.45 to 1.0, if, as of the last day of the most recently completed
fiscal quarter, we and our designated subsidiaries are parties to
Power Purchase Agreements covering, in the aggregate, at least 50%
of the projected Total Consolidated Operating Revenue for the
consecutive period of eight full fiscal quarters following that
date; or
(4) 1.3 to 1.0, if, as of the last day of the most recently completed
fiscal quarter, we and our designated subsidiaries are parties to
Power Purchase Agreements covering, in the aggregate, at least 75%
of the projected Total Consolidated Operating Revenue for the
consecutive period of eight full fiscal quarters following that
date; or
(5) 1.2 to 1.0, if, as of the last day of the most recently completed
fiscal quarter, we and our designated subsidiaries are parties to
Power Purchase Agreements covering, in the aggregate, at least 100%
of the projected Total Consolidated Operating Revenue for the
consecutive period of eight full fiscal quarters following that
date; and
. no significant lease default or lease event of default has occurred and
is continuing; and
We will deliver an officer's certificate to each owner participant and each
pass through trustee certifying as to the above conditions (including the
relevant Power Purchase Agreements), as of the end of the fiscal quarter
immediately preceding the making of the proposed restricted payment. We will
determine the satisfaction of the projected coverage ratio conditions based on
projections prepared by us in good faith based upon assumptions consistent in
all material respects with the relevant contracts and agreements, historical
operations, and our good faith projections of future revenues and projections
of operating and maintenance expenses for us and our subsidiaries in light of
the then existing or reasonably expected regulatory and market environments in
the markets in which the leased facilities or other assets owned by us and our
subsidiaries is or will be operated and upon the assumption that there will be
no early redemption or prepayment of Indebtedness or that any Indebtedness
which matures within such projected periods will be refinanced on reasonable
terms.
Restricted payments do not include: (i) any repurchase or redemption of any
equity interest of us or Subordinated Indebtedness solely in exchange for, or
out of the net cash proceeds from the substantially concurrent issuance or
sale of equity interests of us (issued expressly for that purpose), or (ii)
any repurchase or redemption of any equity interest of us or Subordinated
Indebtedness solely in exchange for, or out of the net cash proceeds from the
substantially concurrent sale of new Subordinated Indebtedness (incurred
expressly for that purpose).
Distributions from Designated Subsidiaries. We will, unless prohibited by
law, cause each designated subsidiary that is our wholly-owned subsidiary to
make distributions to us of all cash available (after taking into account
projected cash requirements necessary for the operation of that designated
subsidiary's business, including mandatory debt service and maintenance
reserves as reasonably determined by us) if, and only to the extent that, we
are unable to meet our obligations under the leases.
Treatment as Subsidiaries for Purposes of Certain Covenants. For the
purposes of making any calculations on a consolidated basis necessary with
respect to the covenants described above under "Limitations on Incurrence of
Indebtedness", "Limitations on Incurrence of Indebtedness by Designated
Subsidiaries" or "Limitations on Restricted Payments", each of Mirant Potomac
River and Mirant Peaker will be treated as subsidiaries, regardless of whether
Mirant Potomac River or Mirant Peaker, as applicable, is, at the time the
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calculation is made, our subsidiary, and so long as (i) Mirant owns at least a
majority of the ownership interest of Mirant Potomac River or Mirant Peaker,
as applicable and (ii) the capital contribution agreement remains in effect.
Limitation on Transactions with Affiliates. We will not, and will not permit
any of our subsidiaries, to enter into or amend any agreement or transaction
with an affiliate other than agreements or transactions or amendments that are
on terms no more favorable to that affiliate than those entered into with
third parties on an arms-length basis. This covenant will not apply to:
. agreements and transactions solely among us and the designated
subsidiaries (provided, that any such agreement will be terminated
without penalty at any time that the applicable designated subsidiary
ceases to be a designated subsidiary), or
. agreements with any of our affiliates that are engaged in the business
of selling and purchasing electricity, capacity and ancillary services,
for (i) cost reimbursement that is no greater than amounts that would be
payable to a third party on an arms-length basis and (ii) other
compensation; provided, that any other compensation will be due and
payable pursuant to the terms of those agreements if, and only to the
extent that, we are permitted to make a restricted payment and shall be
fully subordinated to the payments due under the facility leases and all
other non-disputed obligations then due and payable. Any such agreement
for cost reimbursement and other compensation will be terminated without
penalty at any time that the applicable affiliate ceases to be our
affiliate or upon the exercise of remedies following the occurrence of a
lease event of default.
Definitions
As used herein, the following terms have the meanings set forth below:
"Cash Flow Available for Fixed Charges" for any period shall mean, without
duplication, (i) Consolidated EBITDA for such period, minus (ii) capital
expenditures (excluding capital expenditures relating to the construction of
new fixed assets) made by us and our subsidiaries during such period other
than capital expenditures financed with the proceeds of Subordinated
Indebtedness, contributions to our equity or the equity of our subsidiaries,
restricted payments, the proceeds of indebtedness in existence on December 19,
2000 or IRB Indebtedness or Consolidated EBITDA for an earlier period to the
extent (x) that amount of Consolidated EBITDA was specifically reserved for in
cash during that earlier period for that capital expenditure and (y) that
capital expenditure was, at that time, treated as being made during that
earlier period for purposes of this definition.
"Consolidated EBITDA" shall mean, with respect to us and our subsidiaries on
a consolidated basis for any period, (i) consolidated net income (or loss)
before interest and taxes, plus (ii) to the extent deducted in determining
such consolidated net income (or loss), depreciation, amortization and other
similar non-cash charges and reserves, minus (iii) to the extent recognized in
determining such consolidated net income (or loss), extraordinary gains (or
losses), restructuring charges or other non-recurring items, plus (iv) to the
extent deducted in determining such consolidated net income (or loss), Lease
Payment Obligations.
"Fixed Charge Coverage Ratio" means, for any period, without duplication,
the ratio of (x) Cash Flow Available for Fixed Charges for such period to (y)
Fixed Charges.
"Fixed Charges" shall mean, with respect to us and our subsidiaries on a
consolidated basis for any period, the sum, without duplication, of (i) the
aggregate amount of interest expense with respect to Indebtedness (other than
Intercompany Loans and Subordinated Indebtedness) for such period, including
(A) the net costs under interest rate hedging agreements, (B) all capitalized
interest (except to the extent that such interest is either (x) not paid in
cash or (y) if paid in cash, is paid solely with the proceeds of the
Indebtedness in respect of which such interest accrued), and (C) the interest
portion of any deferred payment obligation, (ii) the aggregate amount of all
mandatory scheduled payments (whether designated as payments or prepayments)
and sinking fund payments with respect to principal of any Indebtedness (other
than Intercompany Loans and Subordinated Indebtedness), and (iii) Lease
Payment Obligations which are scheduled to be paid during such period.
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"Indebtedness" of any person shall mean (i) all indebtedness of such person
for borrowed money, (ii) all obligations of such person evidenced by bonds,
debentures, notes or other similar instruments, (iii) all obligations of such
person to pay the deferred purchase price of property or services (other than
trade payables and accrued liabilities arising in the ordinary course of
business), (iv) all indebtedness created or arising under any conditional sale
or other title retention agreement with respect to property acquired by such
person (even though the rights and remedies of the seller or lender under such
agreement in the event of default are limited to repossession or sale of such
property), (v) all Lease Obligations of such person, (vi) all obligations,
contingent or otherwise, of such person under acceptance, letter of credit or
similar facilities securing Indebtedness, (vii) all unconditional obligations
of such person to purchase, redeem, retire, defease or otherwise acquire for
value any capital stock or other equity interests of such person or any
warrants, rights or options to acquire such capital stock or other equity
interests at any time prior to the first anniversary of the final maturity
date of the lessor notes, (viii) all Indebtedness of any other person of the
type referred to in clauses (i) through (vii) guaranteed by such person or for
which such person shall otherwise (including pursuant to any keepwell,
makewell or similar arrangement) become directly or indirectly liable (other
than indirectly as a result of a performance guarantee not entered into with
respect to Indebtedness), and (ix) all third party Indebtedness of the type
referred to in clauses (i) through (viii) above secured by any lien or
security interest on property (including accounts and contract rights) owned
by the person whose Indebtedness is being measured, even through such person
has not assumed or become liable for the payment of such third party
Indebtedness, the amount of such obligation being 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 us or any of the designated subsidiaries
by us or any of the designated subsidiaries made in the ordinary course of
business, so long as any such loan is at all times thereafter held by us or
one of the designated subsidiaries and that any such loans to us shall
constitute Subordinated Indebtedness.
"IRB Indebtedness" means Indebtedness that is in respect of pollution
control revenue bonds, industrial revenue bonds or similar instruments.
"Lease Obligations" shall mean, without duplication, with respect to any
person for any period, (i) Indebtedness represented by obligations under a
lease that is required to be capitalized for financial reporting purposes
under GAAP, (ii) with respect to noncapital leases (including noncapital
leveraged leases and operating leases), other than synthetic leases or other
similar off-balance sheet leases, (A) non-recourse Indebtedness of the lessor
in such a lease, or (B) if such amount is indeterminable, then the present
value, determined using a discount rate equal to the incremental borrowing
rate (as defined in SFAS No. 13) of the lessee under such a lease, of rent
obligations under such lease, and (iii) with respect to "synthetic" leases or
other off-balance sheet leases, the then outstanding lease balance or other
similar amount payable under such "synthetic" lease or other off-balance sheet
lease.
"Lease Payment Obligations" shall mean, without duplication, with respect to
any person for any period, (i) the interest and principal components of all
Lease Obligations that are described in clause (i) of the definition of "Lease
Obligations" that are scheduled to be paid during such period, plus (ii) all
rent payment obligations relating to Lease Obligations described in clauses
(ii) and (iii) of the definition of "Lease Obligations" that are scheduled to
be paid during such period.
"Non-Recourse Indebtedness" shall mean Indebtedness of any of our
subsidiaries that is a bankruptcy remote entity:
(i) as to which neither the we nor any of the designated subsidiaries (a)
provides credit support that constitutes Indebtedness or (b) is directly or
indirectly liable as a guarantor or otherwise that constitutes Indebtedness
(other than solely as a result of recourse to stock of one of our
subsidiaries (other than that of a designated subsidiary) permitted under
clause (iii) below); and
(ii) that, if in default, would not permit (upon notice, lapse of time or
both) any holder of any other Indebtedness of ours or of the designated
subsidiaries to declare a default on such other Indebtedness or cause the
payment thereof to be accelerated or payable prior to its stated maturity;
and
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(iii) that is issued or incurred pursuant to a written agreement or
instrument the terms of which expressly provide that the lenders will not
have any recourse to our stock or assets or to the stock and assets of any
designated subsidiary (other than stock of one of our subsidiaries other
than a designated subsidiary) for payment of such Indebtedness.
"Permitted Business" shall mean any of the following undertaken by us or any
or our subsidiaries:
. the generation and sale of energy, capacity and ancillary services from
the transaction assets and all activities related or incidental to those
activities;
. the generation and sale of energy, capacity and ancillary services from
non-nuclear generation assets in the United States and all activities
related or incidental to those activities.
However, neither we nor any of our subsidiaries will engage in a Power
Marketing Business.
"Power Purchase Agreement" shall mean:
. an arms-length, executed, valid and binding agreement (including,
without limitation, a tolling agreement) that is then in full force and
effect and not in default in any material respect and that is not
terminable without cause between us or any of our subsidiaries and
either (i) a third party purchaser whose long-term senior unsecured debt
is rated no less than Baa3 by Moody's and BBB-, by S&P; or (ii) one of
our affiliates, so long as that affiliate has executed a valid and
binding agreement with a third party purchaser whose long-term senior
unsecured debt is rated no less than Baa3 by Moody's and BBB-, by S&P
with substantially the same terms (other than any pricing spread) as the
affiliate's agreement with us or our subsidiary, in each case, for the
sale of energy or capacity (in the case of both energy and capacity, on
a take or pay, take and pay, or take, if tendered basis) at prices
established at a formula, index or other price risk management
methodology not based on spot market prices by us or our subsidiary to
the third party or our affiliate; or
. financial hedge agreements relating to energy or capacity pricing that
are fully supported by our available energy or capacity or that of our
subsidiaries and that are with counterparties having long-term senior
unsecured debt that is rated no less than Baa2 by Moody's and BBB by
S&P.
"Power Marketing Business" shall mean the business of selling and/or
purchasing electricity, capacity or ancillary services which is not (i)
incidental to or in support of the sale and marketing of electricity, capacity
and ancillary services from our and our subsidiaries' generating facilities,
or (ii) relating to managing our and our subsidiaries' power market or
operational risks; provided, that in each of clauses (i) and (ii) of this
definition, such sales and purchases shall be hedged in a commercially
reasonable manner except we and our subsidiaries may enter into unhedged
transactions pursuant to which the aggregate value at risk of us and our
subsidiaries is no greater than $25 million (escalated annually based upon the
consumer price index). Such sales transactions shall be deemed hedged to the
extent that the aggregate amount of electricity, capacity or ancillary
services to be sold pursuant to all such sales transactions does not exceed
the aggregate uncommitted capacity of us and our subsidiaries. For purposes of
this definition the term "subsidiaries" includes the designated subsidiaries.
"Prudent Industry Practice" shall mean, at a particular time, either (i) any
of the practices, methods and acts engaged in or approved by a significant
portion of the competitive electric generating industry operating in the
eastern United States at such time, or (ii) with respect to any matter to
which clause (i) does not apply, any of the practices, methods and acts which,
in the exercise of reasonable judgment in light of the facts known at the time
the decision was made, could have been expected to accomplish the desired
result at a reasonable cost consistent with good competitive electric
generation business practices, reliability, safety and expedition. "Prudent
Industry Practice" is not intended to be limited to the optimum practice,
method or act to the exclusion of all others, but rather to be a spectrum of
possible practices, methods or acts having due regard for, among other things,
manufacturers' warranties, the requirements of insurance policies and the
requirements of governmental bodies of competent jurisdiction.
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"Qualifying Credit Support" shall mean an irrevocable, unconditional,
uncollateralized, standby letter of credit, surety bond or guaranty issued in
favor of each owner lessor by a Qualifying Credit Support Issuer (and assigned
to the related indenture trustee) securing our obligation to pay rent,
provided, that in the case of a surety bond, each of S&P and Moody's shall
have confirmed its then current rating on the certificates prior to our first
use of a surety bond as Qualifying Credit Support.
"Qualifying Credit Support Issuer" shall mean any bank or other financial
institution having a long-term unsecured debt rating of at least A or higher
from S&P and A2 or higher from Moody's or any of our affiliates having a long-
term unsecured debt rating of at least BBB-, from S&P and Baa3 from Moody's. A
Qualifying Credit Support Issuer will cease to be a Qualifying Credit Support
Issuer if such entity is at any time rated below the applicable ratings set
forth in the immediately preceding sentence.
"Subordinated Indebtedness" shall mean unsecured Indebtedness that is
expressly subordinated to our payment obligations under each lease and the
other operative documents pursuant to subordination provisions, the terms of
which include, among other things, that any payments thereunder (whether of
principal, interest or otherwise) may only be made to the extent permitted as
a restricted payment (and any failure to pay prior to such time shall not
constitute a default thereunder).
"Termination Date" shall mean each of the monthly dates during the term of
the applicable lease identified as a "Termination Date" on a schedule to each
such lease, which dates are the same days on which periodic lease rent and
renewal rent, if any, are payable under such facility lease.
"Termination Value" shall mean, for any Termination Date, the Termination
Values set forth on a schedule to each lease for such Termination Date.
"Total Consolidated Operating Revenue" shall mean our and the designated
subsidiaries' gross revenues from the sale of electricity, capacity and
ancillary services minus fuel and emissions costs.
Events of Default and Certain Rights Upon an Event of Default
An event of default under the pass through trust agreements is defined as
the occurrence and continuance of an event of default under any of the lease
indentures, which we refer to in this prospectus as a lease indenture event of
default. For a description of the lease indenture events of default, see "The
Lessor Notes--General." Under the lease indentures, the applicable owner
lessor has the right under certain circumstances to cure lease indenture
events of default that result from the occurrence of an event of default under
the related lease, which we refer to in this prospectus as a lease event of
default. If the owner lessor chooses to exercise its cure right, the lease
indenture events of default and consequently the event of default under the
pass through trust agreements will be deemed to be cured. See "The Leases, the
Facility Site Leases and the Facility Site Subleases Rights to Cure."
Each pass through trust agreement provides that, so long as a lease
indenture event of default has occurred and is continuing:
(1) the pass through trustee may, and upon the direction of the
certificate holders evidencing fractional undivided interests aggregating
not less than a majority in interest of a pass through trust, which we
refer to as the majority certificate holders of such pass through trust,
will, vote in favor of directing the applicable indenture trustee to
declare the unpaid principal amount of such lessor notes then outstanding
and any accrued interest thereon to be due and payable;
(2) the pass through trustee may, and upon the direction of the majority
certificate holders of a pass through trust, will, vote to direct the
applicable indenture trustee regarding the exercise of remedies provided in
the indentures and consistent with the terms of the indenture.
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Each indenture provides that so long as a lease indenture event of default
has occurred and is continuing:
(a) the applicable indenture trustee may, and upon the instruction of the
holders of a majority of the aggregate outstanding principal amount of the
lessor notes, will, declare the unpaid principal of and accrued interest on
the lessor notes issued under the indenture to be due and payable; and
(b) the holders of a majority in aggregate outstanding principal amount
of the lessor notes may direct the indenture trustee with respect to the
exercise of remedies under the indenture.
Accordingly, the ability of the holders of the certificates issued with
respect to any one pass through trust to cause the indenture trustee to
accelerate the lessor notes issued under any applicable lease indenture or to
direct the exercise of remedies by the indenture trustee under such lease
indenture will depend, in part, upon the proportion between the aggregate
principal amount of the lessor notes issued under such lease indenture and
held in such pass through trust and the aggregate principal amount of all
lessor notes issued under such lease indentures and held in the other pass
through trusts. Each pass through trust holds lessor notes with different
terms from the lessor notes held in the other pass through trusts and
therefore the certificate holders of one pass through trust may have divergent
or conflicting interests from those of the certificate holders of the other
pass through trusts. In addition, so long as the same institution acts as pass
through trustee of each pass through trust, in the absence of instructions
from the certificate holders of any such pass through trust, the pass through
trustee for such pass through trust could for the same reason be faced with a
potential conflict of interest upon a lease indenture event of default.
As an additional remedy, if a lease indenture event of default has occurred
and is continuing, the pass through trust agreements provide that the pass
through trustee may, and upon the direction of the majority certificate
holders of the related pass through trust must, sell, convey, transfer and
deliver all or part of the lessor notes that are held in such pass through
trust to any person. In addition, if an owner lessor elects to purchase or
redeem the lessor notes upon the occurrence and continuance of a lease
indenture event of default, each pass through trustee will sell the lessor
notes issued by such owner lessors and held in its pass through trust to the
owner lessor at a price equal to the unpaid principal amount of the lessor
note, together with accrued but unpaid interest on the lessor note, but
without any premium. Any proceeds received by a pass through trustee upon any
such sale will be deposited in the special payments account with respect to
such pass through trust and will be distributed to the certificate holders
with respect to such pass through trust on a special distribution date.
The market for lessor notes in default may be very limited and there can be
no assurance that they could be sold for a reasonable price. If a pass through
trustee sells any such lessor notes held in the related pass through trust
with respect to which a lease indenture event of default exists for less than
their outstanding principal amount, the certificate holders with respect to
such pass through trust will receive a smaller amount of principal
distributions than anticipated and will not have any claim for the shortfall
against us, the owner lessors or the pass through trustee.
Any amount distributed to the pass through trustees by the indenture trustee
on account of the lessor notes held in the pass through trusts following a
lease indenture event of default will be deposited in the special payments
account with respect to each pass through trust and will be distributed to the
certificate holders on a special distribution date. In addition, if following
a lease indenture event of default, the related owner lessor or any owner
participant exercises its option to purchase the outstanding lessor notes
issued under the related lease indenture, the purchase price paid by the owner
lessor or the owner participant to each pass through trustee for the lessor
notes held in such pass through trust will be deposited in the special
payments account with respect to such pass through trust and will be
distributed to the certificate holders with respect to such pass through trust
on a special distribution date.
Any funds representing payments received with respect to any lessor notes in
default that are held in a pass through trust, or the proceeds from the sale
by the pass through trustee of any such lessor notes held by the pass through
trustee in the special payments account with respect to such pass through
trust will, to the extent practicable, be invested by the pass through trustee
in permitted government investments pending the distribution
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of those funds on a special distribution date. Permitted government
investments are defined as obligations of the United States maturing in not
more than 60 days or such lesser time as is required for the distribution of
any such funds on a special distribution date. The pass through trustee is
prohibited from selling any permitted government investment prior to its
maturity.
Each pass through trust agreement provides that the pass through trustee
will, within 90 days after the occurrence of a default (as defined below) in
respect of the pass through trust created under the pass through trust
agreement, give to the certificate holders notice of all defaults under the
related pass through trust agreement actually known to a responsible officer
of the pass through trustee. However, except in the case of default in the
payment of principal, premium, if any, or interest on any of the lessor notes
held in such pass through trust, the pass through trustee will be protected in
withholding notice if it in good faith determines that the withholding of
notice is in the interests of such certificate holders with respect to such
pass through trust. The term "default," for the purpose of the provision
described in this paragraph only, shall mean the occurrence of any event which
is or, after notice or lapse of time or both, would become, an event of
default under the pass through trust agreements specified above.
Each pass through trust agreement contains a provision entitling the pass
through trustee, subject to the duty of the pass through trustee to act with
the required standard of care, to be indemnified by the certificate holders
before proceeding to exercise any right or power under the pass through trust
agreement at the request of the certificate holders.
In certain cases, the majority certificate holders of a pass through trust
may on behalf of all certificate holders with respect to such pass through
trust waive any default and its consequences or may instruct the related pass
through trustee to waive any default under a lease indenture, except:
. a default in the deposit of any scheduled payment or special payment or
in the distribution of any such payment,
. a default in payment of the principal of, premium, if any, or interest
on, any of the lessor notes, or
. a default in respect of any covenant or provision of the pass through
trust agreement that cannot be modified or amended without the consent
of each certificate holder affected thereby.
Each lease indenture provides that, with certain exceptions, the holders of
a majority in aggregate unpaid principal amount of the lessor notes issued
under such lease indenture may on behalf of all such holders waive any past
default or lease indenture event of default thereunder.
Modification of the Pass Through Trust Agreements
Each pass through trust agreement contains provisions permitting us and the
pass through trustee to enter into a supplemental trust agreement, without the
consent of any certificate holders, among other things,
. to evidence the succession of another corporation to us and the
assumption by any such successor of our obligations under the pass
through trust agreement,
. to add to our covenants for the protection of the certificate holders,
. to surrender any right or power conferred upon us in such pass through
trust agreement or the registration rights agreement,
. to cure any ambiguity in, or to correct or supplement any defective or
inconsistent provision of, the pass through trust agreement or the
registration rights agreement, or to make any other provisions with
respect to matters or questions arising under the pass through trust
agreement provided those actions will not adversely affect the interests
of the certificate holders,
. to add, eliminate, or change any provision under the pass through trust
agreement that will not adversely affect the interests of the
certificate holders,
. to correct or amplify the description of property that constitutes the
property of the related pass through trust or the conveyance of that
property to the related pass through trustee,
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. to evidence and provide for a successor pass through trustee,
. at any time that the certificates are subject to the Trust Indenture
Act, to modify, eliminate or add to the provisions of such pass through
agreement to the extent necessary to qualify the such pass through trust
agreement under the Trust Indenture Act,
. to modify, amend or supplement any provision in such pass through trust
agreement to reflect changes relating to the assumption and substitution
of a lessor note under a lease indenture,
. to comply with any requirement of the SEC, any applicable law, rule or
regulation of any exchange or quotation system on which the certificates
are listed, any regulatory body or the registration rights agreement to
effectuate this exchange offer, or
. to modify or eliminate provisions relating to the transfer or exchange
of the new certificates or the existing certificates upon consummation
of this exchange offer or the effectiveness of the registration
statement relating to this exchange offer.
Each pass through trust agreement also contains provisions permitting us and
the pass through trustee, with the consent of the majority certificate holders
of the related pass through trust, to execute supplemental trust agreements
adding provisions to or changing or eliminating any of the provisions of the
pass through trust agreement or the registration rights agreement, or
modifying the rights and obligations of the certificate holders, except that
no supplemental trust agreement may, without the consent of each affected
certificate holder,
. reduce in any manner the amount of, or delay the timing of, any receipt
by the pass through trustee of payments on the lessor notes held in the
related pass through trust, or distributions in respect of any
certificate, or make distributions payable in coin or currency other
than that provided for in the certificates, or change the place of
payment where the certificates are payable, or impair the right of any
certificate holder to institute suit for the enforcement of any such
payment when due,
. permit the disposition of any lessor note held in the related pass
through trust, permit the creation of a lien on the pass through trust
or otherwise deprive any certificate holder of the benefit of the lien
of the related lease indenture, or deprive any certificate holder of the
benefit of ownership of the lessor notes, except as provided in such
pass through trust agreement,
. reduce the percentage of the aggregate fractional undivided interest of
the related pass through trust provided for in the pass through trust
agreement that is required to approve any supplemental trust agreement
or reduce the percentage required for any waiver provided for in the
pass through trust agreement, or
. cause the pass through trust to become taxable as an "association" or to
fail to qualify as a fixed investment trust for federal income tax
purposes (as confirmed in an opinion of counsel (reasonably satisfactory
to each of its recipients) delivered to the related indenture trustee
and pass through trustee).
Termination of the Pass Through Trusts
Both our obligations and those of the pass through trustee created by the
pass through trust agreements, and the pass through trusts, will terminate
upon the distribution to certificate holders of all amounts required to be
distributed to them pursuant to the pass through trust agreements and the
disposition of all property held in the pass through trusts. The pass through
trustee will mail to each certificate holder of record notice of the
termination of the related pass through trust, the amount of the proposed
final payment and the proposed date for the distribution of the final payment
for the related pass through trust. The final distribution to any certificate
holder will be made only upon surrender of that certificate holder's
certificates at the office or agency of the pass through trustee specified in
the notice of termination.
The Pass Through Trustee
State Street Bank and Trust Company of Connecticut, National Association is
the pass through trustee for each pass through trust. The pass through trustee
and any of its affiliates may hold certificates in their own names.
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With certain exceptions, the pass through trustee makes no representations as
to the validity or sufficiency of the pass through trust agreements, the
certificates, the lessor notes, the lease indentures, the leases or other
related documents. State Street Bank and Trust Company of Connecticut,
National Association is also the indenture trustee for the lessor notes issued
under the lease indentures.
The pass through trustee may resign with respect to any or all of the pass
through trusts at any time, in which event we will be obligated to appoint a
successor trustee. The majority certificate holders of a pass through trust
may remove the related pass through trustee at any time by notice to the pass
through trustee, us, the owner lessors and the indenture trustee. If the pass
through trustee ceases to be eligible to continue as such under the pass
through trust agreements or becomes insolvent, we may remove the pass through
trustee, or any certificate holder which has held a 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 the pass
through trustee and the appointment of a successor trustee. Any resignation or
removal of the pass through trustee and appointment of a successor trustee for
a pass through trust does not become effective until acceptance of the
appointment by the successor trustee.
Each pass through trust agreement provides that we will pay the pass through
trustee's fees and expenses. Each pass through trust agreement further
provides that the pass through trustee will be entitled to indemnification by
us, in its individual and trustee capacities, for any out-of-pocket expenses,
disbursements and advances arising out of or in connection with the acceptance
or administration of the pass through trust and, solely in its individual
capacity, for any expense or tax (other than any tax attributable to the pass
through trustee's compensation for serving as such) incurred without gross
negligence, willful misconduct or bad faith, on its part, arising out of or in
connection with the acceptance or administration of the pass through trust.
Book-Entry; Delivery and Form
We will arrange for the pass through trusts to issue new certificates in
exchange for existing certificates currently represented by one or more fully
registered global certificates. The new certificates will be represented by
one or more fully registered global certificates, and will be deposited upon
issuance with the Depository Trust Company or a nominee of the Depository
Trust Company.
The pass through trusts will issue new certificates in certificated form
without interest coupons in exchange for existing certificates which were
issued originally in certificated form without interest coupons.
All payments made by us under the leases to the indenture trustees (as
assignees of the owner lessors) and by the indenture trustees to the pass
through trustee will be in immediately available funds and delivered through
the Depository Trust Corporation in immediately available funds.
Secondary trading in long-term notes and debentures of corporate issuers
generally is settled in clearinghouse or next-day funds. In contrast,
secondary trading in certificates generally is settled in immediately
available funds. The certificates will trade in the Depository Trust Company's
Same-Day Funds Settlement System until maturity, and secondary market trading
activity in such certificates will therefore be required by the Depository
Trust Company to settle in immediately available funds. We cannot assure you
as to the effect, if any, of settlement in immediately available funds on
trading activity in the certificates.
The Depository Trust Company has advised us as follows: the Depository Trust
Company is a limited purpose 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 and a "Clearing Agency" registered
pursuant to the provision of Section 17A of the Exchange Act. DTC was created
to hold securities for its participants and facilitate the clearance and
settlement of securities transactions between participants through electronic
book-entry changes in accounts of its participants, thereby eliminating the
need for physical movement of certificates. Participants include securities
brokers and dealers, banks, trust companies and clearing corporations and
certain
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other organizations. Indirect access to the Depository Trust Company system is
available to others such as banks, brokers, dealers and trust companies that
clear through or maintain a custodial relationship with a participant, either
directly or indirectly ("indirect participants").
So long as the Depository Trust Company or its nominee is the registered
owner or holder of the global certificates, DTC or such nominee, as the case
may be, will be considered the sole record owner or holder of the certificates
represented by such global certificates for all purposes under the related
pass through trust agreement. No beneficial owners of an interest in the
global certificates will be able to transfer that interest except in
accordance with the Depository Trust Company's applicable procedures, in
addition to those provided for under the pass through trust agreement and, if
applicable, the Euroclear System or Clearstream Banking societe anonyme.
Payments of the principal of, premium, if any, and interest on the global
certificates will be made to the Depository Trust Company or its nominee, as
the case may be, as the registered owner thereof. Neither us, the pass through
trustee, nor any paying agent will have any responsibility or liability for
any aspect of the records relating to or payments made on account of
beneficial ownership interests in the global certificates or for maintaining,
supervising or reviewing any records relating to such beneficial ownership
interests.
We expect that the Depository Trust Company or its nominee, upon receipt of
any payment of principal, premium, if any, or interest in respect of the
global certificates will credit participants' accounts with payments in
amounts proportionate to their respective beneficial ownership interests in
the principal amount of such global certificates, as shown on the records of
the Depository Trust Company or its nominee. We also expect that payments by
participants to owners of beneficial interests in such global certificates
held through such participants will be governed by standing instructions and
customary practices, as is now the case with securities held for the accounts
of customers registered in the names of nominees for such customers. Such
payments will be the responsibility of such participants.
Neither us, nor the pass through trustee will have any responsibility for
the performance by the Depository Trust Company or its participants or
indirect participants of their respective obligations under the rules and
procedures governing their operations.
If the Depository Trust Company is at any time unwilling or unable to
continue as a depositary for the global certificates and a successor
depositary is not appointed by us within 90 days, the pass through trust will
issue definitive certificates in exchange for the global certificates.
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DESCRIPTION OF THE LESSOR NOTES
General
The lessor notes will be issued in three series (or tranches) under eleven
separate lease indentures between each owner lessor and State Street Bank and
Trust Company of Connecticut, National Association, as indenture trustee.
Each owner lessor will lease its respective undivided interest and ground
interest to us pursuant to the lease, the facility site lease and the facility
site sublease to which it is a party. We are obligated to make rental and
other payments to each owner lessor under each lease in amounts that are at
least sufficient to pay the principal of, premium, if any, and interest on the
related lessor notes when and as due and payable (except principal and
interest payable upon a lease indenture event of default that is not caused by
a lease event of default). However, the lessor notes are not our obligations
or guaranteed by, us (except in certain circumstances described in this
prospectus where we may assume the obligations of the applicable owner lessor
thereunder). Payments under each lease in excess of the amounts required to
make required payments on the applicable lessor notes will be paid by the
indenture trustee to the applicable owner lessor for distribution by it in
accordance with the terms of its respective limited liability company
agreement except in certain cases upon the occurrence of a lease indenture
event of default. Our lease payment obligations under the leases and the other
operative documents to which we are a party are our general obligations.
Lease Indenture Events of Default
A lease indenture event of default under a lease indenture will occur upon:
(a) the occurrence and continuation of a lease event of default (other
than with respect to (i) various customary excepted payments reserved to
the owner lessor or the owner participant, which we refer to as the
excepted payments or (ii) our failure to maintain required insurance so
long as the insurance we actually maintain is in accordance with prudent
industry practice and such lease event of default is waived by the owner
participant);
(b) the owner lessor's failure to pay principal, interest, or any premium
or any other amounts when due under the related lessor notes that continues
unremedied for five business days;
(c) any material representation or warranty made by the owner
participant, the guarantor of an owner participant or the owner lessor in
any operative document or in any officer's certificate delivered pursuant
to any operative document shall prove at any time to have been incorrect
when made in any material respect and continues to be material and
unremedied for a period of 30 days after receipt by such party of written
notice thereof; however, the 30-day period in the preceding sentence will
be extended to up to 120 days in cases where the condition is capable of
being remedied within that 120 day period and the relevant party diligently
pursues that remedy;
(d) failure by the owner lessor to observe or perform any material
covenant or obligation contained in the lease indenture or in any operative
document to which it is a party or failure of the owner participant or the
guarantor of an owner participant to observe or perform any material
covenant contained in any operative document to which it is a party, which
failure remains unremedied for a period of 30 days after written notice
thereof; however, if the failure is capable of being remedied, that 30-day
period will be extended to up to 180 days, so long as such party diligently
pursues such remedy and such failure is capable of being remedied within
such period; and
(e) customary events of bankruptcy and insolvency, whether voluntary or
involuntary, with respect to the owner lessor, the owner participant or the
guarantor of an owner participant under the applicable lease indenture,
with a grace period of 60 days for involuntary events.
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Remedies
Each lease indenture provides that, subject to the various rights of an
owner lessor and owner participant described below, the related indenture
trustee may exercise certain specified rights and remedies and all remedies
available to it at law if a lease indenture event of default has occurred and
is continuing and the lessor notes have been accelerated. These remedies
include, in circumstances where a lease event of default under the related
lease has occurred, remedies with respect to the applicable lease and site
sublease afforded to the applicable owner lessor by such lease for lease
events of default thereunder. These remedies may be exercised by the indenture
trustee to the exclusion of the applicable owner lessor, the applicable owner
participant, and to the exclusion of us. A sale of the applicable undivided
interest and ground interest upon the exercise of such remedies will be free
and clear of any right of those parties (other than, in certain cases, rights
of redemption provided by law), including our rights under such lease. No
exercise of any remedies by the indenture trustee, however, may affect our
rights under such lease unless a lease event of default has occurred and is
continuing thereunder.
Upon the occurrence of a lease indenture event of default arising out of a
lease event of default, no indenture trustee will be entitled to exercise any
remedy under the applicable indenture which could or would divest the related
owner lessor of its ownership interest in any collateral subject thereto,
unless such indenture trustee, to the extent it is then entitled to do so
under the operative documents related thereto and is not then stayed or
otherwise prevented from doing so by operation of law, has commenced the
exercise of one or more of the remedies referred to in the applicable lease
intended to dispossess us of our leasehold interest in the related undivided
interest. However, if such indenture trustee is then stayed or otherwise
prevented by operation of law from exercising such remedies, such indenture
trustee will not divest the owner lessor of its interest in such collateral
until the expiration of the 180 day period following the commencement of such
stay or other prevention.
Upon the occurrence of any lease event of default with respect to the
payment of the equity portion only of rent, the applicable indenture trustee
will not be entitled to exercise remedies under the applicable indenture for a
period of 180 days unless the applicable owner lessor or owner participant
consents to the declaration of a lease event of default under the related
lease by such indenture trustee.
Redemption of Lessor Notes
Redemption With Make-Whole Premium Following an Optional Refinancing. The
owner lessors with respect to a particular leased facility will redeem a
particular series of lessor notes at the principal amount thereof, together
with interest, if any, accrued to and unpaid on, the date of redemption plus a
make-whole premium, if any, upon an optional refinancing of all lessor notes
in that series at our request.
We will agree not to request that any lessor notes be refinanced unless all
lessor notes in a particular series are refinanced. In addition, our right to
request an optional refinancing is exercisable on no more than three
occasions.
Optional Redemption With Make-Whole Premium. With our prior consent, each
owner lessor will have the right, at its option, to redeem all or a portion of
the lessor notes issued by it on any date at the principal amount thereof,
together with interest, if any, accrued to and unpaid on, the date of
redemption, plus a make-whole premium, if any.
The make-whole premium for any lessor note subject to redemption is an
amount equal to the discounted present value of such lessor note less the
unpaid principal amount of such lessor note plus accrued interest thereon;
provided that the make-whole premium will not be less than zero. For purposes
of this definition, the discounted present value of any lessor note subject to
redemption pursuant to any indenture will be equal to the discounted present
value, as of the date of redemption, of all principal and interest payments
scheduled to become due in respect of such lessor note after the date of such
redemption, calculated using a discount rate equal to the
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sum of (1) the yield to maturity on the U.S. Treasury security having 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 plus (2) 50 basis
points. However, if there is no U.S. Treasury security having an average life
equal to the remaining average life of such lessor note, such discount rate
will be calculated using a yield to maturity interpolated or extrapolated on a
straight-line basis (rounding to the nearest calendar month, if necessary)
from the yields to maturity for the two U.S. Treasury securities having
average lives most closely corresponding to the remaining life of such lessor
note and trading in the secondary market at the price closest to par.
Mandatory Redemption With Make-Whole Premium. All lessor notes outstanding
related to a particular leased facility will be redeemed, in whole but not in
part, at any time on or after the seventh anniversary of December 19, 2000 at
the principal amount of the lessor notes being redeemed, together with all
accrued and unpaid interest thereon, if any, to the redemption date, plus a
make-whole premium (as defined above), upon early termination by us of the
related leases following a determination in good faith by us that the related
leased facility is:
(1) economically or technologically obsolete (other than as a result of
(a) a change in law, regulation or tariff of general application or (b)
imposition by the Federal Energy Regulatory Commission or any other
governmental entity having or claiming jurisdiction over us, or the
affected leased facility of any conditions or requirements (including,
without limitation, requiring significant capital improvements to the
affected leased facility) upon the continued effectiveness or renewal of
any license or permit required for the operation or ownership of the
affected leased facility).
(2) surplus to our needs or are no longer useful in our trade or business
(including without limitation, 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 we elect to terminate the leases with respect to a particular leased
facility because that leased facility is obsolete, surplus or no longer
useful, we will, at the request of any owner lessor, use commercially
reasonable efforts, as a non-exclusive agent for such owner lessor, to obtain
bids and sell such owner lessor's interest in the leased facility on the date
such lease terminates.
Mandatory Redemption Without Premium. All lessor notes outstanding under a
lease indenture will be redeemed, in whole but not in part, at the principal
amount of the lessor notes being redeemed, together with all accrued and
unpaid interest thereon, if any, to the redemption date, but without any
premium, on the earliest to occur of any of the following circumstances:
(1) termination of the leases with respect to one of the leased
facilities upon the occurrence of an event of loss as described below under
the caption "--The Leases--Event of Loss," with respect to that leased
facility (unless we elect to rebuild or replace the damaged leased facility
or, in the case of a regulatory event of loss (as defined below) either (a)
we acquire the applicable owner participant's membership interest in the
related owner lessor and waive the regulatory event of loss, and the lease
between us and the applicable owner lessor remains in effect, or (b) assume
the lessor notes issued under such indentures);
(2) exercise by us of our right to terminate the leases with respect to
one of the leased facilities following a determination in good faith by us
that such leased facility is economically or technologically obsolete, as a
result of (a) a change in law, regulation or tariff of general application
or (b) imposition by the Federal Energy Regulatory Commission or any other
governmental entity having or claiming jurisdiction over us, or such leased
facility of any conditions or requirements (including, without limitation,
requiring significant capital improvements to such leased facility) upon
the initial issuance, continued effectiveness, or renewal of any license or
permit required for the operation or ownership of such leased facility; or
(3) exercise by us of our option to terminate one or more of leases with
respect to a leased facility (except under circumstances in which we assume
the applicable lessor notes) if:
(a) a change in law causes it to become illegal for us to continue a
lease or to make payments thereunder and the other operative documents
related to that lease and the transactions contemplated
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thereby cannot be restructured to comply with such change in law in a
manner reasonably acceptable to the relevant parties; or
(b) one or more events not caused by us or any of our affiliates,
wholly or partially for the purposes of exercising our termination
option, occurs that gives rise to indemnity obligations under the
operative documents, such obligations can be avoided if such lease(s)
are terminated and the owner lessors sell their undivided interests
leased thereunder to us, and the present value of such avoided payments
would exceed 2.5% of the original purchase price of such interest.
In the event of an early termination under clause (2) above, we will, at the
request of any owner lessor, use commercially reasonable efforts, as non-
exclusive agent for such owner lessor, to obtain bids and sell such owner
lessors' interests in such affected unit(s).
Assumption by Us of Lessor Notes
So long as no significant lease default or lease event of default has
occurred and is continuing, upon the termination of a lease as a result of:
(1) a regulatory event of loss (as defined below),
(2) a change in law that makes it illegal for us to continue such lease
or make payments under the lease and the other operative documents related
thereto, or
(3) us becoming obligated to pay an indemnity under the applicable
operative documents in an amount in excess of 2.5% of the present value of
the cost of the applicable interest in the leased facilities, and,
in each case, upon the purchase by us of the applicable owner lessor's
undivided interest in the related leased facility, we may assume the related
lessor notes on a fully recourse basis. We may instead elect to purchase, or
arrange the purchase of, the owner participant's membership interest in the
owner lessor and withdraw our notice to terminate such lease by paying to the
owner participant that portion of termination value that we would have had to
pay to the owner participant under the applicable lease (net of all payments
due and owing to the applicable indenture trustee to discharge the lien of
such indenture trustee).
As a condition to the assumption of any lessor notes, the indenture trustee
will receive (i) a confirmation from each of S&P and Moody's that the
assumption will not result in a downgrade of the then existing ratings on the
certificates and (ii) an opinion of our counsel to the effect that, among
other things:
. the assumption agreement and the applicable lessor notes constitute our
legal, valid and binding obligations, subject to certain exceptions;
. the assumption agreement and the assumption of the lessor notes would
not cause a taxable transaction to occur as to any direct or indirect
holder of a lessor note (including any certificate owner) provided, that
if we provide an indemnity against the risk that such assumption of the
lessor notes will cause a taxable transaction event to occur as to any
direct or indirect holder of a lessor note (including any certificate
owner), then an opinion as to this point will not be required; and
. the lien of the lease indenture will continue to be a first priority
perfected lien on the collateral.
A regulatory event of loss with respect to a leased facility will be deemed
to have occurred upon the subjection of an owner participant's, an owner
lessor's or a guarantor of an owner participant's interest in the related
lease or any operative document to any rate of return regulation by any
governmental authority, or upon the subjection of that owner participant or
the related owner lessor to any other public utility regulation of any
governmental authority or law which in the reasonable opinion of that owner
participant is burdensome, in either case by reason of participation by the
owner participant or owner lessor in the leveraged lease transactions, and
not, in any event, as a result of (a) investments, loans or other business
activities of such owner participant or its affiliates in respect of equipment
or facilities similar in nature to the applicable leased facility or any part
of that leased facility or in any other electrical, steam, cogeneration or
other energy or utility related equipment or facilities or the general
business or other activities of such owner participant or affiliates or the
nature of any of
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the properties or assets from time to time owned, leased, operated, managed or
otherwise used or made available for use by such owner participant or its
affiliates or (b) a failure of such owner participant to perform routine,
administrative or ministerial actions the performance of which would not
subject such owner participant to any material adverse consequence (in the
reasonable opinion of the owner participant acting in good faith), However, a
regulatory event of loss will only be deemed to have occurred if elected by
the applicable owner participant and only if termination of the related lease
and transfer of the related leased facility to us will remove the basis of the
regulation described above. We agree to cooperate with the applicable owner
lessor and owner participant to take reasonable measures to alleviate the
source or consequence of any regulation constituting an event of loss under
this paragraph at the cost and expense of the party requesting that
cooperation and so long as there is no material adverse consequences to the
applicable owner lessor or owner participant as a result of cooperation or the
taking of reasonable measures.
Owner Lessor Right to Purchase the Lessor Notes
Each owner lessor has the right to purchase the lessor notes outstanding
under the related lease indenture, without any premium, at a price equal to
the outstanding principal amount of those lessor notes, together with accrued
and unpaid interest thereon to the date of purchase, if any, and all
outstanding fees and expenses owed to or incurred by the applicable indenture
trustee, if all of the following conditions are satisfied:
. Either:
(1) a lease indenture event of default, which also constitutes a lease
event of default, has occurred and is continuing for a period of
at least 90 days without the acceleration of the lessor notes and
the exercise of any remedy under the related lease by the
applicable indenture trustee intended to dispossess us of the
applicable leased facility;
(2) as a result of the occurrence and continuation of a lease
indenture event of default, the applicable indenture trustee
accelerates, in its discretion, or, holders of a majority of the
lessor notes direct the acceleration of, the applicable lessor
notes, and that acceleration has not been rescinded; or
(3) within the previous 30 days the applicable indenture trustee has
provided us and the related owner participant written notice that
it intends to exercise, within not less than 30 days, remedies
available under the related lease intended to dispossess us of the
applicable leased facility as the result of the occurrence of a
lease indenture event of default which also constitutes a lease
event of default; and
. no lease indenture event of default (other than solely as the result of
the occurrence of a lease event of default) has occurred and is
continuing under the related indenture; and
. the applicable owner lessor has notified the applicable indenture
trustee in writing of its intention to purchase the applicable lessor
notes.
Owner Lessor's Right to Cure
Each owner lessor or owner participant may, but is not obligated to, pay an
amount equal to all (but not less than all) of the outstanding principal,
accrued interest and other amounts payable with respect to the related notes
then due and payable, if a lease event of default (or any condition,
occurrence or event which, with notice or lapse of time or both, would be a
lease event of default, which we refer to as a lease default) in the payment
of any installment of periodic lease rent or supplemental lease rent due under
the related lease has occurred and within 10 business days after the earlier
of (a) receipt by the owner lessor and owner participant of notice of or (b)
the owner lessor or owner participant acquiring actual knowledge of the
occurrence of such lease default or lease event of default. If any other lease
default or lease event of default occurs and the owner lessor has been
furnished by the owner participant with all funds necessary for remedying such
lease default or lease event of default, the owner participant may instruct
the owner lessor to exercise the owner lessor's right to perform payment
obligations on our behalf pursuant to the related lease.
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In determining whether a lease indenture event of default has occurred, (a)
payment by the owner participant or the owner lessor in accordance with the
previous paragraph shall be deemed to remedy any lease default or lease event
of default in the payment of installments of periodic lease rent and to remedy
any default by the owner lessor in the payment of any amount due and payable
under the lessor notes or the lease indenture, and (b) any performance by the
owner lessor of any of our obligations pursuant to the related lease shall be
deemed to remedy any lease default or lease event of default (but, any payment
or performance by the applicable owner lessor will not relieve us from our
obligation to pay all rent and perform all our obligations under the related
lease). If a lease default or lease event of default has been remedied by
either of these specified bases, then any determination that a lease default
or lease event of default exists or any acceleration of the lessor notes or
any declaration that a lease indenture default or lease indenture event of
default exists will be deemed to be rescinded, and the owner participant will
be subrogated to the rights of holders under the lease indenture to receive
such payment of rent from us and will be entitled to receive and retain such
payment from us so long as no other lease indenture event of default has
occurred or will result therefrom.
The applicable owner participant will not, so long as the lease indenture
has not been terminated, attempt to recover amounts paid by it on our behalf
except by demanding payment of such amount from us or by commencing an action
at law and obtaining a judgment against us. The applicable owner participant
may not, so long as the lease indenture has not been terminated, obtain any
lien on any part of the indenture estate on account of that payment, nor will
any claim of that owner participant against us or any other party for such
repayment impair the prior right and security interest of the indenture
trustee and the holders in and to the indenture estate. The right of each
owner lessor to purchase the related lessor notes will not apply with respect
to any cure of any default in the payment of periodic lease rent if such cure
has been exercised with respect to (a) four consecutive payments of periodic
lease rent immediately preceding the date of such default, or (b) more than
eight payments of periodic lease rent.
Security
The lessor notes issued by each owner lessor will be secured by a first
priority security interest in and mortgage lien on the indenture estate
granted to the applicable indenture trustee. The indenture estate includes
such owner lessor's interest in the applicable undivided interest and ground
interest and its rights under the related lease, including the right to
receive payments of any kind thereunder (other than the excepted payments),
the facility site sublease and the sublease ground interest thereunder and all
payments of any kind thereunder, the fixtures, the facility deed, the bill of
sale, the ownership and operation agreement, the shared facilities agreement
among us and the owner lessors of the relevant leased facility, the qualifying
credit support and all and any interest in property now or hereafter granted
to the owner lessor pursuant to any provision of the facility site lease,
lease or the facility site sublease and each other operative documents (other
than the tax indemnity agreement) to which the owner lessor is a party.
So long as no lease indenture event of default has occurred and is
continuing under a lease indenture, the applicable owner lessor is entitled to
exercise all of the rights of the owner lessor under the operative documents,
subject to certain specific exceptions (including with respect to amendments,
waivers, modifications and consents under provisions of various operative
documents). The owner lessor's rights, however, do not include the right to
receive payments of periodic rent and certain other amounts due under the
leases, which payments will be made directly to the indenture trustee. The
assignment by the owner lessor to the indenture trustee of its rights under
the related operative documents also excludes certain rights of the owner
lessor, including rights relating to indemnification by us for various matters
and insurance proceeds payable to the owner lessors under liability insurance
maintained by us under the leases.
Funds, if any, held from time to time by the indenture trustee pursuant to
the lease indentures will be invested and reinvested by the indenture trustee,
at the direction and at the expense of each owner lessor, in permitted
investments. The indenture trustee will not be liable for any loss resulting
from any investment required to be made by it pursuant to the terms of the
applicable lease indenture other than by reason of its willful misconduct or
gross negligence.
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Limitation of Liability
The lessor notes are not obligations of, or guaranteed by, us or the owner
participants. None of the owner participants, the owner manager, a guarantor
of an owner participant or the indenture trustee, or any of their respective
affiliates, are personally liable to any holder of a lessor note or to the
indenture trustee for any amounts payable under any lessor notes or, except as
provided in the applicable lease indenture, for any liability under such lease
indenture. Any amounts payable under any lessor notes are non-recourse to the
assets of the indenture trustee, the owner participants, the owner manager or
any guarantor of an owner participant. 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 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 therefrom (including periodic lease rent payable by us under
the related lease).
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DESCRIPTION OF THE LEASES AND OTHER LEASE DOCUMENTS
The Leases
We have entered into four leases that relate to the Dickerson baseload units
and seven leases that relate to the Morgantown baseload units. Pursuant to
these eleven leases, which we refer to as the leases, we lease from the owner
lessors the Dickerson and Morgantown baseload units, which we refer to
collectively as the leased facilities and each, as a leased facility. We will
also lease the property on which the leased facilities are located, called the
facility sites, to the owner lessors pursuant to facility site leases, who
will then sublease such property back to us pursuant to facility site
subleases. We refer to the owner lessors' interest in the facility sites under
such leases as their ground interest.
Term and Rent. The term of each lease for the Dickerson leased facility,
which we will refer to as the basic lease term, commenced on December 19,
2000, which we refer to as the closing date, and continue for a period of 28
1/2 years. The term of each lease for the Morgantown leased facility will
commence on the closing date and continue for a period of 33 3/4 years. We
have the right to renew each lease for one or more renewal lease terms. We
will refer to the basic lease term plus all renewal lease terms for each lease
as its facility lease term.
Rent payable under each lease consists of periodic lease rent, which is
payable with respect to the basic lease term, renewal rent, which is payable
with respect to any renewal lease term, and supplemental rent. Supplemental
rent includes our payment obligations arising out of the operative documents,
other than periodic lease rent and renewal rent, to the owner lessor or any
other person.
During the facility lease term, rent will be paid in advance and/or arrears
on each June 30 and December 30, which we refer to as rent payment dates. The
first rent payment date is June 30, 2001. Supplemental rent is payable when
due and owing, or if there is no due date specified, promptly after demand by
the person entitled to the payment.
Use and Maintenance. In the leases, we covenant that we will:
. maintain the leased facilities, at our own expense, in as good
condition, repair and working order as when delivered, ordinary wear and
tear excepted, and in any event, in all material respects (a) no less
favorably as compared to other generating facilities of a similar type
owned or operated by us or any of our domestic unregulated affiliates,
in each case solely as a result of the status of the applicable leased
facility as a leased facility as opposed to an owned facility (b) in
accordance with prudent industry practice, (c) in compliance with all
applicable laws, rules and regulations of any governing body having
jurisdiction, including, without limitation, all environmental
protection laws, pollution and safety laws, unless non-compliance with
any such laws could not reasonably be expected to have a material
adverse effect on us and the designated subsidiaries, taken as a whole
and (d) in accordance with the terms of all insurance policies required
to be maintained pursuant to each operative document, and
. cause to be made all repairs, renewals, replacements, betterments and
improvements to the leased facilities, all as in our reasonable judgment
may be necessary (x) to operate the leased facilities in accordance with
the operative documents and, (y) to the extent commercially reasonable,
consistent with the estimated remaining economic useful life of the
applicable leased facility, (as set forth in the appraisal delivered on
the closing date). The timing of any repairs, renewals, replacements,
betterments and improvements necessary to fulfill our obligations under
clause (y) is at our sole discretion.
In the ordinary course of maintenance, service, repair or testing of a
leased facility or any component of a leased facility, we, at no cost to the
owner lessors, may remove or cause to be removed from that leased facility any
component of that leased facility, so long as:
. we cause the component to be replaced by a replacement component which
is free and clear of all liens (other than permitted liens) and is in as
good an operating condition as the component replaced (assuming that the
component replaced was maintained in accordance with the terms of the
lease), and
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. the replacement does not diminish, other than in an immaterial respect,
the current and residual value, remaining useful life or utility of the
leased facility as measured immediately prior to the replacement
(assuming that, at that time, the leased facility is in the condition
required by the terms of the related lease) or cause the leased facility
to become "limited use" property.
Improvements to the Leased Facilities
Required Improvements. Without expense to the owner lessors or the owner
participants, and without the consent of any other party to the operative
documents, whom we will refer to as the lease financing parties, we are
required to make or cause to be made any modification, alteration, addition or
improvement to the leased facilities as is required:
. by any applicable law, rule or regulation by any agency or authority
having jurisdiction,
. by any insurance policy required to be maintained by us under any
operative document, or
. by the terms of the operative documents.
These improvements are called required improvements. We may, in good faith
and by appropriate proceedings, diligently contest the validity or application
of any requirement of law in any reasonable manner and according to the terms
of the applicable leases.
Optional Improvements. So long as no lease event of default in respect of
payments shall have occurred and be continuing, we, at any time may, without
expense to the owner lessors or the owner participants, and without the
consent of any other lease financing party, make, cause to be made or permit
to be made any modification, alteration, addition or improvement to the leased
facility as we consider desirable in the proper conduct of our business. These
improvements are called optional improvements. However, no optional
improvement to the leased facility may, other than in an immaterial respect,
diminish the current or residual value, remaining useful life or utility of
the leased facility, or cause the leased facility to become "limited use"
property.
Improvements that can be readily removed without (other than in an
immaterial respect) causing material damage to either leased facility are
called severable improvements. All severable improvements, except for
severable improvements that are also required improvements or severable
improvements that are financed through the leases, remain our property. All
required improvements, non-severable improvements and improvements that are
financed through the leases automatically, upon being affixed to the
applicable leased facility, become the property of the owner lessors and are
subject to the leases and the lease indentures.
If we elect to finance required or non-severable improvements through the
leases, the applicable owner participant will be given the opportunity to
finance and will consider in its sole discretion financing the improvements in
whole or in part with additional equity. We are not obligated to accept, nor
will an owner participant be obligated to provide, any additional equity
financing. Notwithstanding this, however, at our request, each owner lessor
will agree to cooperate with us to finance required or non-severable
improvements through the issuance of additional lessor notes under its lease
indenture (which will rank equally with the lessor notes then outstanding),
subject to the following conditions:
. except with respect to required improvements, there shall be no more
than one such financing in any calendar year;
. the additional lessor notes (x) shall have a final maturity date no
later than the later of (i) two years prior to the end of the basic
lease term and (ii) the maturity date of the lessor notes evidenced by
the certificates and (y), in either case, will be fully repaid out of
additional periodic lease rent as adjusted pursuant to the leases;
. appropriate adjustments to periodic lease rent and termination value set
forth in the leases (determined without regard to any tax benefits
associated with the improvements, unless the owner participant is
financing the improvement with additional equity) will be made to
protect the owner participant's net
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economic return; provided, that there will be no changes made to the
amortization schedule or interest amounts and payment dates of the
lessor notes issued on the closing date;
. we have paid, on an after-tax basis, all reasonable costs and expenses
of the lease financing parties, including fees and expenses of counsel,
in connection with such financing or refinancing;
. no significant lease default or lease event of default has occurred and
is continuing, unless the improvements to be made with the financing
will cure the significant lease default or lease event of default, and
the improvements will be made in compliance with the operative documents
and we have delivered an officer's certificate to the applicable owner
participant and the pass through trustees to that effect;
. the financing to construct the improvement to the leased facility is for
an amount not less than $20 million, nor greater than 100% of the costs
of the improvements being financed; provided, that the aggregate
outstanding balance of all lessor notes related to that leased facility
does not exceed 87% of the fair market value of the relevant leased
facility taking into account the improvements, as determined by an
appraiser selected by us and reasonably acceptable to the applicable
owner participant;
. the applicable owner participant has (i) received an opinion of its tax
counsel reasonably satisfactory to the owner participant to the effect
that the requested financing should not result in any incremental risk
of material adverse federal income tax consequences to the owner
participant and (ii) an indemnity against such risk in form and
substance reasonably satisfactory to such owner participant from or
guaranteed by an entity that has a credit rating of at least BBB from
S&P and at least Baa3 from Moody's (or, if such rating requirement is
not met, the owner participant will have received credit support in
respect of such indemnity reasonably satisfactory to it); provided that
if the opinion referred to in clause (i) will be that such financing
"will" not result in any incremental risk of material adverse federal
income tax consequences to the owner participant, then the rating
requirement in clause (ii) shall not be required with respect to the
indemnity set forth in clause (ii);
. the applicable owner participant will suffer no material adverse
accounting effects under generally accepted accounting principles as a
result of providing the requested financing;
. except with respect to required improvements and improvements made for
the purpose of reducing pollution, we will have, at that time, a credit
rating of at least BBB- from S&P and Baa3 from Moody's; however, this
credit rating requirement will not apply unless the projected amount of
lessor loans issued to finance improvements (other than required
improvements and improvements made for the purpose of reducing
pollution) exceeds 10% of the projected fair market value of the
applicable leased facility, after taking into account any improvements
made to that leased facility, at any time during the remainder of the
facility lease term (the projected fair market value will be determined
by an appraiser selected by the owner participants and reasonably
acceptable to us);
. the applicable indenture trustee has received an opinion of counsel to
the applicable owner lessor that the subsequent lessor notes and the
supplement to the applicable indenture have been duly authorized,
executed and delivered by such owner lessor and constitute the legal,
valid and binding obligations of such owner lessor enforceable in
accordance with their terms; and
. we have made or delivered such representations, warranties, covenants,
opinions or certificates as the applicable owner participant may
reasonably request.
In addition, our right to finance improvements through the related leases is
subject to the limitations on incurrence of indebtedness set forth under the
caption "Description of the Certificates--Covenants--Limitations on the
Incurrence of Indebtedness."
In connection with the financing of any optional improvements through the
related leases, we will deliver an officer's certificate to the applicable
indenture trustees stating that (a) no lease event of default has occurred and
is continuing, (b) the conditions in respect of the issuance of subsequent
lessor notes contained in the
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applicable lease indentures have been satisfied, (c) periodic lease rent and
termination values have been calculated to be sufficient to pay all
outstanding lessor notes, after taking into account the issuance of the
subsequent lessor notes and any related prepayment of lessor notes theretofore
outstanding and (d) all conditions to the supplemental financing or
refinancing contained in any operative document have been satisfied.
Notwithstanding the prior provision regarding the financing of the
improvements through the leases, we will, subject to any limitation on the
incurrence of indebtedness (see the section under the caption "Description of
the Certificates--Covenants--Limitations on the Incurrence of Indebtedness")
at all times have the right to fund improvements to either leased facility
other than through the related lease.
Sublease and Assignment
Sublease. We may sublease any one of the undivided interests without the
consent of the applicable owner lessor, owner participant, indenture trustee
or pass through trustees under the following conditions:
. the sublessee is a United States person that (i) is a solvent
corporation, partnership, business trust, limited liability company or
other person or entity not subject to bankruptcy proceedings, (ii) is
not involved in pending and unresolved material litigation with the
applicable owner participant and (iii) is, or its operating, maintenance
and use obligations under the sublease are guaranteed by, or those
obligations are contracted to be performed by, an experienced operator
of United States based, coal-fired electric generating facilities
similar to the applicable leased facility;
. the sublease does not extend beyond the scheduled expiration of the
basic lease term or any renewal lease term then in effect or irrevocably
elected by us (and may be terminated upon early termination of the
applicable lease) and is expressly subject and subordinate to the
applicable lease;
. all terms and conditions of the applicable lease and related operative
documents remain in effect and we remain fully and primarily liable for
our obligations under that lease and those operative documents;
. no significant lease default or lease event of default has occurred and
is continuing or will be created as a result of the sublease;
. the sublease prohibits further assignment or subletting;
. the sublease requires the sublessee to operate and maintain the
applicable undivided interest in a manner consistent with the applicable
lease;
. the applicable owner lessor, owner participant, indenture trustee and
the pass through trustees obtain an opinion of counsel, which opinion of
counsel is satisfactory to each recipient, to the effect that all
regulatory approvals relating to the sublease have been obtained;
. the sublessee pays on an after-tax basis all reasonable documented out-
of-pocket expenses of the applicable owner lessor, owner participant,
indenture trustee and pass through trustee in connection with the
sublease;
. the applicable owner participant receives (i) an opinion from its tax
counsel reasonably satisfactory to it that such sublease should not
result in any incremental risk of material adverse federal income tax
consequences to such owner participant and (ii) an indemnity against
such risk reasonably satisfactory to such owner participant (without
regard to any minimum credit rating or credit support requirements); and
. the sublease does not result in the property becoming "tax-exempt use
property" within the meaning of Section 168(h) of the Internal Revenue
Code (unless we make a payment to the owner participant
contemporaneously with the execution of the sublease that in the
reasonable judgment of the owner participant compensates the owner
participant for the adverse tax consequences resulting from the
classification of the property as "tax-exempt use property."
As a condition precedent to any sublease, we will provide the applicable owner
lessor, owner participant and indenture trustee with all documentation in
respect of that sublease and an opinion of counsel to the effect that
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the sublease complies with certain of the conditions listed above (such
documentation, counsel and opinion to be reasonably satisfactory to each such
recipient).
Assignment. Except as set forth below, we may not, without the consent of
lease financing parties, assign any lease or any other operative document, or
any interest in any operative document. So long as the assignment does not
result in the applicable owner lessor, owner participant or guarantor of an
owner participant becoming subject to regulation as a "public utility", a
"public utility company", a "holding company", a "subsidiary company" of a
"holding company" or an "affiliate" of a "holding company" within the meaning
of the Federal Power Act or the Public Utility Holding Company Act, we may
assign any lease and the related operative documents to any person or entity
so long as that person or entity (or any party that guarantees the assignee's
obligations under the assigned operative documents) has (i) a credit rating
equal to, or greater than, BBB from S&P and Baa2 from Moody's, (ii)
significant experience owning or operating coal-fired electric generating
facilities in the United States and (iii) a tangible net worth of at least
$750 million after giving effect to the assignment. Upon any assignment and
assumption in accordance with this provision, we will have no further
liability or obligation under the applicable lease or the related operative
documents.
Assignment of the leases, the operative documents or any interest in an
operative document also is subject to satisfaction of the following
requirements:
. after giving effect to the assignment, each of Moody's and S&P confirms
that the certificates will be rated at least equal to their rating in
effect immediately prior to the assignment;
. the applicable owner lessor, owner participant, indenture trustee and
the pass through trustees have received an opinion of counsel, which
opinion of counsel is reasonably satisfactory to the recipients, to the
effect that all regulatory approvals required in connection with the
assignment or necessary to assume our obligations under the applicable
lease and the related operative documents have been obtained;
. the assignment will be made pursuant to an assignment and assumption
agreement in form and substance reasonably satisfactory to the
applicable owner participant and indenture trustee and the pass through
trustees;
. the applicable owner lessor, owner participant, indenture trustee and
the pass through trustees have received an opinion of counsel, which
opinion and counsel are satisfactory to the recipients, in respect of
the assignment and assumption;
. the applicable owner participant has received (i) an opinion from its
tax counsel reasonably satisfactory to it that such assignment should
not result in any incremental risk of material adverse federal income
tax consequences to such owner participant and (ii) an indemnity against
such risk reasonably satisfactory to such owner participant (without
regard to any minimum credit rating or credit support requirements);
. no lease event of default has occurred and is continuing or will be
created by the assignment;
. the assignment does not result in a regulatory event of loss;
. the transferee is not involved in material litigation with the
applicable owner participant or any of its affiliates;
. concurrently with the assignment of any lease with respect to a
particular leased facility, we assign each other lease with respect to
that leased facility to the same transferee;
. we will pay on an after-tax basis all reasonable documented out-of-
pocket expenses of the applicable owner lessor, owner participant,
indenture trustee and the pass through trustees in connection with the
assignment; and
. unless we have provided an indemnity against the risk that such
assignment will cause a tax event to occur as to any direct or indirect
holder of a lessor note (including any certificate owner), the indenture
trustee shall have received an opinion of counsel to us, addressed to
the indenture trustee and the
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holders of the lessor notes, to the effect that such assignment shall
not cause a tax event to occur as to any direct or indirect holder of
any lessor note (including any certificate owner).
Termination
Termination for Burdensome Events. We have the option, by giving notice to
the applicable owner lessor and owner participant no later than 12 months
after the date we receive notice or actual knowledge of an event described
below, to purchase, subject to various conditions, that owner lessor's
interest in a leased facility and terminate the applicable lease if: (1) a
change in law causes it to become illegal for us to continue the lease or for
us to make payments under the lease or other operative documents, and the
transactions cannot be restructured to comply with the change in law in a
manner reasonably acceptable to the parties to the lease; or (2) (i) one or
more events not caused by us (or any of our affiliates), wholly or partially
for purposes of exercising this termination option, has occurred which will,
or can reasonably be expected to, give rise to an obligation by us to pay or
indemnify in respect of general indemnity or tax indemnity payments under the
applicable operative documents, (ii) the indemnity obligation (and the
underlying cost or tax) can be avoided in whole or substantially in part by
the purchase of such owner lessor's undivided interest in the leased facility,
and (iii) the amount of the avoided payments would exceed (on a present value
basis, discounted at the discount rate, compounded on an annual basis to the
date of the termination) 2.5% of such owner lessor's purchase price (it being
understood that the related owner participant may waive its right to indemnity
payments in excess of 2.5% of the purchase price payments or arrange for its
own account the payment thereof).
Notwithstanding the foregoing, if the applicable owner participant or any of
its affiliates owns the membership interest in any other owner lessor in the
same leased facility, we may exercise (if we have the right to do so) our
termination option under the related lease we are concurrently exercising our
termination option under such other owner lessor's lease.
If, in connection with the termination of the lease with respect to one or
more leased facilities under the circumstances described above, we purchase
the owner lessor's interest in the leased facility, execute an assumption
agreement and satisfy certain other conditions (including the indenture
trustee having received a reasonably satisfactory opinion of counsel
confirming that the assumption described below does not result in a taxable
transaction to any direct or indirect holder of the lessor notes unless we
have provided an indemnity against the risk that such assumption will cause a
tax event to occur as to any direct or indirect holder of a lessor note
(including any certificate owner)) contained in the applicable indenture, we
may, so long as no significant lease default or lease event of default has
occurred and is continuing after giving affect to the assumption, assume the
applicable 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 its interest in the leased facilities in connection
therewith) unless and until either we assume the related lessor notes in
accordance with the provisions of the related lease indenture or the
applicable owner lessor has paid all outstanding principal and accrued
interest on the lessor notes and all other amounts due under the lease
indenture on the proposed date of termination. Pursuant to the participation
agreements, we also have the option, subject to certain conditions, of
purchasing the owner participant's membership interest in the applicable owner
lessor or all of the outstanding membership interests in such owner
participant under the above circumstances and waiving the termination right.
Our right to purchase the owner participant's membership interest in the
applicable owner lessor or all of the outstanding membership interests in such
owner participant is subject to (i) the applicable indenture trustee having
received an opinion from our counsel to the effect that such purchase will not
result in more than an immaterial risk of the merger of our interests with
those of the owner lessor in the related lease and (ii) payment by us to the
owner participant of that portion of termination value that would have been
payable to the owner participant or the holder of the outstanding membership
interests in such owner participant, as applicable, (net of all payments due
and owning to the indenture trustee to discharge the lien of the indenture
trustee) if we had terminated the lease.
Termination for Obsolescence. We may, so long as no lease event of default
has occurred and is continuing, terminate all, but not less than all, of the
leases with respect to any leased facility at any time on or
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after the seventh anniversary of the closing date and within 180 days of a
notice (as described below) if we determine in good faith that:
(1) a leased facility is economically or technologically obsolete; or
(2) that leased facility is otherwise economically or technologically
obsolete or surplus to our needs or no longer useful in our trade or
business for any reason, including without limitation, 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.
In order to exercise the termination option, we must give the applicable
owner lessors, owner participants, indenture trustees and the pass through
trustees six months' prior written notice, containing a certification by us.
In the event of an early termination as described immediately above, we
will, as non-exclusive agent for the applicable owner lessors, use
commercially reasonable efforts to obtain bids and sell the applicable owner
lessors' interests in the obsolete, surplus or unusable leased facility on the
termination date, all of the proceeds of which will be for the account of the
owner lessors, provided that, so long as the lessor notes are outstanding, the
proceeds of the sale shall be paid directly to the indenture trustee. The
purchaser of any interest in the leased facility will not be us, any of our
affiliates or any third party with whom we or any of our affiliates have an
arrangement to use or operate the leased facility to generate power for our
benefit or for the benefit of any of our affiliates. On the termination date,
each owner lessor will sell its undivided interest in the leased facility to
the highest bidder, and we shall pay each owner lessor the excess of the
termination value as set forth in the relevant leases over the net proceeds of
the sale, plus certain additional amounts.
Alternatively, in the event we exercise our early termination option, any
owner lessor may elect to retain rather than sell the undivided interest by
providing notice to us 90 days prior to the obsolescence termination date, in
which case we shall pay to that owner lessor on the termination date all rent
and other amounts then owing, and the applicable lease shall terminate.
Unless an owner lessor, with our consent, has entered into a legally binding
contract to sell its interest in the leased facility, we may, not more than 30
days prior to the proposed termination date, revoke our notice of termination,
provided that we may not reissue the notice of termination more than once in
any five year period. In the event of a revocation of a termination notice,
the applicable lease will continue in effect.
Liens
We will not, directly or indirectly, create, incur, assume or suffer to
exist any liens or other encumbrances on the leased facilities or our interest
in any operative document, except for permitted liens. See the section titled
"Description of the Certificates--Covenants--Restrictions on Liens."
Insurance
We will, at our own cost and expense, with respect to each leased facility,
maintain or cause to be maintained (i) all risk property insurance customarily
carried by prudent operators of coal-fired electric generating facilities of
comparable size and risk as that leased facility and, in any case, in an
amount equal to the maximum foreseeable loss of that leased facility and (ii)
commercial general liability insurance (including contractual liability
coverage and sudden and accidental pollution liability coverage), and
commercial automobile liability insurance insuring against claims for bodily
injury (including death) and property damage to third parties arising out of
the ownership, operation, maintenance, condition and use of the applicable
leased facility and the related facility site, with limits of not less than
$100 million per occurrence with respect to the applicable leased facility.
Any liability insurance policy maintained by us or on our behalf will name
each of the owner participants, the owner lessors, the guarantor of the owner
participants, the owner managers, the indenture trustees and the pass through
trustees as additional insureds.
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All insurance proceeds up to $25 million on account of any damage to or
destruction of the leased facilities or any part thereof shall be paid to or
retained by us for application in repair of the affected property unless a
significant lease default or lease event of default has occurred and is
continuing. All insurance proceeds in excess of $25 million on account of any
such damage to, or destruction of, a leased facility and all insurance
proceeds in respect of an event of loss to a leased facility shall be paid to
the indenture trustee for application in accordance with the terms of the
related leases.
If any insurance required to be maintained by us ceases to be available on a
commercially reasonable basis at the time of renewal, we will enter into good
faith negotiations with each owner lessor in order to obtain an alternative to
such insurance.
Events of Loss
Any of the following events, by themselves, are events of loss under the
leases:
(a) the loss of any leased facility or use of the leased facility due to
destruction or damage to the leased facility or facility site rendering
repair uneconomic or rendering the leased facility permanently unfit for
normal use;
(b) any damage to any leased facility that results in an insurance
settlement on the basis of a total loss, an agreed constructive or a
compromised total loss of the leased facility;
(c) seizure, condemnation, confiscation or taking of, or requisition of
title to or use of, any leased facility or any facility site by any
governmental authority (following exhaustion of all permitted appeals or an
election by us not to pursue any appeals) that results in loss by the owner
lessor of title to or use of the undivided interest or the ground interest;
or
(d) if elected by the owner participant (only in circumstances where the
termination of the facility lease and transfer of the leased facility to us
shall remove the basis of the regulation described below), subjection of
(i) the applicable owner participant's, owner lessor's or guarantor of the
owner participant's interest in the applicable leased facility, lease or
the related operative documents to any rate-of-return regulation by any
governmental authority, or (ii) the owner participant, the owner lessor, or
the guarantor of the owner participant to any public utility regulation
which in the reasonable opinion of the owner participant is burdensome, in
either case by reason of the participation of the owner lessor, the owner
participant or the guarantor of the owner participant in the overall
transaction.
If we elect to terminate the lease following the occurrence of an event of
loss described in clauses (a) or (b) above, or upon the occurrence of any
other event of loss described in clauses (c) and (d) above, we will purchase
the owner lessor's undivided interest in the leased facility from the owner
lessor by paying the termination value plus certain other amounts, and the
owner lessor will prepay the outstanding principal of and accrued interest on
the related lessor notes, whereupon the lease will terminate.
Notwithstanding the foregoing, in the case of a regulatory event of loss, if
we assume the applicable lessor notes in accordance with the provisions of the
lease indenture, and so long as no significant lease default or lease event of
default has occurred and is continuing and certain other conditions are
satisfied, our obligation to pay the applicable termination value shall be
reduced by the outstanding principal amount of the lessor notes we assume, and
the applicable owner lessor shall have no further obligation to prepay the
outstanding principal and accrued interest on the lessor notes, it being
understood that by assuming these notes we shall acquire the undivided
interest subject to the lien of the indenture.
Furthermore, notwithstanding the foregoing, in the case of a regulatory
event of loss or a burdensome buyout event, if we choose, subject to the
satisfaction of certain conditions, to purchase all of the applicable member
interests of an owner lessor or all of the member interests of an owner
participant, so long as we remain liable under the applicable facility lease
to pay periodic lease rent, (i) we shall cease to have any liability to the
applicable owner participant with respect to the operative documents, except
for obligations surviving pursuant
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to the express terms of any operative document or which have otherwise accrued
but not been paid as of such date and (ii) the applicable member interests will
be transferred to us. However, if the lien of the applicable indenture has not
been terminated or discharged, such transfer shall not be made to us but shall
be made to our designee and such designee will agree not to transfer the
applicable member interests to us until such lien of the indenture is
discharged.
As an alternative to terminating the applicable lease following an event of
loss, if the event of loss results from one of the events described in clauses
(a) or (b) of the description of events of loss, we have the right to rebuild
or replace the affected leased facility. Our right to rebuild or replace a
leased facility will be subject to the satisfaction the following, among other
things:
. no significant lease default or lease event of default has occurred and
is continuing or will be created by the proposed rebuilding or
replacement;
. the applicable owner participant has received (i) reasonably
satisfactory legal opinions from its tax counsel to the effect that the
proposed rebuilding or replacement should not result in any incremental
risk of material adverse federal income tax consequences to the owner
participant and (ii) an indemnity against such risk in form and
substance reasonably satisfactory to such owner participant from or
guaranteed by an entity that has a credit rating of at least BBB from
S&P and at least Baa2 from Moody's (or, if such rating requirement is
not met, the owner participant will have received credit support in
respect of such indemnity reasonably satisfactory to it); provided that
if the opinion referred to in clause (i) will be that the rebuilding
"will" not result in any incremental risk of material adverse federal
income tax consequences to the owner participant, then the rating
requirement in clause (ii) shall not be required with respect to the
indemnity set forth in clause (ii);
. we will deliver reports of an independent engineer and an environmental
consultant to the effect that the rebuilding or replacement of the
leased facilities is technologically feasible and economically viable
and that it is reasonable to expect that the rebuilding or replacement
can be completed at least 36 months before the end of the basic lease
term or 12 months before the end of any renewal lease term then in
effect or elected by us;
. we will deliver an appraisal of an independent appraiser selected by us
and reasonably acceptable to the applicable owner participant to the
effect that the rebuilt or replaced leased facilities will have at least
the same current value, residual value, utility and useful life as the
leased facilities immediately prior to the event of loss and the
proposed rebuilding or replacement will not result in the leased
facilities being "limited use" property;
. no material adverse accounting effect has occurred or will result with
respect to the applicable owner participant;
. we will demonstrate that we possess adequate financial resources, from
insurance proceeds or otherwise, to complete the rebuilding of the
leased facilities and to pay periodic lease rent or renewal rent, as
applicable, while the leased facilities are being rebuilt and we will
deliver an officer's certificate to that effect to the applicable owner
participants and indenture trustee; and
. we shall commence the rebuilding as soon as practicable after we notify
the owner lessor and the indenture trustee of our intent and, in any
event, within 18 months of the occurrence of the event that caused the
event of loss and we will cause the work on the proposed rebuilding or
replacement to proceed diligently thereafter.
Any proceeds received by us or an owner lessor from a governmental authority
or from insurance proceeds related to an event of loss will be applied as
follows: (i) all such payments received by us shall be paid to the applicable
owner lessor or, so long as the lessor notes are outstanding, to the indenture
trustee, for application pursuant to the terms of the applicable facility
lease, except that, so long as no significant lease default or lease event of
default will have occurred and be continuing or will be created thereby, we may
retain any amounts that the applicable owner lessor would at the time be
obligated to pay to us as reimbursement (as described in clause (ii) of this
paragraph); (ii) so much of such payments as will not exceed the event of loss
payment required to be
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paid by us pursuant to the applicable facility lease will be applied in
reduction of our obligation to pay such amount if not already paid by us or, if
already paid by us, shall, so long as no significant lease default or lease
event of default will have occurred and be continuing or will be created
thereby, be applied to reimburse us for our payment of such amount; and (iii)
the remainder of these proceeds remaining thereafter shall be divided between
us and such owner lessor in accordance with our respective interests in that
leased facility. Notwithstanding the foregoing, if we have elected to rebuild
the leased facilities, such proceeds shall be applied as outlined above under
the section entitled "Insurance."
If any portion of the leased facilities or facility sites are requisitioned
or otherwise taken by a governmental authority under power of eminent domain or
otherwise in a manner which does not constitute an event of loss, our
obligation to pay rent shall continue for the duration of the requisitioning or
taking, but we shall be entitled to receive and retain any amounts payable as
compensation for such taking. However, if at the time of the requisition or
taking, a significant lease default or lease event of default has occurred and
is continuing, such amounts will be held by the owner lessors (or, if lessor
notes are outstanding, the indenture trustee) as security for our obligations
until such default has been cured.
If any of the leased facilities or any part thereof suffers any destruction,
damage, loss or theft not constituting an event of loss, we will rebuild or
make repairs that are necessary (i) to restore the leased facility to the
current value, residual value, utility and remaining useful life it had
immediately prior to that destruction, damage, loss or theft (assuming, for the
purposes of determining the current value, residual value, utility and
remaining useful life of the leased facility, that no severable improvements
that are not required improvements were made to that leased facility during the
lease term) and (ii) to ensure that the applicable leased facility is
maintained in accordance with the related facility lease and that such leased
facility does not become "limited use" property.
Defaults
Significant Lease Defaults. We refer to the occurrence of any of the
following events as a significant lease default.
(1) our failure to pay periodic lease rent, renewal rent or termination
value under a lease when due; or
(2) our failure to pay any other amounts due and payable under any of the
applicable operative documents (other than excepted payments, unless the
applicable owner participant has declared a default with respect to that
excepted payment) in excess of $500,000 except to the extent such amounts
are in dispute and have not been established to be due and payable; or
(3) any event or circumstance which is a lease event of default under
clause (iii), (iv), (vii), (viii) or (ix) of the section headed "Lease
Events of Default" immediately below (with the giving of notice or passage
of time); or
(4) if an owner participant owns the membership interest in more than one
owner lessor with respect to in the same leased facility, a significant
lease default or a lease event of default under any such other owner
lessor's lease.
Lease Events of Default. The occurrence of any of the following events
constitutes an event of default under each lease, which we refer to as a lease
event of default:
(i) our failure to make any payment when due (if we do not cure such
failure within five business days thereof) of any category of rent
or termination value; or
(ii) our failure to make any other payment under any other operative
document (other than excepted payments, unless the applicable owner
participant has declared a default with respect to that excepted
payment) when due, if we fail to cure such failure within 30 days
after receiving written notice thereof; or
(iii) our failure to maintain insurance in the amounts and on the terms
set forth in the operative documents; or
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(iv) our failure to perform or observe in all material respects (a) the
covenants described under the captions "Merger, Consolidation or
Sale of Substantially All Assets", "Sale of Assets", "Limitation on
the Incurrence of Indebtedness", "Limitations on Restricted
Payments", or "Credit Support" in the "Description of
Certificates--Covenants" section of this prospectus or (b) if such
failure is in respect of any borrowed money, the covenant described
under the caption "Restrictions on Liens"; or
(v) our failure to perform or observe any other covenant set forth in
the leases or any covenant set forth in the participation agreement
or in any other operative document (other than any of the covenants
referred to in clauses (i), (ii), (iii) or (iv) of this paragraph)
in any material respect and we do not cure such failure within 30
days after receiving written notice thereof. If such failure cannot
be remedied within that 30-day period, then we shall have up to an
additional 180 days to remedy the failure, so long as (i) we
diligently pursue such remedy and (ii) such failure is reasonably
capable of being remedied within such additional 180-day period.
However, in the case of our obligation to maintain the leased
facilities, to the extent we are contesting in good faith such non-
compliance, (so long as such contest extends no longer than 36
months beyond the scheduled lease term expiration) our failure to
comply with the requirements thereof will not constitute a lease
event of default so long as our contest does not expose the leased
facilities to material risk of forfeiture or loss, or expose a
lease financing party to risk of criminal liability, material risk
of regulation as a public utility, or other material adverse
effects. If such noncompliance is not a type that can be
immediately remedied, our failure to comply will not be a lease
event of default if we are taking all reasonable action to remedy
such noncompliance and if, but only if, such noncompliance shall
not involve any of the risks to the leased facilities or lease
financing parties just described; or
(vi) any of our representations or warranties in the operative documents
(other than a tax representation set forth in the tax indemnity
agreement) proves to have been incorrect in any material respect
when made and continues to be material and the circumstances giving
rise to such misrepresentation is based continue to be unremedied
for a period of 30 days after we receive written notice thereof.
However, if such condition cannot be remedied within 30 days but
could reasonably be remedied within 120 additional days, and we
diligently pursue a remedy during such time, then the cure period
shall be extended by up to an additional 120 days; or
(vii) we, or any of the designated subsidiaries, voluntarily commence or
have instituted against us or the designated subsidiary, as
applicable, bankruptcy proceedings, or consent to any such relief
or the appointment of or taking possession by any such official in
any voluntary case or other proceeding commenced against us or the
designated subsidiaries, as applicable, or if we, or any of the
designated subsidiaries, file an answer admitting the material
allegations of a petition filed against us or the designated
subsidiary, as applicable, in any such proceeding, or if we, or any
of the designated subsidiaries, make a general assignment for the
benefit of creditors, or we, or any of the designated subsidiaries,
are wound up or dissolved, or, in the instance of involuntary
proceedings, such case remains undismissed for 60 days; or
(viii) we default under any bond, debenture, note or other evidence of
indebtedness (but excluding obligations arising under the operative
documents and non-recourse indebtedness) for money borrowed by us
under any mortgage, indenture or instrument, whether such
indebtedness now exists or shall hereafter be created, which
indebtedness is in an aggregate principal amount exceeding
$50 million (as escalated annually based upon the consumer price
index) and which default shall have resulted in such indebtedness
becoming or being declared due and payable prior to the date on
which it would otherwise have become due and payable, without such
indebtedness having been discharged, or such acceleration having
been rescinded or annulled; or
(ix) failure by us to comply with restrictions on assignment described
under the caption "Description of the Leases and other Loan
Documents--Sublease and Assignment--Assignment" or subleases
described under the caption "Description of the Leases and Other
Lease Documents--Sublease and Assignment--Sublease;" or
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(x) Mirant fails to make any payment under the capital contribution
agreement, Mirant Potomac River fails to make any payment under
its note to us, or Mirant Peaker fails to make any payment under
its note to us, when due, and such failure continues unremedied
for ten business days after receipt by Mirant, Mirant Potomac
River, or Mirant Peaker, as the case may be, of written notice of
that failure; or
(xi) Mirant fails to perform or observe any other material covenant
set forth in the capital contribution agreement and that failure
continues unremedied for 30 days after receipt by Mirant of
written notice thereof; provided, that if that failure cannot be
remedied within the 30-day period, then the period within which
to remedy that failure will be extended up to an additional 180
days, so long as Mirant diligently pursues that remedy and the
failure is capable of being remedied within the additional 180-
day period; or
(xii) any representation or warranty of Mirant set forth in the capital
contribution agreement proves to have been incorrect in any
material respect when made and continues to be material and the
circumstances upon which that breach of representation or
warranty is based continue to be material and unremedied for a
period of 30 days after receipt by Mirant of written notice
thereof from the applicable owner participant, owner lessor,
lease indenture trustee or any pass through trustee; provided,
that if such condition cannot be remedied within such 30-day
period, then the period within which to remedy such condition
shall be extended by up to an additional 120 days, so long as
Mirant diligently pursues such remedy, such condition is
reasonably capable of being remedied within such additional 120-
day period; or
(xiii) a change of control, as defined below, occurs; or
(xiv) any material operative document to which we or any of our
affiliates is a party is declared unenforceable against us or any
of our affiliates, is terminated by us or any of our affiliates,
or ceases to be in full force and effect in respect of us or any
of our affiliates (in each case, other than in accordance with
their terms); or
(xv) any lien on a material portion of the indenture estate created in
favor of the indenture trustee ceases to be enforceable or ceases
to be of the same effect and priority purported to be created
thereby.
"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
. our parent, Mirant, or any of its successors into which Mirant has
consolidated or merged or any person to which Mirant 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 Mirant or any other person
described in the first bullet point above; or
. any direct or indirect subsidiary of Mirant, or any other person
described in the two bullet points above,
becoming the beneficial owner, directly or indirectly, of more than 50% of our
voting power, or acquiring, by contract or otherwise, the power to direct or
cause the direction of our management or policies. A change of control will
not be deemed to have occurred if Moody's and S&P confirm that the then
existing ratings of the certificates will not be lowered as a result of any of
these events.
If any of the events described in this definition of change of control
occurs, but such event is not deemed a change of control because Moody's and
S&P confirm that the then existing ratings of the certificates will not be
lowered as a result of such event, we will amend the definition of "Mirant" in
the leases to mean the entity or entities Moody's and S&P relied upon in
confirming the then existing ratings of the certificates.
In addition, if:
. any person (other than Southern Company) becomes a beneficial owner,
directly or indirectly, of more than 50% of the voting power of Mirant;
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. Mirant merges into or consolidates with another entity and Mirant is not
the surviving entity; or
. Mirant transfers all or substantially all of its assets to another
person,
the definition of "Mirant" in the leases will be amended to refer to the
person so acquiring more than 50% of the voting power of Mirant, such
surviving entity or such transferee, as applicable.
Upon the occurrence and continuance of any lease event of default, the
applicable owner lessor may declare the lease to be in default by written
notice delivered to us (provided, that the applicable lease will automatically
be in default without the need for written notice upon the occurrence of a
lease event of default described in clause (vii) above). Except as provided
below, such owner lessor may, at any time thereafter, so long as we have 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 our obligations under such lease and the
other applicable operative documents by appropriate court actions,
either at law or equity, or recover damages for breach thereof;
. terminating such lease, whereupon we shall be required to return
possession of the owner lessor's undivided interest, and our right to
the possession and use of such interest under such lease will absolutely
cease and terminate, but we will remain liable as provided in such
lease;
. selling the applicable undivided interest and ground interest at public
or private sale, free and clear of our rights; or
. holding, keeping idle or leasing to others the applicable undivided
interest and ground interest, free and clear of our rights under such
lease.
Upon the occurrence and continuance of any lease event of default, whether
or not the applicable owner lessor has sold its interest in the applicable
undivided interest and ground interest, such owner lessor may require us to
pay any unpaid periodic lease rent, or renewal rent, as applicable, due and
payable as of the termination date specified in such notice, plus as
liquidated damages for loss of a bargain and not as a penalty (in lieu of the
periodic lease rent, or renewal rent, as applicable, due after the termination
date specified in such notice), (i) an amount equal to the excess, if any, of
the termination value over the fair market value of the applicable undivided
interest and ground interest, as of such termination date; (ii) an amount
equal to the excess, if any, of the termination value computed as of such
termination date over the present value of the fair market rental value of
such owner lessor's interest in the undivided interest and ground interest
during the fixed lease term or the then current renewal lease term; or (iii)
an amount equal to the termination value computed as of such termination date
(which, together with the other amounts payable in connection therewith, will
be at least sufficient to pay the outstanding principal of and accrued
interest on the applicable lessor notes). Upon payment of the amount referred
to in clause (iii), such owner lessor will then use its commercially
reasonable efforts promptly to sell its undivided interest at public or
private sale and will pay to us upon consummation of any such sale the net
proceeds of that sale (after deducting all costs and expenses incurred by the
owner lessor in connection with the sale and all other amounts that may become
payable to the owner lessor, or the related indenture trustee or owner
participant). We have waived all claims against the applicable owner lessor
and the related owner participant in connection with the sale of the undivided
interest. However, in lieu of paying an amount equal to the termination value
pursuant to clause (iii) above, we may make a rejectable offer in writing to
the applicable owner lessor to purchase its undivided interest at a purchase
price equal to or greater than termination value. If the owner lessor rejects
our offer in writing, we will remain liable to pay termination value, but we
will have no obligation to pay the costs and expenses incurred by the owner
lessor solely in connection with any sale of the undivided interest and the
owner lessor will proceed to exercise its best efforts promptly to sell its
undivided interest at public or private sale and will pay to us upon
consummation of any such sale the proceeds of that sale, but not to exceed the
sum of termination value paid by us plus interest from the termination date
until the date such proceeds are paid to us. If we make an offer in accordance
with this paragraph and the owner lessor accepts that offer or fails to
respond to that offer within two business days prior to the date we are
required to pay termination value pursuant to clause (iii) above, we will pay
to the owner lessor the amount of that offer on or before the termination
date. Upon payment of that amount and all other rent then due and unpaid, or
accrued and unpaid,
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by us, we will no longer be liable to pay termination value or other amounts
pursuant to clause (iii) above and the owner lessor will then convey its
interests in the applicable undivided interest and ground interest to us.
Upon the occurrence and continuance of any lease event of default and if the
applicable owner lessor has sold its interest in the applicable undivided
interest and ground interest, such owner lessor may require us to pay as
liquidated damages for loss of a bargain and not as a penalty (in lieu of the
periodic lease rent, or renewal rent, as applicable, due for any period after
such sale) an amount equal to (i) any unpaid periodic lease rent due, or
renewal rent, as applicable, and unpaid, or accrued and unpaid, before the
date of such sale, plus (ii) the amount, if any, by which the termination
value computed as of the termination date next preceding the date of such sale
or, if such sale occurs on a rent payment date or a termination date then
computed as of such date, exceeds the net proceeds of such sale. Upon payment
of such amount, the facility lease and our obligation to pay periodic rent for
any periods subsequent to the date of such payment shall terminate.
Owner Lessor's Right to Perform. If we fail to make any payment under a
lease or perform or comply with any other obligations under a lease and such
failure continues for 10 business days after notice thereof, the applicable
owner lessor or owner participant may itself make such payment or perform or
comply with such obligation, and amounts so paid shall be deemed supplemental
lease rent payable by us to the owner lessor on demand.
Modification of Operative Documents
An indenture trustee may, without the consent of any pass through trustee,
enter into any indenture or indentures supplemental to the applicable lease
indenture or execute any amendment, modification, supplement, waiver or
consent with respect to any other operative document related thereto to do any
of the following:
. to evidence and provide for the acceptance of appointment of a successor
indenture trustee under the applicable lease indenture and to add to or
change any of the provisions of that lease indenture as necessary to
provide for or facilitate the administration by more than one indenture
trustee;
. evidence the succession of another person as owner manager or the
appointment of a co-owner manager;
. correct, confirm or amplify the description of any property at any time
subject to the lien of the lease indenture or to convey, transfer,
assign, mortgage or pledge any property or assets to the indenture
trustee as security for the lessor notes;
. provide for any evidence of the creation and issuance of any additional
lessor notes in accordance with the lease indenture and to establish the
form or terms of those lessor notes;
. cure any ambiguity in, to correct or supplement any defective or
inconsistent provision of, or to add to or modify any other provisions
and agreements in, such lease indenture, or any other operative document
related thereto, in any manner that will not in the judgment of the
indenture trustee materially adversely affect the interests of the
holders of the lessor notes;
. grant or confer upon the indenture trustee for the benefit of the
holders of the related lessor notes any additional rights, remedies,
powers, authority or security which may be lawfully granted or conferred
and which are not contrary or inconsistent with such lease indenture;
. add to the covenants to be observed by the owner lessor and which are
not contrary to such lease indenture, to add lease indenture events of
default for the benefit of the holders of the related lessor notes or
surrender any right or power of the applicable owner lessor;
. effect the assumption of any or all of the lessor notes by us; so long
as the supplemental indenture will contain all of our covenants
contained in the related lease and the related participation agreement
for the benefit of the indenture trustee or the holders of the lessor
notes issued under the indenture, such that our obligations contained
therein, if applicable in the event that the related leases are
terminated, will continue to be in full force and effect; or
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. effect any other amendment, modification, supplement, waiver or consent
with respect to such indenture or any other operative document related
thereto provided that such amendment, modification, supplement, waiver
or consent will not, in the judgment of the indenture trustee,
materially adversely affect the interest of the holders of such lessor
notes.
Notwithstanding the foregoing, no such amendment, modification, supplement,
waiver or consent will, without the consent of the holders of a majority in
interest of such lessor notes, modify the covenants set forth in this
prospectus under the captions "Description of the Certificates--Covenants--
Restriction on Liens," "--Merger, Consolidation or Sale of Substantially All
Assets," "--Restriction on Liens," "--Sale of Assets," "--Maintenance of
Existence and Properties," "--Maintenance of Tax Status," "--Insurance," "--
Limitations on Incurrence of Indebtedness," "--Limitations on Incurrence of
Indebtedness by Designated Subsidiaries" and "--Limitations on Restricted
Payments" and the provisions described under the caption "The Leases--Sublease
and Assignment," other than modifications having no adverse effect on the
interests of the holders of such lessor notes.
In addition, to the extent not expressly permitted by the preceding two
paragraphs, an indenture trustee, with the consent of the holders of a
majority in interest of the related lessor notes, may enter into any indenture
or indentures supplemental to the applicable lease indenture or execute any
amendment, modification, supplement, waiver or consent with respect to any
operative document related thereto.
However, no such supplement to or amendment of such indenture or the related
lease, site lease and sublease, or waiver or modification of or consent to the
terms thereof will, without the consent of the holders representing 100% of
the outstanding principal amount of such lessor notes, do any of the
following:
(1) reduce the percentage of holders of such lessor notes required to
take or approve any action thereunder;
(2) change the amount or the time of payment of any amount owing or
payable with respect to any such lessor note or change the rate or manner
of calculation of interest payable with respect to any such lessor note;
(3) alter or modify the provisions with respect to the manner of payment
or the order of priorities in which distributions thereunder will be made
as between the holders of such lessor notes and the related owner lessor;
(4) reduce the amount (except to any amount as will be sufficient to pay
the aggregate principal of, make-whole premium, if any, and interest on all
such lessor notes) or extend the time of payment of periodic lease rent or
termination value, except as expressly provided in the related lease, or
change any of the circumstances under which periodic lease rent or
termination value is payable;
(5) consent to any assignment of the related lease if in connection
therewith we will be released from our obligation to pay periodic lease
rent and termination value, except as expressly provided herein, or
otherwise release us of our obligations in respect of the payment of
periodic lease rent or termination value or change the absolute and
unconditional character of such obligations; or
(6) deprive the indenture trustee of the lien on a material portion of
the indenture estate or permit the creation of any lien on a material
portion of the indenture estate ranking equally or prior to the lien of the
indenture trustee except permitted liens.
If the pass through trustee, as the holder of the lessor notes in trust for
the benefit of the certificate holders, receives a request for its consent to
any amendment, modification, waiver or supplement under any lease indenture,
lease or other related operative document, the pass through trustee will mail
a notice of, such proposed amendment, modification, waiver or supplement to
each certificate holder of such pass through trust of record as of the date of
such notice. The pass through trustee shall request from the certificate
holders of such pass through trust directions as to (i) whether or not to
direct the indenture trustee to take or refrain from taking any action which a
holder of such lessor note has the option to direct, (ii) whether or not to
give or execute any waivers,
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consents, amendments, modifications or supplements as a holder of such lessor
note, and (iii) how to vote any lessor note if a vote has been called for with
respect thereto. The pass through trustee shall vote or consent with respect
to the lessor notes held in the related pass through trust in the same
proportion as the certificates were actually voted by the certificate holders
of such pass through trust by the date specified in such notice.
Notwithstanding the foregoing, if an event of default has occurred and is
continuing, the pass through trustee, subject to the voting instructions
referred to under "Description of the Certificates--Events of Default and
Certain Rights Upon an Event of Default," may in its own discretion consent to
such amendment, modification, waiver or supplement, and may so notify the
indenture trustee.
Site Leases and Site Subleases
We will lease the ground interests to the owner lessors pursuant to four
separate facility site lease and easement agreements in respect of the
Dickerson leased facility and seven separate facility site lease and easement
agreements in respect of the Morgantown leased facility, which we refer to
collectively as the facility site leases and each, as a facility site lease.
The owner lessors will, in turn, sublease the facility sites back to us
pursuant to four separate facility site sublease agreements in respect of the
Dickerson leased facility and seven separate facility site sublease agreements
in respect of the Morgantown leased facility, which we refer to collectively
as the facility site subleases and each, as a facility site sublease.
Term and Rent. The term of each facility site lease for the Dickerson leased
facility, which we will refer to as the basic facility site lease term,
commenced on December 19, 2000, and will continue for a period of 38 years.
The term of each facility site lease for the Morgantown leased facility
commenced on December 19, 2000, and will continue for a period of 45 years.
The owner lessors have the right to renew each facility site lease for one or
more renewal site lease terms. We refer to the basic facility site lease terms
plus all renewal facility site lease terms for each facility site lease as its
facility site lease term. The term of each facility site sublease with respect
to a particular leased facility is coterminous with the term of each lease
with respect to that facility. Each facility site sublease with respect to a
particular facility terminates upon the termination of the corresponding
lease, and is renewed upon the renewal of that lease. We will refer to the
basic facility site sublease terms plus all renewal facility site sublease
terms as the site sublease terms.
During the facility site sublease terms, the rent payable under each
facility site lease and the rent payable under each facility site sublease
will be automatically offset one against the other, such that no amounts will
be payable by us or the owner lessors in respect thereof.
Rights Reserved by Us. We will reserve the right, from time to time, to use
the ground interest in connection with the development, construction, use,
operation and maintenance of any buildings, facilities (other than the leased
facilities), improvements or other structures on the facility sites,
including, the right to construct, install, operate, use, repair and relocate
buildings, facilities (other than the leased facilities), improvements and
structures on the facility sites, provided that such work does not have a
material adverse affect on the use or operation of the leased facilities.
Reciprocal Easements. We will grant to the owner lessors certain non-
exclusive easements over certain portions of land retained by us and not
subject to the facility site leases where required to enable the owner lessors
to access, use and operate the leased facilities and the owner lessors will
grant to us certain easements over certain portions of the facility sites
where required to enable us to access, use and operate the land and facilities
retained by us and not subject to the facility site leases.
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CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES
The following is a summary of certain U.S. federal income tax consequences
associated with the exchange of original certificates for new certificates,
and the ownership and disposition of new certificates by holders who acquire
new certificates in the exchange offer. The discussion is based upon the
Internal Revenue Code of 1986, as amended (the "Code"), Treasury Regulations,
judicial authorities, published positions of the Internal Revenue Service (the
"IRS") and other applicable authorities, all as in effect on the date hereof
and all of which are subject to change or differing interpretations (possibly
with retroactive effect).
The discussion does not address all of the tax consequences that may be
relevant to a particular holder or to holders subject to special treatment
under federal income tax laws (including banks and certain other financial
institutions, insurance companies, tax-exempt organizations, persons whose
functional currency is not the U.S. dollar, foreign persons, dealers in
securities or foreign currency, and persons holding certificates that are a
hedge against, or that are hedged against, currency risk or that are part of a
straddle, constructive sale or conversion transaction). This discussion is
limited to persons who acquire certificates in the initial offering at the
initial offering price and who hold their certificates as capital assets. No
ruling has been or will be sought from the IRS regarding any matter discussed
herein. No assurance can be given that the IRS would not assert, or that a
court would not sustain, a position contrary to any of the tax aspects set
forth below. Prospective investors must consult their own tax advisers as to
the federal income tax consequences of acquiring, holding and disposing of
certificates as well as the effects of state, local and non-U.S. tax laws.
For purposes of this discussion, you are a "U.S. certificate holder" if you
are a beneficial owner of a certificate and
. a citizen or resident of the United States,
. a corporation, partnership or other entity created or organized in or
under the laws of the United States or any political subdivision
thereof,
. an estate whose income is includable in gross income for U.S. federal
income tax purposes regardless of source, or
. a trust, if (1) a court within the United States is able to exercise
primary supervision over the administration of the trust and one or more
U.S. persons have the authority to control all substantial decisions of
the trust, or (2) the trust was in existence on August 20, 1996 and
properly elected to continue to be treated as a U.S. person.
Otherwise, you are a "non-U.S. certificate holder."
Exchange of Original Certificates
There should be no federal income tax consequences to holders who exchange
original certificates for new certificates pursuant to this exchange offer.
Any such holder should have the same tax basis and holding period in the new
certificates that such holder had in its original certificates immediately
before the exchange.
Tax Treatment of the Pass Through Trusts and Certificate Holders
Each pass through trust that is operated according to the applicable pass
through trust agreement will not itself be subject to U.S. federal income
taxation. Instead, each U.S. certificate holder will be required to report on
its federal income tax return its pro rata share of the entire income from the
lessor notes and any other property held in the pass through trust, in
accordance with the U.S. certificate holder's method of accounting.
Accordingly, each U.S. certificate holder's share of interest paid on the
lessor notes will be taxable as ordinary income, as it is paid or accrued, and
a U.S. certificate holder's share of any premium paid on redemption of a
lessor note will be treated as capital gain. The lessor notes will not be
subject to the original issue discount rules due to the possibility that a
make-whole premium may be payable because the likelihood of such premium being
paid is remote, and the amount of such premium, if paid, would be incidental.
If the proceeds from the sale of
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certificates are held pursuant to an escrow arrangement prior to the purchase
of lessor notes by the pass through trust, each U.S. certificate holder's
share of interest paid on the resulting deposits will be taxable as ordinary
income as it is paid or accrued in accordance with the holder's method of
accounting for U.S. federal income tax purposes. In addition, the deposits may
be subject to the original issue discount rules, with the result that a U.S.
certificate holder may be required to include any original issue discount in
income from a deposit using the accrual method of accounting regardless of its
normal method. We urge you to consult your own tax advisor.
Each U.S. certificate holder will be entitled to deduct, consistent with its
method of accounting, its pro rata share of fees and expenses paid or incurred
by the pass through trust as provided in Section 162 or 212 of the Code.
Although we anticipate that certificate holders will not bear these fees and
expenses, these fees and expenses could be treated as constructively received
by the pass through trust, in which event a U.S. certificate holder could be
required to include in income and be entitled to deduct its pro rata share of
the fees and expenses. If a U.S. certificate holder is an individual, estate
or trust, the deduction for the certificate holder's share of fees or expenses
will be allowed only to the extent that all of the certificate holder's
miscellaneous itemized deductions, including the certificate holder's share of
fees and expenses, exceed 2% of the certificate holder's adjusted gross
income. In addition, in the case of U.S. certificate holders who are
individuals, certain otherwise allowable itemized deductions will generally be
subject to additional limitations on itemized deductions under applicable
provisions of the Code.
Sale or Other Disposition of the Certificates
Upon the sale, exchange or other disposition of a certificate, a U.S.
certificate holder will generally recognize capital gain or loss equal to the
difference between the amount realized on the sale or exchange (other than any
amount attributable to accrued but unpaid interest that the U.S. certificate
holder has not included in gross income previously, which will be taxable as
ordinary income) and the U.S. certificate holder's allocable share of tax
basis in the trust's property attributable to such certificate. Any gain or
loss will be long-term capital gain or loss, to the extent (i) the certificate
holder held its certificate for more than one year, and (ii) the property to
which the gain or loss is allocable was held by the pass through trust for
more than one year. In the case of individuals, estates, and trusts, the
maximum U.S. federal income tax rate on long-term capital gains generally is
20%.
The foregoing discussion of U.S. federal income tax consequences assumes
that each pass through trust is properly classified under the Code as a
grantor trust. If, however, a pass through trust were not classified as a
grantor trust, it would be classified as a partnership and not as an
association or publicly traded partnership taxable as a corporation; the
consequences described above would generally apply to a U.S. certificate
holder, except that (i) items of income, gain, loss or deduction from the
assets held by the pass through trust would generally be determined at the
pass through trust level (ii) a U.S. certificate holder would be required to
report its share of items of income, gain, loss and deduction of the pass
through trust on its tax return for the taxable year within which the pass
through trust's taxable year ends and (iii) income, gain, loss and deduction
would be reported on an accrual basis even if the U.S. certificate holder
otherwise uses the cash method of accounting.
Non-U.S. Certificate Holders
Assuming certain certification requirements are satisfied (which include
identification of the beneficial owner of a certificate), and subject to the
discussion of backup withholding below:
. interest paid (including any original issue discount) on a certificate
to, or on behalf of, any non-U.S. certificate holder will not be subject
to U.S. federal income tax or withholding tax, provided that (i) the
non-U.S. certificate holder does not actually or constructively own 10%
or more of the total combined voting power of all classes of stock of an
owner participant, (ii) the non-U.S. certificate holder is not (A) a
bank receiving interest pursuant to a loan agreement entered into in the
ordinary course of its trade or business, or (B) a controlled foreign
corporation for U.S. tax purposes that is related to an owner
participant, and (iii) the interest payments are not effectively
connected with the non-U.S. certificate holder's conduct of a U.S. trade
or business; and
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. a non-U.S. certificate holder will not be subject to U.S. federal income
tax on any capital gain realized on the sale, exchange or other
disposition of a certificate, unless (i) the non-U.S. certificate holder
is an individual who is present in the United States for 183 days or
more during the taxable year of the sale or exchange and certain other
requirements are met or (ii) the gain is effectively connected with the
non-U.S. certificate holder's conduct of a U.S. trade or business.
The certification referred to above may be made on an IRS Form W-8 BEN (or
any successor form prescribed by the IRS) or substantially similar substitute
form.
Information Reporting and Backup Withholding
In general, information reporting requirements will apply to certain
payments within the United States of principal, interest, original issue
discount and premium on the certificates, and to payments of the proceeds of
certain sales of certificates made to U.S. certificate holders other than
certain exempt recipients (such as corporations). A 31% backup withholding tax
may apply to the payments if the holder fails or has failed to provide an
accurate taxpayer identification number in the manner required by the Treasury
Regulations (generally on IRS Form W-9) or otherwise establish an exemption or
fails to report in full interest income. With respect to non-U.S. certificate
holders, payments made on a certificate and proceeds from the sale of a
certificate owned by a non-U.S. certificate holder will generally not be
subject to information reporting requirements or the backup withholding tax if
the non-U.S. certificate holder provides the required certification of its
non-U.S. status or otherwise establishes an exemption.
Backup withholding is not an additional tax. Any amounts withheld under the
backup withholding rules will be allowed as a refund or credit against the
certificate holder's U.S. federal income tax liability, if any, provided the
required information is furnished to the IRS.
THE FOREGOING DISCUSSION IS NOT INTENDED TO BE A COMPLETE ANALYSIS OR
DESCRIPTION OF ALL POTENTIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES OR
ANY OTHER CONSEQUENCES OF ACQUIRING, HOLDING OR DISPOSING OF CERTIFICATES.
THUS, HOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS AS TO THE SPECIFIC
TAX CONSEQUENCES OF ACQUIRING, HOLDING AND DISPOSING OF CERTIFICATES,
INCLUDING TAX RETURN REPORTING REQUIREMENTS, THE APPLICABILITY AND EFFECT OF
FEDERAL, STATE, LOCAL, FOREIGN AND OTHER APPLICABLE TAX LAWS AND THE EFFECT OF
ANY PROPOSED CHANGES IN THE TAX LAWS.
133
ERISA CONSIDERATIONS
In this prospectus, we will refer to the Employee Retirement Income Security
Act of 1974 as ERISA. If you intend to use plan assets (as discussed below) to
purchase certificates, you should consult your counsel about the potential
consequences of such investment under the fiduciary responsibility provisions
of ERISA and the prohibited transactions provisions of ERISA and the Code.
For the purposes of this discussion, we will refer to employee benefit
plans, certain other retirement plans and arrangements, including individual
retirement accounts and annuities, and any entity holding the assets of any
such plan, account, or annuity, such as a bank common investment fund or an
insurance company general or separate account, as the "plans." Generally, a
person who exercises discretionary authority or control over the assets of a
plan will be considered a fiduciary of the plan under ERISA. Before investing
in a certificate, a plan fiduciary should determine whether such investment is
permitted under the plan documents and the instruments governing the plan and
is appropriate for the plan in view of its overall investment policy and the
composition and diversification of its portfolio. In making this
determination, the plan fiduciary should take into account the limited
liquidity of the certificates.
ERISA and the Code prohibit a wide range of transactions involving the plan
assets and persons who have certain specified relationships to the plan such
as "parties in interest" within the meaning of ERISA or "disqualified persons"
within the meaning of the Code. Thus, a plan fiduciary considering an
investment in the certificates should also determine whether such investment
might constitute or give rise to a non-exempt prohibited transaction under
ERISA or the Code. Further, an investment in the certificates by a plan might
result in the lessor notes of the related pass through trust being deemed to
constitute "plan assets." In such case, the operation of the pass through
trust might give rise to one or more non-exempt prohibited transactions under
ERISA or the Code. Moreover, the plan fiduciary might be deemed to have
improperly delegated its investment management responsibilities with respect
to those assets of the pass through trust deemed to be plan assets to the pass
through trustee.
Neither ERISA nor the Code provides a comprehensive definition of the term
"plan assets." According to Section 2510.3-101 of the United States Department
of Labor regulations, in general, when a plan acquires an equity interest in
an entity and 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, the plan's assets include both the equity interest and
the undivided interest in each of the underlying assets of the entity, unless
it is established that either the entity is an "operating company" or the
plan's equity participation in the entity is not "significant."
In general, the DOL regulations define an "equity interest" as any interest
in an entity other than an instrument that is treated as indebtedness under
applicable local law and that has no substantial equity features. We believe
that the DOL regulations will treat the certificates as equity interests in
the pass through trusts.
A plan's participation in the certificates would not be "significant" if,
immediately after the most recent acquisition of the certificates, less than
25% of the value of the certificates is held by the plans, certain other
employee benefit plans not subject to Title I of ERISA, and certain entities
whose underlying assets include plan assets by reason of a plan's investment
in the entity, all as determined under the DOL regulations. If the
participation is not "significant," the plan assets would not include the
undivided interest in each of the underlying assets of the entity.
Ownership of the certificates will not be restricted or monitored. Plans,
certain other plans not subject to ERISA and certain other entities may hold
25% or more of the certificates during the term of the certificates.
Accordingly, under the DOL regulations, a plan investment in the certificates
during the period such holdings equal or exceed 25% would, in effect, be
considered an investment in the corresponding lessor notes and an ongoing loan
to the owner lessors for purposes of the fiduciary responsibility provisions
of ERISA and the prohibited transaction provisions of ERISA and the Code.
Therefore, if any of the assets of a pass through trust
134
are considered plan assets, a plan's investment in the certificates could
result in a prohibited transaction or an impermissible delegation of
authority.
Further, one or more of the initial purchasers, the pass through trustee, we
or any of our respective affiliates may be a party in interest or a
disqualified person with respect to the plan acquiring, holding or disposing
of the certificates. In such case, acquisition, holding or disposition of the
certificates could give rise to a direct or indirect prohibited transaction,
regardless of whether the assets of a pass through trust are considered plan
assets.
A prohibited transaction may be exempt under ERISA and the Code if the
certificates were acquired, held or disposed of in accordance with one or more
statutory or administrative exemptions. Among the administrative Prohibited
Transaction Class Exemptions or "PTCEs":
1. PTCE 75-1 exempts certain transactions involving employee benefit
plans and registered broker-dealers, such as the initial purchasers, and
certain reporting dealers and banks;
2. PTCE 84-14 exempts certain transactions involving an independent
qualified professional asset manager;
3. PTCE 90-1 exempts certain transactions involving insurance company
pooled separate accounts;
4. PTCE 91-38 exempts certain transactions involving bank collective
investment funds;
5. PTCE 95-60 exempts certain transactions involving insurance company
general accounts; and
6. PTCE 96-23 exempts certain transactions involving a qualified in-house
asset manager.
Some of the exemptions, however, do not afford relief from the prohibitions
on self-dealing contained in Section 406(b) of ERISA and Section
4975(c)(1)(E)-(F) of the Code. In addition, there can be no assurance that any
of these administrative exemptions will be available with respect to any
particular transaction involving the certificates. Thus, a plan fiduciary
considering an investment in the certificates should consider whether the
acquisition, the continued holding, or the disposition might constitute or
give rise to a non-exempt prohibited transaction.
ERISA also prohibits a plan fiduciary from maintaining the indicia of
ownership of any plan assets outside the jurisdiction of the district courts
of the United States, except under certain circumstances. Before investing in
a certificate, a plan fiduciary should consider whether its acquisition,
holding or disposition of a certificate would satisfy such indicia of
ownership rules.
Each person (other than the initial purchasers) who acquires or accepts a
certificate will be deemed by such acquisition or acceptance to have
represented and warranted that either (i) no plan assets have been used to
acquire such certificate; or (ii) the acquisition and holding of such
certificate do not constitute a prohibited transaction under ERISA and the
Code or are exempt from the prohibited transaction restrictions of ERISA and
the Code according to one or more Prohibited Transaction Class Exemptions.
A plan fiduciary and each fiduciary for a governmental or church plan
subject to rules similar to those imposed on plans under ERISA considering the
purchase of certificates should consult its tax and/or legal advisors
regarding the circumstances under which the assets of a pass through trust
would be considered plan assets, the availability, if any, of exemptions from
any potential prohibited transaction and other fiduciary issues and their
potential consequences.
135
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC set forth in no-action
letters issued to third parties, we believe that the new certificates may be
offered for resale, resold and otherwise transferred by you without compliance
with the registration and prospectus delivery requirements of the Securities
Act provided that:
. you acquire any new certificate in the ordinary course of your business;
. you are not participating, do not intend to participate, and have no
arrangement or understanding with any person to participate, in the
distribution of the new certificates;
. you are not a broker-dealer who purchased outstanding certificates
directly from us for resale pursuant to Rule 144A or any other available
exemption under the Securities Act; and
. you are not an "affiliate" (as defined in Rule 405 under the Securities
Act) of our company.
If our belief is inaccurate and you transfer any new certificate without
delivering a prospectus meeting the requirements of the Securities Act or
without an exemption from registration of your certificates from these
requirements, you may incur liability under the Securities Act. We do not
assume any liability or indemnify you against any liability under the
Securities Act.
Each broker-dealer that receives new certificates for its own account
pursuant to this exchange offer must acknowledge that it will deliver a
prospectus in connection with any resale of such new certificates. This
prospectus, as it may be amended or supplemented from time to time, may be
used by a broker-dealer in connection with resales of new certificates
received in exchange for existing certificates where such existing
certificates were acquired as a result of market-making activities or other
trading activities. We have agreed that, for a period of 180 days after the
expiration date, we will make this prospectus, as amended or supplemented,
available to any broker-dealer for use in connection with any such resale. In
addition, until October 4, 2001, all dealers effecting transactions in the new
certificates may be required to deliver a prospectus.
We will not receive any proceeds from any sale of new certificates by
broker-dealers. New certificates received by broker-dealers for their own
account pursuant to this exchange offer may be sold from time to time in one
or more transactions in the over-the-counter market, in negotiated
transactions, through the writing of options on the new certificates or a
combination of such methods of resale, at market prices prevailing at the time
of resale, at prices related to such prevailing market prices or negotiated
prices. Any such resale may be made directly to purchasers or to or through
brokers or dealers who may receive compensation in the form of commissions or
concessions from any such broker-dealer or the purchasers of any such new
certificates. Any broker-dealer that resells new certificates that were
received by it for its own account pursuant to this exchange offer and any
broker or dealer that participates in a distribution of such new certificates
may be deemed to be an "underwriter" within the meaning of the Securities Act
and any profit on any such resale of new 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 be deemed to admit that it is an "underwriter" within
the meaning of the Securities Act.
For a period of 180 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 this exchange
offer (including the expenses of one counsel for the holders of the
certificates) other than commissions or concessions of any brokers or dealers
and will indemnify the holders of the certificates (including any broker-
dealers) against certain liabilities, including liabilities under the
Securities Act.
136
LEGAL MATTERS
Legal matters with respect to the certificates offered will be passed upon
for us by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York and by
Troutman Sanders LLP. Skadden, Arps, Slate, Meagher & Flom LLP also represents
the initial purchasers of the certificates from time to time.
INDEPENDENT PUBLIC ACCOUNTANTS
The financial statements included in this registration statement have been
audited by Arthur Andersen LLP, independent public accountants, as indicated
in their reports with respect thereto, and are included herein in reliance
upon the authority of said firm as experts in giving said reports.
INDEPENDENT ENGINEER
Mirant Corporation has retained R.W. Beck, Inc. to prepare its independent
engineer's report, dated December 7, 2000, and its update thereto, dated April
26, 2001. This update, as well as the original report, 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 of R.W. Beck, Inc. as experts
in the review of the design and operation of electric generation facilities.
R.W. Beck, Inc. performed independent engineering services for Mirant Americas
Generation in connection with financing transactions in 1999 and 2001 for
which it received usual and customary compensation.
INDEPENDENT MARKET EXPERT
Mirant Corporation has retained PA Consulting Services Inc., formerly PHB
Hagler Bailly, Inc., to prepare the independent market expert report dated
April 10, 2001. 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. We have included the independent
market expert report in this prospectus in reliance upon the conclusions in
such report of PA Consulting Services Inc. and upon that firm's authority as
experts in energy market policy, price forecasting and economic analysis. PA
Consulting Services Inc. performed independent market expert services for
Mirant Americas Generation in connection with financing transactions in 1999
and 2001 for which it received usual and customary compensation.
AVAILABLE INFORMATION
Mirant Mid-Atlantic, LLC
We have filed with the SEC, Washington, D.C., a registration statement on
Form S-4 under the Securities Act to register with the SEC the new
certificates to be used in exchange for the existing certificates. This
prospectus does not contain all of the information set forth in the
registration statement and the exhibits and schedules thereto. Certain items
are omitted in accordance with the rules and regulations of the SEC. For
further information about us and the certificates, refer to the registration
statement and the exhibits and schedules filed therewith. Statements contained
in this prospectus as to the contents of any contract or other document
referred to are not necessarily complete and in each instance, if such
contract or document is filed as an exhibit, reference is made to the copy of
such contract or other documents filed as an exhibit to the registration
statement, each statement being qualified in all respects by such reference. A
copy of the registration statement, including the exhibits and schedules
thereto, may be read and copied at the SEC's Public Reference Room at 450
Fifth Street, N.W., Washington, D.C. 20549. Information on the operation of
the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-
0330. In addition, the SEC maintains an Internet site at http://www.sec.gov,
from which interested persons can electronically access the registration
statement, including the exhibits and any
137
schedules thereto, as well as reports, proxy and information statements, and
other information regarding issuers that file electronically with the SEC.
We are obligated, following the effectiveness of a registration statement,
to maintain our status as a reporting company under the Exchange Act (unless
the SEC will not accept the filing of the applicable reports), even though the
SEC rules and regulations may not require us to maintain that status. As a
reporting company, we will file periodic reports and other information with
the SEC for public availability (unless the SEC will not accept such filings).
If we cease to maintain that status, the interest rate on the lessor notes
will be increased by 0.50% per annum for the duration of such cessation
(unless the SEC will not accept the filing of the applicable reports). If the
SEC will not accept the filing of the applicable reports, it might become more
difficult to sell the certificates or to sell them at prices which you
consider favorable.
As long as any certificates remain outstanding, we will furnish to the pass
through trustee unaudited quarterly and audited annual financial statements,
with the accompanying footnotes and audit report. Unaudited quarterly
financial statements will be furnished to the pass through trustee within 60
days following the end of each of our first three fiscal quarters during each
fiscal year and audited annual financial statements will be furnished to the
pass through trustee within 120 days following the end of our fiscal year. The
pass through trustee will furnish all such information directly to certificate
holders and, upon request, certificate owners. We will also furnish to
certificate holders, certificate owners and prospective investors upon request
any information required to be delivered pursuant to Rule 144A(d)(4) under the
Securities Act so long as we are not a reporting company under the Exchange
Act.
138
FINANCIAL TABLE OF CONTENTS
Page
----
Report of Independent Public Accountants.................................. F-2
Consolidated Balance Sheets as of March 31, 2001 and December 31, 2000.... F-3
Consolidated Statements of Income for the three months ended March 31,
2001 and for the period from July 12, 2000 (inception) through
December 31, 2000........................................................ F-4
Consolidated Statements of Members' Equity for the period from July 12,
2000 (inception) through March 31, 2001.................................. F-5
Consolidated Statements of Cash Flows for the three months ended March 31,
2001 and for the period from July 12, 2000 (inception) through
December 31, 2000........................................................ F-6
Notes to Consolidated Financial Statements................................ F-7
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Mirant Mid-Atlantic, LLC:
We have audited the accompanying consolidated balance sheets of MIRANT MID-
ATLANTIC, LLC (a Delaware limited liability company) AND SUBSIDIARIES
(formerly Southern Energy Mid-Atlantic, LLC) as of March 31, 2001 and December
31, 2000, and the related consolidated statements of income, members' equity,
and cash flows for the three months ended March 31, 2001 and the period from
July 12, 2000 (inception) through December 31, 2000. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Mirant Mid-Atlantic, LLC
and subsidiaries as of March 31, 2001 and December 31, 2000, and the results
of their operations and their cash flows for the three months ended March 31,
2001 and the period from July 12, 2000 (inception) through December 31, 2000
in conformity with accounting principles generally accepted in the United
States.
/s/ Arthur Andersen LLP
Atlanta, Georgia
May 23, 2001
F-2
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Millions)
March 31, December 31,
2001 2000
--------- ------------
ASSETS
Current Assets:
Cash and cash equivalents............................... $ 12 $ 22
Receivables:
Customer accounts..................................... 6 1
Related parties (Note 3).............................. 60 29
Prepaid rent............................................ 7 32
Fuel stock.............................................. 50 33
Materials and supplies.................................. 46 47
Note receivable from related party (Note 3)............. 95 --
Assets from risk management activities (Note 7)......... 18 --
Derivative hedging instruments (Notes 1 and 7).......... 5 --
Other................................................... 8 17
------ ------
Total current assets................................ 307 181
------ ------
Property, Plant, and Equipment:
Land.................................................... 15 15
Property and equipment.................................. 986 986
------ ------
1,001 1,001
Less accumulated provision for depreciation............. (10) (1)
------ ------
991 1,000
Construction work in progress........................... 44 30
------ ------
Total property, plant, and equipment, net........... 1,035 1,030
------ ------
Noncurrent Assets:
Notes receivable from related parties (Note 3).......... 223 223
Goodwill, net of accumulated amortization of $9
and $1 at March 31, 2001 and December 31, 2000,
respectively .......................................... 1,344 1,352
Other intangible assets, net of accumulated amortization
of $1 and $-- at March 31, 2001 and December 31, 2000,
respectively........................................... 149 150
------ ------
Total noncurrent assets............................. 1,716 1,725
------ ------
Total assets........................................ $3,058 $2,936
====== ======
LIABILITIES AND MEMBERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities................ $ 65 $ 55
Payables to related parties (Note 3).................... 26 111
Liabilities from risk management activities (Note 7).... 16 --
Derivative hedging instruments (Notes 1 and 7).......... 3 --
Note payable to related party (Note 3).................. 75 75
Other................................................... 1 1
------ ------
Total current liabilities........................... 186 242
------ ------
Commitments and Contingent Matters (Notes 5 and 6)
Members' Equity:
Members' interest....................................... 2,797 2,689
Accumulated other comprehensive income.................. 2 --
Retained earnings....................................... 73 5
------ ------
Total members' equity............................... 2,872 2,694
------ ------
Total liabilities and members' equity............... $3,058 $2,936
====== ======
The accompanying notes are an integral part of these consolidated balance
sheets.
F-3
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Millions)
For the Period
From July 12, 2000
For the Three (Inception)
Months Ended Through December
March 31, 31,
2001 2000
------------- ------------------
Operating Revenues (Note 3)................... $281 $40
---- ---
Operating Expenses:
Cost of fuel, electricity and other
products................................... 127 14
Labor....................................... 20 3
Depreciation and amortization............... 18 2
Rental...................................... 24 3
Maintenance................................. 7 --
Selling, general, and administrative........ 6 6
Other....................................... 14 4
---- ---
Total operating expenses.................. 216 32
---- ---
Operating Income.............................. 65 8
Other Income (Expense):
Interest income............................. 6 1
Interest expense............................ (2) --
Financing fees.............................. (1) (4)
---- ---
Net Income.................................... $ 68 $ 5
==== ===
The accompanying notes are an integral part of these consolidated statements.
F-4
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY
FOR THE PERIOD FROM JULY 12, 2000 (INCEPTION) THROUGH MARCH 31, 2001
(In Millions)
Accumulated
Members' Other Comprehensive Retained Comprehensive
Interest Income Earnings Income
-------- ------------------- -------- -------------
Balance, July 12, 2000..... $ -- $ -- $ -- $ --
Net income............... -- -- 5 5
-----
Comprehensive income..... $ 5
=====
Capital contributions--
cash.................... 1,087 -- --
Capital contributions--
noncash................. 1,602 -- --
------ ----- -----
Balance, December 31,
2000...................... 2,689 -- 5
Net income............... -- -- 68 $ 68
Cumulative effect of
accounting change....... -- (4) -- (4)
Reclassification to
earnings................ -- 6 -- 6
-----
Comprehensive income..... $ 70
=====
Capital contributions--
noncash................. 108 -- --
------ ----- -----
Balance, March 31, 2001.... $2,797 $ 2 $ 73
====== ===== =====
The accompanying notes are an integral part of these consolidated statements.
F-5
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)
For the Period
From July 12, 2000
For the Three (Inception)
Months Ended Through
March 31, December 31,
2001 2000
------------- ------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................... $ 68 $ 5
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization.............. 18 2
Changes in certain assets and liabilities,
excluding effects from acquisition:
Customer accounts receivable............. (5) --
Related party receivables................ (31) (29)
Prepaid rent............................. 25 2
Fuel stock............................... (17) 3
Materials and supplies................... 1 --
Risk management activities, net.......... (2) --
Other current assets..................... 9 10
Accounts payable and accrued
liabilities............................. 10 4
Payables to related parties.............. 23 3
Other current liabilities................ -- 2
----- -------
Net cash provided by operating
activities............................ 99 2
----- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures......................... (14) (2)
Loans to related parties (Note 3)............ (95) (223)
Acquisition of assets........................ -- (917)
----- -------
Net cash used in investing activities.. (109) (1,142)
----- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from note payable to related party
(Note 3).................................... -- 75
Capital contributions........................ -- 1,087
----- -------
Net cash provided by financing
activities............................ -- 1,162
----- -------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS................................. (10) 22
CASH AND CASH EQUIVALENTS, beginning of
period...................................... 22 --
----- -------
CASH AND CASH EQUIVALENTS, end of period..... $ 12 $ 22
===== =======
NONCASH INVESTING AND FINANCING ACTIVITIES:
Fair value of assets contributed............. $ -- $ 1,720
Fair value of liabilities assumed............ -- (118)
----- -------
Net assets contributed................. $ -- $ 1,602
===== =======
Capital contributions (Note 3)............... $ 108 $ --
===== =======
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest....................... $ -- $ --
===== =======
The accompanying notes are an integral part of these consolidated statements.
F-6
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2001 AND DECEMBER 31, 2000
1. NATURE OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mirant Mid-Atlantic, LLC, formerly Southern Energy Mid-Atlantic, LLC, a
Delaware limited liability company ("LLC"), was formed on July 12, 2000 in
conjunction with Mirant Corporation's ("Mirant") planned acquisition of
generating assets and other related assets from Potomac Electric Power Company
("PEPCO") (Note 2). Mirant Mid-Atlantic, LLC and its subsidiaries
(collectively the "Company"), are indirect wholly-owned subsidiaries of Mirant
Americas Generation, Inc. ("Mirant Americas Generation"), formerly Southern
Energy North America Generating, Inc., an indirect wholly-owned subsidiary of
Mirant.
The Company is primarily engaged in the development and operation of
nonregulated power generation facilities in Maryland and the District of
Columbia. The Company's consolidated financial statements include the
following wholly-owned subsidiaries:
. Mirant Chalk Point, LLC ("Mirant Chalk Point");
. Mirant D.C. O&M, LLC ("Mirant D. C. O&M");
. Mirant Piney Point, LLC ("Mirant Piney Point"); and
. Mirant MD Ash Management, LLC ("Mirant MD Ash Management").
The results of operations of the acquired assets (Note 2) are incorporated
into the Company's consolidated results of operations from December 19, 2000
(date of acquisition) onward.
Basis of Presentation
The consolidated financial statements of the Company are presented in
conformity with accounting principles generally accepted in the United States
("U.S. GAAP") and include the accounts of the Company and its wholly-owned
subsidiaries. All significant intercompany accounts and transactions have been
eliminated in consolidation.
The accompanying consolidated financial statements have not been prepared in
accordance with Statement of Financial Accounting Standards ("SFAS") No. 71,
"Accounting for the Effects of Certain Types of Regulation." This
pronouncement, under which most U.S. utilities report financial statements,
applies to entities that are subject to cost-based rate regulation, and
therefore, the provisions of SFAS No. 71 do not apply.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the dates of the financial statements and the reported amounts
of revenues and expenses during the reporting periods. Actual results could
differ from those estimates.
Cash and Cash Equivalents
The Company considers all short-term investments with an original maturity
of three months or less to be cash equivalents.
Fuel Stock and Materials and Supplies
Fuel stock and materials and supplies are carried at the lower of cost or
market. Cost is computed on an average cost basis. Fuel stock is removed from
the inventory account once used in production; materials and supplies are
removed from the account once used for repairs, maintenance, or capital
projects.
F-7
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Property, Plant, and Equipment
Property, plant, and equipment are recorded at cost to the Company, which
includes materials, labor, and appropriate administrative costs that include
the estimated cost of debt funds used during construction. The costs of
maintenance, repairs, and replacement of minor items of property are charged
to maintenance expense as incurred. Production assets are depreciated on a
straight-line basis over a period of 19 to 42 years. Other fixed assets are
depreciated on a straight-line basis over a period of 2 to 10 years.
Recoverability of these assets is reviewed annually or as changes in
circumstances indicate that the carrying amount may exceed fair value in
accordance with the provisions of SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
Construction work in process is recorded at cost, which includes materials,
labor, appropriate administrative costs, and the estimated cost of debt funds
used during construction.
The Company expenses all maintenance costs unless the expenditure increases
the useful life of the capital asset or the expenditure produces a future
economic benefit.
Goodwill and Other Intangible Assets
The Company amortizes costs in excess of the fair value of net assets
acquired using the straight-line method over the 40 year expected useful
economic life of the goodwill.
Specifically identifiable intangible assets consist of acquired trading and
development rights that are amortized over their estimated useful lives
ranging from 35 to 40 years. Recoverability of goodwill and/or intangible
assets (analyzed on the basis of undiscounted operating cash flow) is reviewed
annually or as changes in circumstances indicate that the carrying amount may
exceed fair value in accordance with the provisions of SFAS No. 121 and APB
Opinion No. 17, "Intangible Assets."
Revenue Recognition
Revenues derived from power generation are recognized upon output and
product delivery, all as specified by contractual terms.
Rental Expense
Rent expense related to the Company's operating leases (Note 5) is
recognized on a straight-line basis over the terms of the leases.
Non-Recurring Charges
The Company cancelled a $1.5 billion bank commitment letter before December
31, 2000. The facility would have provided flexibility in the purchase of
certain assets (Note 2) had the lease transaction (Note 5) been delayed. Fees
associated with this facility were approximately $4 million for the period
from July 12, 2000 (inception) through December 31, 2000 and are included in
financing fees on the accompanying consolidated statements of income.
Income Taxes
The Company was formed as an LLC on July 12, 2000 and is treated as a
partnership for income tax purposes. As such, the individual LLC members are
subject to federal and state taxes based on their allocated portion of income
and expenses and the Company is not subject to federal and state income
taxation. Accordingly, no provision for federal or state income taxes has been
made in the accompanying consolidated financial statements.
F-8
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Fair Value of Financial Instruments
The Company's financial instruments consist primarily of cash, accounts and
notes receivable, accounts payable, and short-term debt. The Company also
engages in risk management activities to hedge exposure to fluctuations in
power and fuel prices. See Note 7 where the fair value of financial
instruments is discussed further.
Comprehensive Income
Mirant Mid-Atlantic's comprehensive income, consisting of net income, the
cumulative effect of accounting change and reclassification to earnings is
presented in the consolidated statements of members' equity. The objective of
the statement is to report a measure of all changes in members' equity of an
enterprise that result from transactions and other economic events of the
period other than transactions with members.
Accounting Change
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which establishes accounting
and reporting standards for derivative instruments and hedging activities. The
statement requires that certain derivative instruments be recorded in the
balance sheet as either assets or liabilities measured at fair value, and that
changes in the fair value be recognized currently in earnings, unless specific
hedge accounting criteria are met. If the derivative is designated as a fair
value hedge, the changes in the fair value of the derivative and of the hedged
item attributable to the hedged risk are recognized currently in earnings. If
the derivative is designated as a cash flow hedge, the changes in the fair
value of the derivative are recorded in other comprehensive income ("OCI"),
and the gains and losses related to these derivatives are recognized in
earnings in the same period as the settlement of the underlying hedged
transaction. If the derivative is designated as a net investment hedge, the
changes in the fair value of the derivative are also recorded in OCI. Any
ineffectiveness relating to these hedges is recognized currently in earnings.
The assets and liabilities related to derivative instruments for which hedge
accounting criteria is met are reflected as derivative hedging instruments in
the accompanying consolidated balance sheet as of March 31, 2001. The
derivative instruments for which hedge accounting criteria is not met are
reflected as risk management assets and liabilities in the accompanying
consolidated balance sheet as of March 31, 2001.
The adoption of SFAS No. 133 resulted in a cumulative reduction of OCI of $4
million, and is attributable to deferred losses on cash flow hedges. During
the twelve-month period ending December 31, 2001, the Company expects to
reclassify the $4 million loss from OCI into earnings. The derivative gains or
losses reclassified to earnings, combined with the settlement of the
underlying physical transactions together represent the Company's net
commodity revenues and costs.
2. ACQUISITION OF PEPCO ASSETS
On December 19, 2000, Mirant, through its subsidiaries and together with
lessors in a leveraged lease transaction, purchased PEPCO's generation assets
in Maryland and Virginia. The acquired assets are located in the PJM
interconnection market ("PJM"), which encompasses all or a part of
Pennsylvania, New Jersey, Maryland, Delaware, Virginia, and the District of
Columbia. As part of the acquisition, Mirant Americas Energy Marketing, LP
("Mirant Americas Energy Marketing"), a wholly-owned subsidiary of Mirant,
assumed transition power agreements ("TPAs") and obligations under power
purchase agreements ("PPAs"), that represented a net liability of
approximately $2.3 billion.
The acquired and leased assets consist primarily of four electric generating
stations:
. the 1,412 megawatt (MW) coal and oil-fired Morgantown station located in
Charles County, Maryland;
. the 2,423 MW coal, oil, and gas-fired Chalk Point station located in
Prince George's County, Maryland, including the assignment of PEPCO's
rights and obligations to the 84 MW Southern Maryland Electric
Cooperative, Inc. ("SMECO") combustion turbine located at the Chalk
Point station site;
F-9
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
. the 837 MW coal, oil, and gas-fired Dickerson station located in upper
Montgomery County, Maryland; and
. the 482 MW coal and oil-fired Potomac River station located in
Alexandria, Virginia.
In addition to the electric generating stations described above, Mirant also
acquired three coal ash storage facilities, a 51.5 mile oil pipeline serving
the Chalk Point and Morgantown stations, an engineering and maintenance
service facility and related assets. Mirant's rights to acquire the assets
were assigned to certain of its subsidiaries and Mirant executed and delivered
to PEPCO a parent guarantee to support the obligations of subsidiaries under
the project agreements. In addition, as part of the acquisition, approximately
950 former PEPCO employees became employees of Mirant Mid-Atlantic Services,
LLC ("Mirant Mid-Atlantic Services"), an indirect wholly-owned subsidiary of
Mirant (Note 3).
In connection with the above transaction, the Company paid $917 million for
materials and supplies and property, plant, and equipment. The Company also
received a noncash contribution of assets of $1,720 million, $1,674 million of
which related directly to the acquired assets, and assumed liabilities of $118
million from Mirant. As a result, the Company and its subsidiaries own the
baseload and cycling units at the Chalk Point facility (1,907 MW), the peaking
units at the Morgantown facility (248 MW), the peaking units at the Dickerson
facility (291 MW), three ash storage facilities, the 51.5 mile oil pipeline,
and the engineering and maintenance service facility. The Company also entered
into an operating lease for the Morgantown (1,164 MW) and Dickerson (546 MW)
baseload facilities (Note 5).
The Company accounted for the acquisition as a purchase business combination
in accordance with Accounting Principles Board Opinion No. 16. Direct costs of
the acquisition amounted to approximately $27 million. The preliminary
purchase price allocation is as follows (in millions):
Current assets.................................................... $ 61
Property, plant and equipment..................................... 1,027
Goodwill and other intangibles.................................... 1,503
Current liabilities............................................... (118)
------
Purchase price.................................................... $2,473
======
Mirant assigned to Mirant Potomac River, LLC ("Mirant Potomac River") and
Mirant Peaker, LLC ("Mirant Peaker") the 482 MW Potomac River facility and the
remaining 516 MWs at the Chalk Point facility, respectively. Mirant Peaker
also acquired the rights and obligations related to the 84 MW combustion
turbine owned by SMECO. Mirant Potomac River and Mirant Peaker are direct
wholly owned subsidiaries of Mirant and are affiliates of the Company.
3. RELATED-PARTY TRANSACTIONS AND FUNDING
Management, Personnel and Administrative Services Agreements
Mirant Mid-Atlantic Services and Mirant Services, LLC ("Mirant Services"),
each acting as an independent contractor, provide various management,
personnel and administrative services to the Company. Mirant Mid-Atlantic
Services hired former PEPCO personnel to provide operation, maintenance and
general management services and advice to the Company. Mirant Mid-Atlantic
Services has a labor contract with the International Brotherhood of Electrical
Workers that extends to May 2003 and involves approximately 70% of the
Company's operating personnel. Mirant Mid-Atlantic Services assumes all
liability for pension and other employee benefits for its employees. The
Company pays a fee to Mirant Mid-Atlantic Services equal to Mirant Mid-
Atlantic Services' costs of providing such services. The Company has no
obligation to provide for post-acquisition
F-10
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
pension obligations or other benefits to Mirant Mid-Atlantic Services
employees. A pre-acquisition liability for pension and employee benefits of
approximately $92 million is included in payables to related parties in the
accompanying December 31, 2000 consolidated balance sheet. This payable was
converted by Mirant to a capital contribution during the three months ended
March 31, 2001 (see below). The Mirant Mid-Atlantic Services agreement with
the Company expires on December 31, 2001, but will automatically renew for
successive one year terms unless either party to the agreement notifies the
other party, at least 30 days prior to the expiration date, that the agreement
will not be renewed.
Mirant Services, a direct wholly-owned subsidiary of Mirant, provides the
following services to the Company: contract administrative services;
bookkeeping, accounting and auditing services; finance and treasury services;
tax assistance; and insurance and bonding assistance. The Company will pay a
fee to Mirant Services equal to Mirant Services' cost of providing these
services. Mirant Services' agreement with the Company expires on December 31,
2001, but will automatically renew for successive one year terms unless either
party to the agreement notifies the other party, at least 30 days prior to the
expiration date, that the agreement will not be renewed.
The total fees incurred under both agreements for the three months ended
March 31, 2001 were approximately $29 million and for the period from July 12,
2000 (inception) through December 31, 2000 were approximately $8 million.
Total fees accrued as of March 31, 2001 were approximately $9 million and as
of December 31, 2000 were approximately $8 million.
Ash Disposal and Storage Services Agreements
Mirant MD Ash Management, acting as an independent contractor, provides
services, personnel and resources to load, transport, unload and store ash
produced by each of the generating stations. Each generating station utilizing
such services pays a fee to Mirant MD Ash Management equal to Mirant MD Ash
Management's cost of providing such services. This agreement will expire on
December 31, 2001, but will automatically renew for successive one year terms
unless either party to the agreement notifies the other party, at least 30
days prior to the expiration date, that the agreement will not be renewed.
After intercompany eliminations, the total revenue recognized under this
agreement for the three months ended March 31, 2001 was $159 thousand and for
the period from July 12, 2000 (inception) through December 31, 2000 was $21
thousand. The receivable under this agreement as of March 31, 2001 was $20
thousand and as of December 31, 2000 was $21 thousand.
Common Facilities Agreement
Mirant Chalk Point provides services and resources for and access to the
common facilities shared by Mirant Chalk Point and Mirant Peaker at the Chalk
Point generating facility. Mirant Peaker pays a fee to Mirant Chalk Point
equal to Mirant Chalk Point's costs of providing such services in conjunction
with the operation and maintenance of the combustion turbine at the Chalk
Point generating facility. This common facilities agreement will expire on
December 31, 2001, but will automatically renew for successive one year terms
unless either party to the agreement notifies the other party to the
agreement, at least 30 days prior to the expiration date, that the agreement
will not be renewed. For the three months ended March 31, 2001, and for the
period from July 12, 2000 (inception) through December 31, 2000 the Company
incurred no costs and recognized no revenue associated with this agreement.
Capital Contribution Agreement
The purchases of the Potomac River generating facility and the Chalk Point
combustion turbines (including the rights and obligations with respect to the
SMECO combustion turbine) by Mirant Potomac River and Mirant
F-11
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Peaker, respectively, were funded by a capital contribution from Mirant and
loans from the Company evidenced by notes. Under the capital contribution
agreement, Mirant Potomac River and Mirant Peaker will make distributions to
Mirant at least once per quarter. Distributions will equal all cash available
after taking into account projected cash requirements, including mandatory
debt service, prepayments permitted under the Mirant Potomac River and the
Mirant Peaker notes, and maintenance reserves, as reasonably determined by
Mirant. Mirant will contribute or cause these amounts to be contributed to the
Company.
Power Sales Agreements
The Company has entered into a power sales agreement with Mirant Americas
Energy Marketing to supply all capacity, ancillary services and energy
requirements to meet Mirant Americas Energy Marketing's obligation under the
PEPCO TPAs which are not met by deliveries under the PEPCO PPAs. In addition
to supplying Mirant Americas Energy Marketing's obligations under the TPAs,
the Company must also meet the load requirements for any previous PEPCO retail
customer now served by a Mirant Americas Energy Marketing wholesale customer.
Mirant Americas Energy Marketing's obligation to pay the Company, Mirant
Potomac River, and Mirant Peaker market price is not affected by the price in
Mirant Americas Energy Marketing's TPAs with PEPCO.
The Company supplies capacity, ancillary services and energy to Mirant
Americas Energy Marketing either from its own generating facilities or through
power purchases arranged by Mirant Americas Energy Marketing on its behalf.
Such power purchases do not include power purchased under the PPAs assumed by
Mirant Americas Energy Marketing. The purchase price for all capacity,
ancillary services and energy sold by the Company, Mirant Potomac River, and
Mirant Peaker to Mirant Americas Energy Marketing for the PEPCO TPAs is the
market price for such products, initially established as follows:
. For capacity, the price is the PJM unforced capacity credits as set
forth in the final PJM auction for the PJM capacity credit market held
prior to the month of delivery.
. For ancillary services, the price is the price credited to Mirant
Americas Energy Marketing by PJM attributable to the quantities of
energy delivered by the Company, to supply Mirant Americas Energy
Marketing's PEPCO TPA obligations.
. For energy, the price is the PJM first settlement day ahead locational
marginal pricing, or LMP, for each applicable hour multiplied by the
quantity of energy delivered by the Company to Mirant Americas Energy
Marketing for Mirant Americas Energy Marketing's PEPCO TPA obligation.
The Company sells Mirant Americas Energy Marketing additional capacity,
ancillary services and energy to the extent such products are available after
supplying the Company's obligations to Mirant Americas Energy Marketing
regarding Mirant Americas Energy Marketing's PEPCO TPA supply requirements.
The price for such sales is the actual price Mirant Americas Energy Marketing
obtains from the resale of such products to third parties, including power
pools.
Services and Risk Management Agreements
The Company has entered into multiple services and risk management
agreements with Mirant Americas Energy Marketing. The Company's services and
risk management agreements provide that:
. Mirant Americas Energy Marketing is responsible for all dispatching or
bidding of the Company's generating facilities.
. Mirant Americas Energy Marketing provides fuel, including fuel oil, gas
and coal, for the Company's generating facilities at Mirant Americas
Energy Marketing's cost. Fuel costs are calculated as Mirant Americas
Energy Marketing's actual cost for transportation, inventory and related
costs, as adjusted for any gains or losses on fuel hedges and trading
activities.
F-12
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
. Mirant Americas Energy Marketing procures all emissions credits
necessary for the operation of the Company's generating facilities and
sells excess credits. Mirant Americas Energy Marketing charges its
actual cost of acquiring the credits and remits the proceeds of any
emission credit sales to the Company, as adjusted for any gains or
losses on emission hedges and trading activities.
. Mirant Americas Energy Marketing procures or advises the Company to
procure business interruption insurance and forced outage insurance. The
cost of insurance is charged to the Company. Any proceeds from such
insurance will be included within revenues, as defined in the risk
management agreement, for purposes of calculating the Company's net
revenues for the year and any bonus payable to Mirant Americas Energy
Marketing.
. Mirant Americas Energy Marketing enters into financial products
(including, but not limited to, swaps, contracts for differences,
options and weather derivatives) purchased for the Company. The costs,
including without limitation, third party broker costs, transaction fees
and gains or losses related to such financial products, are charged to
or paid to the Company.
. Mirant Americas Energy Marketing enters into forward sales, hedges and
other transactions for the Company's benefit. The costs of such
transactions, including without limitation, purchased power costs,
transmission costs, third party broker costs, transaction fees,
incremental credit costs and gains or losses related to such activities,
are charged to or paid to the Company.
Mirant Americas Energy Marketing is entitled to deduct from the revenues
payable to the Company, all fuel, hedging, emissions and other costs. The
Company's gross revenues from Mirant Americas Energy Marketing less an annual
service fee payable to Mirant Americas Energy Marketing, designed to cover its
personnel and other administrative costs, are referred to as the Company's net
revenues. Once the net revenues received by the Company together with the net
revenues received by Mirant Peaker and Mirant Potomac River reach a specified
level, Mirant Americas Energy Marketing is entitled to 50% of the aggregate
net revenues in excess of such amount. Mirant Americas Energy Marketing and
the Company establish, on an annual basis, the specified amount of aggregate
net revenues used to calculate Mirant Americas Energy Marketing's bonus. There
was no bonus applicable for the period from July 12, 2000 (inception) through
December 31, 2000. For 2001, Mirant Americas Energy Marketing is entitled to
50% of the Company's, Mirant Peaker's, and Mirant Potomac River's aggregate
net revenues in excess of $896 million. The annual service fee for 2001 which
is shared by the Company, Mirant Peaker and Mirant Potomac River, is
$7 million of which approximately $2 million was expensed by the Company
during the three months ended March 31, 2001. Amounts of net revenues due to
Mirant Americas Energy Marketing under this agreement will only be payable to
the extent that the Company could at the time make a restricted payment that
shall be fully subordinated to the payments due under the facility leases and
all other non-disputed obligations then due and payable. This agreement may be
terminated by the Company without further payment upon the exercise of
remedies following the occurrence of an event of default.
Mirant Americas Energy Marketing's agreements with the Company and with
Mirant Potomac River and Mirant Peaker expire on December 31, 2001, but
automatically renew for successive one year terms unless either party to the
agreement notifies the other party, at least three months prior to the
expiration date, that the agreement will not be renewed.
Total power sales to Mirant Americas Energy Marketing by the Company
amounted to $274 million for the three months ended March 31, 2001 and $40
million for the period from July 12, 2000 (inception) through December 31,
2000. Total fuel inventory purchased by Mirant Americas Energy Marketing on
behalf of the Company was $99 million for the three months ended March 31,
2001 and $10 million for the period from July 12, 2000 (inception) through
December 31, 2000. As of March 31, 2001 and December 31, 2000 the Company had
a receivable from Mirant Americas Energy Marketing of $48 million and $29
million, respectively.
F-13
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Notes Receivable
Mirant Peaker and Mirant Potomac River borrowed funds from the Company in
order to finance their respective acquisitions of generation assets. At both
March 31, 2001 and December 31, 2000, notes receivable from these two related
parties consisted of the following:
Borrower Principal Interest Rate Maturity
-------- -------------- ------------- ----------
(in millions)
Mirant Potomac River.............. $152 10% 12/30/2028
Mirant Peaker..................... $ 71 10% 12/30/2028
Principal is due on maturity with interest due semiannually, in arrears, on
June 30 and December 30. Any amount not paid when due bears interest
thereafter at 12%. Mirant Potomac River and Mirant Peaker may prepay up to $5
million and $3 million per year, respectively. Interest earned from related
parties for the three months ended March 31, 2001 was $6 million and for the
period from July 12, 2000 (inception) through December 31, 2000 was $1
million. Accrued interest due from related parties was $6 million as of March
31, 2001 and $1 million as of December 31, 2000.
In March 2001, the Company advanced Mirant $95 million under a note
receivable agreement. The note is due on demand, or if no demand is made, then
on March 30, 2002. The note accrues interest at a monthly rate equal to the
30-day yield of Federated Investor's Fund 851 (5.41% at March 31, 2001),
payable quarterly.
Note Payable
The Company has a credit facility available from Mirant Americas Generation
up to $150 million, bearing an interest rate equivalent to Mirant Americas
Generation's cost of funds (9.5% at March 31, 2001), and payable upon demand.
As of both March 31, 2001 and December 31, 2000 the Company has drawn $75
million on this facility. Interest expense for the three months ended March
31, 2001 was $2 million and for the period from July 12, 2000 (inception)
through December 31, 2000 was $213 thousand. Accrued interest was $2 million
as of March 31, 2001 and $213 thousand as of December 31, 2000.
Capital Contributions
During the three months ended March 31, 2001, Mirant caused a $108 million
capital contribution and a reduction of the Company's payables to Mirant Mid-
Atlantic Services and Mirant Americas Generation.
4. CONCENTRATION OF CREDIT RISK
Under the power sales agreements with Mirant Americas Energy Marketing (Note
3) the Company retains the ultimate credit risk for Mirant Americas Energy
Marketing's sales to third parties. Per the power sales agreements, Mirant
Americas Energy Marketing will use the capacity, energy and ancillary services
provided by the Company's generating facilities to meet its obligations under
the TPAs. Mirant Americas Energy Marketing meets its TPA obligation by selling
substantially all of the power produced by the facilities to the PJM power
pool which in turn sells wholesale power to utilities and others including
PEPCO. Accordingly, the Company and other wholesalers participating in the PJM
power pool indirectly bear the aggregate credit risk of PJM's customer base.
5. LEASE COMMITMENTS FOR DICKERSON AND MORGANTOWN STATIONS
Operating Leases
On December 19, 2000, in conjunction with the purchase of the PEPCO assets,
the Company entered into multiple sale-leaseback transactions totaling $1.5
billion relating to the Dickerson and the Morgantown baseload
F-14
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
units and associated property. The terms of each lease vary between 28.5 and
33.75 years. The Company is accounting for these leases as operating leases.
The Company's expenses associated with the commitments under the Dickerson
and Morgantown operating leases totaled approximately $24 million for the
three months ended March 31, 2001 and approximately $3 million for the period
from July 12, 2000 (inception) through December 31, 2000. As of March 31,
2001, estimated minimum rental commitments for non-cancelable operating leases
are $196 million for the nine months ended December 31, 2001 and $170 million,
$151 million, $122 million and $116 million for the years 2002, 2003, 2004 and
2005, respectively. As of March 31, 2001, the total remaining minimum lease
payments over the non-cancelable terms of the leases are approximately $3.1
billion. The lease agreements contain restrictive covenants that restrict the
Company's ability to, among other things, make dividend distributions, incur
indebtedness, or sublease the facilities. Permitted indebtedness as defined in
the Participation Agreement allows increased debt for working capital
purposes, intercompany loans, subordinated indebtedness, and guaranteed
indebtedness. Indebtedness plus the value at risk under unhedged transactions
may not exceed $100 million less indebtedness incurred by Mirant Chalk Point,
Mirant Potomac River, and Mirant Peaker.
These leases are part of a leveraged lease transaction. Three series of
certificates were issued and sold pursuant to a 144A offering. These
certificates are interests in pass through trusts that hold the lessor notes
issued by the owner lessors. The Company pays rent to an indenture trustee,
which in turn makes payments of principal and interest to the pass through
trusts and any remaining balance to the owner lessors for the benefit of the
owner participants. According to the registration rights agreement dated
December 18, 2000, the Company must maintain its status as a reporting company
under the Exchange Act. The Company is also obliged to consummate the exchange
offer pursuant to an effective registration statement or to cause a shelf
registration statement to be effective under the Securities Act. The Company
agreed to pay additional interest at a rate of .50% per annum on the existing
pass through certificates if it fails to consummate the exchange offer on or
prior to December 18, 2001 for so long as such failure continues.
The Company has an option to renew the lease for a period that would cover
up to 75% of the economic useful life of the facility, as measured near the
end of the lease term. However, the extended term of the lease will always be
less than 75% of the revised economic useful life of the facility.
Upon an event of default by the Company, the lessors may require a
termination value payment as defined in the agreements.
Site Leases and Site Subleases
The Company leases the ground interests for the Dickerson and Morgantown
leased facilities to the owner lessors who in turn sublease the ground
interests to the Company. The terms of each site lease vary between 38 and 45
years. The terms of each site sublease are coterminous with the term of each
lease for the respective facility. Rent payable under each site lease and site
sublease is automatically offset against the other, such that no amounts will
be payable by the Company or the owner lessors.
6. COMMITMENTS AND CONTINGENT MATTERS
Legal Matters
The Company is involved in various lawsuits and disputes which arose in the
ordinary course of business. In management's opinion, the outcome of these
matters will not have a material adverse impact on the Company's consolidated
financial position, results of operations, or cash flows.
F-15
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Environmental
In January 2001, the U.S. Environmental Protection Agency ("the EPA") issued
a request to the Company for information under the Clean Air Act, Section 114
concerning the air permitting implications of past repair and maintenance
activities at the Chalk Point, Dickerson, Morgantown and Potomac River
facilities. The Company is in the process of responding fully to this request.
At this time, the Company cannot determine whether, or to what extent, any
action will be brought by the EPA resulting from this matter.
Other
The Company is involved in discussions with Pepco regarding various closing
adjustments in connection with the asset acquisition in December 2000 (Note
2). In management's opinion, the outcome of these matters will not have a
material adverse impact on the Company's consolidated financial position,
results of operations or cash flows.
7. FINANCIAL INSTRUMENTS
Derivative Hedging Instruments
The Company is exposed to market risk including changes in certain commodity
prices. To manage the volatility relating to those exposures, the Company
enters into various derivative transactions pursuant to the Company's policies
in areas such as counterparty exposure and hedging practices.
The Company enters into commodity financial instruments in order to hedge
market risk and exposure to electricity and to natural gas, coal, and other
fuels utilized by its generation assets. These financial instruments primarily
include forwards, futures, and swaps. Prior to the Company's January 1, 2001
adoption of SFAS No. 133, the gains and losses related to these derivatives
were recognized in the same period as the settlement of the underlying
physical transaction. These realized gains and losses are included in
operating revenues and operating expenses in the accompanying income statement
for the period from July 12, 2000 (inception) through December 31, 2000.
At December 31, 2000, the Company had unrealized net losses of approximately
$4 million related to these financial instruments. The fair value of its
nontrading commodity financial instruments is determined using various
factors, including closing exchange or over-the-counter market price
quotations, time value and volatility factors underlying options and
contractual commitments.
Subsequent to the adoption of SFAS No. 133 on January 1, 2001, these
derivative instruments are recorded in the consolidated balance sheet as
either derivative hedging assets or liabilities measured at fair value, and
changes in the fair value are recognized currently in earnings, unless
specific hedge accounting criteria are met. If the criteria for hedge
accounting are met, changes in the fair value are recognized in other
comprehensive income until such time as the underlying physical transaction is
settled and the gains and losses related to these derivatives are recognized
in earnings. During the three months ended March 31, 2001, $6 million of
derivative losses were reclassified to operating income. The derivative
losses, when combined with the settlement of the underlying physical
transactions together represented the Company's net commodity revenues and
costs.
The adoption of SFAS No. 133 resulted in a cumulative reduction to OCI of $4
million, and is attributable to deferred losses on cash flow hedges used for
commodity price management.
F-16
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Mirant estimates the $2 million of net derivative gains included in OCI at
March 31, 2001 will be reclassified into earnings or otherwise settled within
the next twelve months as certain forecasted transactions relating to
commodity contracts become realized. The derivative gains and losses
reclassified to earnings are expected to be offset by realized amounts arising
from the settlement of the underlying physical transactions being hedged.
The Company anticipates that SFAS No. 133 will increase the volatility of
both net income and other comprehensive income as derivative instruments are
valued based on market prices. Therefore, as the prices change, the change in
fair value of the derivatives will change.
At March 31, 2001 and December 31, 2000, the Company had contracts that
related to periods through 2002. The net notional amount of the derivative
hedging instruments at March 31, 2001 and December 31, 2000 was approximately
1,114 thousand and 163 thousand equivalent megawatt-hours, respectively. The
notional amount is indicative only of the volume of activity and not of the
amount exchanged by the parties to the financial instruments. Consequently,
these amounts are not a measure of market risk.
Risk Management Activities
Certain financial instruments used by the Company to manage risk exposure to
energy prices do not meet the hedge criteria under SFAS No. 133. These
financial instruments are recorded at fair value as risk management assets and
risk management liabilities in the accompanying consolidated balance sheet at
March 31, 2001.
At March 31, 2001, the Company had contracts that related to periods through
2001. The net notional amount of the risk management assets and liabilities at
March 31, 2001 was approximately 1.3 million equivalent megawatt-hours. The
net notional amount is indicative only of the volume of activity and not of
the amount exchanged by the parties to the financial instruments.
Consequently, these amounts are not a measure of market risk.
The fair values of the risk management assets and liabilities recorded on
the consolidated balance sheet as of March 31, 2001 are included in the
following table (in millions):
Risk Management
------------------
Assets Liabilities
------ -----------
Oil.................................................... $16 $15
Electricity............................................ 1 1
Natural gas............................................ 1 --
--- ---
$18 $16
=== ===
Fair Values
SFAS No. 107, "Disclosures About Fair Value of Financial Instruments,"
requires the disclosure of the fair value of all financial instruments. At
March 31, 2001 and December 31, 2000, financial instruments recorded at
contractual amounts that approximate market or fair value includes cash and
cash equivalents, accounts and notes receivable, accounts payable and short
term debt. The market values of such items are not materially sensitive to
shifts in market interest rates because of the limited term to maturity of
many of these instruments and /or their variable interest rates.
F-17
MIRANT MID-ATLANTIC, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
8. Subsequent Events (Unaudited)
In August 2001, Mirant caused Mirant Americas Energy Marketing to enter into
a fixed rate power purchase agreement for Mirant Mid-Atlantic's capacity and
energy for the period from August 1, 2001 through June 30, 2004, extendable
through December 31, 2004 at Mirant Americas Energy Marketing's option. The
agreement includes all of the output of the Company's facilities over the
agreement term. However, Mirant Americas Energy Marketing has the option to
reduce the committed capacity and energy purchases for fiscal 2002, limited to
75% of the total output of the Company's facilities, and after December 31,
2002, may reduce the committed capacity and energy purchases to zero. At the
inception of this agreement, the pricing over the term of the agreement based
on Mirant Americas Energy Marketing's minimum committed capacity and energy
purchases was favorable to the Company by approximately $167 million when
compared to forecasted market rates in the PJM. The amount resulting from the
favorable pricing terms will be amortized to income as an offset to revenues
under the power purchase agreement through December 31, 2002 based on volumes
delivered. The power purchase agreement is being accounted for as an operating
lease in accordance with SFAS No. 13 "Accounting for Leases."
On August 2, 2001, PEPCO filed a civil action against Mirant in the U.S.
District Court for the District of Columbia, alleging that Mirant breached the
Asset Purchase and Sale Agreement ("APSA") between PEPCO and Mirant governing
Mirant's purchase of most of PEPCO's electric generation assets. Specifically,
PEPCO alleges that Mirant's withholding of $11.7 million from a post-closing
payment for fuel inventory is in breach of the APSA. Due to the early stages
of this litigation and the uncertainties in the litigation process, the
Company cannot predict the outcome of this proceeding at this time.
F-18
GLOSSARY OF ELECTRIC INDUSTRY TERMS
Ancillary Services--services provided by a utility and other suppliers to a
wholesale energy supplier to support the transmission of electrical energy,
including quality, safety loading, accounting and planning necessary to move
electricity from one point to another.
Annual Net Heat Rate--the average thermal efficiency of a generating
facility.
Base Load Unit--a generating unit which is normally operated to take all or
part of the minimum load of a system and which, consequently, operates at
substantially all times.
Bilateral Sales Agreement--an agreement between a buyer and a seller to
purchase and sell capacity and/or ancillary services of a given type,
duration, timing and reliability over a contractual term.
BTU (British thermal unit)--the standard unit for measuring the quantity of
heat energy, such as heat content of fuel.
Bulk Power (or Wholesale Electricity)--the power produced by the aggregate
of the electric generating facilities, transmission lines and related
equipment.
Bulk Power System--the aggregate of the electric generating facilities,
transmission lines and related equipment.
Capacity--the load for which a generating facility or other electrical
apparatus is capable of producing. The real power output rating of a
generating facility or other electrical apparatus measured on an instantaneous
basis.
Centrally Dispatched--the monitoring and regulation of electricity provided
by a central operator, such as an independent system operator.
Central Station Generated Electricity--electricity produced by main station,
efficient generating units such as base load units.
Combustion Turbines--a fuel-fired turbine engine used to drive an electric
generator. Because of their generally rapid firing time, combustion turbines
are used to meet short-term peak demand placed on power systems.
Competitive Bid Pricing--electric service prices determined in an open
market of supply and demand under which the price is set solely by agreement
as to what a buyer will pay and a seller will accept.
Customer Load--the load required by or delivered to a specific customer.
Cycling (or Intermediate) (or Mid-range) Unit--a generating unit used when
electricity demand exceeds base load capacity but before electricity demand
reaches peak capacity.
Dispatch--the monitoring and regulation of an electrical system to provide
coordinated operation; the sequence in which generating resources are called
upon to generate power to serve fluctuating loads.
Dispatch Curve--the curve depicting the relationship between the cost of
dispatching to the demand for electricity.
Distribution--the system of lines, transformers and switches that connect
between the transmission network and customer load. The portion of an electric
system that is dedicated to delivering electric energy to an end user.
G-1
Distribution Facilities--equipment used to deliver electric power from the
transmission system to the final user.
Distribution System--the portion of an electric system that is dedicated to
delivering electric energy to an end user.
Electric Load Pocket--the demand or use of electricity in a specific area.
Electric Utilities--regulated enterprises engaged in the distribution of
electricity to the public.
Energy--that which does or is capable of doing work; electric energy is
usually measured in kilowatt hours.
Equivalent Availability Factor--the percentage of total time in a specified
period that a unit was available to operate (at any load), limited only by
outages, overhauls and deratings.
Gas Assets--those assets which take natural gas from the ground and aid in
delivering gas to the ultimate customer, including gas supply agreements.
Generating Assets--the sum of the generating units owned by an energy
supplier.
Generating Facility--also known as a power plant or generating station, the
plant at which fuel is converted into electrical energy.
Generating Unit--any combination of physically connected generator(s),
reactor(s), boiler(s), combustion turbine(s), or other prime mover(s) operated
together to produce electric power.
Generation--the process of producing electric energy by transforming other
forms of energy; also, the amount of energy produced.
Gigawatt (GW)--1,000,000 kilowatts.
Grid--a system of interconnected transmission lines and generating
facilities that is managed so that the electricity produced by the generating
facilities is dispatched as needed to meet the requirements of the customers
connected to the grid at various points.
Heat Rate--the measurement of a generating facility's thermal efficiency in
converting input fuel into electricity, generally measured in terms of Btu per
net kilowatt-hour. It is computed by dividing the total number of Btu content
of the fuel burned by the resulting net kilowatt-hours generated.
Independent System Operator (ISO)--a neutral operator responsible for
maintaining an instantaneous balance of the electric system. The ISO performs
its function by controlling the dispatch of flexible plants to ensure that
loads match resources available to the system.
Intermediate (or Cycling) Unit--a generating unit used when electricity
demand exceeds base load capacity but before electricity demand reaches peak
capacity.
Kilowatt (kW)--the power required to do work at the rate of 1000 joules per
second.
Kilowatt-hour (kWh)--a unit of electrical energy which is equivalent to one
kilowatt of power used for one hour.
Liquid Trading Hubs--on-line auctions that offer trading for a for wholesale
electricity, natural gas and related products.
Load--the amount of electricity required or delivered at any specific point
or points by devices connected to the electrical generating system.
Load Center--a point where the load of a given area is assumed to be
concentrated.
G-2
Load Profiles--the varying magnitude of load required over a certain period
of time on a given electrical generating system.
Megawatt (MW)--1,000 kilowatts.
Megawatt-hour (MWh)--unit of electrical energy which is equivalent to one
megawatt of power used for one hour.
Megawatt-month (MW-month)--the amount of electrical energy used in one month
as measured in Megawatts.
Microturbines--compact multi-fuel turbines which can produce between 25 kW
and 200 kW of electricity without the need for added infrastructure but at a
higher cost than regular power, making them more attractive to lighter
industrial or commercial operations not on the main power grid, such as rural
cooperatives.
MMBtu--one million British thermal units.
Net Capacity Factor--the ratio, expressed as a percentage, of the actual net
generation of a generating unit over a period of time to the maximum potential
generation of the generating unit over that period based on its capacity.
Nondiscriminatory Basis--to allow all energy suppliers other than the owners
of the transmission system to have equal access to such system.
Open Access (see Nondiscriminatory Basis)--the ability to use transmission
facilities that are owned or controlled by a third party.
Outage--periods, both planned and unexpected, during which power system
facilities cease to provide generation or transmission of power.
Output--the net electricity supplied by a generating facility.
Peaking Units--a plant usually housing low-efficiency, quick response steam
units, gas turbines, or pumped-storage hydroelectric equipment normally used
during the maximum load periods.
Power Marketer--any firm that buys and resells power but does not own
transmission facilities.
Power Pool--an association of two or more interconnected electric systems
having an agreement to coordinate operations and planning for improved
reliability and efficiencies.
Reliability Council--a regional industry association created to enhance the
availability of electricity in a sufficient quantity and quality to those who
need it in a dependable and safe manner.
Spot Purchase--the purchase of capacity and related products on the open
market for immediate delivery.
Transmission Assets--equipment used to deliver electric power in bulk
quantity, from generating facilities to other parts of the electric system for
ultimate retail use.
Transmission Network--an interconnected group of electric transmission lines
and associated equipment for the transfer of electricity in bulk between
points of supply and points at which the electricity is delivered to the
ultimate customers.
Transmission Service--the movement or transfer of electric energy in bulk.
Wholesale Customers--purchasers of electricity who then resell the
electricity to end users.
Wholesale Electricity Market--selling and buying of bulk power from a
generator across a transmission system to electric utilities, cooperatives,
municipalities and federal and state electric agencies for resale to ultimate
customers.
G-3
[RW BECK LOGO]
April 26, 2001
Mirant Mid-Atlantic, LLC
1155 Perimeter Center West
Atlanta, GA 30338-4780
Subject: Update to the Independent Engineer's Report on the
Mirant Mid-Atlantic, LLC Generating Facilities
Ladies and Gentlemen:
Presented herein is a letter report (the "Letter Report") providing
additional information which has become known to us since December 7, 2000, the
date on which we submitted an independent engineer's report (the "Report") of
our review and analyses of the 2,423 megawatt ("MW") (net) Chalk Point power
plant located in Prince George's County, Maryland (the "Chalk Point Facility");
the 837 MW (net) Dickerson power plant located in Montgomery County, Maryland
(the "Dickerson Facility"); the 1,412 MW (net) Morgantown power plant located in
Charles County, Maryland (the "Morgantown Facility"); and the 482 MW (net)
Potomac River power plant located in Alexandria, Virginia (the "Potomac River
Facility" and, together with the Chalk Point, Dickerson, and Morgantown
Facilities, the "Generating Facilities") operated by Mirant Mid-Atlantic, LLC
("Mirant Mid-Atlantic"), formerly known as Southern Energy Mid-Atlantic, LLC.
All capitalized terms used herein but not defined have the same meanings given
to them in the Report.
Since the date of the Report, parties which supplied us information,
on which the Projected Operating Results were based, have provided us with
updated estimates and projections. In developing the Projected Operating
Results, we relied upon a revised report by PA Consulting Services Inc.,
formerly known as PHB Hagler Bailly Consulting, Inc. ("PA Consulting"), attached
as Appendix B to the Prospectus, of which this Letter Report is a part, for
projections of the Generating Facilities' electricity sales, revenues, and fuel
costs. In addition, for the purposes of developing the Projected Operating
Results, operating and maintenance expenses for the Generating Facilities have
been estimated by Mirant Mid-Atlantic. Mirant Mid-Atlantic has provided a new
estimate of the operating and maintenance expenses for the Generating
Facilities. Based upon these revised projections, we have revised the Base Case
Projected Operating Results and sensitivity cases presented in the Report. This
Letter Report summarizes our work up to the date of the Letter Report. Thus,
changed conditions occurring or becoming known after such date could affect the
material presented to the extent of such changes. Other than the information
presented herein, changed conditions occurring or becoming known after December
7, 2000 could affect the information presented in the Report to the extent of
such changes.
On the basis of these revised assumptions and the other assumptions
set forth in the Report, we are of the opinion that, for the Base Case Projected
Operating Results, the projected revenues from the sale of electricity are
adequate to pay annual operating and maintenance expenses (including capital
expenditures and major maintenance), fuel expense, and other operating expenses.
Such revenues provide an annual coverage on the Certificates of at least 3.16
times the annual Fixed Charge requirement (including Rent) in each year during
the term of the Certificates and a weighted average coverage of 5.62 times the
annual Fixed Charge requirement (including Rent) over the term of the
Certificates. A summary of the Fixed Charge coverages for the Base Case
Projected Operating Results and each sensitivity case is presented in Table 1.
These sensitivity cases are attached as Exhibits A-1 through A-7 to this Letter
Report.
A-1
Table 1
Projected Fixed Charge Coverage
Base Case Sensitivity Cases
A B C D E F
--- --- --- --- --- ---
Capacity
Year Low Gas Overbuild Breakeven Increased
Ending Market Price Market Price Market Reduced Increased Heat Operating
Dec 31, Scenario Scenario Prices (1) Availability Rate Expenses
- ---------------- ------------ --------------- ---------- ------------ -------------- ---------
2001 3.43 3.23 3.42 1.00 3.24 3.28 3.31
2002 3.29 3.21 3.29 1.00 3.11 3.14 3.17
2003 3.16 3.00 3.16 1.00 2.97 3.00 3.03
2004 3.17 3.01 2.50 1.00 2.94 2.97 2.98
2005 3.28 3.29 2.08 1.00 3.04 3.09 3.09
2010 3.70 3.34 3.39 1.00 3.44 3.52 3.52
2015 5.19 4.68 4.94 1.00 4.82 4.92 4.91
2020 6.14 5.49 5.85 1.00 5.70 5.83 5.82
2025 45.25 39.56 42.43 1.00 42.04 42.94 42.91
Minimum(2) 3.16 3.00 2.08 1.00 2.94 2.97 2.98
Average(3) 5.62 5.09 5.20 1.00 5.23 5.34 5.34
____________________
(1) Represents coverage on the Fixed Charges assuming the market electricity price is set such that the total operating revenue
results in a Fixed Charge coverage of 1.00 in all years.
(2) Represents minimum coverage during any year over the term of the Certificates.
(3) Represents the weighted average coverage over the term of the Certificates.
It should be noted that PA Consulting has assumed SO\2\ and NO\X\
allowance prices that are significantly higher than those assumed in the
Projected Operating Results. In the event that the actual allowance prices are
as assumed by PA Consulting, the projected minimum and average Fixed Charge
coverage ratios would decrease in the Base Case by approximately 0.12 and 0.26,
respectively.
As a result of the revisions to the Projected Operating Results, the
Leased Facilities are projected by PA Consulting to generate approximately 50
percent of the electricity sales over the term of the Certificates. Based upon
the revised electricity revenue and fuel costs for the Leased Facilities
estimated by PA Consulting, the variable operating and maintenance costs of the
Leased Facilities as estimated by Mirant Mid-Atlantic, and the various other
assumptions used in the Projected Operating Results as described in the Report,
the Leased Facilities are estimated to provide approximately 47 percent of the
projected gross operating margin of the Generating Facilities over the term of
the Certificates, or an average of approximately $410,000,000 per year over the
term of the Certificates. The gross operating margin has been calculated as the
difference between electricity revenue and the fuel and variable operating and
maintenance cost, including the cost of emissions allowances.
Respectfully submitted,
/s/ R. W. BECK, INC.
A-2
Exhibit A-1
Mirant Mid-Atlantic
Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------------------ -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 54.5% 52.1% 50.0% 48.1% 47.9% 49.7% 49.5% 49.3% 49.5% 50.3%
Energy Generation (GWh) 25,125 24,039 23,068 22,205 22,116 22,912 22,834 22,720 22,847 23,190
Heat Rate (Btu/kWh)(4) 9,736 9,716 9,655 9,700 9,709 9,698 9,694 9,680 9,686 9,683
Fuel Consumption (BBtu) 244,605 233,562 222,736 215,397 214,721 222,190 221,360 219,944 221,296 224,549
SO\2\ Allowances Purchased
(Tons)(5) 84,300 77,031 75,310 61,076 60,221 67,094 67,469 68,004 68,562 79,741
NO\X\ Allowances Purchased
(Tons)(6) 7,669 1,880 5,843 3,999 3,263 1,527 1,218 (1,104) (1,227) (1,098)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 57.80 53.11 49.07 47.51 46.46 49.21 50.74 50.97 52.15 53.54
Fuel Price ($/MMBtu)(9) $ 2.19 2.08 1.93 1.98 1.88 1.92 1.95 1.98 2.03 2.07
SO\2\ Allowances
($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances
($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point $ 630,933 561,827 478,221 458,823 438,703 470,387 490,281 478,898 494,217 514,404
Dickerson $ 237,088 207,371 195,508 181,158 179,766 191,477 196,002 197,726 203,967 208,358
Morgantown $ 414,647 363,190 329,446 300,376 296,764 344,321 344,156 350,943 358,902 376,006
Potomac River $ 169,522 144,298 128,782 114,685 112,338 121,287 128,102 130,412 134,372 142,891
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,452,190 1,276,686 1,131,958 1,055,042 1,027,571 1,127,472 1,158,541 1,157,979 1,191,457 1,241,658
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 284,808 248,017 206,342 219,554 193,688 203,677 201,037 200,828 208,761 220,204
Emissions Allowances $ 2,915 (483) 3,338 2,665 2,341 1,158 780 (868) (1,163) 269
Operations & Maintenance $ 38,660 34,187 32,403 33,521 34,453 35,531 36,686 37,699 38,629 40,019
Other (13) $ 18,226 18,700 19,186 19,685 20,197 20,722 21,260 21,813 22,381 22,962
Dickerson
Fuel $ 75,634 70,005 65,552 62,247 62,204 63,336 64,880 65,087 68,053 66,712
Emissions Allowances $ 5,293 4,785 5,439 4,229 3,410 3,590 3,704 3,671 3,913 4,137
Operations & Maintenance $ 22,935 20,868 22,035 20,521 21,107 21,666 22,286 22,859 23,477 24,006
Other (13) $ 9,720 9,973 10,232 10,498 10,771 11,051 11,338 11,633 11,935 12,246
Morgantown
Fuel $ 113,597 109,746 105,456 97,783 100,133 108,863 110,670 113,059 114,903 118,171
Emissions Allowances $ 10,303 8,024 13,568 10,196 9,335 8,661 8,910 6,940 7,109 7,535
Operations & Maintenance $ 22,263 20,272 20,552 19,417 19,920 21,101 21,641 22,214 22,670 23,217
Other (13) $ 9,560 9,808 10,064 10,325 10,594 10,869 11,152 11,442 11,739 12,044
Potomac River
Fuel $ 61,657 57,597 52,450 46,621 47,384 49,848 54,197 55,666 57,259 60,801
Emissions Allowances $ 1,804 1,409 2,987 802 471 698 590 438 458 1,006
Operations & Maintenance $ 27,684 25,608 24,743 24,712 25,184 26,133 27,085 27,914 28,567 29,655
Other (13) $ 2,176 2,233 2,290 2,350 2,411 2,474 2,538 2,604 2,672 2,742
Production Service Center
(14) $ 17,740 18,201 18,675 19,160 19,658 20,169 20,694 21,232 21,784 22,350
Administration & General
(15) $ 6,852 7,030 7,213 7,400 7,593 7,790 7,993 8,201 8,414 8,633
---------- -------- --------- --------- --------- --------- --------- -------- --------- ---------
Total Operating Expenses $ 731,828 665,981 622,526 611,685 590,855 617,336 627,441 632,432 651,562 676,708
NET OPERATING REVENUES
($000) $ 720,362 610,705 509,432 443,358 436,716 510,136 531,100 525,546 539,895 564,951
CAPITAL EXPENDITURES
($000)(16) $ 48,321 49,364 33,232 58,128 55,798 80,912 79,600 77,846 46,448 46,304
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 672,041 561,341 476,200 385,230 380,918 429,224 451,500 447,700 493,447 518,647
FIXED CHARGES ($000)(17) $ 196,065 170,468 150,720 121,500 116,005 105,671 112,348 120,723 142,339 140,220
ANNUAL FIXED CHARGE
COVERAGE (18) 3.43 3.29 3.16 3.17 3.28 4.06 4.02 3.71 3.47 3.70
AVERAGE FIXED CHARGE
COVERAGE (19) 5.62
A-3
Exhibit A-1
Mirant Mid-Atlantic Generating
Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018
- --------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- -----------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 51.0% 50.5% 50.5% 50.3% 50.5% 50.2% 50.1% 50.2%
Energy Generation (GWh) 23,505 23,283 23,301 23,214 23,313 23,144 23,125 23,162
Heat Rate (Btu/kWh)(4) 9,697 9,689 9,690 9,688 9,683 9,676 9,679 9,676
Fuel Consumption (BBtu) 227,931 225,583 225,797 224,892 225,729 223,934 223,822 224,123
SO\2\ Allowances Purchased
(Tons)(5) 80,682 80,438 80,116 80,313 81,360 81,163 80,632 81,155
NO\X\ Allowances Purchased
(Tons)(6) (894) (886) (1,036) (1,042) (1,025) (1,173) (1,136) (1,127)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 55.54 56.61 58.77 59.63 60.72 62.09 63.74 65.93
Fuel Price ($/MMBtu)(9) $ 2.15 2.18 2.24 2.29 2.34 2.38 2.45 2.51
SO\2\ Allowances ($/Ton)(10) $ 194 199 204 209 215 220 226 232
NO\X\ Allowances ($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point $ 538,620 541,669 563,206 567,715 577,831 581,556 596,300 617,974
Dickerson $ 223,343 223,771 233,287 235,327 241,374 246,091 251,962 260,658
Morgantown $ 393,697 401,168 415,598 421,387 431,819 441,657 453,438 469,707
Potomac River $ 149,757 151,330 157,294 159,763 164,625 167,684 172,237 178,804
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,305,417 1,317,938 1,369,384 1,384,193 1,415,649 1,436,988 1,473,937 1,527,143
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 231,070 230,248 237,481 241,764 247,487 246,635 254,751 261,428
Emissions Allowances $ 306 328 127 309 215 (215) (93) (8)
Operations & Maintenance $ 41,115 41,718 42,652 43,804 45,086 46,060 47,355 48,584
Other (13) $ 23,560 24,171 24,801 25,445 26,107 26,786 27,482 28,196
Dickerson
Fuel $ 72,995 72,554 75,677 75,054 77,822 79,324 80,831 83,062
Emissions Allowances $ 4,481 4,526 4,534 4,539 4,861 4,990 4,902 5,084
Operations & Maintenance $ 24,704 25,315 25,985 26,635 27,357 28,057 28,771 29,525
Other (13) $ 12,564 12,891 13,226 13,570 13,923 14,285 14,656 15,037
Morgantown
Fuel $ 122,400 125,663 128,166 130,313 132,695 136,783 141,258 143,505
Emissions Allowances $ 7,942 8,209 8,397 8,578 8,871 9,168 9,495 9,678
Operations & Maintenance $ 23,839 24,462 25,090 25,745 26,426 27,118 27,817 28,544
Other (13) $ 12,358 12,679 13,009 13,346 13,694 14,049 14,415 14,790
Potomac River
Fuel $ 62,898 63,883 65,472 67,066 69,218 70,549 72,284 74,524
Emissions Allowances $ 1,142 1,136 1,133 1,161 1,282 1,304 1,305 1,403
Operations & Maintenance $ 30,431 31,128 31,749 32,785 33,488 34,453 35,342 36,438
Other (13) $ 2,812 2,886 2,961 3,038 3,117 3,198 3,281 3,367
Production Service Center
(14) $ 22,931 23,528 24,139 24,767 25,411 26,071 26,749 27,445
Administration & General
(15) $ 8,857 9,087 9,324 9,566 9,815 10,070 10,332 10,600
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 706,406 714,413 733,924 747,485 766,875 778,684 800,934 821,204
NET OPERATING REVENUES
($000) $ 599,011 603,525 635,459 636,708 648,774 658,304 673,003 705,939
CAPITAL EXPENDITURES
($000)(16) $ 53,915 61,801 55,751 57,870 78,064 52,377 55,481 92,587
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 545,096 541,724 579,708 578,838 570,710 605,927 617,522 613,352
FIXED CHARGES ($000)(17) $ 134,000 131,500 138,000 131,000 110,000 150,000 144,000 105,000
ANNUAL FIXED CHARGE
COVERAGE (18) 4.07 4.12 4.20 4.42 5.19 4.04 4.29 5.84
AVERAGE FIXED CHARGE
COVERAGE (19) 5.62
Year Ending December 31, 2019 2020
- --------------------------- ---------- ----------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266
Summer Capacity (MW) 5,154 5,154
Availability (%)(2) 88.0% 88.0%
Capacity Factor (%)(3) 50.2% 50.5%
Energy Generation (GWh) 23,140 23,314
Heat Rate (Btu/kWh)(4) 9,682 9,686
Fuel Consumption (BBtu) 224,046 225,824
SO\2\ Allowances Purchased
(Tons)(5) 80,764 81,901
NO\X\ Allowances Purchased
(Tons)(6) (1,132) (1,031)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60
Market Electricity Price
($/MWh)(8) 67.31 68.73
Fuel Price ($/MMBtu)(9) 2.58 2.65
SO\2\ Allowances ($/Ton)(10) 238 244
NO\X\ Allowances ($/Ton)(11) 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point 631,490 648,289
Dickerson 267,191 276,761
Morgantown 476,834 489,357
Potomac River 182,024 187,928
--------- ---------
Total Operating Revenues 1,557,539 1,602,335
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel 269,582 279,154
Emissions Allowances (26) 16
Operations & Maintenance 49,753 51,587
Other (13) 28,930 29,682
Dickerson
Fuel 86,397 90,559
Emissions Allowances 5,213 5,647
Operations & Maintenance 30,306 31,134
Other (13) 15,428 15,829
Morgantown
Fuel 146,613 150,860
Emissions Allowances 9,855 10,240
Operations & Maintenance 29,277 30,059
Other (13) 15,175 15,569
Potomac River
Fuel 75,830 78,331
Emissions Allowances 1,429 1,526
Operations & Maintenance 37,224 38,534
Other (13) 3,454 3,543
Production Service Center
(14) 28,158 28,890
Administration & General
(15) 10,876 11,159
--------- ---------
Total Operating Expenses
843,474 872,318
NET OPERATING REVENUES
($000) 714,066 730,017
CAPITAL EXPENDITURES
($000)(16) 56,235 84,968
CASH AVAILABLE
FOR FIXED CHARGES ($000) 657,831 645,049
FIXED CHARGES ($000)(17) 139,500 105,000
ANNUAL FIXED CHARGE
COVERAGE (18) 4.72 6.14
AVERAGE FIXED CHARGE
COVERAGE (19)
A-4
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027
- ------------------------ ----------- ---------- ---------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 50.5% 50.5% 50.5% 50.5% 50.5% 50.5% 50.5%
Energy Generation (GWh) 23,314 23,314 23,314 23,314 23,314 23,314 23,314
Heat Rate (Btu/kWh)(4) 9,686 9,686 9,686 9,686 9,686 9,686 9,686
Fuel Consumption (BBtu) 225,824 225,824 225,824 225,824 225,824 225,824 225,824
SO\2\ Allowances Purchased (Tons)(5) 81,901 81,901 81,901 81,901 81,901 81,901 81,901
NO\X\ Allowances Purchased (Tons)(6) (1,031) (1,031) (1,031) (1,031) (1,031) (1,031) (1,031)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price ($/MWh)(8) $ 70.47 72.26 74.10 76.00 77.95 79.96 82.03
Fuel Price ($/MMBtu)(9) $ 2.72 2.79 2.87 2.94 3.02 3.10 3.19
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990
OPERATING REVENUES ($000)
Market Electricity Revenues
Chalk Point $ 664,427 681,024 698,094 715,649 733,704 752,273 771,371
Dickerson $ 282,661 288,708 294,907 301,260 307,773 314,448 321,290
Morgantown $ 503,215 517,528 532,315 547,597 563,398 579,740 596,649
Potomac River $ 192,610 197,409 202,328 207,369 212,536 217,832 223,259
---------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,642,913 1,684,669 1,727,643 1,771,876 1,817,410 1,864,292 1,912,569
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 287,122 295,320 303,753 312,430 321,357 330,541 339,990
Emissions Allowances $ 17 17 19 19 19 20 20
Operations & Maintenance $ 52,902 53,811 55,001 56,537 58,192 59,591 61,257
Other (13) $ 30,453 31,245 32,058 32,891 33,746 34,623 35,524
Dickerson
Fuel $ 92,926 95,355 97,849 100,408 103,034 105,730 108,496
Emissions Allowances $ 5,795 5,945 6,100 6,259 6,421 6,589 6,759
Operations & Maintenance $ 31,944 32,774 33,627 34,500 35,398 36,318 37,263
Other (13) $ 16,242 16,663 17,097 17,541 17,997 18,465 18,945
Morgantown
Fuel $ 154,636 158,508 162,476 166,545 170,715 174,991 179,374
Emissions Allowances $ 10,506 10,779 11,059 11,348 11,643 11,945 12,256
Operations & Maintenance $ 30,840 31,641 32,464 33,308 34,173 35,063 35,974
Other (13) $ 15,973 16,389 16,816 17,252 17,701 18,161 18,634
Potomac River
Fuel $ 80,098 81,904 83,752 85,641 87,573 89,548 91,568
Emissions Allowances $ 1,565 1,607 1,648 1,691 1,735 1,780 1,826
Operations & Maintenance $ 39,459 40,415 41,211 42,544 43,383 44,657 45,799
Other (13) $ 3,635 3,730 3,827 3,927 4,029 4,134 4,242
Production Service Center (14) $ 29,642 30,412 31,203 32,014 32,847 33,701 34,577
Administration & General (15) $ 11,449 11,746 12,052 12,365 12,687 13,017 13,355
---------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 895,204 918,262 942,011 967,219 992,650 1,018,873 1,045,859
NET OPERATING REVENUES ($000) $ 747,710 766,408 785,632 804,657 824,761 845,419 866,710
CAPITAL EXPENDITURES ($000)(16) $ 83,300 69,768 68,116 89,506 89,981 63,442 87,592
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 664,410 696,640 717,516 715,151 734,780 781,977 779,118
FIXED CHARGES ($000)(17) $ 41,633 35,616 22,401 16,142 16,238 11,518 74,250
ANNUAL FIXED CHARGE COVERAGE (18) 15.96 19.56 32.03 44.30 45.25 67.89 10.49
AVERAGE FIXED CHARGE COVERAGE (19) 5.62
Year Ending December 31, 2028
- ------------------------ ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266
Summer Capacity (MW) 5,154
Availability (%)(2) 88.0%
Capacity Factor (%)(3) 50.5%
Energy Generation (GWh) 23,314
Heat Rate (Btu/kWh)(4) 9,686
Fuel Consumption (BBtu) 225,824
SO\2\ Allowances Purchased (Tons)(5) 81,901
NO\X\ Allowances Purchased (Tons)(6) (1,031)
COMMODITY PRICES
General Inflation (%)(7) 2.60
Market Electricity Price ($/MWh)(8) 84.17
Fuel Price ($/MMBtu)(9) 3.27
SO\2\ Allowances ($/Ton)(10) 300
NO\X\ Allowances ($/Ton)(11) 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues
Chalk Point 791,012
Dickerson 328,303
Morgantown 614,153
Potomac River 228,822
---------
Total Operating Revenues 1,962,290
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel 349,712
Emissions Allowances 21
Operations & Maintenance 62,849
Other (13) 36,448
Dickerson
Fuel 111,336
Emissions Allowances 6,936
Operations & Maintenance 38,232
Other (13) 19,438
Morgantown
Fuel 183,868
Emissions Allowances 12,574
Operations & Maintenance 36,909
Other (13) 19,118
Potomac River
Fuel 93,633
Emissions Allowances 1,873
Operations & Maintenance 47,143
Other (13) 4,352
Production Service Center (14) 35,476
Administration & General (15) 13,702
---------
Total Operating Expenses 1,073,619
NET OPERATING REVENUES ($000) 888,671
CAPITAL EXPENDITURES ($000)(16) 107,879
CASH AVAILABLE
FOR FIXED CHARGES ($000) 780,792
FIXED CHARGES ($000)(17) 80,000
ANNUAL FIXED CHARGE COVERAGE (18) 9.76
AVERAGE FIXED CHARGE COVERAGE (19)
A-5
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------------------ -------- ------- ------- ------- ------- ------- ------- ------- ------- -------
CHALK POINT FACILITY
- --------------------
PERFORMANCE
Average Annual
Capacity (MW)(1) 2,468 2,468 2,468 2,468 2,468 2,468 2,468 2,468 2,468 2,468
Summer Capacity (MW) 2,423 2,423 2,423 2,423 2,423 2,423 2,423 2,423 2,423 2,423
Plant Availability (% )(2) 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0%
Plant Capacity Factor (%)(3) 40.1% 38.5% 36.8% 39.0% 38.5% 39.2% 38.0% 37.4% 37.6% 38.4%
Energy Generation(GWh) 8,674 8,325 7,967 8,424 8,334 8,477 8,222 8,086 8,137 8,301
Net Heat Rate(Btu/kWh)(4) 9,874 9,856 9,777 9,873 9,877 9,883 9,879 9,854 9,864 9,860
Fuel Consumption (BBtu) 85,646 82,057 77,893 83,173 82,310 83,775 81,225 79,680 80,262 81,842
SO\2\ Allowances Purchased
(Tons)(5) 10,284 8,693 10,505 7,973 7,722 8,242 7,792 7,878 8,001 15,833
NO\X\ Allowances Purchased
(Tons)(6) 1,372 (1,821) 730 687 622 (142) (326) (1,243) (1,400) (1,409)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity ($/MWh)(8) $ 72.74 67.48 60.03 54.46 52.64 55.49 59.63 59.23 60.74 61.97
Fuel ($/MMBtu)(9) $ 3.33 3.02 2.65 2.64 2.35 2.43 2.48 2.52 2.60 2.69
SO\2\ Allowances ($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances ($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES ($000)
Market Electricity Revenues $630,933 561,827 478,221 458,823 438,703 470,387 490,281 478,898 494,217 514,404
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $630,933 561,827 478,221 458,823 438,703 470,387 490,281 478,898 494,217 514,404
OPERATING EXPENSES ($000)(12)
Fuel Costs $284,808 248,017 206,342 219,554 193,688 203,677 201,037 200,828 208,761 220,204
Emissions Allowances $ 2,915 (483) 3,338 2,665 2,341 1,158 780 (868) (1,163) 269
Operating and Maintenance $ 38,660 34,187 32,403 33,521 34,453 35,531 36,686 37,699 38,629 40,019
Insurance $ 1,810 1,857 1,905 1,955 2,006 2,058 2,111 2,166 2,223 2,280
Property Taxes $ 16,416 16,843 17,281 17,730 18,191 18,664 19,149 19,647 20,158 20,682
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $344,610 300,421 261,269 275,425 250,680 261,087 259,763 259,472 268,608 283,454
NET OPERATING REVENUES ($000) $286,323 261,406 216,952 183,397 188,023 209,299 230,517 219,426 225,609 230,950
CAPITAL EXPENDITURES ($000) $ 11,676 13,625 9,515 18,770 15,108 28,182 21,802 27,491 12,586 10,000
A-6
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------------------ -------- ------- ------- ------- ------- ------- ------- ------- ------- -------
CHALK POINT FACILITY
- --------------------
PERFORMANCE
Average Annual
Capacity (MW)(1) 2,468 2,468 2,468 2,468 2,468 2,468 2,468 2,468 2,468 2,468
Summer Capacity (MW) 2,423 2,423 2,423 2,423 2,423 2,423 2,423 2,423 2,423 2,423
Plant Availability (%)(2) 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0%
Plant Capacity Factor (%)(3) 38.9% 38.2% 38.3% 38.0% 38.0% 37.3% 37.3% 37.3% 37.3% 37.5%
Energy Generation(GWh) 8,420 8,255 8,272 8,213 8,215 8,058 8,070 8,066 8,066 8,116
Net Heat Rate(Btu/kWh)(4) 9,868 9,860 9,850 9,862 9,849 9,833 9,834 9,833 9,845 9,850
Fuel Consumption (BBtu) 83,085 81,399 81,479 80,999 80,910 79,229 79,355 79,319 79,408 79,940
SO\2\ Allowances Purchased
(Tons)(5) 16,084 15,972 15,913 15,865 16,077 15,929 15,816 15,907 15,808 16,065
NO\X\ Allowances Purchased
(Tons)(6) (1,419) (1,400) (1,495) (1,407) (1,474) (1,653) (1,586) (1,559) (1,556) (1,564)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity ($/MWh)(8) $ 63.97 65.61 68.09 69.12 70.34 72.17 73.89 76.61 78.29 79.88
Fuel ($/MMBtu)(9) $ 2.78 2.83 2.91 2.98 3.06 3.11 3.21 3.30 3.39 3.49
SO\2\ Allowances ($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances ($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity Revenues $538,620 541,669 563,206 567,715 577,831 581,556 596,300 617,974 631,490 648,289
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $538,620 541,669 563,206 567,715 577,831 581,556 596,300 617,974 631,490 648,289
OPERATING EXPENSES ($000)(12)
Fuel Costs $231,070 230,248 237,481 241,764 247,487 246,635 254,751 261,428 269,582 279,154
Emissions Allowances $ 306 328 127 309 215 (215) (93) (8) (26) 16
Operating and Maintenance $ 41,115 41,718 42,652 43,804 45,086 46,060 47,355 48,584 49,753 51,587
Insurance $ 2,340 2,400 2,463 2,527 2,593 2,660 2,729 2,800 2,873 2,948
Property Taxes $ 21,220 21,771 22,338 22,918 23,514 24,126 24,753 25,396 26,057 26,734
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $296,051 296,465 305,061 311,323 318,895 319,267 329,496 338,200 348,239 360,439
NET OPERATING REVENUES ($000) $242,570 245,204 258,145 256,392 258,935 262,289 266,804 279,774 283,252 287,850
CAPITAL EXPENDITURES ($000) $ 10,568 14,233 20,886 22,783 26,480 12,862 15,869 36,063 13,598 26,602
A-7
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ -------- ------- ------- ------- ------- ------- ------- -------
CHALK POINT FACILITY
- --------------------
PERFORMANCE
Average Annual Capacity (MW)(1) 2,468 2,468 2,468 2,468 2,468 2,468 2,468 2,468
Summer Capacity (MW) 2,423 2,423 2,423 2,423 2,423 2,423 2,423 2,423
Plant Availability (%)(2) 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0%
Plant Capacity Factor (%)(3) 37.5% 37.5% 37.5% 37.5% 37.5% 37.5% 37.5% 37.5%
Energy Generation (GWh) 8,116 8,116 8,116 8,116 8,116 8,116 8,116 8,116
Net Heat Rate (Btu/kWh)(4) 9,850 9,850 9,850 9,850 9,850 9,850 9,850 9,850
Fuel Consumption (BBtu) 79,940 79,940 79,940 79,940 79,940 79,940 79,940 79,940
SO\2\ Allowances Purchased (Tons)(5) 16,065 16,065 16,065 16,065 16,065 16,065 16,065 16,065
NO\X\ Allowances Purchased (Tons)(6) (1,564) (1,564) (1,564) (1,564) (1,564) (1,564) (1,564) (1,564)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity ($/MWh)(8) $ 81.87 83.91 86.02 88.18 90.40 92.69 95.05 97.47
Fuel ($/MMBtu)(9) $ 3.59 3.69 3.80 3.91 4.02 4.13 4.25 4.37
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues $664,427 681,024 698,094 715,649 733,704 752,273 771,371 791,012
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $664,427 681,024 698,094 715,649 733,704 752,273 771,371 791,012
OPERATING EXPENSES ($000)(12)
Fuel Costs $287,122 295,320 303,753 312,430 321,357 330,541 339,990 349,712
Emissions Allowances $ 17 17 19 19 19 20 20 21
Operating and Maintenance $ 52,902 53,811 55,001 56,537 58,192 59,591 61,257 62,849
Insurance $ 3,024 3,103 3,184 3,266 3,351 3,438 3,528 3,620
Property Taxes $ 27,429 28,142 28,874 29,625 30,395 31,185 31,996 32,828
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $370,494 380,393 390,830 401,877 413,314 424,775 436,791 449,029
NET OPERATING REVENUES ($000) $293,933 300,631 307,263 313,772 320,390 327,498 334,580 341,982
CAPITAL EXPENDITURES ($000) $ 16,597 15,384 26,997 32,623 30,973 16,626 23,940 43,101
A-8
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------------------ -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
DICKERSON FACILITY
- ------------------
PERFORMANCE
Average Annual Capacity (MW)(1) 869 869 869 869 869 869 869 869 869 869
Summer Capacity (MW) 837 837 837 837 837 837 837 837 837 837
Plant Availability (%)(2) 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0%
Plant Capacity Factor (%)(3) 58.7% 56.6% 55.1% 51.3% 51.6% 52.1% 52.3% 52.0% 52.6% 52.3%
Energy Generation (GWh) 4,465 4,310 4,192 3,905 3,928 3,967 3,979 3,957 4,004 3,979
Net Heat Rate (Btu/kWh)(4) 9,734 9,722 9,702 9,746 9,769 9,754 9,752 9,737 9,750 9,715
Fuel Consumption (BBtu) 43,466 41,898 40,669 38,061 38,371 38,694 38,801 38,535 39,043 38,653
SO\2\ Allowances Purchased
(Tons)(5) 18,320 17,171 16,597 13,539 13,265 13,903 13,980 14,081 14,237 14,706
NO\X\ Allowances Purchased
(Tons)(6) 2,545 2,142 1,225 1,018 709 699 703 623 685 703
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity ($/MWh)(8) $ 53.10 48.12 46.64 46.39 45.77 48.27 49.26 49.96 50.94 52.37
Fuel ($/MMBtu)(9) $ 1.74 1.67 1.61 1.64 1.62 1.64 1.67 1.69 1.74 1.73
SO\2\ Allowances ($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances ($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES ($000)
Market Electricity Revenues $237,088 207,371 195,508 181,158 179,766 191,477 196,002 197,726 203,967 208,358
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $237,088 207,371 195,508 181,158 179,766 191,477 196,002 197,726 203,967 208,358
OPERATING EXPENSES ($000)(12)
Fuel Costs $ 75,634 70,005 65,552 62,247 62,204 63,336 64,880 65,087 68,053 66,712
Emissions Allowances $ 5,293 4,785 5,439 4,229 3,410 3,590 3,704 3,671 3,913 4,137
Operating and Maintenance $ 22,935 20,868 22,035 20,521 21,107 21,666 22,286 22,859 23,477 24,006
Insurance $ 1,071 1,099 1,127 1,157 1,187 1,218 1,249 1,282 1,315 1,349
Property Taxes $ 8,649 8,874 9,105 9,341 9,584 9,833 10,089 10,351 10,620 10,897
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $113,582 105,632 103,258 97,494 97,492 99,643 102,207 103,250 107,378 107,100
NET OPERATING REVENUES ($000) $123,507 101,739 92,251 83,664 82,274 91,834 93,795 94,476 96,588 101,257
CAPITAL EXPENDITURES ($000) $ 21,251 20,820 12,735 16,906 10,655 13,048 14,653 9,201 11,210 14,705
A-9
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------------------ -------- ------- ------- ------- ------- -------- ------- ------- ------- -------
DICKERSON FACILITY
- ------------------
PERFORMANCE
Average Annual Capacity
(MW)(1) 869 869 869 869 869 869 869 869 869 869
Summer Capacity (MW) 837 837 837 837 837 837 837 837 837 837
Plant Availability (%)(2) 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0%
Plant Capacity Factor (%)(3) 53.8% 53.2% 53.4% 52.9% 53.4% 53.2% 53.0% 53.1% 53.3% 53.9%
Energy Generation (GWh) 4,093 4,046 4,064 4,026 4,068 4,052 4,033 4,040 4,056 4,106
Net Heat Rate (Btu/kWh)(4) 9,756 9,736 9,752 9,728 9,730 9,729 9,725 9,722 9,733 9,744
Fuel Consumption (BBtu) 39,934 39,391 39,631 39,169 39,580 39,427 39,217 39,281 39,482 40,005
SO\2\ Allowances Purchased
(Tons)(5) 14,886 14,851 14,736 14,831 15,113 15,056 14,914 14,969 14,940 15,197
NO\X\ Allowances Purchased
(Tons)(6) 804 773 731 669 734 741 661 679 680 775
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
($/MWh)(8) $ 54.56 55.31 57.41 58.45 59.33 60.73 62.48 64.51 65.87 67.41
Fuel ($/MMBtu)(9) $ 1.83 1.84 1.91 1.92 1.97 2.01 2.06 2.11 2.19 2.26
SO\2\ Allowances
($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances
($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity
Revenues $223,343 223,771 233,287 235,327 241,374 246,091 251,962 260,658 267,191 276,761
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $223,343 223,771 233,287 235,327 241,374 246,091 251,962 260,658 267,191 276,761
OPERATING EXPENSES
($000)(12)
Fuel Costs $ 72,995 72,554 75,677 75,054 77,822 79,324 80,831 83,062 86,397 90,559
Emissions Allowances $ 4,481 4,526 4,534 4,539 4,861 4,990 4,902 5,084 5,213 5,647
Operating and Maintenance $ 24,704 25,315 25,985 26,635 27,357 28,057 28,771 29,525 30,306 31,134
Insurance $ 1,384 1,420 1,457 1,495 1,534 1,574 1,615 1,657 1,700 1,744
Property Taxes $ 11,180 11,471 11,769 12,075 12,389 12,711 13,041 13,380 13,728 14,085
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $114,744 115,287 119,422 119,798 123,963 126,655 129,160 132,709 137,344 143,169
NET OPERATING
REVENUES ($000) $108,599 108,485 113,864 115,530 117,411 119,436 122,802 127,949 129,846 133,592
CAPITAL EXPENDITURES ($000) $ 24,526 25,405 15,234 12,934 16,327 17,784 11,592 17,200 18,527 30,640
A-10
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ -------- ------- ------- ------- ------- ------- ------- -------
DICKERSON FACILITY
- ------------------
PERFORMANCE
Average Annual Capacity
(MW)(1) 869 869 869 869 869 869 869 869
Summer Capacity (MW) 837 837 837 837 837 837 837 837
Plant Availability (%)(2) 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0% 86.0%
Plant Capacity Factor (%)(3) 53.9% 53.9% 53.9% 53.9% 53.9% 53.9% 53.9% 53.9%
Energy Generation (GWh) 4,106 4,106 4,106 4,106 4,106 4,106 4,106 4,106
Net Heat Rate (Btu/kWh)(4) 9,744 9,744 9,744 9,744 9,744 9,744 9,744 9,744
Fuel Consumption (BBtu) 40,005 40,005 40,005 40,005 40,005 40,005 40,005 40,005
SO\2\ Allowances Purchased
(Tons)(5) 15,197 15,197 15,197 15,197 15,197 15,197 15,197 15,197
NO\X\ Allowances Purchased
(Tons)(6) 775 775 775 775 775 775 775 775
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
($/MWh)(8) $ 68.84 70.32 71.83 73.37 74.96 76.59 78.25 79.96
Fuel ($/MMBtu)(9) $ 2.32 2.38 2.45 2.51 2.58 2.64 2.71 2.78
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues $282,661 288,708 294,907 301,260 307,773 314,448 321,290 328,303
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $282,661 288,708 294,907 301,260 307,773 314,448 321,290 328,303
OPERATING EXPENSES ($000)(12)
Fuel Costs $ 92,926 95,355 97,849 100,408 103,034 105,730 108,496 111,336
Emissions Allowances $ 5,795 5,945 6,100 6,259 6,421 6,589 6,759 6,936
Operating and Maintenance $ 31,944 32,774 33,627 34,500 35,398 36,318 37,263 38,232
Insurance $ 1,790 1,836 1,884 1,933 1,983 2,035 2,087 2,142
Property Taxes $ 14,452 14,827 15,213 15,608 16,014 16,430 16,858 17,296
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $146,906 150,738 154,672 158,707 162,850 167,101 171,463 175,941
NET OPERATING REVENUES
($000) $135,755 137,971 140,235 142,553 144,923 147,346 149,827 152,363
CAPITAL EXPENDITURES
($000) $ 37,341 30,901 15,745 22,809 19,013 18,726 21,560 19,973
A-11
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------------------ -------- ------- ------- ------- ------- ------- ------- ------- ------- -------
MORGANTOWN FACILITY
- -------------------
PERFORMANCE
Average Annual Capacity
(MW)(1) 1,447 1,447 1,447 1,447 1,447 1,447 1,447 1,447 1,447 1,447
Summer Capacity (MW) 1,412 1,412 1,412 1,412 1,412 1,412 1,412 1,412 1,412 1,412
Plant Availability
(%)(2) 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0%
Plant Capacity Factor
(%)(3) 66.4% 64.2% 63.1% 57.9% 57.8% 62.1% 61.9% 62.1% 62.3% 63.0%
Energy Generation (GWh) 8,419 8,134 7,997 7,336 7,331 7,871 7,848 7,876 7,890 7,988
Net Heat Rate (Btu/kWh)(4) 9,118 9,118 9,090 9,094 9,105 9,101 9,102 9,102 9,099 9,097
Fuel Consumption (BBtu) 76,762 74,168 72,694 66,708 66,752 71,632 71,434 71,690 71,788 72,666
SO\2\ Allowances Purchased
(Tons)(5) 47,740 45,020 44,239 37,808 37,570 42,845 42,596 42,868 43,057 43,989
NO\X\ Allowances Purchased
(Tons)(6) 3,142 1,095 2,862 2,035 1,818 776 814 (412) (436) (403)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
($/MWh)(8) $ 49.25 44.65 41.20 40.95 40.48 43.74 43.85 44.56 45.49 47.07
Fuel ($/MMBtu)(9) $ 1.48 1.48 1.45 1.47 1.50 1.52 1.55 1.58 1.60 1.63
SO\2\ Allowances
($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances
($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES ($000)
Market Electricity
Revenues $414,647 363,190 329,446 300,376 296,764 344,321 344,156 350,943 358,902 376,006
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating
Revenues $414,647 363,190 329,446 300,376 296,764 344,321 344,156 350,943 358,902 376,006
OPERATING EXPENSES
($000)(12)
Fuel Costs $113,597 109,746 105,456 97,783 100,133 108,863 110,670 113,059 114,903 118,171
Emissions Allowances $ 10,303 8,024 13,568 10,196 9,335 8,661 8,910 6,940 7,109 7,535
Operating and Maintenance $ 22,263 20,272 20,552 19,417 19,920 21,101 21,641 22,214 22,670 23,217
Insurance $ 1,321 1,355 1,391 1,427 1,464 1,502 1,541 1,581 1,622 1,664
Property Taxes $ 8,239 8,453 8,673 8,898 9,130 9,367 9,611 9,861 10,117 10,380
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $155,724 147,850 149,641 137,721 139,982 149,494 152,373 153,656 156,421 160,967
NET OPERATING REVENUES
($000) $258,923 215,340 179,805 162,655 156,782 194,827 191,782 197,287 202,481 215,039
CAPITAL EXPENDITURES
($000) $ 10,386 8,552 7,233 16,596 21,814 29,966 32,347 31,082 16,870 16,501
A-12
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------------------ -------- ------- ------- ------- ------- ------- ------- ------- ------- -------
MORGANTOWN FACILITY
- -------------------
PERFORMANCE
Average Annual Capacity
(MW)(1) 1,447 1,447 1,447 1,447 1,447 1,447 1,447 1,447 1,447 1,447
Summer Capacity (MW) 1,412 1,412 1,412 1,412 1,412 1,412 1,412 1,412 1,412 1,412
Plant Availability (%)(2) 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0%
Plant Capacity Factor (%)(3) 63.4% 63.5% 63.3% 63.4% 63.6% 63.7% 63.6% 63.6% 63.5% 63.8%
Energy Generation (GWh) 8,035 8,045 8,025 8,030 8,059 8,071 8,056 8,063 8,043 8,087
Net Heat Rate (Btu/kWh)(4) 9,104 9,107 9,108 9,103 9,097 9,100 9,108 9,100 9,099 9,098
Fuel Consumption (BBtu) 73,150 73,270 73,090 73,092 73,306 73,446 73,374 73,374 73,186 73,572
SO\2\ Allowances Purchased
(Tons)(5) 44,293 44,328 44,139 44,270 44,656 44,720 44,420 44,647 44,482 44,920
NO\X\Allowances Purchased
(Tons)(6) (326) (300) (293) (324) (330) (306) (239) (288) (302) (293)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
($/MWh)(8) $ 49.00 49.86 51.79 52.48 53.58 54.72 56.28 58.25 59.28 60.51
Fuel ($/MMBtu)(9) $ 1.67 1.72 1.75 1.78 1.81 1.86 1.93 1.96 2.00 2.05
SO\2\ Allowances
($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances
($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity
Revenues $393,697 401,168 415,598 421,387 431,819 441,657 453,438 469,707 476,834 489,357
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $393,697 401,168 415,598 421,387 431,819 441,657 453,438 469,707 476,834 489,357
OPERATING EXPENSES ($000)(12)
Fuel Costs $122,400 125,663 128,166 130,313 132,695 136,783 141,258 143,505 146,613 150,860
Emissions Allowances $ 7,942 8,209 8,397 8,578 8,871 9,168 9,495 9,678 9,855 10,240
Operating and Maintenance $ 23,839 24,462 25,090 25,745 26,426 27,118 27,817 28,544 29,277 30,059
Insurance $ 1,708 1,752 1,798 1,844 1,892 1,941 1,992 2,044 2,097 2,151
Property Taxes $ 10,650 10,927 11,211 11,502 11,802 12,108 12,423 12,746 13,078 13,418
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $166,539 171,013 174,662 177,982 181,686 187,119 192,985 196,517 200,919 206,728
NET OPERATING REVENUES ($000) $227,158 230,155 240,935 243,406 250,133 254,539 260,453 273,190 275,915 282,629
CAPITAL EXPENDITURES ($000) $ 13,044 14,659 14,785 14,583 26,169 11,307 18,215 33,721 17,233 21,755
A-13
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ -------- ------- ------- ------- ------- ------- ------- -------
MORGANTOWN FACILITY
- -------------------
PERFORMANCE
Average Annual Capacity (MW)(1) 1,447 1,447 1,447 1,447 1,447 1,447 1,447 1,447
Summer Capacity (MW) 1,412 1,412 1,412 1,412 1,412 1,412 1,412 1,412
Plant Availability (%)(2) 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0% 85.0%
Plant Capacity Factor (%)(3) 63.8% 63.8% 63.8% 63.8% 63.8% 63.8% 63.8% 63.8%
Energy Generation (GWh) 8,087 8,087 8,087 8,087 8,087 8,087 8,087 8,087
Net Heat Rate (Btu/kWh)(4) 9,098 9,098 9,098 9,098 9,098 9,098 9,098 9,098
Fuel Consumption (BBtu) 73,572 73,572 73,572 73,572 73,572 73,572 73,572 73,572
SO\2\ Allowances Purchased (Tons)(5) 44,920 44,920 44,920 44,920 44,920 44,920 44,920 44,920
NO\X\ Allowances Purchased (Tons)(6) (293) (293) (293) (293) (293) (293) (293) (293)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity ($/MWh)(8) $ 62.23 64.00 65.83 67.72 69.67 71.69 73.78 75.95
Fuel ($/MMBtu)(9) $ 2.10 2.15 2.21 2.26 2.32 2.38 2.44 2.50
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues $503,215 517,528 532,315 547,597 563,398 579,740 596,649 614,153
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $503,215 517,528 532,315 547,597 563,398 579,740 596,649 614,153
OPERATING EXPENSES ($000)(12)
Fuel Costs $154,636 158,508 162,476 166,545 170,715 174,991 179,374 183,868
Emissions Allowances $ 10,506 10,779 11,059 11,348 11,643 11,945 12,256 12,574
Operating and Maintenance $ 30,840 31,641 32,464 33,308 34,173 35,063 35,974 36,909
Insurance $ 2,207 2,265 2,324 2,384 2,446 2,509 2,575 2,642
Property Taxes $ 13,766 14,124 14,492 14,868 15,255 15,652 16,059 16,476
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $211,955 217,317 222,815 228,452 234,232 240,160 246,238 252,469
NET OPERATING REVENUES ($000) $291,260 300,211 309,500 319,145 329,165 339,580 350,412 361,684
CAPITAL EXPENDITURES ($000) $ 21,895 13,783 19,111 24,288 28,248 14,615 29,418 37,563
A-14
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------------------ ----- ----- ----- ------ ------- ------- ------- ------- ------- -------
POTOMAC RIVER FACILITY
- ----------------------
PERFORMANCE
Average Annual
Capacity (MW)(1) 482 482 482 482 482 482 482 482 482 482
Summer Capacity (MW) 482 482 482 482 482 482 482 482 482 482
Plant
Availability (%)(2) 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0%
Plant Capacity
Factor (%)(3) 84.5% 77.4% 69.0% 60.1% 59.8% 61.5% 66.0% 66.3% 66.7% 69.2%
Energy Generation
(GWh) 3,566 3,270 2,913 2,540 2,524 2,597 2,786 2,801 2,815 2,923
Net Heat Rate
(Btu/kWh)(4) 10,861 10,838 10,807 10,810 10,813 10,817 10,734 10,725 10,729 10,737
Fuel
Consumption (BBtu) 38,731 35,439 31,480 27,455 27,288 28,089 29,900 30,039 30,203 31,388
SO\2\ Allowances
Purchased (Tons)(5) 7,957 6,146 3,969 1,755 1,663 2,104 3,100 3,176 3,267 5,213
NO\X\ Allowances
Purchased (Tons)(6) 610 463 1,026 259 115 195 27 (72) (76) 11
COMMODITY PRICES
General Inflation
(%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
($/MWh)(8) $ 47.54 44.13 44.21 45.16 44.51 46.71 45.99 46.56 47.73 48.88
Fuel ($/MMBtu)(9) $ 1.59 1.63 1.67 1.70 1.74 1.77 1.81 1.85 1.90 1.94
SO\2\ Allowances
($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances
($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING
REVENUES ($000)
Market
Electricity
Revenues $169,522 144,298 128,782 114,685 112,338 121,287 128,102 130,412 134,372 142,891
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating
Revenues $169,522 144,298 128,782 114,685 112,338 121,287 128,102 130,412 134,372 142,891
OPERATING EXPENSES
($000)(12)
Fuel Costs $ 61,657 57,597 52,450 46,621 47,384 49,848 54,197 55,666 57,259 60,801
Emissions
Allowances $ 1,804 1,409 2,987 802 471 698 590 438 458 1,006
Operating and
Maintenance $ 27,684 25,608 24,743 24,712 25,184 26,133 27,085 27,914 28,567 29,655
Insurance $ 500 513 526 540 554 568 583 598 614 630
Property Taxes $ 1,676 1,720 1,764 1,810 1,857 1,906 1,955 2,006 2,058 2,112
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating
Expenses $ 93,321 86,847 82,470 74,484 75,450 79,153 84,410 86,622 88,957 94,203
NET OPERATING
REVENUES ($000) $ 76,201 57,451 46,312 40,201 36,888 42,134 43,693 43,790 45,415 48,688
CAPITAL
EXPENDITURES ($000) $ 5,008 6,367 3,749 5,856 8,221 9,716 10,798 10,072 5,782 5,098
A-15
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------------------ -------- ------- ------- ------- ------- ------- ------- ------- ------- -------
POTOMAC RIVER FACILITY
- ------------------------
PERFORMANCE
Average Annual
Capacity (MW)(1) 482 482 482 482 482 482 482 482 482 482
Summer Capacity (MW) 482 482 482 482 482 482 482 482 482 482
Plant Availability
(%)(2) 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0%
Plant Capacity
Factor (%)(3) 70.0% 69.5% 69.6% 69.7% 70.4% 70.2% 70.3% 70.9% 70.5% 71.2%
Energy Generation
(GWh) 2,956 2,936 2,940 2,944 2,971 2,963 2,966 2,992 2,975 3,006
Net Heat Rate
(Btu/kWh)(4) 10,743 10,736 10,746 10,744 10,748 10,744 10,745 10,747 10,747 10,748
Fuel Consumption
(BBtu) 31,762 31,523 31,597 31,632 31,933 31,832 31,876 32,149 31,970 32,307
SO\2\ Allowances
Purchased
(Tons)(5) 5,419 5,288 5,328 5,348 5,513 5,458 5,482 5,632 5,534 5,719
NO\X\ Allowances
Purchased
(Tons)(6) 46 41 22 19 44 45 28 41 46 52
COMMODITY PRICES
General
Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
($/MWh)(8) $ 50.65 51.54 53.50 54.27 55.41 56.60 58.06 59.77 61.19 62.52
Fuel ($/MMBtu)(9) $ 1.98 2.03 2.07 2.12 2.17 2.22 2.27 2.32 2.37 2.42
SO\2\ Allowances
($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances
($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity
Revenues $149,757 151,330 157,294 159,763 164,625 167,684 172,237 178,804 182,024 187,928
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating
Revenues $149,757 151,330 157,294 159,763 164,625 167,684 172,237 178,804 182,024 187,928
OPERATING EXPENSES
($000)(12)
Fuel Costs $ 62,898 63,883 65,472 67,066 69,218 70,549 72,284 74,524 75,830 78,331
Emissions
Allowances $ 1,142 1,136 1,133 1,161 1,282 1,304 1,305 1,403 1,429 1,526
Operating and
Maintenance $ 30,431 31,128 31,749 32,785 33,488 34,453 35,342 36,438 37,224 38,534
Insurance $ 646 663 680 698 716 735 754 774 794 814
Property Taxes $ 2,166 2,223 2,281 2,340 2,401 2,463 2,527 2,593 2,660 2,729
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating
Expenses $ 97,283 99,033 101,316 104,050 107,105 109,503 112,212 115,733 117,937 121,933
NET OPERATING
REVENUES ($000) $ 52,474 52,296 55,978 55,713 57,520 58,181 60,025 63,071 64,087 65,995
CAPITAL EXPENDITURES
($000) $ 5,777 7,504 4,846 7,570 9,088 10,424 9,805 5,603 6,877 5,971
A-16
Exhibit A-1
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Base Case
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ -------- -------- -------- -------- -------- -------- -------- --------
POTOMAC RIVER FACILITY
- ----------------------
PERFORMANCE
Average Annual Capacity (MW)(1) 482 482 482 482 482 482 482 482
Summer Capacity (MW) 482 482 482 482 482 482 482 482
Plant Availability (%)(2) 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0% 90.0%
Plant Capacity Factor (%)(3) 71.2% 71.2% 71.2% 71.2% 71.2% 71.2% 71.2% 71.2%
Energy Generation (GWh) 3,006 3,006 3,006 3,006 3,006 3,006 3,006 3,006
Net Heat Rate (Btu/kWh)(4) 10,748 10,748 10,748 10,748 10,748 10,748 10,748 10,748
Fuel Consumption (BBtu) 32,307 32,307 32,307 32,307 32,307 32,307 32,307 32,307
SO\2\ Allowances Purchased (Tons)(5) 5,719 5,719 5,719 5,719 5,719 5,719 5,719 5,719
NO\X\ Allowances Purchased (Tons)(6) 52 52 52 52 52 52 52 52
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity ($/MWh)(8) $ 64.08 65.67 67.31 68.99 70.71 72.47 74.27 76.13
Fuel ($/MMBtu)(9) $ 2.48 2.54 2.59 2.65 2.71 2.77 2.83 2.90
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues $192,610 197,409 202,328 207,369 212,536 217,832 223,259 228,822
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $192,610 197,409 202,328 207,369 212,536 217,832 223,259 228,822
OPERATING EXPENSES ($000)(12)
Fuel Costs $ 80,098 81,904 83,752 85,641 87,573 89,548 91,568 93,633
Emissions Allowances $ 1,565 1,607 1,648 1,691 1,735 1,780 1,826 1,873
Operating and Maintenance $ 39,459 40,415 41,211 42,544 43,383 44,657 45,799 47,143
Insurance $ 835 857 879 902 926 950 975 1,000
Property Taxes $ 2,800 2,873 2,948 3,025 3,103 3,184 3,267 3,352
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $124,757 127,656 130,438 133,803 136,719 140,119 143,435 147,002
NET OPERATING REVENUES ($000) $ 67,853 69,753 71,889 73,566 75,817 77,712 79,824 81,820
CAPITAL EXPENDITURES ($000) $ 7,467 9,700 6,263 9,786 11,747 13,475 12,674 7,242
A-17
Footnotes to Exhibit A-1
1. Represents average annual capacity based on historical data provided by
Mirant Mid-Atlantic.
2. As projected by Mirant Mid-Atlantic based on historical data provided by
Pepco.
3. Capacity factors represent weighted average capacity factors for the
Generating Facilities as projected by PA Consulting.
4. Weighted average heat rate calculated as the sum of total fuel consumed by
the Generating Facilities divided by the energy generated by the Generating
Facilities.
5. SO\2\ allowances that Mirant Mid-Atlantic is projected to purchase or sell
based on assumed emission rates as estimated by Mirant Mid-Atlantic and
capacity factors as projected by PA Consulting.
6. NO\X\ allowances that Mirant Mid-Atlantic is projected to purchase or sell
based on assumed emission rates as estimated by Mirant Mid-Atlantic and
ozone season generation as projected by PA Consulting. Assumes additional
environmental capital expenditures that will reduce NO\X\ emissions as
projected by Mirant Mid-Atlantic.
7. Rate of change in general inflation assumed to be 2.6 percent per year,
based on an October 10, 2000 projection prepared by Blue Chip Economic
Indicators.
8. As projected by PA Consulting. Weighted average market electricity price
calculated as the sum of the electricity revenues of the Generating
Facilities divided by the total energy generation as projected by PA
Consulting.
9. As projected by PA Consulting. Weighted average fuel price for the
Generating Facilities calculated as sum of the fuel expenses divided by the
total fuel consumed by the Generating Facilities.
10. Assumed to be $150 per ton in 2000 dollars and to escalate at the rate of
inflation.
11. Assumed to be $1,000 per ton through 2002, $2,300 per ton in 2003, $2,000
per ton in 2004, and $1,700 per ton in 2005. Assumed to escalate thereafter
at the rate of inflation.
12. Non-fuel operating expenses as estimated by Mirant Mid-Atlantic. Assumed
to increase at the rate of inflation except as noted in the Report.
13. Includes property taxes and insurance estimated by Mirant Mid-Atlantic
through 2001 and assumed to escalate at the rate of inflation thereafter.
Property tax estimate reflects legislation providing exemptions for
machinery used to generate electricity.
14. All expenses associated with the PSC as estimated by Mirant Mid-Atlantic.
15. General and administrative expenses as estimated by Mirant Mid-Atlantic.
16. As estimated by Mirant Mid-Atlantic.
17. Fixed Charges are based on semi-annual payments due each June 30 and
December 30 beginning June 30, 2001, as reported by Credit Suisse First
Boston. Assumes monthly accrual of Rent payments six months prior to due
date.
18. Fixed Charge coverage is equal to the net operating revenue less all
capital expenditures divided by the Fixed Charges.
19. Average Fixed Charge coverage is equal to the total net operating revenue
over the term of the Certificates ending December 30, 2028, less all capital
expenditures divided by the total Fixed Charges over the term of the
Certificates.
A-18
Exhibit A-2
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity A - Low Gas Market Price Scenario
Year Ending December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------------------ -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 54.6% 52.3% 49.7% 47.3% 47.2% 48.9% 48.6% 48.4% 48.3% 49.0%
Energy Generation (GWh) 25,169 24,141 22,912 21,826 21,781 22,537 22,409 22,308 22,280 22,605
Heat Rate (Btu/kWh)(4) 9,736 9,718 9,658 9,708 9,710 9,700 9,696 9,682 9,688 9,684
Fuel Consumption (BBtu) 245,054 234,600 221,279 211,886 211,489 218,606 217,270 215,977 215,860 218,909
SO\2\ Allowances Purchased
(Tons)(5) 84,285 76,917 73,346 56,576 57,038 63,479 63,558 64,193 63,499 74,584
NO\X\ Allowances Purchased
(Tons)(6) 7,674 1,881 5,690 3,724 3,075 1,369 1,053 (1,212) (1,384) (1,267)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 55.38 51.80 47.78 45.34 46.41 48.06 49.60 49.84 50.62 51.62
Fuel Price ($/MMBtu)(9) $ 2.11 2.02 1.88 1.80 1.83 1.87 1.90 1.93 1.98 2.02
SO\2\ Allowances ($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances ($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point $ 608,709 557,157 468,535 435,492 430,532 452,645 470,539 460,333 468,019 483,794
Dickerson $ 226,609 201,091 187,375 167,367 175,454 182,861 187,071 189,402 192,700 195,071
Morgantown $ 396,949 352,335 315,195 277,593 290,122 327,331 326,955 334,093 336,043 350,476
Potomac River $ 161,534 139,903 123,746 109,141 114,764 120,212 126,851 128,088 131,101 137,505
---------- --------- --------- ------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,393,800 1,250,486 1,094,851 989,593 1,010,872 1,083,049 1,111,416 1,111,917 1,127,862 1,166,846
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 268,498 238,178 198,243 185,620 182,832 192,367 189,213 189,023 195,550 206,007
Emissions Allowances $ 2,939 (437) 3,364 2,584 2,130 978 550 (1,050) (1,380) 51
Operations & Maintenance $ 38,687 34,252 32,445 33,557 34,427 35,506 36,641 37,654 38,565 39,953
Other (13) $ 18,226 18,700 19,186 19,685 20,197 20,722 21,260 21,813 22,381 22,962
Dickerson
Fuel $ 73,908 68,604 63,944 56,933 60,473 61,567 63,069 63,526 65,856 64,688
Emissions Allowances $ 5,286 4,768 5,304 3,838 3,276 3,445 3,558 3,562 3,704 3,917
Operations & Maintenance $ 22,934 20,865 22,012 20,444 21,077 21,633 22,253 22,833 23,429 23,956
Other (13) $ 9,720 9,973 10,232 10,498 10,771 11,051 11,338 11,633 11,935 12,246
Morgantown
Fuel $ 112,813 109,027 103,858 93,993 98,252 106,471 108,029 110,129 110,872 114,057
Emissions Allowances $ 10,302 8,011 13,250 9,509 9,030 8,308 8,517 6,533 6,519 6,924
Operations & Maintenance $ 22,263 20,271 20,520 19,339 19,882 21,049 21,583 22,149 22,575 23,119
Other (13) $ 9,560 9,808 10,064 10,325 10,594 10,869 11,152 11,442 11,739 12,044
Potomac River
Fuel $ 61,522 57,273 50,868 45,460 45,250 47,597 51,830 53,496 54,775 57,951
Emissions Allowances $ 1,790 1,376 2,750 681 273 482 381 254 246 755
Operations & Maintenance $ 27,674 25,581 24,601 24,614 24,998 25,934 26,878 27,726 28,351 29,407
Other (13) $ 2,176 2,233 2,290 2,350 2,411 2,474 2,538 2,604 2,672 2,742
Production Service
Center (14) $ 17,740 18,201 18,675 19,160 19,658 20,169 20,694 21,232 21,784 22,350
Administration &
General (15) $ 6,852 7,030 7,213 7,400 7,593 7,790 7,993 8,201 8,414 8,633
---------- --------- --------- ------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 712,888 653,715 608,818 565,991 573,123 598,413 607,478 612,760 627,987 651,760
NET OPERATING
REVENUES ($000) $ 680,912 596,771 486,032 423,603 437,748 484,636 503,937 499,156 499,876 515,086
CAPITAL EXPENDITURES
($000)(16) $ 48,321 49,364 33,232 58,128 55,798 80,912 79,600 77,846 46,448 46,304
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 632,591 547,407 452,800 365,475 381,950 403,724 424,337 421,310 453,428 468,782
FIXED CHARGES ($000)(17) $ 196,065 170,468 150,720 121,500 116,005 105,671 112,348 120,723 142,339 140,220
ANNUAL FIXED CHARGE
COVERAGE (18) 3.23 3.21 3.00 3.01 3.29 3.82 3.78 3.49 3.19 3.34
AVERAGE FIXED CHARGE
COVERAGE (19) 5.09
A-19
Exhibit A-2
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity A - Low Gas Market Price Scenario
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------------------ -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 49.5% 49.0% 49.0% 48.7% 48.9% 48.6% 48.6% 48.7% 48.8% 49.2%
Energy Generation (GWh) 22,819 22,624 22,606 22,468 22,580 22,440 22,437 22,443 22,529 22,690
Heat Rate (Btu/kWh)(4) 9,701 9,692 9,694 9,691 9,685 9,677 9,679 9,677 9,682 9,685
Fuel Consumption (BBtu) 221,359 219,282 219,151 217,739 218,692 217,156 217,169 217,183 218,134 219,740
SO\2\ Allowances Purchased
(Tons)(5) 74,666 74,372 73,703 73,618 74,699 74,814 74,553 74,743 75,216 76,353
NO\X\ Allowances Purchased
(Tons)(6) (1,094) (1,083) (1,237) (1,265) (1,252) (1,392) (1,347) (1,353) (1,323) (1,238)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 53.72 55.14 57.09 57.87 58.87 60.21 61.70 63.67 64.85 66.15
Fuel Price ($/MMBtu)(9) $ 2.09 2.13 2.19 2.23 2.28 2.33 2.39 2.45 2.52 2.59
SO\2\ Allowances
($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances
($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point $ 506,436 515,059 532,888 535,016 544,986 548,838 561,435 580,346 595,265 609,843
Dickerson $ 208,983 210,813 218,815 219,673 225,232 230,182 235,267 242,137 249,438 257,465
Morgantown $ 366,243 374,518 386,611 390,984 399,944 409,659 421,403 434,177 441,758 453,292
Potomac River $ 144,138 147,003 152,380 154,494 159,075 162,317 166,263 172,253 174,551 180,331
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,225,798 1,247,393 1,290,694 1,300,167 1,329,237 1,350,995 1,384,368 1,428,914 1,461,013 1,500,932
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 215,486 216,335 222,750 226,174 232,093 231,219 238,231 244,855 253,298 261,810
Emissions Allowances $ 47 86 (144) 45 (40) (475) (341) (253) (261) (190)
Operations & Maintenance $ 41,032 41,657 42,582 43,726 45,016 45,987 47,277 48,510 49,692 51,525
Other (13) $ 23,560 24,171 24,801 25,445 26,107 26,786 27,482 28,196 28,930 29,682
Dickerson
Fuel $ 70,200 69,977 73,043 71,994 74,664 76,262 77,666 79,609 83,511 86,835
Emissions Allowances $ 4,175 4,240 4,267 4,157 4,473 4,622 4,525 4,654 4,920 5,212
Operations & Maintenance $ 24,635 25,251 25,924 26,548 27,270 27,973 28,684 29,427 30,238 31,035
Other (13) $ 12,564 12,891 13,226 13,570 13,923 14,285 14,656 15,037 15,428 15,829
Morgantown
Fuel $ 117,436 120,291 122,122 124,253 126,523 130,733 135,266 137,098 140,725 145,230
Emissions Allowances $ 7,207 7,413 7,489 7,655 7,911 8,239 8,594 8,689 8,951 9,376
Operations & Maintenance $ 23,721 24,335 24,945 25,597 26,273 26,970 27,673 28,386 29,133 29,921
Other (13) $ 12,358 12,679 13,009 13,346 13,694 14,049 14,415 14,790 15,175 15,569
Potomac River
Fuel $ 59,950 60,755 62,323 63,638 65,649 66,948 68,643 70,657 72,110 74,461
Emissions Allowances $ 879 854 849 852 953 970 968 1,044 1,079 1,159
Operations & Maintenance $ 30,172 30,855 31,477 32,485 33,179 34,140 35,028 36,103 36,901 38,199
Other (13) $ 2,812 2,886 2,961 3,038 3,117 3,198 3,281 3,367 3,454 3,543
Production Service
Center (14) $ 22,931 23,528 24,139 24,767 25,411 26,071 26,749 27,445 28,158 28,890
Administration &
General (15) $ 8,857 9,087 9,324 9,566 9,815 10,070 10,332 10,600 10,876 11,159
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 678,023 687,292 705,086 716,856 736,031 748,046 769,129 788,215 812,317 839,246
NET OPERATING REVENUES
($000) $ 547,776 560,102 585,608 583,310 593,206 602,949 615,239 640,698 648,696 661,686
CAPITAL EXPENDITURES
($000)(16) $ 53,915 61,801 55,751 57,870 78,064 52,377 55,481 92,587 56,235 84,968
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 493,861 498,301 529,857 525,440 515,142 550,572 559,758 548,111 592,461 576,718
FIXED CHARGES ($000)(17) $ 134,000 131,500 138,000 131,000 110,000 150,000 144,000 105,000 139,500 105,000
ANNUAL FIXED CHARGE
COVERAGE (18) 3.69 3.79 3.84 4.01 4.68 3.67 3.89 5.22 4.25 5.49
AVERAGE FIXED CHARGE
COVERAGE (19) 5.09
A-20
Exhibit A-2
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity A - Low Gas Market Price Scenario
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ ---------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 49.2% 49.2% 49.2% 49.2% 49.2% 49.2% 49.2% 49.2%
Energy Generation (GWh) 22,690 22,690 22,690 22,690 22,690 22,690 22,690 22,690
Heat Rate (Btu/kWh)(4) 9,685 9,685 9,685 9,685 9,685 9,685 9,685 9,685
Fuel Consumption (BBtu) 219,740 219,740 219,740 219,740 219,740 219,740 219,740 219,740
SO\2\ Allowances Purchased
(Tons)(5) 76,353 76,353 76,353 76,353 76,353 76,353 76,353 76,353
NO\X\ Allowances Purchased
(Tons)(6) (1,238) (1,238) (1,238) (1,238) (1,238) (1,238) (1,238) (1,238)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 67.70 69.30 70.94 72.62 74.36 76.14 77.97 79.85
Fuel Price ($/MMBtu)(9) $ 2.65 2.72 2.80 2.87 2.95 3.03 3.11 3.19
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues
Chalk Point $ 624,170 638,888 654,006 669,537 685,491 701,880 718,715 736,009
Dickerson $ 262,701 268,064 273,558 279,185 284,948 290,852 296,899 303,093
Morgantown $ 464,894 476,853 489,186 501,910 515,042 528,602 542,611 557,089
Potomac River $ 184,405 188,571 192,831 197,188 201,643 206,199 210,858 215,622
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,536,170 1,572,376 1,609,581 1,647,819 1,687,124 1,727,532 1,769,082 1,811,813
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 269,255 276,914 284,792 292,897 301,234 309,811 318,635 327,712
Emissions Allowances ($195) (200) (205) (210) (216) (221) (228) (234)
Operations & Maintenance $ 52,840 53,747 54,935 56,470 58,122 59,520 61,183 62,774
Other (13) $ 30,453 31,245 32,058 32,891 33,746 34,623 35,524 36,448
Dickerson
Fuel $ 89,101 91,427 93,815 96,265 98,779 101,360 104,008 106,726
Emissions Allowances $ 5,347 5,487 5,629 5,776 5,926 6,080 6,238 6,400
Operations & Maintenance $ 31,843 32,670 33,520 34,391 35,285 36,203 37,145 38,110
Other (13) $ 16,242 16,663 17,097 17,541 17,997 18,465 18,945 19,438
Morgantown
Fuel $ 148,863 152,587 156,406 160,320 164,332 168,446 172,662 176,985
Emissions Allowances $ 9,621 9,870 10,127 10,390 10,660 10,937 11,222 11,514
Operations & Maintenance $ 30,699 31,496 32,315 33,156 34,018 34,903 35,810 36,741
Other (13) $ 15,973 16,389 16,816 17,252 17,701 18,161 18,634 19,118
Potomac River
Fuel $ 76,140 77,858 79,614 81,410 83,246 85,124 87,044 89,008
Emissions Allowances $ 1,189 1,220 1,252 1,284 1,317 1,352 1,387 1,423
Operations & Maintenance $ 39,116 40,063 40,851 42,174 43,003 44,267 45,399 46,733
Other (13) $ 3,635 3,730 3,827 3,927 4,029 4,134 4,242 4,352
Production Service Center (14) $ 29,642 30,412 31,203 32,014 32,847 33,701 34,577 35,476
Administration & General (15) $ 11,449 11,746 12,052 12,365 12,687 13,017 13,355 13,702
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 861,214 883,325 906,103 930,312 954,714 979,882 1,005,783 1,032,426
NET OPERATING REVENUES ($000) $ 674,956 689,051 703,478 717,507 732,410 747,651 763,299 779,386
CAPITAL EXPENDITURES ($000)(16) $ 83,300 69,768 68,116 89,506 89,981 63,442 87,592 107,879
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 591,656 619,283 635,362 628,001 642,429 684,209 675,707 671,507
FIXED CHARGES ($000)(17) $ 41,633 35,616 22,401 16,142 16,238 11,518 74,250 80,000
ANNUAL FIXED CHARGE COVERAGE (18) 14.21 17.39 28.36 38.90 39.56 59.40 9.10 8.39
AVERAGE FIXED CHARGE COVERAGE (19) 5.09
A-21
Footnotes to Exhibit A-2
The footnotes to Exhibit A-2 are the same as the footnotes for Exhibit A-1,
except:
3. Capacity factor as estimated by PA Consulting under its "Low Gas Price"
scenario.
8. As estimated by PA Consulting in its "Low Gas Price" scenario. Weighted
average market electricity price for the Generating Facilities calculated as
the sum of the electricity revenues divided by the electricity generation, as
estimated by PA Consulting.
9. As estimated by PA Consulting in its "Low Gas Price" scenario. Weighted
average fuel price for the Generating Facilities calculated as sum of the
fuel expenses divided by the total fuel consumed by the Generating
Facilities.
A-22
Exhibit A-3
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity B - Capacity Overbuild Market Price Scenario
Year Ending December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------------------ -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 54.4% 52.1% 50.1% 47.1% 46.3% 48.0% 48.3% 48.4% 48.7% 49.6%
Energy Generation (GWh) 25,090 24,049 23,096 21,745 21,343 22,125 22,276 22,328 22,486 22,882
Heat Rate (Btu/kWh)(4) 9,734 9,716 9,655 9,695 9,708 9,695 9,690 9,675 9,682 9,677
Fuel Consumption (BBtu) 244,240 233,665 222,997 210,819 207,193 214,493 215,858 216,014 217,702 221,438
SO\2\ Allowances Purchased
(Tons)(5) 84,138 77,418 75,462 58,778 54,677 62,034 63,768 65,805 66,620 78,270
NO\X\ Allowances Purchased
(Tons)(6) 7,649 1,913 5,860 3,814 2,910 1,226 1,002 (1,233) (1,326) (1,182)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 57.78 53.01 49.08 42.87 40.84 42.87 46.11 48.72 50.68 51.94
Fuel Price ($/MMBtu)(9) $ 2.19 2.07 1.93 1.83 1.88 1.91 1.94 1.97 2.02 2.06
SO\2\ Allowances ($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances ($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point $ 629,280 558,196 478,910 397,878 371,232 392,964 432,485 444,857 465,945 484,515
Dickerson $ 236,787 207,649 196,038 162,715 152,317 162,540 172,078 185,193 196,467 198,609
Morgantown $ 414,358 363,849 329,480 269,606 252,534 291,162 307,472 333,040 346,707 365,442
Potomac River $ 169,256 145,225 128,990 101,922 95,535 101,827 115,127 124,628 130,421 139,846
---------- --------- --------- ------- ------- ------- --------- --------- --------- ---------
Total Operating Revenues $1,449,682 1,274,918 1,133,417 932,121 871,619 948,493 1,027,163 1,087,718 1,139,540 1,188,412
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 283,791 245,896 206,737 186,033 186,964 194,316 195,165 194,878 202,456 213,713
Emissions Allowances $ 2,912 (484) 3,341 2,492 2,097 900 643 (978) (1,259) 177
Operations & Maintenance $ 38,653 34,170 32,407 33,400 34,328 35,369 36,588 37,605 38,531 39,920
Other (13) $ 18,226 18,700 19,186 19,685 20,197 20,722 21,260 21,813 22,381 22,962
Dickerson
Fuel $ 75,522 70,094 65,724 59,028 59,405 61,088 62,165 63,382 66,913 65,772
Emissions Allowances $ 5,279 4,801 5,475 4,105 2,908 3,187 3,204 3,358 3,696 3,953
Operations & Maintenance $ 22,932 20,872 22,042 20,496 20,993 21,574 22,172 22,786 23,428 23,964
Other (13) $ 9,720 9,973 10,232 10,498 10,771 11,051 11,338 11,633 11,935 12,246
Morgantown
Fuel $ 113,517 109,954 105,468 96,016 97,020 105,823 109,304 112,502 114,061 117,747
Emissions Allowances $ 10,287 8,060 13,572 9,898 8,726 8,118 8,665 6,852 6,975 7,467
Operations & Maintenance $ 22,261 20,277 20,552 19,383 19,843 21,025 21,607 22,200 22,648 23,206
Other (13) $ 9,560 9,808 10,064 10,325 10,594 10,869 11,152 11,442 11,739 12,044
Potomac River
Fuel $ 61,527 58,002 52,536 45,272 45,543 47,885 52,468 54,261 56,122 59,734
Emissions Allowances $ 1,791 1,451 3,005 657 304 512 440 318 361 911
Operations & Maintenance $ 27,676 25,642 24,752 24,592 25,027 25,961 26,935 27,791 28,467 29,564
Other (13) $ 2,176 2,233 2,290 2,350 2,411 2,474 2,538 2,604 2,672 2,742
Production Service Center
(14) $ 17,740 18,201 18,675 19,160 19,658 20,169 20,694 21,232 21,784 22,350
Administration & General
(15) $ 6,852 7,030 7,213 7,400 7,593 7,790 7,993 8,201 8,414 8,633
---------- --------- --------- ------- ------- ------- --------- --------- --------- ---------
Total Operating Expenses $ 730,421 664,679 623,271 570,789 574,381 598,834 614,331 621,882 641,324 667,105
NET OPERATING REVENUES
($000) $ 719,260 610,239 510,147 361,332 297,237 349,659 412,832 465,836 498,216 521,307
CAPITAL EXPENDITURES
($000)(16) $ 48,321 49,364 33,232 58,128 55,798 80,912 79,600 77,846 46,448 46,304
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 670,939 560,875 476,915 303,204 241,439 268,747 333,232 387,990 451,768 475,003
FIXED CHARGES ($000)(17) $ 196,065 170,468 150,720 121,500 116,005 105,671 112,348 120,723 142,339 140,220
ANNUAL FIXED CHARGE
COVERAGE (18) 3.42 3.29 3.16 2.50 2.08 2.54 2.97 3.21 3.17 3.39
AVERAGE FIXED CHARGE
COVERAGE (19) 5.20
A-23
Exhibit A-3
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity B - Capacity Overbuild Market Price Scenario
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------------------ -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 50.6% 50.1% 50.3% 50.0% 50.4% 50.1% 50.0% 50.0% 50.1% 50.4%
Energy Generation (GWh) 23,322 23,131 23,183 23,072 23,239 23,104 23,064 23,087 23,108 23,232
Heat Rate (Btu/kWh)(4) 9,695 9,686 9,688 9,686 9,681 9,674 9,678 9,675 9,681 9,683
Fuel Consumption (BBtu) 226,101 224,051 224,592 223,473 224,975 223,519 223,222 223,375 223,711 224,960
SO\2\ Allowances Purchased
(Tons)(5) 79,877 79,660 79,452 79,500 81,038 80,904 80,233 80,801 80,552 81,703
NO\X\ Allowances Purchased
(Tons)(6) (939) (932) (1,072) (1,091) (1,046) (1,190) (1,155) (1,148) (1,148) (1,045)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 54.87 55.69 57.67 58.58 59.63 61.20 62.86 65.08 66.29 67.45
Fuel Price ($/MMBtu)(9) $ 2.14 2.18 2.24 2.28 2.33 2.38 2.45 2.51 2.58 2.64
SO\2\ Allowances ($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances ($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point $ 522,899 526,649 547,471 552,451 564,022 570,425 586,839 606,702 622,170 630,539
Dickerson $ 220,012 219,713 227,664 229,096 235,833 241,151 248,128 257,190 262,398 272,402
Morgantown $ 388,984 392,893 406,608 412,750 424,041 438,230 445,736 463,374 468,434 480,553
Potomac River $ 147,725 149,002 155,319 157,336 161,892 164,125 169,126 175,242 178,788 183,477
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,279,620 1,288,256 1,337,063 1,351,633 1,385,788 1,413,931 1,449,828 1,502,507 1,531,789 1,566,972
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 226,684 227,453 235,267 239,388 245,495 246,310 253,883 259,608 269,296 275,690
Emissions Allowances $ 259 297 106 301 197 (210) (90) (20) (19) (10)
Operations & Maintenance $ 41,052 41,678 42,620 43,774 45,058 46,057 47,345 48,559 49,751 51,539
Other (13) $ 23,560 24,171 24,801 25,445 26,107 26,786 27,482 28,196 28,930 29,682
Dickerson
Fuel $ 72,524 72,021 75,170 74,193 77,528 78,971 80,535 82,673 86,008 90,499
Emissions Allowances $ 4,387 4,420 4,432 4,371 4,804 4,917 4,840 5,007 5,134 5,643
Operations & Maintenance $ 24,682 25,291 25,962 26,596 27,345 28,040 28,758 29,508 30,288 31,133
Other (13) $ 12,564 12,891 13,226 13,570 13,923 14,285 14,656 15,037 15,428 15,829
Morgantown
Fuel $ 121,996 125,416 127,898 130,024 132,620 136,842 140,954 143,450 146,680 150,842
Emissions Allowances $ 7,877 8,168 8,353 8,530 8,858 9,178 9,444 9,669 9,866 10,237
Operations & Maintenance $ 23,828 24,456 25,083 25,737 26,424 27,120 27,809 28,542 29,278 30,058
Other (13) $ 12,358 12,679 13,009 13,346 13,694 14,049 14,415 14,790 15,175 15,569
Potomac River
Fuel $ 62,463 63,085 64,986 66,518 68,952 70,132 72,019 74,142 75,538 77,810
Emissions Allowances $ 1,101 1,064 1,087 1,110 1,255 1,265 1,280 1,369 1,402 1,477
Operations & Maintenance $ 30,394 31,058 31,710 32,737 33,467 34,416 35,319 36,403 37,199 38,488
Other (13) $ 2,812 2,886 2,961 3,038 3,117 3,198 3,281 3,367 3,454 3,543
Production Service Center
(14) $ 22,931 23,528 24,139 24,767 25,411 26,071 26,749 27,445 28,158 28,890
Administration & General
(15) $ 8,857 9,087 9,324 9,566 9,815 10,070 10,332 10,600 10,876 11,159
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 700,330 709,649 730,136 743,011 764,069 777,498 799,010 818,347 842,444 868,079
NET OPERATING REVENUES
($000) $ 579,290 578,607 606,927 608,622 621,719 636,432 650,817 684,161 689,345 698,893
CAPITAL EXPENDITURES
($000)(16) $ 53,915 61,801 55,751 57,870 78,064 52,377 55,481 92,587 56,235 84,968
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 525,375 516,806 551,176 550,752 543,655 584,055 595,336 591,574 633,110 613,925
FIXED CHARGES ($000)(17) $ 134,000 131,500 138,000 131,000 110,000 150,000 144,000 105,000 139,500 105,000
ANNUAL FIXED CHARGE
COVERAGE (18) 3.92 3.93 3.99 4.20 4.94 3.89 4.13 5.63 4.54 5.85
AVERAGE FIXED CHARGE
COVERAGE (19) 5.20
A-24
Exhibit A-3
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity B - Capacity Overbuild Market Price Scenario
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ ---------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 50.4% 50.4% 50.4% 50.4% 50.4% 50.4% 50.4% 50.4%
Energy Generation (GWh) 23,232 23,232 23,232 23,232 23,232 23,232 23,232 23,232
Heat Rate (Btu/kWh)(4) 9,683 9,683 9,683 9,683 9,683 9,683 9,683 9,683
Fuel Consumption (BBtu) 224,960 224,960 224,960 224,960 224,960 224,960 224,960 224,960
SO\2\ Allowances Purchased
(Tons)(5) 81,703 81,703 81,703 81,703 81,703 81,703 81,703 81,703
NO\X\ Allowances Purchased
(Tons)(6) (1,045) (1,045) (1,045) (1,045) (1,045) (1,045) (1,045) (1,045)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 69.07 70.74 72.46 74.23 76.04 77.91 79.84 81.82
Fuel Price ($/MMBtu)(9) $ 2.71 2.79 2.86 2.94 3.01 3.09 3.18 3.26
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues
Chalk Point $ 645,292 660,446 676,012 692,002 708,426 725,298 742,627 760,428
Dickerson $ 277,867 283,464 289,196 295,066 301,078 307,236 313,542 320,001
Morgantown $ 493,677 507,219 521,197 535,632 550,544 565,954 581,885 598,363
Potomac River $ 187,876 192,386 197,011 201,753 206,615 211,601 216,714 221,958
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,604,711 1,643,514 1,683,416 1,724,453 1,766,664 1,810,089 1,854,769 1,900,750
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 283,552 291,640 299,961 308,522 317,329 326,390 335,712 345,303
Emissions Allowances ($10) (10) (10) (11) (11) (11) (12) (12)
Operations & Maintenance $ 52,854 53,761 54,949 56,485 58,138 59,536 61,200 62,790
Other (13) $ 30,453 31,245 32,058 32,891 33,746 34,623 35,524 36,448
Dickerson
Fuel $ 92,865 95,293 97,784 100,341 102,966 105,660 108,424 111,262
Emissions Allowances $ 5,789 5,939 6,094 6,253 6,415 6,582 6,753 6,929
Operations & Maintenance $ 31,943 32,773 33,625 34,499 35,396 36,317 37,261 38,230
Other (13) $ 16,242 16,663 17,097 17,541 17,997 18,465 18,945 19,438
Morgantown
Fuel $ 154,618 158,489 162,457 166,525 170,695 174,970 179,353 183,846
Emissions Allowances $ 10,503 10,777 11,057 11,344 11,639 11,941 12,252 12,570
Operations & Maintenance $ 30,839 31,640 32,463 33,307 34,173 35,062 35,973 36,909
Other (13) $ 15,973 16,389 16,816 17,252 17,701 18,161 18,634 19,118
Potomac River
Fuel $ 79,565 81,360 83,195 85,072 86,990 88,953 90,959 93,011
Emissions Allowances $ 1,516 1,555 1,596 1,637 1,679 1,723 1,767 1,814
Operations & Maintenance $ 39,412 40,367 41,162 42,493 43,331 44,604 45,744 47,087
Other (13) $ 3,635 3,730 3,827 3,927 4,029 4,134 4,242 4,352
Production Service Center (14) $ 29,642 30,412 31,203 32,014 32,847 33,701 34,577 35,476
Administration & General (15) $ 11,449 11,746 12,052 12,365 12,687 13,017 13,355 13,702
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 890,839 913,768 937,386 962,456 987,747 1,013,828 1,040,664 1,068,273
NET OPERATING REVENUES ($000) $ 713,872 729,746 746,030 761,997 778,917 796,261 814,105 832,477
CAPITAL EXPENDITURES ($000)(16) $ 83,300 69,768 68,116 89,506 89,981 63,442 87,592 107,879
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 630,572 659,978 677,914 672,491 688,936 732,819 726,513 724,598
FIXED CHARGES ($000)(17) $ 41,633 35,616 22,401 16,142 16,238 11,518 74,250 80,000
ANNUAL FIXED CHARGE COVERAGE (18) 15.15 18.53 30.26 41.66 42.43 63.62 9.78 9.06
AVERAGE FIXED CHARGE COVERAGE (19) 5.20
A-25
Footnotes to Exhibit A-3
The footnotes to Exhibit A-3 are the same as the footnotes for Exhibit A-1,
except:
3. Capacity factor as estimated by PA Consulting under its "Capacity Overbuild"
scenario.
8. As estimated by PA Consulting in its "Capacity Overbuild" scenario. Weighted
average market electricity price for the Generating Facilities calculated as
the sum of the electricity revenues divided by the electricity generation, as
estimated by PA Consulting.
9. As estimated by PA Consulting in its "Capacity Overbuild" scenario. Weighted
average fuel price for the Generating Facilities calculated as sum of the
fuel expenses divided by the total fuel consumed by the Generating
Facilities.
A-26
Exhibit A-4
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity C - Breakeven Market Prices
Year Ending December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------------------ -------- ------- ------- ------- ------- ------- ------- ------- ------- -------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 54.5% 52.1% 50.0% 48.1% 47.9% 49.7% 49.5% 49.3% 49.5% 50.3%
Energy Generation (GWh) 25,125 24,039 23,068 22,205 22,116 22,912 22,834 22,720 22,847 23,190
Heat Rate (Btu/kWh)(4) 9,736 9,716 9,655 9,700 9,709 9,698 9,694 9,680 9,686 9,683
Fuel Consumption (BBtu) 244,605 233,562 222,736 215,397 214,721 222,190 221,360 219,944 221,296 224,549
SO\2\ Allowances Purchased
(Tons)(5) 84,300 77,031 75,310 61,076 60,221 67,094 67,469 68,004 68,562 79,741
NO\X\ Allowances Purchased
(Tons)(6) 7,669 1,880 5,843 3,999 3,263 1,527 1,218 (1,104) (1,227) (1,098)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 38.85 36.85 34.96 35.64 34.48 35.09 35.88 36.57 36.78 37.22
Fuel Price ($/MMBtu)(9) $ 2.19 2.08 1.93 1.98 1.88 1.92 1.95 1.98 2.03 2.07
SO\2\ Allowances ($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances ($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES ($000)
Market Electricity Revenues
Chalk Point $424,136 389,817 340,715 344,130 325,603 335,398 346,755 343,672 348,577 357,627
Dickerson $159,379 143,882 139,292 135,874 133,421 136,528 138,624 141,894 143,860 144,856
Morgantown $278,741 251,995 234,718 225,291 220,256 245,510 243,407 251,847 253,138 261,409
Potomac River $113,959 100,120 91,753 86,017 83,377 86,481 90,602 93,587 94,774 99,342
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $976,215 885,814 806,478 791,312 762,657 803,917 819,388 831,000 840,349 863,233
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $284,808 248,017 206,342 219,554 193,688 203,677 201,037 200,828 208,761 220,204
Emissions Allowances $ 2,915 (483) 3,338 2,665 2,341 1,158 780 (868) (1,163) 269
Operations & Maintenance $ 38,660 34,187 32,403 33,521 34,453 35,531 36,686 37,699 38,629 40,019
Other (13) $ 18,226 18,700 19,186 19,685 20,197 20,722 21,260 21,813 22,381 22,962
Dickerson
Fuel $ 75,634 70,005 65,552 62,247 62,204 63,336 64,880 65,087 68,053 66,712
Emissions Allowances $ 5,293 4,785 5,439 4,229 3,410 3,590 3,704 3,671 3,913 4,137
Operations & Maintenance $ 22,935 20,868 22,035 20,521 21,107 21,666 22,286 22,859 23,477 24,006
Other (13) $ 9,720 9,973 10,232 10,498 10,771 11,051 11,338 11,633 11,935 12,246
Morgantown
Fuel $113,597 109,746 105,456 97,783 100,133 108,863 110,670 113,059 114,903 118,171
Emissions Allowances $ 10,303 8,024 13,568 10,196 9,335 8,661 8,910 6,940 7,109 7,535
Operations & Maintenance $ 22,263 20,272 20,552 19,417 19,920 21,101 21,641 22,214 22,670 23,217
Other (13) $ 9,560 9,808 10,064 10,325 10,594 10,869 11,152 11,442 11,739 12,044
Potomac River
Fuel $ 61,657 57,597 52,450 46,621 47,384 49,848 54,197 55,666 57,259 60,801
Emissions Allowances $ 1,804 1,409 2,987 802 471 698 590 438 458 1,006
Operations & Maintenance $ 27,684 25,608 24,743 24,712 25,184 26,133 27,085 27,914 28,567 29,655
Other (13) $ 2,176 2,233 2,290 2,350 2,411 2,474 2,538 2,604 2,672 2,742
Production Service Center (14) $ 17,740 18,201 18,675 19,160 19,658 20,169 20,694 21,232 21,784 22,350
Administration & General (15) $ 6,852 7,030 7,213 7,400 7,593 7,790 7,993 8,201 8,414 8,633
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $731,828 665,981 622,526 611,685 590,855 617,336 627,441 632,432 651,562 676,708
NET OPERATING REVENUES ($000) $244,387 219,833 183,952 179,628 171,803 186,582 191,947 198,568 188,787 186,525
CAPITAL EXPENDITURES ($000)(16) $ 48,321 49,364 33,232 58,128 55,798 80,912 79,600 77,846 46,448 46,304
CASH AVAILABLE
FOR FIXED CHARGES ($000) $196,066 170,469 150,720 121,500 116,005 105,670 112,347 120,722 142,339 140,221
FIXED CHARGES ($000)(17) $196,065 170,468 150,720 121,500 116,005 105,671 112,348 120,723 142,339 140,220
ANNUAL FIXED CHARGE
COVERAGE (18) 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00
AVERAGE FIXED CHARGE
COVERAGE (19) 1.00
A-27
Exhibit A-4
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity C - Breakeven Market Prices
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------------------ -------- ------- ------- ------- ------- ------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 51.0% 50.5% 50.5% 50.3% 50.5% 50.2% 50.1% 50.2% 50.2% 50.5%
Energy Generation (GWh) 23,505 23,283 23,301 23,214 23,313 23,144 23,125 23,162 23,140 23,314
Heat Rate (Btu/kWh)(4) 9,697 9,689 9,690 9,688 9,683 9,676 9,679 9,676 9,682 9,686
Fuel Consumption (BBtu) 227,931 225,583 225,797 224,892 225,729 223,934 223,822 224,123 224,046 225,824
SO\2\ Allowances Purchased
(Tons)(5) 80,682 80,438 80,116 80,313 81,360 81,163 80,632 81,155 80,764 81,901
NO\X\ Allowances Purchased
(Tons)(6) (894) (886) (1,036) (1,042) (1,025) (1,173) (1,136) (1,127) (1,132) (1,031)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 38.05 38.99 39.81 40.34 40.96 42.39 43.26 43.99 44.91 45.56
Fuel Price ($/MMBtu)(9) $ 2.15 2.18 2.24 2.29 2.34 2.38 2.45 2.51 2.58 2.65
SO\2\ Allowances ($/Ton)
(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances ($/Ton)
(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point $369,000 373,068 381,538 384,038 389,781 397,040 404,731 412,264 421,338 429,790
Dickerson $153,008 154,120 158,037 159,190 162,821 168,012 171,016 173,890 178,273 183,481
Morgantown $269,715 276,299 281,542 285,053 291,287 301,529 307,765 313,352 318,149 324,424
Potomac River $102,596 104,227 106,557 108,074 111,049 114,481 116,904 119,284 121,449 124,589
-------- ------- ------- ------- ------- ------- --------- --------- --------- ---------
Total Operating Revenues $894,320 907,714 927,674 936,354 954,939 981,062 1,000,414 1,018,791 1,039,208 1,062,285
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $231,070 230,248 237,481 241,764 247,487 246,635 254,751 261,428 269,582 279,154
Emissions Allowances $ 306 328 127 309 215 (215) (93) (8) (26) 16
Operations & Maintenance $ 41,115 41,718 42,652 43,804 45,086 46,060 47,355 48,584 49,753 51,587
Other (13) $ 23,560 24,171 24,801 25,445 26,107 26,786 27,482 28,196 28,930 29,682
Dickerson
Fuel $ 72,995 72,554 75,677 75,054 77,822 79,324 80,831 83,062 86,397 90,559
Emissions Allowances $ 4,481 4,526 4,534 4,539 4,861 4,990 4,902 5,084 5,213 5,647
Operations & Maintenance $ 24,704 25,315 25,985 26,635 27,357 28,057 28,771 29,525 30,306 31,134
Other (13) $ 12,564 12,891 13,226 13,570 13,923 14,285 14,656 15,037 15,428 15,829
Morgantown
Fuel $122,400 125,663 128,166 130,313 132,695 136,783 141,258 143,505 146,613 150,860
Emissions Allowances $ 7,942 8,209 8,397 8,578 8,871 9,168 9,495 9,678 9,855 10,240
Operations & Maintenance $ 23,839 24,462 25,090 25,745 26,426 27,118 27,817 28,544 29,277 30,059
Other (13) $ 12,358 12,679 13,009 13,346 13,694 14,049 14,415 14,790 15,175 15,569
Potomac River
Fuel $ 62,898 63,883 65,472 67,066 69,218 70,549 72,284 74,524 75,830 78,331
Emissions Allowances $ 1,142 1,136 1,133 1,161 1,282 1,304 1,305 1,403 1,429 1,526
Operations & Maintenance $ 30,431 31,128 31,749 32,785 33,488 34,453 35,342 36,438 37,224 38,534
Other (13) $ 2,812 2,886 2,961 3,038 3,117 3,198 3,281 3,367 3,454 3,543
Production Service Center
(14) $ 22,931 23,528 24,139 24,767 25,411 26,071 26,749 27,445 28,158 28,890
Administration & General
(15) $ 8,857 9,087 9,324 9,566 9,815 10,070 10,332 10,600 10,876 11,159
-------- ------- ------- ------- ------- ------- --------- --------- --------- ---------
Total Operating Expenses $706,406 714,413 733,924 747,485 766,875 778,684 800,934 821,204 843,474 872,318
NET OPERATING REVENUES
($000) $187,914 193,301 193,750 188,869 188,064 202,378 199,481 197,587 195,735 189,967
CAPITAL EXPENDITURES
($000)(16) $ 53,915 61,801 55,751 57,870 78,064 52,377 55,481 92,587 56,235 84,968
CASH AVAILABLE
FOR FIXED CHARGES ($000) $133,999 131,500 137,999 130,999 110,000 150,001 144,000 105,000 139,500 104,999
FIXED CHARGES ($000)(17) $134,000 131,500 138,000 131,000 110,000 150,000 144,000 105,000 139,500 105,000
ANNUAL FIXED CHARGE
COVERAGE (18) 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00
AVERAGE FIXED CHARGE
COVERAGE (19) 1.00
A-28
Exhibit A-4
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity C - Breakeven Market Prices
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ ---------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 50.5% 50.5% 50.5% 50.5% 50.5% 50.5% 50.5% 50.5%
Energy Generation (GWh) 23,314 23,314 23,314 23,314 23,314 23,314 23,314 23,314
Heat Rate (Btu/kWh)(4) 9,686 9,686 9,686 9,686 9,686 9,686 9,686 9,686
Fuel Consumption (BBtu) 225,824 225,824 225,824 225,824 225,824 225,824 225,824 225,824
SO\2\ Allowances Purchased (Tons)(5) 81,901 81,901 81,901 81,901 81,901 81,901 81,901 81,901
NO\X\ Allowances Purchased (Tons)(6) (1,031) (1,031) (1,031) (1,031) (1,031) (1,031) (1,031) (1,031)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price ($/MWh)(8) $ 43.76 43.91 44.29 46.02 47.13 46.92 51.80 54.11
Fuel Price ($/MMBtu)(9) $ 2.72 2.79 2.87 2.94 3.02 3.10 3.19 3.27
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues
Chalk Point $ 412,564 413,806 417,217 433,324 443,622 441,380 487,086 508,517
Dickerson $ 175,513 175,426 176,252 182,413 186,090 184,495 202,880 211,056
Morgantown $ 312,462 314,462 318,139 331,569 340,649 340,150 376,757 394,820
Potomac River $ 119,598 119,950 120,921 125,561 128,506 127,808 140,978 147,103
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,020,137 1,023,645 1,032,528 1,072,867 1,098,867 1,093,832 1,207,701 1,261,497
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 287,122 295,320 303,753 312,430 321,357 330,541 339,990 349,712
Emissions Allowances $ 17 17 19 19 19 20 20 21
Operations & Maintenance $ 52,902 53,811 55,001 56,537 58,192 59,591 61,257 62,849
Other (13) $ 30,453 31,245 32,058 32,891 33,746 34,623 35,524 36,448
Dickerson
Fuel $ 92,926 95,355 97,849 100,408 103,034 105,730 108,496 111,336
Emissions Allowances $ 5,795 5,945 6,100 6,259 6,421 6,589 6,759 6,936
Operations & Maintenance $ 31,944 32,774 33,627 34,500 35,398 36,318 37,263 38,232
Other (13) $ 16,242 16,663 17,097 17,541 17,997 18,465 18,945 19,438
Morgantown
Fuel $ 154,636 158,508 162,476 166,545 170,715 174,991 179,374 183,868
Emissions Allowances $ 10,506 10,779 11,059 11,348 11,643 11,945 12,256 12,574
Operations & Maintenance $ 30,840 31,641 32,464 33,308 34,173 35,063 35,974 36,909
Other (13) $ 15,973 16,389 16,816 17,252 17,701 18,161 18,634 19,118
Potomac River
Fuel $ 80,098 81,904 83,752 85,641 87,573 89,548 91,568 93,633
Emissions Allowances $ 1,565 1,607 1,648 1,691 1,735 1,780 1,826 1,873
Operations & Maintenance $ 39,459 40,415 41,211 42,544 43,383 44,657 45,799 47,143
Other (13) $ 3,635 3,730 3,827 3,927 4,029 4,134 4,242 4,352
Production Service Center (14) $ 29,642 30,412 31,203 32,014 32,847 33,701 34,577 35,476
Administration & General (15) $ 11,449 11,746 12,052 12,365 12,687 13,017 13,355 13,702
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 895,204 918,262 942,011 967,219 992,650 1,018,873 1,045,859 1,073,619
NET OPERATING REVENUES ($000) $ 124,933 105,383 90,517 105,649 106,218 74,959 161,842 187,877
CAPITAL EXPENDITURES ($000)(16) $ 83,300 69,768 68,116 89,506 89,981 63,442 87,592 107,879
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 41,633 35,615 22,401 16,143 16,237 11,517 74,250 79,998
FIXED CHARGES ($000)(17) $ 41,633 35,616 22,401 16,142 16,238 11,518 74,250 80,000
ANNUAL FIXED CHARGE COVERAGE (18) 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00
AVERAGE FIXED CHARGE COVERAGE (19) 1.00
A-29
Footnotes to Exhibit A-4
The footnotes to Exhibit A-4 are the same as the footnotes for Exhibit A-1,
except:
8. Market electricity prices are set such that the total operating revenue
results in a Fixed Charge coverage of 1.00 in all years.
A-30
Exhibit A-5
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity D - Reduced Availability
Year Ending
December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------ ---------- --------- --------- --------- ------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0%
Capacity Factor (%)(3) 51.7% 49.5% 47.5% 45.7% 45.5% 47.2% 47.0% 46.8% 47.1% 47.8%
Energy Generation
(GWh) 23,868 22,837 21,915 21,095 21,010 21,766 21,692 21,584 21,704 22,031
Heat Rate (Btu/kWh)(4) 9,736 9,716 9,656 9,700 9,709 9,697 9,694 9,680 9,686 9,683
Fuel Consumption (BBtu) 232,375 221,880 211,601 204,628 203,981 211,077 210,293 208,946 210,235 213,323
SO\2\ Allowances
Purchased (Tons)(5) 74,908 68,002 66,369 52,847 52,034 58,560 58,923 59,428 59,960 70,998
NO\X\ Allowances
Purchased (Tons)(6) 6,557 1,064 5,167 3,415 2,714 1,067 773 (1,433) (1,549) (1,428)
COMMODITY PRICES
General Inflation
(%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
Price ($/MWh)(8) $ 58.04 53.31 49.22 47.51 46.46 49.21 50.74 50.97 52.15 53.54
Fuel Price
($/MMBtu)(9) $ 2.19 2.08 1.93 1.98 1.88 1.92 1.95 1.98 2.03 2.07
SO\2\ Allowances
($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances
($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES
($000)
Market Electricity
Revenues
Chalk Point $ 602,115 535,978 455,838 435,881 416,768 446,867 465,767 454,953 469,506 488,684
Dickerson $ 226,126 197,724 186,224 172,100 170,778 181,903 186,202 187,840 193,768 197,940
Morgantown $ 395,458 346,304 313,849 285,358 281,926 327,105 326,948 333,396 340,957 357,205
Potomac River $ 161,590 137,536 122,657 108,951 106,721 115,223 121,697 123,891 127,653 135,746
---------- --------- --------- --------- ------- --------- --------- --------- --------- ---------
Total Operating
Revenues $1,385,290 1,217,542 1,078,568 1,002,290 976,192 1,071,098 1,100,614 1,100,080 1,131,884 1,179,576
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 270,577 235,610 196,029 208,575 184,002 193,488 190,986 190,778 198,317 209,192
Emissions Allowances $ 2,229 (1,007) 2,579 1,971 1,694 556 183 (1,397) (1,693) (280)
Operations &
Maintenance $ 38,452 33,982 32,202 33,302 34,232 35,299 36,456 37,467 38,389 39,768
Other (13) $ 18,226 18,700 19,186 19,685 20,197 20,722 21,260 21,813 22,381 22,962
Dickerson
Fuel $ 71,843 66,500 62,267 59,126 59,095 60,166 61,635 61,836 64,654 63,379
Emissions Allowances $ 4,798 4,313 4,839 3,709 2,950 3,112 3,214 3,175 3,397 3,600
Operations &
Maintenance $ 22,824 20,758 21,925 20,415 20,998 21,553 22,170 22,740 23,354 23,880
Other (13) $ 9,720 9,973 10,232 10,498 10,771 11,051 11,338 11,633 11,935 12,246
Morgantown
Fuel $ 107,923 104,259 100,188 92,901 95,110 103,422 105,130 107,409 109,174 112,273
Emissions Allowances $ 9,287 7,114 12,331 9,159 8,371 7,720 7,943 6,058 6,206 6,594
Operations &
Maintenance $ 22,140 20,150 20,429 19,300 19,801 20,970 21,507 22,076 22,528 23,069
Other (13) $ 9,560 9,808 10,064 10,325 10,594 10,869 11,152 11,442 11,739 12,044
Potomac River
Fuel $ 58,573 54,715 49,831 44,292 45,014 47,356 51,487 52,880 54,399 57,759
Emissions Allowances $ 1,480 1,110 2,615 552 250 460 353 203 217 743
Operations &
Maintenance $ 27,419 25,359 24,515 24,508 24,976 25,913 26,843 27,665 28,309 29,381
Other (13) $ 2,176 2,233 2,290 2,350 2,411 2,474 2,538 2,604 2,672 2,742
Production Service
Center (14) $ 17,740 18,201 18,675 19,160 19,658 20,169 20,694 21,232 21,784 22,350
Administration &
General (15) $ 6,852 7,030 7,213 7,400 7,593 7,790 7,993 8,201 8,414 8,633
---------- --------- --------- --------- ------- --------- --------- --------- --------- ---------
Total Operating
Expenses $ 701,819 638,807 597,409 587,230 567,715 593,089 602,882 607,815 626,175 650,337
NET OPERATING REVENUES
($000) $ 683,471 578,735 481,158 415,060 408,477 478,009 497,732 492,265 505,710 529,239
CAPITAL EXPENDITURES
($000)(16) $ 48,321 49,364 33,232 58,128 55,798 80,912 79,600 77,846 46,448 46,304
CASH AVAILABLE
FOR FIXED CHARGES
($000) $ 635,150 529,371 447,926 356,932 352,679 397,097 418,132 414,419 459,262 482,935
FIXED CHARGES
($000)(17) $ 196,065 170,468 150,720 121,500 116,005 105,671 112,348 120,723 142,339 140,220
ANNUAL FIXED CHARGE
COVERAGE (18) 3.24 3.11 2.97 2.94 3.04 3.76 3.72 3.43 3.23 3.44
AVERAGE FIXED CHARGE
COVERAGE (19) 5.23
A-31
Exhibit A-5
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity D - Reduced Availability
Year Ending
December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------ ---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0%
Capacity Factor
(%)(3) 48.4% 47.9% 48.0% 47.8% 48.0% 47.7% 47.6% 47.7% 47.7% 48.0%
Energy Generation
(GWh) 22,329 22,119 22,136 22,053 22,147 21,987 21,969 22,004 21,983 22,148
Heat Rate
(Btu/kWh)(4) 9,697 9,689 9,690 9,688 9,683 9,676 9,679 9,677 9,682 9,686
Fuel Consumption
(BBtu) 216,535 214,308 214,508 213,641 214,443 212,739 212,632 212,918 212,844 214,526
SO\2\ Allowances
Purchased (Tons)(5) 71,892 71,662 71,354 71,538 72,537 72,348 71,843 72,344 71,972 73,046
NO\X\ Allowances
Purchased (Tons)(6) (1,234) (1,225) (1,367) (1,375) (1,358) (1,498) (1,464) (1,455) (1,461) (1,365)
COMMODITY PRICES
General Inflation
(%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
Price ($/MWh)(8) $ 55.54 56.61 58.77 59.63 60.72 62.09 63.74 65.93 67.31 68.73
Fuel Price
($/MMBtu)(9) $ 2.15 2.18 2.24 2.29 2.34 2.38 2.45 2.51 2.58 2.65
SO\2\ Allowances
($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances
($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES
($000)
Market Electricity
Revenues
Chalk Point $ 511,689 514,586 535,045 539,329 548,939 552,478 566,485 587,075 599,916 615,875
Dickerson $ 212,176 212,583 221,622 223,561 229,305 233,786 239,364 247,625 253,831 262,923
Morgantown $ 374,012 381,109 394,818 400,318 410,228 419,575 430,766 446,222 452,992 464,889
Potomac River $ 142,269 143,763 149,429 151,775 156,394 159,300 163,625 169,864 172,923 178,532
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Revenues $1,240,146 1,252,041 1,300,914 1,314,983 1,344,866 1,365,138 1,400,240 1,450,786 1,479,662 1,522,218
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 219,512 218,741 225,604 229,669 235,111 234,306 242,009 248,349 256,105 265,190
Emissions
Allowances ($259) (251) (457) (298) (403) (827) (728) (664) (698) (676)
Operations &
Maintenance $ 40,854 41,455 42,382 43,529 44,804 45,776 47,063 48,284 49,445 51,269
Other (13) $ 23,560 24,171 24,801 25,445 26,107 26,786 27,482 28,196 28,930 29,682
Dickerson
Fuel $ 69,348 68,920 71,895 71,292 73,926 75,359 76,793 78,909 82,084 86,026
Emissions
Allowances $ 3,919 3,953 3,951 3,945 4,243 4,355 4,262 4,425 4,536 4,938
Operations &
Maintenance $ 24,572 25,181 25,847 26,494 27,212 27,908 28,619 29,369 30,145 30,967
Other (13) $ 12,564 12,891 13,226 13,570 13,923 14,285 14,656 15,037 15,428 15,829
Morgantown
Fuel $ 116,279 119,393 121,769 123,795 126,067 129,948 134,203 136,334 139,257 143,296
Emissions
Allowances $ 6,966 7,206 7,370 7,522 7,787 8,053 8,344 8,502 8,648 8,997
Operations &
Maintenance $ 23,686 24,306 24,930 25,580 26,257 26,944 27,639 28,361 29,089 29,865
Other (13) $ 12,358 12,679 13,009 13,346 13,694 14,049 14,415 14,790 15,175 15,569
Potomac River
Fuel $ 59,757 60,691 62,198 63,710 65,756 67,022 68,671 70,799 72,040 74,415
Emissions
Allowances $ 868 856 846 867 976 990 985 1,072 1,090 1,175
Operations &
Maintenance $ 30,147 30,839 31,452 32,479 33,171 34,129 35,010 36,094 36,873 38,169
Other (13) $ 2,812 2,886 2,961 3,038 3,117 3,198 3,281 3,367 3,454 3,543
Production Service
Center (14) $ 22,931 23,528 24,139 24,767 25,411 26,071 26,749 27,445 28,158 28,890
Administration &
General (15) $ 8,857 9,087 9,324 9,566 9,815 10,070 10,332 10,600 10,876 11,159
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Expenses $ 678,730 686,531 705,246 718,317 736,972 748,423 769,785 789,270 810,636 838,304
NET OPERATING
REVENUES ($000) $ 561,416 565,510 595,668 596,666 607,894 616,715 630,454 661,516 669,026 683,913
CAPITAL
EXPENDITURES
($000)(16) $ 53,915 61,801 55,751 57,870 78,064 52,377 55,481 92,587 56,235 84,968
CASH AVAILABLE
FOR FIXED CHARGES
($000) $ 507,501 503,709 539,917 538,796 529,830 564,338 574,973 568,929 612,791 598,945
FIXED CHARGES
($000)(17) $ 134,000 131,500 138,000 131,000 110,000 150,000 144,000 105,000 139,500 105,000
ANNUAL FIXED CHARGE
COVERAGE (18) 3.79 3.83 3.91 4.11 4.82 3.76 3.99 5.42 4.39 5.70
AVERAGE FIXED CHARGE
COVERAGE (19) 5.23
A-32
Exhibit A-5
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity D - Reduced Availability
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ ---------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0% 83.0%
Capacity Factor (%)(3) 48.0% 48.0% 48.0% 48.0% 48.0% 48.0% 48.0% 48.0%
Energy Generation (GWh) 22,148 22,148 22,148 22,148 22,148 22,148 22,148 22,148
Heat Rate (Btu/kWh)(4) 9,686 9,686 9,686 9,686 9,686 9,686 9,686 9,686
Fuel Consumption (BBtu) 214,526 214,526 214,526 214,526 214,526 214,526 214,526 214,526
SO\2\ Allowances Purchased
(Tons)(5) 73,046 73,046 73,046 73,046 73,046 73,046 73,046 73,046
NO\X\ Allowances Purchased
(Tons)(6) (1,365) (1,365) (1,365) (1,365) (1,365) (1,365) (1,365) (1,365)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 70.47 72.26 74.10 76.00 77.95 79.96 82.03 84.17
Fuel Price ($/MMBtu)(9) $ 2.72 2.79 2.87 2.94 3.02 3.10 3.19 3.27
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues
Chalk Point $ 631,206 646,973 663,189 679,867 697,019 714,659 732,802 751,461
Dickerson $ 268,528 274,273 280,162 286,197 292,384 298,725 305,225 311,888
Morgantown $ 478,054 491,652 505,699 520,218 535,228 550,753 566,817 583,445
Potomac River $ 182,980 187,539 192,211 197,000 201,909 206,940 212,096 217,381
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,560,767 1,600,436 1,641,261 1,683,282 1,726,540 1,771,078 1,816,941 1,864,176
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 272,759 280,547 288,559 296,802 305,282 314,007 322,983 332,218
Emissions Allowances ($693) (711) (730) (749) (768) (788) (809) (830)
Operations & Maintenance $ 52,577 53,477 54,658 56,186 57,831 59,221 60,877 62,459
Other (13) $ 30,453 31,245 32,058 32,891 33,746 34,623 35,524 36,448
Dickerson
Fuel $ 88,275 90,583 92,952 95,382 97,877 100,438 103,066 105,763
Emissions Allowances $ 5,066 5,198 5,333 5,472 5,614 5,760 5,910 6,063
Operations & Maintenance $ 31,773 32,598 33,446 34,315 35,208 36,123 37,063 38,026
Other (13) $ 16,242 16,663 17,097 17,541 17,997 18,465 18,945 19,438
Morgantown
Fuel $ 146,882 150,559 154,329 158,193 162,154 166,216 170,379 174,647
Emissions Allowances $ 9,230 9,471 9,717 9,969 10,229 10,495 10,768 11,048
Operations & Maintenance $ 30,642 31,437 32,255 33,094 33,954 34,837 35,743 36,672
Other (13) $ 15,973 16,389 16,816 17,252 17,701 18,161 18,634 19,118
Potomac River
Fuel $ 76,094 77,810 79,565 81,360 83,195 85,072 86,990 88,953
Emissions Allowances $ 1,206 1,237 1,268 1,302 1,336 1,371 1,406 1,443
Operations & Maintenance $ 39,085 40,032 40,818 42,141 42,969 44,232 45,363 46,696
Other (13) $ 3,635 3,730 3,827 3,927 4,029 4,134 4,242 4,352
Production Service Center (14) $ 29,642 30,412 31,203 32,014 32,847 33,701 34,577 35,476
Administration & General (15) $ 11,449 11,746 12,052 12,365 12,687 13,017 13,355 13,702
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 860,290 882,423 905,224 929,457 953,889 979,085 1,005,016 1,031,693
NET OPERATING REVENUES ($000) $ 700,477 718,013 736,037 753,825 772,651 791,993 811,925 832,483
CAPITAL EXPENDITURES ($000)(16) $ 83,300 69,768 68,116 89,506 89,981 63,442 87,592 107,879
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 617,177 648,245 667,921 664,319 682,670 728,551 724,333 724,604
FIXED CHARGES ($000)(17) $ 41,633 35,616 22,401 16,142 16,238 11,518 74,250 80,000
ANNUAL FIXED CHARGE COVERAGE (18) 14.82 18.20 29.82 41.15 42.04 63.25 9.76 9.06
AVERAGE FIXED CHARGE COVERAGE (19) 5.23
A-33
Footnotes to Exhibit A-5
The footnotes to Exhibit A-5 are the same as the footnotes for Exhibit A-1,
except:
2. Availability of the Generating Facilities is assumed to be 5 percentage
points less than that assumed in the Base Case based on a 5 percentage point
increase in the forced outage rate for each Facility.
3. Capacity factor is assumed to decrease such that annual generation for each
Facility is reduced by 5 percent from that assumed in the Base Case.
A-34
Exhibit A-6
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity E - Increased Heat Rate
Year Ending
December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------ ---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor
(%)(3) 54.5% 52.1% 50.0% 48.1% 47.9% 49.7% 49.5% 49.3% 49.5% 50.3%
Energy Generation
(GWh) 25,125 24,039 23,068 22,205 22,116 22,912 22,834 22,720 22,847 23,190
Heat Rate
(Btu/kWh)(4) 10,223 10,202 10,138 10,185 10,194 10,182 10,179 10,164 10,171 10,167
Fuel Consumption
(BBtu) 256,839 245,237 233,877 226,165 225,456 233,297 232,429 230,935 232,368 235,775
SO\2\ Allowances
Purchased (Tons)(5) 93,691 86,061 84,253 69,304 68,408 75,624 76,021 76,578 77,170 88,484
NO\X\ Allowances
Purchased (Tons)(6) 8,782 2,694 6,520 4,583 3,811 1,988 1,663 (774) (902) (769)
COMMODITY PRICES
General Inflation
(%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
Price ($/MWh)(8) $ 57.80 53.11 49.07 47.51 46.46 49.21 50.74 50.97 52.15 53.54
Fuel Price
($/MMBtu)(9) $ 2.19 2.08 1.93 1.98 1.88 1.92 1.95 1.98 2.03 2.07
SO\2\ Allowances
($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances
($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING REVENUES
($000)
Market Electricity
Revenues
Chalk Point $ 630,933 561,827 478,221 458,823 438,703 470,387 490,281 478,898 494,217 514,404
Dickerson $ 237,088 207,371 195,508 181,158 179,766 191,477 196,002 197,726 203,967 208,358
Morgantown $ 414,647 363,190 329,446 300,376 296,764 344,321 344,156 350,943 358,902 376,006
Potomac River $ 169,522 144,298 128,782 114,685 112,338 121,287 128,102 130,412 134,372 142,891
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Revenues $1,452,190 1,276,686 1,131,958 1,055,042 1,027,571 1,127,472 1,158,541 1,157,979 1,191,457 1,241,658
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 299,062 260,408 216,672 230,530 203,373 213,850 211,085 210,852 219,191 231,205
Emissions
Allowances $ 3,601 41 4,096 3,359 2,988 1,759 1,379 (338) (634) 817
Operations &
Maintenance $ 38,660 34,187 32,403 33,521 34,453 35,531 36,686 37,699 38,629 40,019
Other (13) $ 18,226 18,700 19,186 19,685 20,197 20,722 21,260 21,813 22,381 22,962
Dickerson
Fuel $ 79,417 73,501 68,823 65,354 65,312 66,502 68,121 68,338 71,465 70,047
Emissions
Allowances $ 5,788 5,258 6,037 4,750 3,870 4,066 4,194 4,168 4,431 4,674
Operations &
Maintenance $ 22,935 20,868 22,035 20,521 21,107 21,666 22,286 22,859 23,477 24,006
Other (13) $ 9,720 9,973 10,232 10,498 10,771 11,051 11,338 11,633 11,935 12,246
Morgantown
Fuel $ 119,302 115,222 110,725 102,677 105,138 114,301 116,203 118,721 120,670 124,079
Emissions
Allowances $ 11,321 8,932 14,807 11,234 10,297 9,601 9,878 7,824 8,016 8,475
Operations &
Maintenance $ 22,263 20,272 20,552 19,417 19,920 21,101 21,641 22,214 22,670 23,217
Other (13) $ 9,560 9,808 10,064 10,325 10,594 10,869 11,152 11,442 11,739 12,044
Potomac River
Fuel $ 64,735 60,476 55,078 48,952 49,754 52,344 56,910 58,445 60,124 63,842
Emissions
Allowances $ 2,127 1,708 3,360 1,053 692 937 828 673 701 1,268
Operations &
Maintenance $ 27,684 25,608 24,743 24,712 25,184 26,133 27,085 27,914 28,567 29,655
Other (13) $ 2,176 2,233 2,290 2,350 2,411 2,474 2,538 2,604 2,672 2,742
Production Service
Center (14) $ 17,740 18,201 18,675 19,160 19,658 20,169 20,694 21,232 21,784 22,350
Administration &
General (15) $ 6,852 7,030 7,213 7,400 7,593 7,790 7,993 8,201 8,414 8,633
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Expenses $ 761,169 692,428 646,990 635,496 613,313 640,867 651,271 656,294 676,232 702,281
NET OPERATING
REVENUES ($000) $ 691,021 584,259 484,967 419,546 414,258 486,605 507,270 501,685 515,225 539,378
CAPITAL EXPENDITURES
($000)(16) $ 48,321 49,364 33,232 58,128 55,798 80,912 79,600 77,846 46,448 46,304
CASH AVAILABLE
FOR FIXED CHARGES
($000) $ 642,700 534,895 451,735 361,418 358,460 405,693 427,670 423,839 468,777 493,074
FIXED CHARGES
($000)(17) $ 196,065 170,468 150,720 121,500 116,005 105,671 112,348 120,723 142,339 140,220
ANNUAL FIXED CHARGE
COVERAGE (18) 3.28 3.14 3.00 2.97 3.09 3.84 3.81 3.51 3.29 3.52
AVERAGE FIXED CHARGE
COVERAGE (19) 5.34
A-35
Exhibit A-6
Mirant Mid-Atlantic Generating
Facilities
Projected Operating Results
Sensitivity E - Increased Heat Rate
Year Ending December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 51.0 50.5% 50.5% 50.3% 50.5% 50.2% 50.1% 50.2% 50.2% 50.5%
Energy Generation (GWh) 23,505 23,283 23,301 23,214 23,313 23,144 23,125 23,162 23,140 23,314
Heat Rate (Btu/kWh)(4) 10,182 10,173 10,175 10,172 10,167 10,160 10,163 10,160 10,166 10,170
Fuel Consumption (BBtu) 239,327 236,863 237,089 236,132 237,018 235,132 235,012 235,331 235,250 237,107
SO\2\ Allowances Purchased
(Tons)(5) 89,473 89,218 88,878 89,084 90,186 89,978 89,418 89,972 89,557 90,748
NO\X\ Allowances Purchased
(Tons)(6) (555) (545) (703) (710) (691) (847) (809) (799) (805) (699)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 55.54 56.61 58.77 59.63 60.72 62.09 63.74 65.93 67.31 68.73
Fuel Price ($/MMBtu)(9) $ 2.15 2.18 2.24 2.29 2.34 2.38 2.45 2.51 2.58 2.65
SO\2\ Allowances
($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances
($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Market Electricity
Revenues
Chalk Point $ 538,620 541,669 563,206 567,715 577,831 581,556 596,300 617,974 631,490 648,289
Dickerson $ 223,343 223,771 233,287 235,327 241,374 246,091 251,962 260,658 267,191 276,761
Morgantown $ 393,697 401,168 415,598 421,387 431,819 441,657 453,438 469,707 476,834 489,357
Potomac River $ 149,757 151,330 157,294 159,763 164,625 167,684 172,237 178,804 182,024 187,928
----------- -------- --------- --------- --------- --------- --------- --------- -------- ---------
Total Operating Revenues $1,305,417 1,317,938 1,369,384 1,384,193 1,415,649 1,436,988 1,473,937 1,527,143 ,557,539 1,602,335
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 242,616 241,758 249,357 253,839 259,868 258,968 267,485 274,493 283,074 293,109
Emissions Allowances $ 869 908 711 918 835 399 543 649 646 709
Operations & Maintenance $ 41,115 41,718 42,652 3,804 45,086 46,060 47,355 48,584 49,753 51,587
Other (13) $ 23,560 24,171 24,801 25,445 26,107 26,786 27,482 28,196 28,930 29,682
Dickerson
Fuel $ 76,648 76,178 79,467 78,800 81,709 83,288 84,874 87,210 90,729 95,077
Emissions Allowances $ 5,045 5,101 5,117 5,131 5,479 5,625 5,542 5,744 5,890 6,357
Operations & Maintenance $ 24,704 25,315 25,985 26,635 27,357 28,057 28,771 29,525 30,306 31,134
Other (13) $ 12,564 12,891 13,226 13,570 13,923 14,285 14,656 15,037 15,428 15,829
Morgantown
Fuel $ 128,510 131,943 134,574 136,828 139,342 143,618 148,328 150,692 153,936 158,387
Emissions Allowances $ 8,917 9,214 9,426 9,632 9,957 10,285 10,644 10,857 11,058 11,480
Operations & Maintenance $ 23,839 24,462 25,090 25,745 26,426 27,118 27,817 28,544 29,277 30,059
Other (13) $ 12,358 12,679 13,009 13,346 13,694 14,049 14,415 14,790 15,175 15,569
Potomac River
Fuel $ 66,048 67,081 68,746 70,418 72,675 74,079 75,896 78,252 79,618 82,242
Emissions Allowances $ 1,417 1,418 1,419 1,454 1,587 1,617 1,624 1,734 1,769 1,877
Operations & Maintenance $ 30,431 31,128 31,749 32,785 33,488 34,453 35,342 36,438 37,224 38,534
Other (13) $ 2,812 2,886 2,961 3,038 3,117 3,198 3,281 3,367 3,454 3,543
Production Service Center
(14) $ 22,931 23,528 24,139 24,767 25,411 26,071 26,749 27,445 28,158 28,890
Administration & General
(15) $ 8,857 9,087 9,324 9,566 9,815 10,070 10,332 10,600 10,876 11,159
---------- -------- --------- --------- --------- --------- --------- --------- -------- ---------
Total Operating Expenses $ 733,241 741,465 761,754 775,721 795,876 808,025 831,138 852,157 875,301 905,221
NET OPERATING REVENUES
($000) $ 572,176 576,473 607,630 608,472 619,773 628,963 642,799 674,986 682,238 697,113
CAPITAL EXPENDITURES
($000)(16) $ 53,915 61,801 55,751 57,870 78,064 52,377 55,481 92,587 56,235 84,968
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 518,261 514,672 551,879 550,602 541,709 576,586 587,318 582,399 626,003 612,145
FIXED CHARGES ($000)(17) $ 134,000 131,500 138,000 131,000 110,000 150,000 144,000 105,000 139,500 105,000
ANNUAL FIXED CHARGE
COVERAGE (18) 3.87 3.91 4.00 4.20 4.92 3.84 4.08 5.55 4.49 5.83
AVERAGE FIXED CHARGE
COVERAGE (19) 5.34
A-36
Exhibit A-6
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity E - Increased Heat Rate
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ ---------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 50.5% 50.5% 50.5% 50.5% 50.5% 50.5% 50.5% 50.5%
Energy Generation (GWh) 23,314 23,314 23,314 23,314 23,314 23,314 23,314 23,314
Heat Rate (Btu/kWh)(4) 10,170 10,170 10,170 10,170 10,170 10,170 10,170 10,170
Fuel Consumption (BBtu) 237,107 237,107 237,107 237,107 237,107 237,107 237,107 237,107
SO\2\ Allowances
Purchased (Tons)(5) 90,748 90,748 90,748 90,748 90,748 90,748 90,748 90,748
NO\X\ Allowances
Purchased (Tons)(6) (699) (699) (699) (699) (699) (699) (699) (699)
COMMODITY PRICES
General Inflation
(%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market
Electricity
Price ($/MWh)(8) $ 70.47 72.26 74.10 76.00 77.95 79.96 82.03 84.17
Fuel Price
($/MMBtu)(9) $ 2.72 2.79 2.87 2.94 3.02 3.10 3.19 3.27
SO\2\ Allowances
($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances
($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES
($000)
Market Electricity
Revenues
Chalk Point $ 664,427 681,024 698,094 715,649 733,704 752,273 771,371 791,012
Dickerson $ 282,661 288,708 294,907 301,260 307,773 314,448 321,290 328,303
Morgantown $ 503,215 517,528 532,315 547,597 563,398 579,740 596,649 614,153
Potomac River $ 192,610 197,409 202,328 207,369 212,536 217,832 223,259 228,822
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Revenues $1,642,913 1,684,669 1,727,643 1,771,876 1,817,410 1,864,292 1,912,569 1,962,290
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 301,475 310,082 318,938 328,048 337,422 347,065 356,986 367,194
Emissions
Allowances $ 727 746 766 785 805 827 848 870
Operations &
Maintenance $ 52,902 53,811 55,001 56,537 58,192 59,591 61,257 62,849
Other (13) $ 30,453 31,245 32,058 32,891 33,746 34,623 35,524 36,448
Dickerson
Fuel $ 97,562 100,113 102,730 105,417 108,174 111,004 113,909 116,890
Emissions
Allowances $ 6,522 6,691 6,866 7,044 7,227 7,415 7,607 7,805
Operations &
Maintenance $ 31,944 32,774 33,627 34,500 35,398 36,318 37,263 38,232
Other (13) $ 16,242 16,663 17,097 17,541 17,997 18,465 18,945 19,438
Morgantown
Fuel $ 162,352 166,416 170,582 174,854 179,232 183,721 188,323 193,041
Emissions
Allowances $ 11,778 12,084 12,398 12,720 13,051 13,390 13,739 14,096
Operations &
Maintenance $ 30,840 31,641 32,464 33,308 34,173 35,063 35,974 36,909
Other (13) $ 15,973 16,389 16,816 17,252 17,701 18,161 18,634 19,118
Potomac River
Fuel $ 84,097 85,994 87,933 89,917 91,945 94,019 96,140 98,308
Emissions
Allowances $ 1,925 1,975 2,027 2,079 2,134 2,188 2,245 2,304
Operations &
Maintenance $ 39,459 40,415 41,211 42,544 43,383 44,657 45,799 47,143
Other (13) $ 3,635 3,730 3,827 3,927 4,029 4,134 4,242 4,352
Production
Service
Center (14) $ 29,642 30,412 31,203 32,014 32,847 33,701 34,577 35,476
Administration
& General (15) $ 11,449 11,746 12,052 12,365 12,687 13,017 13,355 13,702
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Expenses $ 928,977 952,927 977,595 1,003,744 1,030,144 1,057,359 1,085,365 1,114,175
NET OPERATING
REVENUES ($000) $ 713,936 731,743 750,048 768,132 787,266 806,933 827,204 848,115
CAPITAL
EXPENDITURES
($000)(16) $ 83,300 69,768 68,116 89,506 89,981 63,442 87,592 107,879
CASH AVAILABLE
FOR FIXED
CHARGES ($000) $ 630,636 661,975 681,932 678,626 697,285 743,491 739,612 740,236
FIXED CHARGES
($000)(17) $ 41,633 35,616 22,401 16,142 16,238 11,518 74,250 80,000
ANNUAL FIXED
CHARGE COVERAGE (18) 15.15 18.59 30.44 42.04 42.94 64.55 9.96 9.25
AVERAGE FIXED
CHARGE COVERAGE (19) 5.34
Footnotes to Exhibit A-6
The footnotes to Exhibit A-6 are the same as the footnotes for Exhibit A-1,
except:
4. Heat rate for each of the Generating Facilities is assumed to be 5 percent
higher than that assumed in the Base Case.
A-38
Exhibit A-7
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity F - Increased Operating Expenses
Year Ending
December 31, 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
- ------------ ---------- --------- --------- --------- --------- --------- --------- --------- --------- --------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity
(MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer
Capacity
(MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability
(%)(2) 88.0 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity
Factor
(%)(3) 54.5 52.1% 50.0% 48.1% 47.9% 49.7% 49.5% 49.3% 49.5% 50.3%
Energy
Generation
(GWh) 25,125 24,039 23,068 22,205 22,116 22,912 22,834 22,720 22,847 23,190
Heat Rate
(Btu/kWh)(4) 9,736 9,716 9,655 9,700 9,709 9,698 9,694 9,680 9,686 9,683
Fuel
Consumption
(BBtu) 244,605 233,562 222,736 215,397 214,721 222,190 221,360 219,944 221,296 224,549
SO\2\ Allowances
Purchased
(Tons)(5) 84,300 77,031 75,310 61,076 60,221 67,094 67,469 68,004 68,562 79,741
NO\X\ Allowances
Purchased
(Tons)(6) 7,669 1,880 5,843 3,999 3,263 1,527 1,218 (1,104) (1,227) (1,098)
COMMODITY PRICES
General Inflation
(%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market
Electricity
Price
($/MWh)(8) $ 57.80 53.11 49.07 47.51 46.46 49.21 50.74 50.97 52.15 53.54
Fuel Price
($/MMBtu)(9) $ 2.19 2.08 1.93 1.98 1.88 1.92 1.95 1.98 2.03 2.07
SO\2\ Allowances
($/Ton)(10) $ 150 154 158 162 166 171 175 180 184 189
NO\X\ Allowances
($/Ton)(11) $ 1,000 1,000 2,300 2,000 1,700 1,744 1,790 1,836 1,884 1,933
OPERATING
REVENUES ($000)
Market
Electricity
Revenues
Chalk Point $ 630,933 561,827 478,221 458,823 438,703 470,387 490,281 478,898 494,217 514,404
Dickerson $ 237,088 207,371 195,508 181,158 179,766 191,477 196,002 197,726 203,967 208,358
Morgantown $ 414,647 363,190 329,446 300,376 296,764 344,321 344,156 350,943 358,902 376,006
Potomac River $ 169,522 144,298 128,782 114,685 112,338 121,287 128,102 130,412 134,372 142,891
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total
Operating
Revenues $1,452,190 1,276,686 1,131,958 1,055,042 1,027,571 1,127,472 1,158,541 1,157,979 1,191,457 1,241,658
OPERATING
EXPENSES
($000)(12)
Chalk Point
Fuel $ 284,808 248,017 206,342 219,554 193,688 203,677 201,037 200,828 208,761 220,204
Emissions
Allowances $ 2,915 (483) 3,338 2,665 2,341 1,158 780 (868) (1,163) 269
Operations &
Maintenance $ 42,527 37,605 35,644 36,874 37,899 39,083 40,354 41,468 42,492 44,021
Other (13) $ 20,049 20,570 21,105 21,653 22,216 22,794 23,386 23,995 24,619 25,258
Dickerson
Fuel $ 75,634 70,005 65,552 62,247 62,204 63,336 64,880 65,087 68,053 66,712
Emissions
Allowances $ 5,293 4,785 5,439 4,229 3,410 3,590 3,704 3,671 3,913 4,137
Operations &
Maintenance $ 25,229 22,955 24,238 22,572 23,217 23,832 24,515 25,144 25,825 26,406
Other (13) $ 10,692 10,970 11,255 11,547 11,848 12,156 12,472 12,796 13,130 13,470
Morgantown
Fuel $ 113,597 109,746 105,456 97,783 100,133 108,863 110,670 113,059 114,903 118,171
Emissions
Allowances $ 10,303 8,024 13,568 10,196 9,335 8,661 8,910 6,940 7,109 7,535
Operations &
Maintenance $ 24,491 22,300 22,608 21,358 21,912 23,212 23,806 24,436 24,937 25,539
Other (13) $ 10,516 10,790 11,070 11,357 11,653 11,956 12,267 12,586 12,913 13,249
Potomac River
Fuel $ 61,657 57,597 52,450 46,621 47,384 49,848 54,197 55,666 57,259 60,801
Emissions
Allowances $ 1,804 1,409 2,987 802 471 698 590 438 458 1,006
Operations &
Maintenance $ 30,453 28,168 27,217 27,183 27,703 28,746 29,793 30,705 31,423 32,621
Other (13) $ 2,394 2,456 2,520 2,585 2,652 2,721 2,793 2,864 2,939 3,016
Production
Service Center
(14) $ 19,514 20,021 20,542 21,076 21,624 22,186 22,763 23,355 23,962 24,585
Administration
& General (15) $ 7,537 7,733 7,934 8,140 8,352 8,569 8,792 9,021 9,255 9,496
---------- --------- --------- -------- --------- --------- --------- --------- --------- ---------
Total Operating
Expenses $ 749,412 682,669 639,266 628,442 608,043 635,086 645,708 651,191 670,788 696,495
NET OPERATING
REVENUES
($000) $ 702,778 594,017 492,692 426,600 419,528 492,386 512,833 506,787 520,669 545,164
CAPITAL
EXPENDITURES
($000)(16) $ 53,156 54,300 36,557 63,940 61,377 89,005 87,558 85,629 51,094 50,936
CASH AVAILABLE
FOR FIXED
CHARGES
($000) $ 649,622 539,717 456,135 362,660 358,151 403,381 425,275 421,158 469,575 494,228
FIXED CHARGES
($000)(17) $ 196,065 170,468 150,720 121,500 116,005 105,671 112,348 120,723 142,339 140,220
ANNUAL FIXED
CHARGE
COVERAGE (18) 3.31 3.17 3.03 2.98 3.09 3.82 3.79 3.49 3.30 3.52
AVERAGE FIXED
CHARGE
COVERAGE (19) 5.34
A-39
Exhibit A-7
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity F - Increased Operating Expenses
Year Ending
December 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
- ------------ ---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor
(%)(3) 51.0% 50.5% 50.5% 50.3% 50.5% 50.2% 50.1% 50.2% 50.2% 50.5%
Energy Generation
(GWh) 23,505 23,283 23,301 23,214 23,313 23,144 23,125 23,162 23,140 23,314
Heat Rate
(Btu/kWh)(4) 9,697 9,689 9,690 9,688 9,683 9,676 9,679 9,676 9,682 9,686
Fuel Consumption
(BBtu) 227,931 225,583 225,797 224,892 225,729 223,934 223,822 224,123 224,046 225,824
SO\2\ Allowances
Purchased (Tons)(5) 80,682 80,438 80,116 80,313 81,360 81,163 80,632 81,155 80,764 81,901
NO\X\ Allowances
Purchased (Tons)(6) (894) (886) (1,036) (1,042) (1,025) (1,173) (1,136) (1,127) (1,132) (1,031)
COMMODITY PRICES
General Inflation
(%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity
Price ($/MWh)(8) $ 55.54 56.61 58.77 59.63 60.72 62.09 63.74 65.93 67.31 68.73
Fuel Price
($/MMBtu)(9) $ 2.15 2.18 2.24 2.29 2.34 2.38 2.45 2.51 2.58 2.65
SO\2\ Allowances
($/Ton)(10) $ 194 199 204 209 215 220 226 232 238 244
NO\X\ Allowances
($/Ton)(11) $ 1,983 2,035 2,088 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES
($000)
Market Electricity
Revenues
Chalk Point $ 538,620 541,669 563,206 567,715 577,831 581,556 596,300 617,974 631,490 648,289
Dickerson $ 223,343 223,771 233,287 235,327 241,374 246,091 251,962 260,658 267,191 276,761
Morgantown $ 393,697 401,168 415,598 421,387 431,819 441,657 453,438 469,707 476,834 489,357
Potomac River $ 149,757 151,330 157,294 159,763 164,625 167,684 172,237 178,804 182,024 187,928
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Revenues $1,305,417 1,317,938 1,369,384 1,384,193 1,415,649 1,436,988 1,473,937 1,527,143 1,557,539 1,602,335
OPERATING EXPENSES
($000)(12)
Chalk Point
Fuel $ 231,070 230,248 237,481 241,764 247,487 246,635 254,751 261,428 269,582 279,154
Emissions
Allowances $ 306 328 127 309 215 (215) (93) (8) (26) 16
Operations &
Maintenance $ 45,226 45,890 46,916 48,185 49,594 50,665 52,091 53,443 54,728 56,745
Other (13) $ 25,916 26,590 27,280 27,990 28,718 29,464 30,230 31,016 31,822 32,650
Dickerson
Fuel $ 72,995 72,554 75,677 75,054 77,822 79,324 80,831 83,062 86,397 90,559
Emissions
Allowances $ 4,481 4,526 4,534 4,539 4,861 4,990 4,902 5,084 5,213 5,647
Operations &
Maintenance $ 27,174 27,846 28,584 29,298 30,093 30,863 31,649 32,479 33,337 34,248
Other (13) $ 13,821 14,180 14,549 14,927 15,316 15,713 16,122 16,542 16,971 17,413
Morgantown
Fuel $ 122,400 125,663 128,166 130,313 132,695 136,783 141,258 143,505 146,613 150,860
Emissions
Allowances $ 7,942 8,209 8,397 8,578 8,871 9,168 9,495 9,678 9,855 10,240
Operations &
Maintenance $ 26,222 26,908 27,599 28,318 29,069 29,830 30,598 31,398 32,204 33,064
Other (13) $ 13,593 13,947 14,309 14,682 15,063 15,455 15,856 16,269 16,691 17,125
Potomac River
Fuel $ 62,898 63,883 65,472 67,066 69,218 70,549 72,284 74,524 75,830 78,331
Emissions
Allowances $ 1,142 1,136 1,133 1,161 1,282 1,304 1,305 1,403 1,429 1,526
Operations &
Maintenance $ 33,475 34,242 34,925 36,063 36,837 37,899 38,877 40,083 40,946 42,387
Other (13) $ 3,094 3,174 3,257 3,342 3,429 3,517 3,609 3,703 3,799 3,898
Production Service
Center (14) $ 25,224 25,880 26,553 27,244 27,952 28,679 29,424 30,189 30,974 31,780
Administration &
General (15) $ 9,743 9,996 10,256 10,523 10,796 11,077 11,365 11,660 11,964 12,275
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Expenses $ 726,723 735,200 755,215 769,357 789,317 801,698 824,553 845,459 868,328 897,919
NET OPERATING
REVENUES ($000) $ 578,694 582,738 614,168 614,836 626,332 635,289 649,383 681,684 689,211 704,416
CAPITAL EXPENDITURES
($000)(16) $ 59,305 67,978 61,326 63,658 85,871 57,615 61,028 101,847 61,859 93,465
CASH AVAILABLE
FOR FIXED CHARGES
($000) $ 519,389 514,760 552,842 551,178 540,461 577,674 588,355 579,837 627,352 610,951
FIXED CHARGES
($000)(17) $ 134,000 131,500 138,000 131,000 110,000 150,000 144,000 105,000 139,500 105,000
ANNUAL FIXED CHARGE
COVERAGE (18) 3.88 3.91 4.01 4.21 4.91 3.85 4.09 5.52 4.50 5.82
AVERAGE FIXED CHARGE
COVERAGE (19) 5.34
A-40
Exhibit A-7
Mirant Mid-Atlantic Generating Facilities
Projected Operating Results
Sensitivity F - Increased Operating Expenses
Year Ending December 31, 2021 2022 2023 2024 2025 2026 2027 2028
- ------------------------ ---- ---- ---- ---- ---- ---- ---- ----
CONSOLIDATED
- ------------
PERFORMANCE
Capacity (MW)(1) 5,266 5,266 5,266 5,266 5,266 5,266 5,266 5,266
Summer Capacity (MW) 5,154 5,154 5,154 5,154 5,154 5,154 5,154 5,154
Availability (%)(2) 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0% 88.0%
Capacity Factor (%)(3) 50.5% 50.5% 50.5% 50.5% 50.5% 50.5% 50.5% 50.5%
Energy Generation (GWh) 23,314 23,314 23,314 23,314 23,314 23,314 23,314 23,314
Heat Rate (Btu/kWh)(4) 9,686 9,686 9,686 9,686 9,686 9,686 9,686 9,686
Fuel Consumption (BBtu) 225,824 225,824 225,824 225,824 225,824 225,824 225,824 225,824
SO\2\ Allowances Purchased
(Tons)(5) 81,901 81,901 81,901 81,901 81,901 81,901 81,901 81,901
NO\X\ Allowances Purchased
(Tons)(6) (1,031) (1,031) (1,031) (1,031) (1,031) (1,031) (1,031) (1,031)
COMMODITY PRICES
General Inflation (%)(7) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Market Electricity Price
($/MWh)(8) $ 70.47 72.26 74.10 76.00 77.95 79.96 82.03 84.17
Fuel Price ($/MMBtu)(9) $ 2.72 2.79 2.87 2.94 3.02 3.10 3.19 3.27
SO\2\ Allowances ($/Ton)(10) $ 251 257 264 271 278 285 292 300
NO\X\ Allowances ($/Ton)(11) $ 2,563 2,630 2,698 2,769 2,841 2,914 2,990 3,068
OPERATING REVENUES ($000)
Market Electricity Revenues
Chalk Point $ 664,427 681,024 698,094 715,649 733,704 752,273 771,371 791,012
Dickerson $ 282,661 288,708 294,907 301,260 307,773 314,448 321,290 328,303
Morgantown $ 503,215 517,528 532,315 547,597 563,398 579,740 596,649 614,153
Potomac River $ 192,610 197,409 202,328 207,369 212,536 217,832 223,259 228,822
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Revenues $1,642,913 1,684,669 1,727,643 1,771,876 1,817,410 1,864,292 1,912,569 1,962,290
OPERATING EXPENSES ($000)(12)
Chalk Point
Fuel $ 287,122 295,320 303,753 312,430 321,357 330,541 339,990 349,712
Emissions Allowances $ 17 17 19 19 19 20 20 21
Operations & Maintenance $ 58,192 59,192 60,501 62,192 64,010 65,550 67,382 69,134
Other (13) $ 33,499 34,370 35,264 36,180 37,121 38,086 39,077 40,093
Dickerson
Fuel $ 92,926 95,355 97,849 100,408 103,034 105,730 108,496 111,336
Emissions Allowances $ 5,795 5,945 6,100 6,259 6,421 6,589 6,759 6,936
Operations & Maintenance $ 35,138 36,051 36,989 37,951 38,937 39,950 40,989 42,054
Other (13) $ 17,865 18,330 18,806 19,295 19,797 20,312 20,839 21,382
Morgantown
Fuel $ 154,636 158,508 162,476 166,545 170,715 174,991 179,374 183,868
Emissions Allowances $ 10,506 10,779 11,059 11,348 11,643 11,945 12,256 12,574
Operations & Maintenance $ 33,923 34,806 35,710 36,638 37,591 38,569 39,571 40,601
Other (13) $ 17,571 18,028 18,497 18,977 19,470 19,977 20,496 21,030
Potomac River
Fuel $ 80,098 81,904 83,752 85,641 87,573 89,548 91,568 93,633
Emissions Allowances $ 1,565 1,607 1,648 1,691 1,735 1,780 1,826 1,873
Operations & Maintenance $ 43,405 44,457 45,333 46,798 47,721 49,123 50,380 51,859
Other (13) $ 3,999 4,104 4,210 4,320 4,432 4,547 4,665 4,787
Production Service Center (14) $ 32,606 33,454 34,323 35,216 36,131 37,071 38,035 39,024
Administration & General (15) $ 12,594 12,921 13,257 13,602 13,955 14,318 14,691 15,072
---------- --------- --------- --------- --------- --------- --------- ---------
Total Operating Expenses $ 921,457 945,150 969,545 995,508 1,021,662 1,048,646 1,076,414 1,104,988
NET OPERATING REVENUES ($000) $ 721,456 739,520 758,098 776,368 795,749 815,647 836,155 857,303
CAPITAL EXPENDITURES ($000)(16) $ 91,631 76,744 74,930 98,455 98,980 69,786 96,352 118,668
CASH AVAILABLE
FOR FIXED CHARGES ($000) $ 629,825 662,776 683,168 677,913 696,769 745,861 739,803 738,635
FIXED CHARGES ($000)(17) $ 41,633 35,616 22,401 16,142 16,238 11,518 74,250 80,000
ANNUAL FIXED CHARGE COVERAGE (18) 15.13 18.61 30.50 42.00 42.91 64.76 9.96 9.23
AVERAGE FIXED CHARGE COVERAGE (19) 5.34
A-41
Footnotes to Exhibit A-7
The footnotes to Exhibit A-7 are the same as the footnotes for Exhibit A-1,
except:
12. Assumed to be 10 percent higher than that assumed in the Base Case.
13. Assumed to be 10 percent higher than that assumed in the Base Case.
14. Assumed to be 10 percent higher than that assumed in the Base Case.
15. Assumed to be 10 percent higher than that assumed in the Base Case.
16. Assumed to be 10 percent higher than that assumed in the Base Case.
A-42
APPENDIX A
INDEPENDENT ENGINEER'S REPORT
SOUTHERN ENERGY
MID-ATLANTIC, LLC
GENERATING FACILITIES
[LOGO OF RW BECK]
APPENDIX A
INDEPENDENT ENGINEER'S REPORT
SOUTHERN ENERGY MID-ATLANTIC, LLC GENERATING FACILITIES
TABLE OF CONTENTS
Page
----
INTRODUCTION............................................................. A-1
THE CHALK POINT FACILITY................................................. A-2
The Plant Site.......................................................... A-3
Description of the Facility............................................. A-3
Mechanical Equipment and Systems...................................... A-3
Electrical and Control Systems........................................ A-7
Environmental Controls and Equipment.................................. A-8
Off-Site Requirements................................................. A-9
Review of Technology.................................................... A-10
Estimated Useful Life................................................... A-10
THE DICKERSON FACILITY................................................... A-11
The Plant Site.......................................................... A-11
Description of the Facility............................................. A-11
Mechanical Equipment and Systems...................................... A-11
Electrical and Control Systems........................................ A-13
Environmental Controls and Equipment.................................. A-14
Off-Site Requirements................................................. A-15
Review of Technology.................................................... A-16
Estimated Useful Life................................................... A-16
THE MORGANTOWN FACILITY.................................................. A-16
The Plant Site.......................................................... A-17
Description of the Facility............................................. A-17
Mechanical Equipment and Systems...................................... A-17
Electrical and Control Systems........................................ A-20
Environmental Controls and Equipment.................................. A-21
Off-Site Requirements................................................. A-22
Review of Technology.................................................... A-22
Estimated Useful Life................................................... A-23
THE POTOMAC RIVER FACILITY............................................... A-23
The Plant Site.......................................................... A-23
Description of the Facility............................................. A-24
Mechanical Equipment and Systems...................................... A-24
Electrical and Control Systems........................................ A-26
Environmental Controls and Equipment.................................. A-27
Off-Site Requirements................................................. A-27
Review of Technology.................................................... A-28
Estimated Useful Life................................................... A-28
A-i
APPENDIX A
INDEPENDENT ENGINEER'S REPORT
SOUTHERN ENERGY MID-ATLANTIC, LLC GENERATING FACILITIES
TABLE OF CONTENTS
(continued)
Page
----
THE PRODUCTION SERVICE CENTER............................................ A-28
THE PINEY POINT PIPELINE................................................. A-29
THE ASH STORAGE FACILITIES............................................... A-30
Brandywine............................................................ A-30
Faulkner.............................................................. A-31
Westland.............................................................. A-31
ENVIRONMENTAL ASSESSMENTS................................................ A-32
Environmental Site Assessments.......................................... A-32
The Chalk Point Facility.............................................. A-32
The Dickerson Facility................................................ A-33
The Morgantown Facility............................................... A-33
The Potomac River Facility............................................ A-33
The Production Service Center......................................... A-33
The Piney Point Pipeline.............................................. A-33
The Ash Storage Facilities............................................ A-34
Summary............................................................... A-34
Status of Permits and Approvals......................................... A-34
OPERATION AND MAINTENANCE................................................ A-38
Operation of the Generating Facilities.................................. A-38
Operating Programs and Procedures....................................... A-39
The Chalk Point Facility.............................................. A-39
The Dickerson Facility................................................ A-39
The Morgantown Facility............................................... A-40
The Potomac River Facility............................................ A-41
The Production Service Center......................................... A-42
Summary................................................................. A-43
OPERATING HISTORY........................................................ A-43
Performance............................................................. A-43
The Chalk Point Facility.............................................. A-44
The Dickerson Facility................................................ A-45
The Morgantown Facility............................................... A-46
The Potomac River Facility............................................ A-48
Summary............................................................... A-49
Regulatory Compliance................................................... A-50
The Chalk Point Facility.............................................. A-52
The Dickerson Facility................................................ A-54
The Morgantown Facility............................................... A-56
The Potomac River Facility............................................ A-58
The Piney Point Pipeline.............................................. A-60
The Ash Storage Facilities............................................ A-61
Summary............................................................... A-61
A-ii
APPENDIX A
INDEPENDENT ENGINEER'S REPORT
SOUTHERN ENERGY MID-ATLANTIC, LLC GENERATING FACILITIES
TABLE OF CONTENTS
(continued)
Page
----
PROJECTED OPERATING RESULTS.............................................. A-62
Annual Operating Revenues............................................... A-62
Revenues from Electricity Sales....................................... A-62
Annual Operating Expenses............................................... A-62
Fuel Costs............................................................ A-62
Operating and Maintenance Costs....................................... A-62
Emissions Allowances.................................................. A-62
General and Administrative and Other Expenses......................... A-63
Capital Expenditures.................................................... A-63
Annual Fixed Charges.................................................... A-63
Fixed Charge Coverage................................................... A-63
Contribution from the Leased Facilities................................. A-64
Sensitivity Analyses.................................................... A-64
Summary Comparison of Projected Operating Results....................... A-64
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS USED IN
THE PROJECTION OF OPERATING RESULTS................................... A-65
CONCLUSIONS.............................................................. A-66
EXHIBITS
EXHIBIT A-1 Base Case Projected Operating Results..................... A-68
EXHIBIT A-2 Sensitivity A - Low Gas Market Price Scenario............. A-84
EXHIBIT A-3 Sensitivity B - Capacity Overbuild Market Price Scenario.. A-88
EXHIBIT A-4 Sensitivity C - Breakeven Market Prices................... A-92
EXHIBIT A-5 Sensitivity D - Reduced Availability...................... A-96
EXHIBIT A-6 Sensitivity E - Increased Heat Rate....................... A-100
EXHIBIT A-7 Sensitivity F - Increased Operating Expenses.............. A-104
Copyright (C) 2000, R. W. Beck, Inc.
All Rights Reserved
A-iii
[RW BECK LOGO]
December 7, 2000
Credit Suisse First Boston
Eleven Madison Avenue
New York, NY 10010
Subject: Independent Engineer's Report on
Southern Energy Mid-Atlantic, LLC Generating Facilities
Ladies and Gentlemen:
INTRODUCTION
Presented herein is the report (the "Report") of our review and
analyses of the 2,423 megawatt ("MW") (net) Chalk Point power plant located in
Prince George's County, Maryland (the "Chalk Point Facility"); the 837 MW (net)
Dickerson power plant located in Montgomery County, Maryland (the "Dickerson
Facility"); the 1,412 MW (net) Morgantown power plant located in Charles County,
Maryland (the "Morgantown Facility"); and the 482 MW (net) Potomac River power
plant located in Alexandria, Virginia (the "Potomac River Facility" and,
together with the Chalk Point, Dickerson, and Morgantown Facilities, the
"Generating Facilities"). Southern Energy, Inc. ("Southern Energy") entered
into an Asset Purchase and Sale Agreement dated June 7, 2000 (the "Asset
Purchase Agreement") to acquire the Generating Facilities, as well as certain
other assets and obligations, from Potomac Electric Power Company ("Pepco").
Prior to the acquisition of the Generating Facilities, Southern Energy will
assign its rights in the Generating Facilities and related assets to Southern
Energy Mid-Atlantic, LLC and its subsidiaries and affiliates (collectively, "SE
Mid-Atlantic"), all of which are direct or indirect wholly-owned subsidiaries of
Southern Energy. SE PJM Management, LLC, an indirect wholly owned subsidiary of
Southern Energy will hire Pepco personnel in conjunction with the acquisition
and will provide operations, maintenance and general management personnel to SE
Mid-Atlantic. Southern Energy Resources, Inc. ("SERI"), a direct wholly owned
subsidiary of Southern Energy will provide executive personnel and
administrative services to SE Mid-Atlantic. SE Mid-Atlantic will also acquire a
fuel oil delivery pipeline and associated pumping and storage facilities for
supplying fuel oil to the Chalk Point and Morgantown Facilities (the "Piney
Point Pipeline"), as well as the Faulkner ash storage facility ("Faulkner"), the
Brandywine ash storage facility ("Brandywine"), and the Westland ash storage
facility ("Westland", and together with Faulkner and Brandywine, the "Ash
Storage Facilities").
SE Mid-Atlantic is entering into a leveraged lease transaction (the
"Lease") pursuant to which SE Mid-Atlantic will lease a portion of the
Generating Facilities (the "Leased Facilities") from owner lessors who will
purchase the Leased Facilities directly from Pepco. The purchase of the Leased
Facilities will be financed, in part, through the issuance by a pass through
trust of $1,224,000,000 of Pass Through Certificates, Series A, Series B, and
Series C (the "Certificates"). SE Mid-Atlantic will be responsible for making
rent payments on the Lease (the "Rent"). The Rent will have the same priority
as payments on any other senior debt of SE Mid-Atlantic (together with the Rent,
the "Fixed Charges").
The Chalk Point Facility consists of two coal-fired electric
generating units, two dual-fueled electric generating units, and seven
combustion turbine ("CT") units, one of which is owned by Southern Maryland
Electric Cooperative ("SMECO"). SE Mid-Atlantic is entitled to the entire
output of the CT owned by SMECO. Chalk Point Units 1 and 2 have a combined
nominal net generating capability of 683 MW. Chalk Point Units 3 and 4 have a
A-1
nominal net generating capability of 1,224 MW. The seven Chalk Point CTs have a
combined nominal net generating capability of 516 MW. Fuel for the Chalk Point
Facility is under short-term agreement.
The Dickerson Facility consists of three coal-fired electric
generating units and three CTs. Dickerson Units 1, 2 and 3 have a combined
nominal net generating capability of 546 MW. The Dickerson CTs have a combined
nominal net generating capability of 291 MW. Fuel for the Dickerson Facility is
under short-term agreement.
The Morgantown Facility consists of two coal-fired electric generating
units and six CTs. Morgantown Units 1 and 2 have a combined nominal net
generating capability of 1,164 MW. The Morgantown CTs have a combined nominal
net generating capability of 248 MW. Fuel for the Morgantown Facility is under
short-term agreement.
The Potomac River Facility consists of five coal-fired electric
generating units. Potomac River Units 1 and 2 have a combined nominal net
generating capability of 176 MW. Potomac River Units 3, 4 and 5 have a combined
nominal net generating capability of 306 MW. Fuel for the Potomac River
Facility is under short-term agreement.
During the course of our review, we visited and made general field
observations of the Generating Facilities and the sites of the Generating
Facilities. The general field observations were visual, above-ground
examinations of selected areas which we deemed adequate to comment on the
existing condition of the sites but which were not in the level of detail
necessary to reveal conditions with respect to geological or environmental
conditions, the internal physical condition of any equipment, or the conformance
with agreements, codes, permits, rules, or regulation of any party having
jurisdiction with respect to the sites.
In addition, we have reviewed: (1) the status of permits and approvals
and compliance with those permits; (2) environmental assessment reports; (3) the
historic and projected levels of production of the Generating Facilities; (4)
the historic and projected operating and maintenance expenses of the Generating
Facilities; (5) the projected revenues of the Generating Facilities; (6)
historical operating records of the Generating Facilities, and (7) operating
programs and procedures. Based on our review, we have prepared a projection of
revenues and expenses of the Generating Facilities and Fixed Charge coverage
ratios, which are attached as Exhibits A-1 through A-7 to this Report (the
"Projected Operating Results").
In developing the Projected Operating Results, we have relied upon a
report by PHB Hagler Bailly Consulting, Inc. ("Hagler Bailly") attached as
Appendix B to the Confidential Offering Circular, of which this Report is a
part, for projections of the Generating Facilities' electricity sales, revenues,
and fuel costs. Based on their experience in developing such projections, we
believe it is reasonable to rely upon the projections prepared by Hagler Bailly.
THE CHALK POINT FACILITY
The Chalk Point Facility is comprised of four conventional steam
turbine units and seven simple-cycle CTs, with a total net summer generating
capacity of approximately 2,423 MW. Included in this amount is SE Mid-
Atlantic's entitlement to the output of one on-site CT that is owned by SMECO.
The Chalk Point Facility is the largest of SE Mid-Atlantic's generating stations
and provides baseload, mid-range and peaking generation and is capable of
utilizing a variety of fuels.
Chalk Point Units 1 and 2 are identical coal-fired electric generating
units that have been in commercial operation since 1964 and 1965, respectively.
Each unit consists of a single boiler and cross compound steam turbine generator
with nameplate capacity ratings of 364 MW. The units have actual maximum
capacity ratings of approximately 341 to 343 MW, depending on the season, and
can be dispatched down to 210 MW. The annual average net heat rates are
approximately 9,700 British thermal units per kilowatt-hour ("Btu/kWh") for each
unit. Each unit has a Babcock and Wilcox ("B&W") pulverized coal-fired boiler
and General Electric ("GE") steam turbine and generator.
A-2
Chalk Point Units 3 and 4 are identical electric generating units that
can be fired by either No. 6 residual fuel oil or natural gas and have been in
commercial operation since 1975 and 1981, respectively. Each unit consists of a
single boiler and steam turbine generator with nameplate capacity ratings of 659
MW. The units have actual maximum capacity ratings of approximately 612 MW and
can be dispatched down to 130 MW. The annual average net heat rates have ranged
between approximately 12,000 Btu/kWh and 13,500 Btu/kWh over the past five
years. Each unit has a Combustion Engineering ("CE") oil- and gas-fired boiler
and GE steam turbine and generator.
The Chalk Point CTs are simple-cycle units that provide the Chalk
Point Facility with both black starting capability and peaking generation. The
units range from 18 MW to 107 MW of capacity, with a summer total capacity for
all seven units of 516 MW. With the exception of Chalk Point CTs 1 and 2, the
two black start units that only fire No. 2 distillate oil, all of the other CTs
are capable of firing either No. 2 distillate oil or natural gas.
In addition, the Chalk Point Facility has certain common facilities
shared by all units such as river water pumping stations, fuels receiving,
storage and handling systems, water treatment systems, warehouses, maintenance
shops, chemistry laboratory, administrative offices, groundwater monitoring
wells, and electrical switchyard.
The Plant Site
- --------------
The Chalk Point Facility is located approximately 45 miles southeast
of Washington, DC on a 1,160-acre site at the confluence of the Patuxent River
and Swanson Creek in Prince George's County, Maryland. The site is easily
accessible from Eagle Harbor Road off of Maryland State Highway 381 and provides
adequate access to necessary utilities and rail transportation. The site is in
a largely rural area bordered on the east by the Patuxent River, on the south by
Swanson Creek, and on the north and west by farmland. On the basis of our
observations and the historical operations of the Chalk Point Facility, we are
of the opinion that the site is suitable for the Chalk Point Facility's
continued operation.
Description of the Facility
- ---------------------------
Mechanical Equipment and Systems
Steam Generators
The Chalk Point Units 1 and 2 steam generators consist of identical
B&W once through, double reheat, supercritical, balanced draft, indoor units
with two Ljungstrom regenerative secondary air preheaters operating in parallel
with a tubular primary air preheater. The units were originally designed as
positive draft units, but were converted to balanced draft operation in the
early 1980s. Each steam generator includes two multi-stage superheaters, a
multi stage reheater, a single stage convection reheater, an economizer, reheat
spray desuperheaters, and a steam sootblowing system. Each steam generator has
a maximum continuous capacity of 2,500,000 pounds per hour ("lb/hr") of steam
when operating at 3,575 pounds per square inch ("psig") and 1,000(degrees)F
superheater outlet temperature and final reheat temperatures of 1,050(degrees)F
and 1,000(degrees)F. The steam generators are designed to fire pulverized coal
as the primary fuel and have been retrofitted to fire natural gas as a secondary
fuel. In 1994 to 1995, to control oxides of nitrogen ("NO\X\"), the 24 wall
mounted coal burners were replaced with Riley Low-NO\X\ burners and a separated
over-fire air ("SOFA") systems was installed. Either natural gas or No. 2
distillate oil may be used for start-up and low load flame stabilization.
There are six positive pressure B&W type "EL" coal pulverizers and two
primary air fans for each unit. The pulverizer motors and main shafts have both
been upgraded to provide higher reliability. Primary and secondary air are
provided to each steam generator by two forced draft fans which supply air to
the two regenerative air preheaters, and two primary air fans which supply air
to the tubular primary air preheaters. Inlet air to all of the air preheaters
is heated by passing it through steam coils. The heated air flows as primary
air to the coal pulverizers to heat and dry the coal and transport it to the
burners, and as secondary air to the steam generator's windboxes to provide
adequate air for combustion of the coal. Two induced draft fans per unit draw
flue gas from the steam generator to maintain a slight negative pressure within
the unit, and discharge into the electrostatic precipitators ("ESPs") and then
to the 712-foot stack that is shared by both units.
A-3
The Chalk Point Units 3 and 4 steam generators consist of identical CE
controlled circulation, reheat, subcritical, balanced draft, indoor units with
two Ljungstrom regenerative air preheaters. Each steam generator includes a
divided furnace consisting of a tilting tangentially-fired, center wall furnace
with an economizer, a multi-stage superheater, a single-stage reheater,
superheat and reheat spray desuperheaters, and a steam sootblowing system. Each
steam generator has a maximum continuous capacity of 4,600,000 lb/hr of steam
when operating at 1,980 psig and 953(degrees)F superheater outlet temperature
with a final reheat temperature of 952(degrees)F. The steam generators are
designed to fire No. 6 residual oil as the primary fuel and have been
retrofitted to fire natural gas as a secondary fuel. Fuel is fired through
tilting tangential nozzles mounted in four elevations in each of the eight
corners of the divided furnace. Either natural gas or No. 2 distillate oil may
be used for start-up and low load flame stabilization.
Secondary air for combustion is provided to each steam generator by
two forced draft fans that supply air to the two regenerative air preheaters.
Inlet air to the air preheaters is heated by passing it through steam coils.
Two booster fans are provided to supply air to each steam generator's igniters.
There are four induced draft fans per unit, arranged in two trains of two fans
in series that draw flue gas from the steam generator to maintain a slight
negative pressure within the unit. The primary induced draft fans in each train
are not used, but remain in place in free-wheeling operation. The induced draft
fans discharge flue gases into ductwork that bypasses the gas scrubber units
which have been retired in place. Flue gases are discharged out each unit's
712-foot stack.
Steam Cycle and Heat Rejection Systems
Each Chalk Point Units 1 and 2 steam generator provides steam to a
single GE cross-compound, four flow, reheat, condensing steam turbine. Each of
the units is rated at 350,000 kilowatts ("kW") at inlet throttle conditions of
2,289,000 lb/hr of steam flow at 3,500 psig and 1,000(degrees)F with
1,050(degrees)F/1,000(degrees)F reheat inlet temperatures and 1.25 inches of
mercury ("inches Hg") backpressure. Each turbine is protected from water
induction by a water induction protection system. The low pressure turbines
exhaust into twin parallel shell surface condensers where the steam is condensed
by rejection of heat into the circulating water.
Circulating water for each condenser is obtained through an intake
canal and structure on the Patuxent River. The brackish water from the river is
screened and pumped by two 50 percent capacity vertical circulating water pumps
through cylindrical conduits to the condensers. After passing through the
condensers, the circulating water flows through conduits to the discharge canal
for return to the river.
Feedwater for each of Chalk Point Units 1 and 2 is provided by two 60
percent capacity steam-turbine-driven feedwater pumps, two full capacity
feedwater booster pumps and two full capacity condensate pumps through three
stages of low pressure feedwater heating including a deaerator, and three stages
of high pressure feedwater heating. The feedwater pumps and several of the
feedwater heaters have been replaced.
Each Chalk Point Units 3 and 4 steam generator provides steam to a
single GE tandem-compound, four flow, reheat, condensing steam turbine. Each of
the units is rated at 600,854 kW at inlet throttle conditions of 3,971,337 lb/hr
of steam flow at 1,800 psig and 950(degrees)F with 950(degrees)F reheat inlet
temperatures and 0.5 inches Hg backpressure. Each turbine is protected from
water induction by a water induction protection system. The low pressure
turbines exhaust into twin parallel shell surface condensers where the steam is
condensed by rejection of heat into the circulating water.
Each Chalk Point Units 3 and 4 circulating water system is a closed-
loop system that uses a crossflow, natural draft, concrete cooling tower. There
are two horizontal circulating water pumps which take suction from the cooling
tower basin and supply the condenser with cooling water that is returned to the
cooling tower. Makeup water for the cooling towers is supplied from the Chalk
Point Units 1 and 2 discharge canal by three makeup water pumps.
Feedwater for each of Chalk Point Units 3 and 4 is provided by two 60
percent capacity steam-turbine-driven feedwater pumps, three 50 percent capacity
feedwater booster pumps and two full capacity condensate pumps through three
stages of low pressure feedwater heating including a deaerator, and two stages
of high pressure feedwater heating.
A-4
Fuel Handling System
Coal for Chalk Point Units 1 and 2 is delivered in unit trains of
approximately 80 cars. Utilizing either of the Chalk Point Facility's two
locomotives, the coal cars are unloaded in a recently upgraded rotary car dumper
and conveyed to two Bradford breakers to screen out refuse and oversized
material. The sized coal is then conveyed to a rail mounted traveling bucket
wheel stacking/reclaiming machine. This machine is capable of stacking out coal
to the storage area, which normally has approximately 30 to 35 days of inventory
on site, or conveying coal to the conveyor system supplying the Chalk Point
Facility's coal storage bunkers, which hold approximately a 16 hour supply of
coal at full load burn rates. Both of these functions can be performed
simultaneously. Coal conveyed into the plant passes through a single roll
crusher to break up any frozen coal and over a magnetic separator to remove
pieces of metal that may be in the coal. All weighing and sampling of coal is
performed at the mines per the terms of the coal sales agreements. Coal storage
bunkers are located on each side of each boiler, with each bunker supplying coal
to three pulverizers. An emergency reclaim system is provided to permit fueling
of the plant in the event that the stacker/reclaimer is out of service.
No. 6 residual oil for Chalk Point Units 3 and 4 is transported to the
site from Piney Point in southern Maryland via the Piney Point Pipeline. The
oil is stored in three storage tanks, with a total capacity of 234,000 barrels
of No. 6 residual oil with 0.7 percent sulfur for Chalk Point Unit 4 and 469,000
barrels of No. 6 residual oil with 1.0 percent sulfur for Chalk Point Unit 3.
Tank and in-line piping heaters are utilized to maintain the temperature of the
oil during storage and pumping from the storage tanks into the Chalk Point
Facility. Duplex basket strainers are located at the inlet of each of the four
in-line heaters. Four pumps are utilized to pump the oil through additional
duplex strainer baskets, heaters, and meters to the fuel oil pump rooms within
the Chalk Point Facility. From the pump rooms, the oil is pumped by three fuel
oil booster pumps to the main oil burners for each of the units.
No. 2 distillate oil is used in the CTs and auxiliary boilers and as
start-up and low load flame stabilization fuel in the steam units. The oil is
delivered by truck to the Chalk Point Facility where there is a total storage
capacity of 1.774 million gallons in two interconnected tanks. In addition,
SMECO owns a 1.18 million-gallon storage tank dedicated to providing fuel solely
to the SMECO CT.
Natural gas can be burned in all the steam units and CTs except for
units Chalk Point CTs 1 and 2. Natural gas is received through a 20-inch
diameter, 3.5-mile long, 900 psig spur line from the Cove Point LNG, L.P.
pipeline. Washington Gas Light Company owns and operates this spur line and
there is a contract in place with Washington Gas Light Company for the firm
transportation of up to 480,000 dekatherms of natural gas per day on this spur
line.
Ash Handling Systems
Bottom ash and slag that fall to the bottom of the furnace section of
each of the Chalk Point Units 1 and 2 steam generators are collected in three
water-filled, refractory-lined ash hoppers located under the furnace. Each
hopper feeds a double-roll clinker grinder which discharges into an ash sump.
From the ash sump, the ash-laden water is pumped to an outdoor dewatering bin.
The water in the bin is decanted and returned to a surge tank, from which it
flows back to the ash hoppers. The dewatered bottom ash is loaded into trucks
for disposal. Approximately 60 to 65 percent of the bottom ash is sold for
manufacturing cinder blocks, and the remainder is stored on site in the coal
yard area.
The fly ash collection system is a combination of original plant
equipment and new equipment added when the units were converted to balanced
draft. There are three fly ash handling systems installed on each unit. The
system for removing ash from the economizer hoppers utilizes water for
transporting the ash to an outdoor dewatering bin. The other two systems are
dry pneumatic systems of which one is a pressurized and one is a vacuum system.
The vacuum system transports ash from the original precipitators to ash storage
silo No. 1, and the pressurized system transports ash from the new precipitators
to ash storage silos Nos. 2 or 3. Ash from each silo is loaded into trucks and
hauled to Brandywine for disposal.
A-5
Make-Up Water System
Make-up water for the steam generators is produced from well water
from the six on-site artesian wells using pretreatment and demineralizer
systems. Pretreatment consists of softening, coagulation and filtering. Chalk
Point Units 1 and 2 have a demineralizer capable of treating 180 gallons per
minute ("gpm") with 144,000 gallons per regeneration, and Chalk Point Units 3
and 4 have a demineralizer capable of treating 600 gpm with 360,000 gallons per
regeneration. Demineralized water is used either directly in the plant or
stored in either of the two Chalk Point Units 1 and 2 250,000-gallon storage
tanks, or the two Chalk Point Unit 3 and 4 450,000-gallon storage tanks.
For the CTs, demineralized water is produced by truck delivered
portable demineralizers and stored separately from the remainder of the Chalk
Point Facility. In addition, the SMECO unit has its own dedicated demineralizer
system.
Combustion Turbines
The CTs at the Chalk Point Facility are utilized for black starting
the steam units and for peaking service. The first unit, Chalk Point CT 1, is
an 18 MW Pratt and Whitney FT4A-7 unit installed in 1967 to provide black start
capability for steam Chalk Point Units 1 and 2. Chalk Point CT 2, a 30 MW
Westinghouse W-251-B2 unit, was installed in 1974 to provide black start
capability for Chalk Point Units 3 and 4 and for Chalk Point CT 5. Both units
operate on No. 2 distillate oil and are also used for peaking service.
In 1991, Chalk Point CTs 4 through 6 were installed for peaking
service. Chalk Point CTs 3 and 4 are 85 MW GE PG7111EA units, and Chalk Point
CTs 5 and 6 are 107 MW Kraftwerk Union/Siemens V84.2 units. The SMECO unit was
installed in 1990 and is an 84 MW GE unit that is owned by SMECO and is leased
by SE Mid-Atlantic. Pursuant to a Facility and Capacity Credit Agreement, SMECO
receives a monthly capacity credit from SE Mid-Atlantic in return for which SE
Mid-Atlantic has the right to use the entire installed capacity and energy of
the unit, subject to operating the unit to Prudent Utility Practice for
maintenance, insurance, and environmental management. Under the Facility and
Capacity Credit Agreement, SE Mid-Atlantic has complete control of the unit and
is responsible for all costs. The Facility and Capacity Credit Agreement
expires on November 30, 2015. SE Mid-Atlantic will lease the land upon which
the unit is located to SMECO. All five of these units operate with natural gas
as the primary fuel and No. 2 distillate oil as a secondary fuel. We note that
all CT capacities referenced above are summer ratings.
Additional Structures and Systems
There are seven auxiliary boilers at the Chalk Point Facility.
Auxiliary boilers Nos. 1, 2 and 4 are out of service and have been retired in
place. Auxiliary boilers Nos. 3, 5, 6 and 7 are currently operated utilizing
No. 2 distillate oil for load carrying and propane for starting up.
Instrument and service compressed air for Chalk Point Units 1 and 2
are supplied by three reciprocating air compressors. Instrument air is filtered
and dried prior to use in the instrument air system. The original compressed
air system has been augmented with the installation of additional drying
capacity for the pressurized fly ash system installed on the new precipitators,
and the installation of one rotary air compressor per unit to supply burner
atomizing air. When Chalk Point Units 3 and 4 were installed, two additional
reciprocating air compressors were furnished along with sufficient dryers and
filters to meet the instrument and service air needs of the units. There are
interconnections between the Chalk Point Units 1 and 2 and Chalk Point Units 3
and 4 compressed air systems to provide operational flexibility.
The major fire protection system consists of three electric motor
driven and one gasoline engine driven fire pumps supplied by water from the
pretreated well water storage tanks. The SMECO unit also has its own electric
and diesel driven fire pumps. In addition to the water based system which is
used for hydrants, sprinkler and deluge systems in many key areas of the Chalk
Point Facility, there are carbon dioxide ("CO\2\"), halon, and foam based
systems in the Chalk Point Facility in areas such as cable spreading rooms,
control rooms, and lube oil storage areas. Portable fire extinguishers are
located strategically throughout the Chalk Point Facility.
A-6
Chalk Point Units 1 and 2 have a common 712-foot tall, reinforced
concrete, steel lined chimney that was installed when the units were converted
to balanced draft and new precipitators were installed in the early 1980s. The
two original chimneys for these units have been capped and retired in place.
Chalk Point Units 3 and 4 each have a 712-foot tall reinforced concrete chimney.
Chalk Point Units 1 and 2 share a common control room, as do Chalk
Point Units 3 and 4. All the units at the Chalk Point Facility share other
structures and facilities such as warehouses, administrative offices, water
storage and treatment facilities, fuel storage and handling facilities, drainage
and sewage treatment facilities, hydrogen, nitrogen and CO\2\ bulk storage
facilities, and the fire protection system.
Electrical and Control Systems
Each of the Chalk Point Unit 1 and 2 steam turbines drives a GE
hydrogen-cooled generator. As these are cross compound steam turbines, each
unit has two generators. Each of the four generators is a two pole, 3 phase, 60
cycle, 3,600 revolutions per minute ("rpm"), 20 kV unit rated at 214,000 kVA at
0.85 power factor and 30 psig hydrogen pressure. There are a total of five
motor driven exciters, one for each generator and one spare, for the two units.
Each of the Chalk Point Unit 3 and 4 steam turbines also drives a GE hydrogen
and water-cooled generator. However, as these are tandem compound steam
turbines, each unit has a single generator. Each of the two generators is a 2
pole, 3 phase, 60 cycle, 3,600 rpm, 24 kV unit rated at 732,200 kVA at 0.90
power factor and 60 psig hydrogen pressure. Each unit has its own exciter.
Chalk Point Units 1 and 2 each use a three-phase, forced oil, forced
air-cooled main power transformer. The Chalk Point Unit 1 transformer was
manufactured by GE and the Chalk Point Unit 2 transformer was manufactured by
Asea Brown Boveri ("ABB"). Both are rated 19.3 kV-234 kV, 400 MVA. Chalk Point
Units 3 and 4 each use a three-phase, forced oil, forced air-cooled main power
transformer manufactured by Westinghouse. These transformers are rated 24 kV-
234 kV, 650 MVA. One spare main power transformer is shared with the Morgantown
Facility.
On Chalk Point Units 1 and 2, the auxiliary power system is divided
into two voltage classes. The medium voltage equipment including all motors
above 300 horsepower ("hp") as well as the 250 hp pulverizer motors is operated
at 4,160 volts, and the low voltage equipment is operated at 480 volts.
Auxiliary power for each generating unit's auxiliary usage is supplied by two
auxiliary transformers that are connected to their respective generator's
isolated phase bus. A reserve station service transformer in the switchyard
that is connected to the 69 kV system supplies start-up and emergency power to
the 4,160 volt switchgear assemblies.
On Chalk Point Units 3 and 4, the auxiliary power system is divided
into three voltage classes. The high voltage equipment including 4000 and 7000
hp motors is operated at 13,800 volts, the medium voltage equipment including
all motors from 300 to 4000 hp operate at 4,160 volts, and the low voltage
equipment is operated at 480 volts. For each unit, auxiliary power is supplied
by two station service transformers, one to the 13,800 volt buses and the other
to the 4,160 volt buses. For start-up or emergency conditions, these buses are
also fed by the 69 kV switchyard through reserve transformers. One spare
auxiliary transformer is shared with the Morgantown Facility.
For the CTs, Chalk Point CTs 1 and 2 have no separate main
transformers. Chalk Point CT 1 feeds directly into the 4,160 volt system for
Chalk Point Unit 1, and Chalk Point CT 2 can feed through the reserve
transformer or to the Chalk Point Unit 2 13,800 volt buses. Each of Chalk Point
CTs 3 through 6 generators generates at 13,800 volts. For each pair of these
generators, a three winding main power transformer steps the voltage up to 230
kV. Each of these generators has its own 13,800 volt generator breaker.
Station service for these units is provided by 13.8 kV-4,160 volt and 13.8 kV-
480 volt auxiliary transformers connected to the line side of each generator
breaker. Standby power is supplied to each of the units from a reserve
transformer served by the 69 kV the Chalk Point Facility's system.
A-7
AC and DC Critical Systems
Each of Chalk Point CTs 3 through 6 has two self-contained batteries
and charger supplying 125 volt direct current ("dc") to each generator's
switchgear, control and protective relaying. The battery supplies provide
separate 125 volt dc sources for redundant protection schemes.
The Chalk Point Facility is equipped with an uninterruptable power
supply system designed to supply AC and DC power to critical motors, control
systems and computer systems associated with the plant.
Plant Control System
There are three main control rooms at the Chalk Point Facility. The
control room for Chalk Point Units 1 and 2 also provides remote start capability
for all the CTs except for Chalk Point CT 2. The control room for Chalk Point
Units 3 and 4 also provides remote start capability for Chalk Point CT 2, and
the CT control room is available for operating all the CTs except Chalk Point
CTs 1 and 2.
The control room for Chalk Point Units 1 and 2 provides for separate
operation of each unit utilizing a Foxboro Digital Control System ("DCS"), which
was retrofitted into the control room in 1996. These computerized systems
include combustion control, burner management systems, automatic generator
control, emissions monitoring systems, and control of auxiliary systems such as
fly ash handling and sootblowing.
The control room for steam Chalk Point Units 3 and 4 was originally
equipped with a Bailey 820 control system for operating the units. While the
entire control system has not been replaced as it has on Chalk Point Units 1 and
2, many of the Bailey control system functions have been replaced by updated
Foxboro DCS components, including burner management systems, sootblower
controls, fuel and airflow controls, steam temperature and pressure controls and
an automatic generator control panel.
Environmental Controls and Equipment
Air Emissions
The Chalk Point Facility is permitted for air emissions within the
limits established in the permits. The key pollutants which must be controlled
include particulate matter, sulfur dioxide ("SO\2\"), NO\X\, and opacity. The
basic strategies and air pollution control technologies employed at the Chalk
Point Facility to control these pollutants include: (i) purchasing fuels of the
required sulfur content in order to control emissions of SO\2\; (ii) utilizing
ESPs on Chalk Point Units 1 and 2 for particulate and opacity control; (iii)
utilizing low-NO\X\ burners, SOFA systems, and gas re-burn on Chalk Point Units
1 and 2 to reduce NO\X\ emissions; (iv) restoring the SOFA system on Chalk Point
Unit 3 to reduce NO\X\ emissions and improved burner nozzles and fuel control
systems on Chalk Point Units 3 and 4 to reduce both NO\X\ emissions and opacity;
and (v) utilizing water injection on Chalk Point CTs 5 and 6 to reduce NO\X\
emissions when firing No. 2 distillate oil.
Chalk Point Units 1 and 2 were originally equipped with Research-
Cottrell precipitators that operated under positive pressure and had a
collection efficiency of 97.5 percent. When the steam generators were converted
to balanced draft in the early 1980s, these original precipitators were modified
and reinforced to operate under negative pressure, and new Buell precipitators
were installed in series with the original precipitators. The original
Research-Cottrell precipitators are not currently energized, but could be
returned to service with minimal repairs. The Buell precipitators are designed
to have a collection efficiency of 99.2 percent. Flue gas scrubbers were
originally installed on Chalk Point Units 3 and 4 for particulate removal.
However, these units have been bypassed and retired in place as particulate
emission and opacity limits are being met through improvements to the fuel
firing system equipment and operations.
All of the steam units are equipped with continuous emissions monitors
("CEMs") as required by state and federal regulations. These monitors are
installed at the 286-foot elevation of the chimneys to measure and record
emission levels for opacity, SO\2\, NO\X\, CO\2\, as well as volumetric flow. CO
probes have also been installed on each of the steam units. The Chalk Point
Facility's CEMs availability has been greater than the 95 percent level required
by the United States Environmental Protection Agency ("USEPA").
A-8
Wastewater/Solid Waste Disposal
Solid waste at the Chalk Point Facility consists primarily of the coal
processing and combustion byproducts generated by Chalk Point Units 1 and 2.
Bottom ash from Chalk Point Units 1 and 2 is pumped as a water/ash mixture to
dewatering bins where the water is decanted off and recycled for use in the
bottom ash transporting system. The dewatered bottom ash is loaded into trucks
for disposal.
Fly ash from Chalk Point Units 1 and 2 is collected and transported to
ash storage silos, where it is loaded into trucks for transport to Brandywine
located approximately 16 miles from the Chalk Point Facility.
The small amounts of iron pyrites removed from the pulverizers of
Chalk Point Units 1 and 2 are stored on site in a lined storage area.
Low volume wastewaters such as coal pile runoff, demineralizer
backwash, boiler blowdown, filter backwash, intake screen backwash, sanitary
wastewater, and settling pond discharges, along with storm water run-off are
collected and treated in two settling ponds that have concrete bottoms. The
ponds are arranged in parallel fashion so that one pond is in service while
solids are being cleaned out of the other pond. The pH of the water in the
ponds is controlled by the addition of caustic, and the ponds discharge to the
cooling water canal that empties into the Patuxent River. A packaged sewage
treatment plant treats sanitary waste for most of the site. Oil/water
separators treat the storm water runoff from the fuel storage and handling
areas.
Off-Site Requirements
Fuel Supply
Chalk Point Units 1 and 2 burn bituminous coal that is delivered by
the CSX Transportation Company from mines generally located in the northern
Appalachian coal mining region, which includes western Pennsylvania, Maryland,
and West Virginia. Coal is purchased pursuant to four coal contracts that also
cover coal supply to the Dickerson and Morgantown Facilities. These contacts
are short-term contracts which, with certain extension options, will expire
between December 31, 2000 and June 30, 2002. Minimum quality parameters and
minimum tonnages are specified, and all of the contracts have provisions to
purchase additional tonnage at a discount to the current spot market price. In
addition to the contracts, coal may be purchased on the spot market depending on
quantity requirements and market conditions. SE Mid-Atlantic will acquire
approximately 244 rail cars that are used for coal deliveries to the Chalk
Point, Morgantown and Dickerson Facilities.
The No. 6 residual oil burned in Chalk Point Units 3 and 4 is
purchased on the spot market under short-term contracts with no minimum purchase
requirements and delivered to the Chalk Point Facility via the Piney Point
Pipeline from the unloading and storage facilities in Piney Point, Maryland.
The Piney Point Pipeline is operated under contract by ST Services. In
addition, Pepco leases space for 1.5 million barrels of storage of No. 6 oil at
the Piney Point Terminal. This storage can also provide service to Morgantown
Units 1 and 2 as a back-up fuel. This lease expires June 30, 2001, with the
option to extend an additional five years by mutual agreement.
No. 2 distillate fuel oil is purchased pursuant to short-term,
renewable contracts with each of three vendors. The oil is delivered to the
Chalk Point Facility by truck from the vendors' terminals.
Natural gas is purchased in the spot market under short-term
agreements. Gas transportation to the Chalk Point Facility is through a
Washington Gas Light Company lateral pipeline under an agreement which expires
December 31, 2003.
Electrical Interconnection
The Chalk Point Facility's electric output is interconnected to the
grid through the Chalk Point Facility's switchyard. The Chalk Point Facility
has two 500 kV, six 230 kV, and two 60 kV lines connected to the Chalk Point
Facility's switchyard. Chalk Point Units 1 through 4 and Chalk Point CTs 3
through 6 are connected to the Chalk Point 230 kV ring bus. Two 230 kV lines
tie into the Chalk Point 500 kV switchyard, which has one tie to
A-9
Baltimore Gas and Electric and one tie to the 500 kV transmission system owned
by the Pennsylvania-New Jersey-Maryland power pool ("PJM").
Water Supply
Raw cooling water for the Chalk Point Unit 1 and 2 condensers and for
makeup water to the Chalk Point Unit 3 and 4 cooling towers is obtained from the
Patuxent River. Water for other uses within the Chalk Point Facility is
obtained from the six on-site artesian wells. Screening, filtering, treatment,
pumping and storage facilities are available for processing the well water for
various uses within the Chalk Point Facility.
Review of Technology
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The design and construction of electric utility generating units using
pulverized coal, No. 6 residual oil, or natural gas to fire steam boilers has
been common for many years, as has the firing of natural gas or No. 2 distillate
oil in CTs. The Chalk Point Facility was designed utilizing the standard
technologies available at the time it was built. Where it has proven
economically desirable, or where regulatory changes have required, new
technologies have been "backfit" into the Chalk Point Facility to improve
operations, environmental compliance, and efficiencies. Major examples of this
include the conversion of Chalk Point Units 1 and 2 to balanced draft operation
and installation of new, more efficient precipitators in the early 1980s,
provision of gas firing capability for Chalk Point Units 1 and 2 in the 1990s,
and replacement of the control systems of Chalk Point Units 1 and 2.
In general, Chalk Point Units 1 and 2 have been normally base-loaded,
which is common for large, coal-fired units which are generally designed for
this type of operation. The Chalk Point Units 3 and 4 have been generally used
in intermediate or peaking service. Many large steam units were originally
designed for base load service and later converted to peaking service. In
general, these units experienced thermal cycling damage such as cracking of
major steam generator and turbine components, accelerated erosion of turbine
components, and operational difficulties with systems that were not designed to
be cycled on and off frequently. However, Chalk Point Units 3 and 4 were
intended for peaking service when originally proposed, and as such, the
equipment was designed to take frequent start/stop cycles into account. Having
had numerous opportunities to inspect the units during the 25- to 30-year period
they have been in operation, the operators have reported that the equipment has
performed well and does not exhibit to any great degree any of the problems
usually associated with the cycling of large steam units.
The CTs utilize mature, commercially proven technology. Additionally,
inlet fogging systems are being installed on Chalk Point CTs 3 through 6 which
are expected to increase summer capacity by approximately 4 to 6 MW. This
incremental capacity is not included in the Projected Operating Results.
Based on our review, we are of the opinion that the Chalk Point
Facility has been designed and constructed with good engineering practices and
generally accepted industry practices, and the technologies in use at the Chalk
Point Facility are sound, proven conventional methods of electric generation.
If operated and maintained as proposed by SE Mid-Atlantic, the Chalk Point
Facility should be capable of meeting the currently applicable environmental
permit requirements. Furthermore, all off-site requirements of the Chalk Point
Facility have been adequately provided for, including fuel supply, water supply,
ash and wastewater disposal, and electrical interconnection.
Estimated Useful Life
- ---------------------
We have reviewed the quality of equipment installed at the Chalk Point
Facility, the general plans for operating and maintaining the facility and the
historical performance of the Chalk Point Facility. On the basis of this review
and assuming that: (1) the units are operated and maintained by SE PJM
Management in accordance with the policies and procedures as presented by SE
Mid-Atlantic, (2) all required renewals and replacements are made on a timely
basis as the units age, and (3) coal, gas and oil burned by the units are within
the expected range with respect to quantity and quality, we are of the opinion
that the Chalk Point Facility should have a useful life extending well beyond
the term of the Certificates.
A-10
THE DICKERSON FACILITY
The Dickerson Facility is comprised of three conventional steam
turbine units and three simple-cycle CTs (CT D1, CT H1, and CT H2), with a total
net summer generating capacity of approximately 837 MW. The Dickerson Facility
provides baseload and peaking generation and is capable of using both coal and
oil for fuel in the steam units, oil in Dickerson CT D1 and both oil and gas in
Dickerson CTs H1 and H2.
Dickerson Units 1, 2 and 3 are identical coal-fired electric
generating units that have been in commercial operation since 1959, 1960 and
1962, respectively. Each unit consists of a single boiler and cross compound
steam turbine generator with nameplate capacity ratings of 196 MW. The units
have actual maximum capacity ratings of approximately 182 MW, depending on the
season, and can be dispatched down to 75 MW. The annual average net heat rates
have ranged between approximately 9,300 Btu/kWh and 9,450 Btu/kWh for each unit.
Each unit has a CE pulverized coal-fired boiler and GE steam turbine and
generator.
The CTs at the Dickerson Facility are simple-cycle units that provide
the Dickerson Facility with both black starting capability and peaking
generation. The units range from 13 MW to 139 MW of capacity, with a summer
total capacity for all three units of 291 MW. With the exception of Dickerson
CT D1, the black start unit that only fires No. 2 distillate oil, both Dickerson
CTs H1 and H2 are capable of firing either No. 2 distillate oil or natural gas.
In addition, the Dickerson Facility has certain common facilities
shared by all units such as river water pumping stations, fuels receiving,
storage and handling systems, water treatment systems, warehouses, maintenance
shops, chemistry laboratory, administrative offices, groundwater monitoring
wells, and electrical switchyard.
The Plant Site
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The Dickerson Facility is located approximately 31 miles from
Washington, DC and 12 miles south of Frederick, Maryland on a 1,001-acre site
less than a mile downstream from the confluence of the Potomac River and
Monocacy River in northwestern Montgomery County, Maryland. The site is easily
accessible from Martinsburg Road off of Maryland State Highway 28 and provides
adequate access to necessary utilities and rail transportation. The site is in
a largely rural area bordered on the east by farmland, on the south by farmland
and the Dickerson Regional Park, on the north west by the Potomac River. On the
basis of our observations and the historical operations of the Dickerson
Facility, we are of the opinion that the site is suitable for the Dickerson
Facility's continued operation.
Description of the Facility
- ---------------------------
Mechanical Equipment and Systems
Steam Generators
The Dickerson Units 1, 2 and 3 steam generators consist of identical
CE controlled circulation twin furnace units with Ljungstrom air preheaters and
tangentially-fired burners. Each boiler also includes a superheater, a reheater,
an economizer, a sootblowing system, circulation pumps, coal pulverizers and
coal feeders. The boilers were designed to operate at 1,300,000 lb/hr
superheater steam flow at 2,486 psig. Each corner of each furnace has four coal
burners, four coal pilot oil torches, an oil gun, and an oil pilot torch. The
furnace was retrofitted in 1999 with 32 ABB-CE low-NO\X\ burners. The boilers
are designed to fire pulverized coal as the primary fuel and to fire No. 2 fuel
oil for start-up, flame stabilization, and as alternate fuel to replace mill
capacity when needed.
Four Raymond Bowl Mills with integral exhausters feed the coal
nozzles. To maintain fire balance with any number of mills in service, each
mill supplies all eight coal nozzles at each of the four levels. Two forced
draft fans per boiler discharge the secondary air and primary air through the
corresponding Ljungstrom air preheaters. Two induced draft fans per boiler draw
50 percent of the flue gases to the precipitators and 50 percent through the
scrubber vessel to the scrubber induced draft fan. The scrubber induced draft
fan discharges the gases to the 700-foot stack.
A-11
Steam Cycle and Heat Rejection Systems
Each Dickerson Units 1, 2 and 3 steam generator provides steam to a
single GE cross-compound steam turbine. Each of the units are rated at 175,000
kW at an inlet throttle pressure of 2,400 psig and 1,050(degrees)F/
1,000(degrees)F reheat and 2.0 inches Hg backpressure. Each turbine is protected
from water induction by a computer-controlled water induction production system.
The low-pressure turbine exhausts into a two-pass surface condenser where the
steam is condensed by rejection of heat into the circulating water.
Circulating water for each condenser is obtained through an intake
structure and canal consisting of two traveling water intake screens and two 50-
percent capacity circulating water pumps. The pumps discharge to the condenser,
and after passing through the condenser, the circulating water is discharged to
the river through a discharge structure and canal.
Feedwater for each unit is provided by two 100-percent capacity
condensate pumps, two 100-percent capacity condensate booster pumps, one main
boiler feed pump, and one turbine-driven auxiliary boiler feed pump. The boiler
feedwater system discharges through a condensate cooler, a hydrogen seal oil
cooler, hydrogen coolers, a gland steam condenser, three closed-type low-
pressure feedwater heaters, an open-type deaerator, and three twin-shell closed-
type high-pressure feedwater heaters.
Fuel Handling Systems
Coal for Dickerson Units 1, 2 and 3 is delivered in trains of
approximately 70 to 80 coal cars with each car containing from 95 to 100 tons of
coal. Capability of preheating the cars with kerosene fuel oil torches allows
for complete unloading to occur in freezing weather. As coal cars are emptied
by a rotary car dumper into a double receiving hopper beneath the dumper, two
belt feeders feed the coal from the hopper onto a weightometer-equipped
conveyor. This conveyor discharges to either a Bradford Hammermill breaker
(crusher) or a by-pass. By-pass material is discharged to a steel tank set up
for truck loading. Coal discharged through the breaker is placed onto a belt
feeder to be routed over station conveyors for delivery to the initial bunkers
or over-stocking conveyor for outdoor storage of up to 240,000 tons. Coal from
the initial bunkers flows through to one of the four Raymond Bowl Mills below.
The initial design of the coal handling system provides for future
installation of additional conveyors. Coal yard storage coal is reclaimed by
bulldozer and delivered to three reclaim hoppers. The coal is then delivered to
the weightometer-equipped conveyor at the beginning of the cycle. The as-
received coal sampling system has been retired in place. Both the 1,000 hp and
1,200 hp switching locomotives were rebuilt in 1996.
No. 2 distillate oil is used in the CTs and as start-up and low load
flame stabilization fuel in the steam units. The oil is delivered by truck to
the Dickerson Facility where there is a total storage capacity of 10.9 million
gallons in two aboveground tanks.
Natural gas can be burned in all of the CTs units except for Dickerson
CT D1. Natural gas is received through a 20-inch diameter, 1,250 psig spur line
with 350,000 dekatherms per day capacity capable of supplying the gas-burning
CTs if converted to combined cycle operation.
Ash Handling Systems
Bottom ash from each boiler furnace drops into two water-filled
refractory-lined hoppers. Each double-outlet hopper feeds to a clinker grinder
and two 150-ton hydro-bins. Separation of water and ash takes place in the
hydro-bin, with excess water overflow placed into one of two surge banks. The
remaining ash is stored in the hydro-bins for later removal, while the surge
tanks store and furnish the necessary water for bottom ash transport back to the
hydro-bins.
Fly ash from each unit is collected in 10 hoppers. Two hoppers
collect ash from economizer gases, while the other eight hoppers collect ash
from the precipitators. Fly ash is transported to the primary and secondary
collectors which dump fly ash into the fly ash storage silo located in the 400-
foot stacks. The fly ash is then transported from the silo via two air slide
assemblies into a rotary unloading unit. Dumping into trucks for hauling to the
ash storage site completes the cycle.
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Make-Up Water System
Boiler make-up water is generated from river water using a water
pretreatment system and demineralizer. The Dickerson Facility consists of two
demineralizer trains. Demineralizer No. 2 was removed from the Buzzard Point
facility and installed at the Dickerson Facility in the early 1990s. Capacity
of demineralizer No. 1 is 65,000 gallons per regeneration, while demineralizer
No. 2 provides 30,000 gallons per regeneration. Demineralized water is either
used directly in the plant or stored in three demineralized water storage tanks.
Combustion Turbines
The CTs at the Dickerson Facility are used for black starting the
steam units and for peaking service. The first unit, Dickerson CT D1, is a 13
MW Pratt and Whitney FT4 unit installed in 1967 to provide black start
capability for Dickerson Units 1, 2 and 3. The unit operates on No. 2
distillate oil and is also used for peaking service.
The second and third CTs, Dickerson CTs H1 and H2, respectively, were
installed for peaking service in 1992 and 1993. Both units are 139 MW GE 7001F
units. Both of these units operate on either natural gas or No. 2 distillate
oil. The CT capacities referenced above are summer ratings.
Additional Structures and Systems
Compressed air for all units is supplied by four station air
compressors and one instrument air compressor. Main plant instrument air is
dried by one main air dryer, while scrubber and/or wastewater treatment plant
instrument air is dried by two smaller air dryers.
A motor-driven fire pump and a diesel engine-driven fire pump both
receive water from the river. A jockey pump and an air compressor normally
maintain fire water system pressure. A CO\2\ fire protection system protects the
bottles and cylinders in the lube oil room, turbine oil tanks, voith oil tanks,
auxiliary boiler feed pump oil tanks, gas turbine and generator, and No. 3 cable
tray rooms, and all portable extinguishers throughout the plant.
Dickerson Units 1 and 2 have a 700-foot, brick-lined, reinforced
concrete chimney and fly ash silo with a diameter of 18 feet, 6 inches.
Dickerson Unit 3 has a similar stack. In 1979, a 700-foot, steel-lined
reinforced concrete chimney with a diameter of 32 feet, 6 inches was erected for
common use by Dickerson Units 1, 2 and 3.
Other significant structures and systems shared by Dickerson Units 1,
2 and 3 include the control room, fuel oil tanks, yard coal handling, warehouse,
administration building, circulating water intake structure, demineralized water
storage tanks, water treatment system, Westland, spare main transformer, and
fire protection system.
Electrical and Control Systems
Each of the Dickerson Units 1, 2 and 3 steam turbines drive a GE
hydrogen-cooled generator rated at 115 MVA at 0.85 power factor and 13.8 kV.
Each generator is connected through an isolated phase bus duct to its
main generator step-up transformer. Dickerson Units 1, 2 and 3 use a three-
phase outdoor oil-filled unit rated 13.5-234 kV, 217 MVA with forced oil/forced
air-cooling. The transformer for Dickerson Unit 1 is manufactured by Maloney,
Dickerson Unit 2 by GE, and Dickerson Unit 3 by ABB. One spare main generator
step-up transformer of the same rating, manufactured by GE, is on site and
available for any of the three units.
In addition to the main generator step-up transformer, each generator
is connected to a three-phase indoor type station service transformer rated
4.325-13.5 kV, 7.5-11.4 MVA with fan cooling. The secondary side of the
transformer is connected to a set of voltage regulators prior to reaching the
medium voltage 4,160 volt station service breaker.
A-13
For the CTs, electric power is supplied through the 4 kV breakers to
the secondary side of the reserve station service breakers and the line
supplying the scrubber. Power may also pass into the reserve station service
transformer where it will be stepped up to 230 kV.
Fed from the 230 kV switchyard, the reserve station service
transformer, rated 4.325-230 kV, 10-12.5 MVA with forced oil/forced air cooling,
is used when the service transformer is out of service.
Each unit has two breakers on the medium voltage 4,160 volt bus which
supply the low voltage 480 volt bus. Twelve 480-4,160 volt transformers, four
rated 1,000 kVA and eight rated 750 kVA, provide low voltage power for small
motors and miscellaneous plant loads. Lighting transformers are connected to
the 480 volt system for lighting throughout the plant.
AC and DC Critical Systems
The emergency lighting 125 volt dc system automatically engages upon
failure of the 480 volt alternating current ("ac") lighting feeders.
The Dickerson Facility is equipped with an uninterruptable power
supply system designed to supply AC and DC power to critical motors, control
systems and computer systems associated with the plant.
The Dickerson CT D1 provides the Dickerson Facility with black start
capability.
Plant Control System
There is one main control room at the Dickerson Facility. The control
room for Dickerson Units 1, 2 and 3 also provides remote start capability for
all the CTs.
The control room for Dickerson Units 1, 2 and 3 provides for separate
operation of each steam unit using a Honeywell DCS which was retrofitted into
the control room in 1999. These computerized systems include combustion
control, feedwater control, combustion turbine control interface, black start
controls, and data acquisition. An on-site DCS simulator is used for training
purposes.
Dickerson CT D1 is equipped with a Digicon control system while
Dickerson CTs H1 and H2 are equipped with GE Mark IV control systems.
Environmental Controls and Equipment
Air Emissions
The Dickerson Facility is permitted for air emissions within the
limits established in the permits. The key pollutants which must be controlled
include particulate matter, SO\2\, NO\X\, and opacity. The basic strategies and
air pollution control technologies employed at the Dickerson Facility to control
these pollutants include: (i) purchasing fuels of the required sulfur content in
order to control emissions of SO\2\; (ii) utilizing ESPs and wet particulate
scrubbers on Dickerson Units 1, 2 and 3; (iii) upgraded burner tips with
modified air distribution system on Dickerson Units 1, 2 and 3 to reduce NO\X\
emissions; and (iv) using water injection on Dickerson CTs H1 and H2 to reduce
NO\X\ emissions when firing No. 2 distillate oil.
Dickerson Units 1, 2 and 3 are equipped with Research-Cottrell ESPs.
Each precipitator consists of two units of 21 ducts each. Each precipitator is
guaranteed to have a collection efficiency of 97.5 percent when handling 492,000
cubic feet per minute ("cfm") of gas flow at 245(degrees)F.
In addition to the ESPs, Dickerson Units 1 and 2 have employed
scrubbers since 1978, when the new 700-foot stack and industrial wastewater
treatment plant were installed at the Dickerson Facility. Dickerson Unit 3 wet
particulate scrubber was placed in service in 1972. After several shutdowns and
operational modifications, Dickerson Unit 3 was placed back into service in 1978
along with the additional scrubbers for Dickerson Units 1 and 2.
A-14
All three of the steam units at the Dickerson Facility are equipped
with CEMs as required by state and federal regulations. These monitors measure
and record emission levels for opacity, SO\2\, NO\X\, CO\2\, as well as
volumetric flow. The Dickerson Facility's CEMs availability has been greater
than the 95 percent load required by the USEPA.
Wastewater/Solid Waste Disposal
Solid waste at the Dickerson Facility consists primarily of the coal
processing and combustion by-products generated by Dickerson Units 1, 2 and 3.
Bottom ash from each of the three steam units is collected and transported to
the bottom ash storage silo where it is loaded into trucks for disposal off-
site. Additionally, bottom ash is marketed to several local governments for use
on roads in winter.
Fly ash from each of the three steam units is collected and
transported to one of two fly ash storage silos where it is loaded into trucks
for transport to Westland. Additionally, fly ash is marketed to Genstar, a
local cement company, for mixing into concrete.
Major water treatment equipment at the Dickerson Facility includes
clarifiers, settling ponds, neutralization systems, flow equalization systems,
oil/water separators and sanitary waste treatment. With the exception of once-
through cooling water and clean stormwater, all water is treated prior to
discharge into the Potomac River or C&O Canal. Equalization tanks collect storm
runoff, coal pile runoff, plant process water, floor drain runoff, sewage
treatment runoff, and demineralizer regeneration effluent for discharge to the
industrial wastewater treatment plant. Effluent from the industrial wastewater
treatment plant goes to the plant discharge flume and into the Potomac River.
Scrubber process flows and scrubber runoff is routed to a drain tank and into a
series of cascading settling ponds. After the removal of solids, the water from
the settling ponds goes to the plant discharge flume and into the Potomac River.
Off-Site Requirements
Fuel Supply
Dickerson Units 1, 2 and 3 burn bituminous coal delivered by the CSX
Transportation Company from mines generally located in the northern Appalachian
coal mining region, which includes western Pennsylvania, Maryland and West
Virginia. Coal is purchased pursuant to four coal contracts that also cover
coal supply to the Chalk Point and Morgantown Facilities. These contacts are
short-term contracts which, with certain extension options, will expire between
December 31, 2000 and June 30, 2002. Minimum quality parameters and minimum
tonnages are specified, and all of the contracts have provisions to purchase
additional tonnage at a discount to the current spot market price. In addition
to the contracts, coal may be purchased on the spot market depending on quantity
requirements and market conditions. SE Mid-Atlantic will acquire approximately
244 rail cars that are used for coal deliveries to the Chalk Point, Morgantown
and Dickerson Facilities.
No. 2 distillate fuel oil is purchased pursuant to one-year contracts
with each of three vendors. The oil is delivered to the Dickerson Facility by
truck from the vendors' terminals.
Natural gas is purchased in the spot market under short-term (one to
three months) agreements. There are also two longer-term agreements with the
Washington Gas Light Company for gas supply and delivery. The first agreement
is a non-obligatory contract for the purchase and sale of gas under a set of
commercial parameters. The second is an interruptible transportation agreement
to the Dickerson Facility expiring January 1, 2002.
Electrical Interconnection
The Dickerson Facility's electric output is interconnected to the grid
through the Dickerson Facility's switchyard. The Dickerson Facility is
connected to the Doubs Substation via two 230 kV lines. The Dickerson Facility
provides crucial voltage support to the PJM system, as a 400-MW contingency is
placed on the Dickerson Facility. This contingency would reduce the current
1,800 MW import capability by 400 MW if one of the steam units were off line.
A-15
Water Supply
Raw cooling water for each of the steam units at the Dickerson
Facility is obtained from the Potomac River. Water for other uses within the
Dickerson Facility is obtained from a potable water deep well. Screening,
filtering, treatment, pumping and storage facilities are available for
processing the river water for various uses in the Dickerson Facility.
Review of Technology
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The design and construction of electric utility generating units using
pulverized coal or No. 2 distillate oil to fire steam boilers has been common
for many years, as has the firing of natural gas or No. 2 distillate oil in CTs.
The Dickerson Facility was designed utilizing the standard technologies
available at the time it was built. Where it has proven economically desirable,
or where regulatory changes have required, new technologies have been "backfit"
into the Dickerson Facility to improve operations, environmental compliance, and
efficiencies. Major examples of this include the installation of wet
particulate scrubbers to Dickerson Unit 3 in 1972 and to Dickerson Units 1 and 2
in 1978, and replacement of the pneumatic control systems of Dickerson Units 1,
2 and 3 in 1999.
In general, Dickerson Units 1, 2 and 3 have been normally base-loaded,
which is common for medium sized coal-fired units located close to a
metropolitan area.
The CTs utilize mature, commercially proven technology.
Based on our review, we are of the opinion that the Dickerson Facility
has been designed and constructed with good engineering practices and generally
accepted industry practices, and the technologies in use at the Dickerson
Facility are sound, proven conventional methods of electric generation. If
operated and maintained as proposed by SE Mid-Atlantic, the Dickerson Facility
should be capable of meeting the currently applicable environmental permit
requirements. Furthermore, all off-site requirements of the Dickerson Facility
have been adequately provided for, including fuel supply, water supply, ash and
wastewater disposal, and electrical interconnection.
Estimated Useful Life
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We have reviewed the quality of equipment installed at the Dickerson
Facility, the general plans for operating and maintaining the facility and the
historical performance of the Dickerson Facility. On the basis of this review
and assuming that: (1) the units are operated and maintained by SE PJM
Management in accordance with the policies and procedures as presented by SE
Mid-Atlantic, (2) all required renewals and replacements are made on a timely
basis as the units age, and (3) coal, gas and oil burned by the units are within
the expected range with respect to quantity and quality, we are of the opinion
that the Dickerson Facility should have a useful life extending well beyond the
term of the Certificates.
THE MORGANTOWN FACILITY
The Morgantown Facility is comprised of two conventional steam turbine
units and six simple-cycle CTs, with a total net summer generating capacity of
approximately 1,412 MW. The Morgantown Facility provides baseload and peaking
generation and is capable of utilizing both coal and oil for fuel.
Morgantown Units 1 and 2 are nearly identical coal- and/or oil-fired
electric generating units that have been in commercial operation since 1970 and
1971 respectively. Each unit consists of a single boiler and tandem compound
steam turbine generator with nameplate capacity ratings of 626 MW. The units
have actual maximum capacity ratings of approximately 582 to 583 MW, depending
on the season, and can be dispatched down to 190 MW. The annual average net
heat rates have ranged between approximately 9,200 Btu/kWh and 9,650 Btu/kWh
over the past five years. Each unit has a CE pulverized coal-fired boiler.
Morgantown Unit 1 has an ABB steam turbine and a Westinghouse generator, and
Morgantown Unit 2 has a GE steam turbine and generator.
A-16
The CTs at the Morgantown Facility are simple-cycle units that provide
the Morgantown Facility with both black starting capability and peaking
generation. The units range from 16 MW to 54 MW of capacity, with a summer
total capacity for all six units of 248 MW. All of the CTs were supplied by GE
and fire No. 2 distillate oil.
In addition, the Morgantown Facility has certain common facilities
shared by all units such as river water pumping stations, fuels receiving,
storage and handling systems, water treatment systems, warehouses, maintenance
shops, chemistry laboratory, administrative offices, groundwater monitoring
wells, and electrical switchyard.
The Plant Site
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The Morgantown Facility is located approximately 50 miles south of
Washington, DC on a 620-acre site adjacent to the Potomac River near Newburg in
Charles County, Maryland. The site is easily accessible from Maryland State
Highway 301 and provides adequate access to necessary utilities, and barge and
rail transportation. The site is in a largely rural area bordered on the on the
south by the Potomac River, and on the east, north and west by farm land. On
the basis of our observations and the historical operations of the Morgantown
Facility, we are of the opinion that the site is suitable for the Morgantown
Facility's continued operation.
Description of the Facility
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Mechanical Equipment and Systems
Steam Generators
The Morgantown Units 1 and 2 steam generators consist of identical CE
once through, single reheat, supercritical, balanced draft, indoor units with
two Ljungstrom regenerative secondary air heaters. Each steam generator
includes a divided furnace consisting of a tilting tangentially-fired, center
wall furnace with an economizer, a superheater, a reheater, superheat and reheat
spray desuperheaters, and a steam sootblowing system. Each steam generator has
a maximum continuous capacity of 4,250,000 lb/hr of steam when operating at
3,810 psig and 1,000(degrees)F superheater outlet temperature and final reheat
temperature of 1,000(degrees)F. The steam generators are designed to fire
pulverized coal as the primary fuel and also have the capability to co-fire up
to 75 percent by heat input of No. 6 residual oil as a secondary fuel. In 1994
to 1995, the corner mounted coal burners of both steam generators were replaced
with low-NO\X\ concentric firing system ("LNCFS") Level III and SOFA systems
were installed. Fuel is fired through tilting tangential nozzles mounted in five
elevations in each of the eight corners of the divided furnaces. No. 2
distillate oil is used for start-up and low load flame stabilization.
There are five negative pressure CE Raymond Bowl Mills with integral
exhausters to pulverize the coal. Primary and secondary air are provided to
each steam generator by two forced draft fans which supply air to the two
regenerative air preheaters. Inlet air to the air preheaters is heated by
passing it through steam coils. The heated air flows as primary air to the coal
pulverizers to heat and dry the coal and transport it to the burners, and as
secondary air to the steam generator's windboxes to provide adequate air for
combustion of the coal. Two induced draft fans per unit draw flue gas from the
steam generator to maintain a slight negative pressure within the unit, and
discharge into the ESPs and then to each unit's 700-foot stack.
Steam Cycle and Heat Rejection Systems
Each Morgantown Unit 1 and 2 steam generator provides steam to a
single tandem-compound, four flow, reheat, condensing steam turbine. The
original Morgantown Unit 1 Westinghouse steam turbine was replaced in 1998 with
steam turbine supplied by ABB. The ABB steam turbine is rated at 636,021 kW at
inlet throttle conditions of 3,500 psig and 1,000(degrees)F with 1,000(degrees)F
reheat inlet temperatures and 1.25 inches Hg backpressure. The Morgantown Unit 2
GE steam turbine was upgraded in 1991 with a new high pressure/intermediate
pressure ("HP/IP") turbine rotor and is rated at 551,021 kW at inlet throttle
conditions of 3,500 psig and 1,000(degrees)F with 1,000(degrees)F reheat inlet
temperatures and 1.25 inches Hg backpressure. At five percent overpressure,
Morgantown Unit 1 is rated at 664,023 kW and Morgantown Unit 2 is rated at
625,496 kW. Each turbine is protected from water induction by a water induction
protection system that is controlled by the Morgantown Facility's DCS control
system. The low pressure turbines
A-17
exhaust into twin parallel shell surface condensers where the steam is
condensed by rejection of heat into the circulating water. Each of the
condensers was retubed in the mid-1990s with titanium tubing replacing the
original cupro-nickel tubing.
Circulating water for each condenser is obtained through an intake
canal and structure on the Potomac River. The brackish water from the river is
screened and pumped by three one-third capacity vertical circulating water pumps
through cylindrical conduits to the condensers. After passing through the
condensers, the circulating water flows through conduits to the discharge canal
for return to the river.
Feedwater for each of Morgantown Unit 1 and 2 is provided by two 60
percent capacity steam-turbine-driven feedwater pumps, three 50 percent capacity
feedwater booster pumps and two full capacity condensate pumps through three
stages of low pressure feedwater heating including a deaerator. On Morgantown
Unit 1, there is also one stage of intermediate pressure and two stages of high
pressure feedwater heating, and on Morgantown Unit 2 there are two stages of
intermediate pressure and one stage of high pressure feedwater heating.
Approximately half of all the feedwater heaters have been replaced in prior
years.
Fuel Handling System
Coal for Morgantown Units 1 and 2 is delivered in unit trains of
approximately 80 cars. Utilizing either of the Morgantown Facility's two radio-
controlled locomotives, the coal cars are unloaded in a rotary car dumper and
conveyed to two Bradford breakers to screen out refuse and oversized material.
A thawing shed that utilizes electric heaters is available to thaw coal cars
with frozen coal. The sized coal is then conveyed to a rail mounted traveling
bucket wheel stacking/reclaiming machine. This machine is capable of stacking
out coal to the storage area, which normally has approximately 17 to 18 days of
inventory on site, or conveying coal to the conveyor system supplying the
Morgantown Facility's coal storage bunkers, which hold approximately a 24 hour
supply of coal at full load burn rates. Both of these functions can be
performed simultaneously. Coal conveyed into the plant passes over a magnetic
separator to remove pieces of metal that may be in the coal. All weighing and
sampling of coal is performed at the mines per the terms of the coal sales
agreements. Each of Morgantown Units 1 and 2 has its own coal storage bunkers
which supply coal to the unit's five pulverizers. An emergency reclaim system
is provided to permit fueling of the Morgantown Facility in the event that the
stacker/reclaimer is out of service. While the Morgantown Facility has barge
unloading capability for fuel oil, there is no such capability for coal
unloading.
No. 6 residual oil for Morgantown Units 1 and 2 is generally
transported to the site from Piney Point in southern Maryland via the Piney
Point Pipeline. The secondary means of delivering No. 6 oil to the Morgantown
Facility is by truck. The oil is stored in storage tanks with a total capacity
of 501,000 barrels and in-line piping heaters are utilized to maintain the
temperature of the oil during storage and pumping from the storage tanks into
the Morgantown Facility. Three pumps are utilized to pump the oil from the
storage tank, through inline heaters to the inlet header of the burner fuel oil
heaters, and then to the booster pumps which pump the oil at 1000 psig to the
oil burners in each of the steam generators.
No. 2 distillate oil is used as a primary fuel in the CTs and
auxiliary boilers and as start-up and low load flame stabilization fuel in the
steam units. The oil is delivered by barge to the Morgantown Facility where
there is a total storage capacity of 11.813 million gallons in two
interconnected tanks.
Ash Handling Systems
Bottom ash and slag that fall to the bottom of the furnace section of
each of the Morgantown Unit 1 and 2 steam generators are collected by the ash
hoppers located under the furnace. In 1998, new bottom ash systems supplied by
United Conveyor were installed on each unit. These systems utilize a submerged
flight conveyor to remove the bottom ash from the ash hoppers. As part of the
same project, dry transfer conveyors were provided for removing ash from the
hoppers beneath the steam generators' economizers. Both the bottom ash and the
economizer ash are transferred on a common transfer conveyor to an onsite
storage location, where they can be loaded onto trucks for disposal. Virtually
all of the bottom ash was sold in 1999, primarily for the manufacturing of
cinder blocks.
A-18
The fly ash collection system for each unit is generally the original
plant equipment in each unit. The fly ash transport system is a pressurized dry
pneumatic system which utilizes four rotary blowers to supply the air flow
necessary to transport the ash. Each unit has 32 fly ash hoppers for collecting
ash. Each hopper is equipped with an airlock assembly which allows ash to be
removed from the hopper under negative pressure and discharged into the positive
pressure transport system. The fly ash for each unit is transported to silos
from which it is periodically loaded into trucks and hauled to Faulkner for
disposal. In 1999, approximately 12 percent of the fly ash was sold, primarily
for use as a concrete additive.
Make-Up Water System
Make-up water for the steam generators and auxiliary boilers is
produced from well water from the four on-site artesian wells using a dual-train
demineralizer system. Each train of the demineralizer is capable of treating
300 gpm of raw water with approximately 360,000 gallons per regeneration.
Demineralized water is used either directly in the plant or pumped to the two
demineralized water storage tanks. In addition to being used for makeup water
for the steam generators, demineralized water is used as hotwell fill, deaerator
fill, boiler feed pump injection water, closed cooling water fill and make-up,
and for chemical handling and condensate polishing services. Well water is
supplied directly for domestic water services, pump seal water, and is the
source for the fire system's water supply.
Combustion Turbines
The CTs at the Morgantown Facility are utilized for black starting the
steam units and for peaking service. The first two units, Morgantown CTs 1 and
2, are 16 MW GE Frame 5 units installed in 1970 and 1971 to provide black start
capability for Morgantown Units 1 and 2. Both units operate on No. 2 distillate
oil which is stored in a 400,000-gallon storage tank and are also used for
peaking service.
In 1973, units Morgantown CTs 3 through 6 were installed for peaking
service. These four units are all 54 MW GE Frame 7 units. All of these units
operate with No. 2 distillate oil as the primary fuel, which is stored in a
268,000-gallon storage tank, as the primary fuel. We note that all CT
capacities referenced above are summer ratings.
Additional Structures and Systems
There are four auxiliary boilers at the Morgantown Facility for
supplying steam for start-up and auxiliary systems. These boilers are fired
with No. 2 distillate oil and use propane for starting up. Two of these boilers
are currently out of service and would need to have their superheaters and
control systems replaced in order to return them to service. One auxiliary
boiler is required to support a black start-up, although start-up can be
achieved in a shorter period of time with two auxiliary boilers. During normal
start-ups, auxiliary steam for starting a unit is taken from the other
(operating) steam unit through a crosstie line between the units.
Instrument and house service compressed air for the Morgantown
Facility is supplied by three reciprocating air compressors. To supply
instrument air, house service air at 100 psig flows through a moisture
separator, a prefilter, a dryer and afterfilter, and is then stored in one of
two instrument air receivers. From the receivers, it flows through post
filters, of which there is one for each steam generating unit, and then is
distributed to the instrument air system for use in control systems and
pneumatic devices requiring clean and dry air.
The major fire protection system consists of one electric motor driven
and one gasoline engine driven fire pump supplied by water from the well water
storage tanks. In addition to the water based system, which is used for
hydrants, sprinkler and deluge systems in many key areas of the Morgantown
Facility, there are CO\2\ and foam based systems in the Morgantown Facility in
areas such as cable spreading rooms, control rooms, and lube oil storage areas.
Portable fire extinguishers are located strategically throughout the Morgantown
Facility.
The two 700-foot tall chimneys for the Morgantown steam units are each
built of reinforced concrete with a "Corten" supported steel liner plate. The
upper 30 feet of the liner, caps and flashing for each chimney are
A-19
made of 316-L stainless steel. Aviation lights and markings are provided as
required by the Federal Aviation Administration.
Morgantown Units 1 and 2 share a common control room. All of the
units at the Morgantown Facility share other structures and facilities such as
warehouses, administrative offices, water storage and treatment facilities, fuel
storage and handling facilities, drainage and sewage treatment facilities,
hydrogen, nitrogen and CO\2\ bulk storage facilities, and the fire protection
system.
Electrical and Control Systems
The Morgantown Unit 1 steam turbine drives a Westinghouse hydrogen-
cooled generator. The generator is a two pole, 3 phase, 60 cycle, 3,600 rpm, 18
kV unit rated at 695,000 kVA at 0.90 power factor and 60 psig hydrogen pressure.
Excitation is provided by a 2,900 kW, 500 volt, 3,600 rpm shaft driven brushless
exciter that is directly connected to the generator. The Morgantown Unit 2
steam turbine drives a GE hydrogen and water-cooled generator. The generator is
a 2 pole, 3 phase, 60 cycle, 3,600 rpm, 24 kV unit rated at 695,000 kVA at 0.90
power factor and 60 psig hydrogen pressure. Excitation is provided by a 2,310
kW, 500 volt DC, 3,600 rpm shaft driven alternator exciter that is directly
connected to the generator.
The Morgantown Units 1 and 2 generator terminals are each connected
through force-cooled isolated phase buswork to the low-voltage terminals of
their main transformer. Each of the units use a three-phase, forced oil, forced
air-cooled main power transformer manufactured by GE. Both transformers are
rated at 650 MVA, with Morgantown Unit 1 at 17.1 kV-234 kV and Morgantown Unit 2
at 22.8 kV-234 kV. One spare main power transformer is shared with the Chalk
Point Facility.
On Morgantown Units 1 and 2, the auxiliary power system is divided
into two voltage classes. The medium voltage equipment including all motors
above 300 hp is operated at 4,160 volts, and the low voltage equipment is
operated at 480 volts. Auxiliary power for each generating unit's auxiliary
usage is supplied by one station service transformer that is connected to each
unit's respective generator's isolated phase bus. Each three phase, forced oil,
forced air-cooled station service transformer was manufactured by Westinghouse
and is rated at 25 MVA. Two reserve station service transformers in the
switchyard that are connected to the 69 kV system supply start-up and emergency
power to the 4,160 volt switchgear assemblies for both steam units. The black
start Morgantown CTs 1 and 2 may also be used to feed into the auxiliary 4 kV
bus network for the steam units. One spare auxiliary transformer is shared with
the Chalk Point Facility.
For the CT units, as noted above, Morgantown CTs 1 and 2 each serves
its respective unit through the auxiliary bus network at 4 kV. With either or
both of the steam generating units in service, it is possible to use the
Morgantown CTs 1 and 2 units for peaking power through the reserve transformers
to the 69 kV and 230 kV switchyard. Morgantown CTs 3 through 6 are connected to
the switchyard in a similar manner.
AC and DC Critical Systems
The Morgantown Facility is equipped with an uninterruptable power
supply system designed to supply AC and DC power to critical motors, control
systems and computer systems associated with the plant.
Plant Control System
There is one main control room at the Morgantown Facility. The
control room for Morgantown Units 1 and 2 also provides remote start capability
for all the CTs, although the units are generally started manually.
The control room for Morgantown Units 1 and 2 provides for separate
operation of each unit utilizing a Foxboro DCS which was retrofitted into the
control room in 1994. These computerized systems include combustion control,
burner management systems, automatic generator control, emissions monitoring
systems, and control of auxiliary systems such as fly ash handling and
sootblowing.
The CT units are equipped with GE Speedtronic control systems.
A-20
Environmental Controls and Equipment
Air Emissions
The Morgantown Facility is permitted for air emissions within the
limits established in the permits. The key pollutants which must be controlled
include particulate matter, SO\2\, NO\X\, and opacity. The basic strategies and
air pollution control technologies employed at the Morgantown Facility to
control these pollutants include: (i) purchasing fuels of the required sulfur
content in order to control emissions of SO\2\; (ii) utilizing ESPs on
Morgantown Units 1 and 2 for particulate and opacity control; and (iii)
utilizing LNCFS Level III burners and SOFA systems on Morgantown Units 1 and 2
to reduce NO\X\ emissions.
Each of the Morgantown Units 1 and 2 are equipped with Research-
Cottrell precipitators. These precipitators are each composed of two separate
sections which each discharge into one of the units' induced draft fans. Each
precipitator is guaranteed to have a collection efficiency of 99.5 percent when
handling 830,000 cfm of gas flow containing 24,200 pounds of fly ash per hour.
To improve the collection efficiency of the precipitators, a flue gas
conditioning system was installed approximately five years ago. The flue gas
conditioning system heats molten sulfur to form SO\2\, which in turn is
converted by a vanadium pentoxide catalyst into sulfur trioxide ("SO\3\"), which
is injected into the flue gas prior to the precipitators. The SO\3\ acts to
improve the electrical charge of the fly ash particles so that they are more
readily attracted and collected by the precipitator. This system is operated
only when needed, primarily during unit start-ups.
The Morgantown Facility's steam units are equipped with CEMs as
required by state and federal regulations. These monitors measure and record
emission levels for opacity, SO\2\, NO\X\, CO\2\, as well as volumetric flow. CO
probes have also been installed on each of the steam units. The Morgantown
Facility's CEMs availability has been greater than the 95 percent level required
by the USEPA.
Wastewater/Solid Waste Disposal
Solid waste at the Morgantown Facility consists primarily of the coal
processing and combustion byproducts generated by Morgantown Units 1 and 2.
Bottom ash from Morgantown Units 1 and 2 is pumped as a water/ash mixture to
dewatering bins where the water is decanted off and recycled for use in the
bottom ash transporting system. The dewatered bottom ash is loaded into trucks
for disposal.
Fly ash from Morgantown Units 1 and 2 is collected and transported to
ash storage silos, where it is loaded into trucks for transport to Faulkner.
The small amounts of iron pyrites removed from the pulverizers of
Morgantown Units 1 and 2 are stored on site in a lined storage area.
Major water treatment equipment at the Morgantown Facility includes
settling ponds, neutralization systems, oil/water separators and sanitary waste
treatment. With the exception of once-through cooling water and clean storm
water, all water is treated prior to discharge to the Potomac River or
Pasquahanza Creek. Two settling ponds are arranged in series for the collection
and treatment of contaminated storm waters and all process discharges from the
Morgantown Facility. A caustic injection system is utilized in the secondary
pond to control pH. Solids are removed from the ponds through a sedimentation
process. Both the settling ponds and a packaged sewage treatment plant
discharge into the Morgantown Facility's discharge canal. Also there is a
separate settling pond for the water runoff from the lined coal storage area.
The Morgantown Facility is also permitted to burn waste oils, which
are collected and stored on-site, and oily rags which are shredded and injected
into one of the steam generators.
A-21
Off-Site Requirements
Fuel Supply
Morgantown Units 1 and 2 burn bituminous coal that is delivered by the
CSX Transportation Company from mines generally located in the northern
Appalachian coal mining region, which includes western Pennsylvania, Maryland,
and West Virginia. Coal is purchased pursuant to four coal contracts that also
cover coal supply to the Dickerson and Chalk Point Facilities. These contacts
are short-term contracts which, with certain extension options, will expire
between December 31, 2000 and June 30, 2002. Minimum quality parameters and
minimum tonnages are specified, and all of the contracts have provisions to
purchase additional tonnage at a discount to the current spot market price. In
addition to the contracts, coal may be purchased on the spot market depending on
quantity requirements and market conditions. SE Mid-Atlantic will acquire
approximately 244 rail cars that are used for coal deliveries to the Morgantown,
Chalk Point and Dickerson Facilities.
The No. 6 residual oil burned at the Morgantown Facility is purchased
on the spot market and is primarily delivered to the Morgantown Facility via the
Piney Point Pipeline from the unloading and storage facilities in Piney Point,
Maryland. The Piney Point Pipeline is operated under contract by ST Services.
The secondary means of delivering No. 6 residual oil to the Morgantown Facility
is via truck. No. 6 oil is purchased under short-term contracts with no minimum
purchase requirements.
No. 2 distillate fuel oil is purchased with each of three vendors
under short-term contracts with no minimum purchase requirements. The oil is
delivered to the Morgantown Facility by barge from the vendors' terminals.
Electrical Interconnection
The Morgantown Facility's electric output is interconnected to the
grid through the Morgantown Facility's switchyard. Morgantown Units 1 and 2 and
Morgantown CTs 3 through 6 are connected to the Morgantown 230 kV ring bus.
There are six 230 kV transmission lines emanating from the switchyard that tie
into the Hawkins Gate, Oak Grove, Talbert and Ryceville Substations. In
addition, there are two 69 kV lines emanating from the switchyard that tie into
the SMECO system.
Water Supply
Raw cooling water for the Morgantown Unit 1 and 2 is obtained from the
Potomac River. Water for other uses within the Morgantown Facility is obtained
from the four on-site artesian wells. Screening, filtering, treatment, pumping
and storage facilities are available for processing the well water for various
uses within the Morgantown Facility.
Review of Technology
- --------------------
The design and construction of electric utility generating units using
pulverized coal or No. 6 residual oil to fire steam boilers has been common for
many years, as has the firing of No. 2 distillate oil in CTs. The Morgantown
Facility although designed and constructed a few years earlier than the Chalk
Point Facility shares many of the same technologies with Chalk point. Thus, the
same information included in the Review of Technology section for the Chalk
Point Facility is applicable to the Morgantown Facility.
In general, Morgantown Units 1 and 2 have been normally base-loaded,
which is common for large, coal-fired units which are generally designed for
this type of operation.
The Morgantown CTs utilize mature, commercially proven technology.
Based on our review, we are of the opinion that the Morgantown
Facility has been designed and constructed with good engineering practices and
generally accepted industry practices, and the technologies in use at the
Morgantown Facility are sound, proven conventional methods of electric
generation. If operated and maintained as proposed by SE Mid-Atlantic, the
Morgantown Facility should be capable of meeting the currently applicable
A-22
environmental permit requirements. Furthermore, all off-site requirements of
the Morgantown Facility have been adequately provided for, including fuel
supply, water supply, ash and wastewater disposal, and electrical
interconnection.
Estimated Useful Life
- ---------------------
We have reviewed the quality of equipment installed at the Morgantown
Facility, the general plans for operating and maintaining the facility and the
historical performance of the Morgantown Facility. On the basis of this review
and assuming that: (1) the units are operated and maintained by SE PJM
Management in accordance with the policies and procedures as presented by SE
Mid-Atlantic, (2) all required renewals and replacements are made on a timely
basis as the units age, and (3) coal and oil burned by the units are within the
expected range with respect to quantity and quality, we are of the opinion that
the Morgantown Facility should have a useful life extending well beyond the term
of the Certificates.
THE POTOMAC RIVER FACILITY
The Potomac River Facility is comprised of five conventional steam
turbine units, with a total net summer generating capacity of approximately 482
MW. The Potomac River Facility provides baseload and cycling generation and is
capable of utilizing both coal and oil for fuel.
Potomac River Units 1 and 2 are identical coal-fired electric
generating units that have been in commercial operation since 1949 and 1950,
respectively. Each unit consists of a single boiler and straight condensing
steam turbine generator with nameplate capacity ratings of 92 MW. Each unit has
an actual maximum capacity rating of approximately 88 MW and can be dispatched
down to 25 MW. The annual average net heat rates have ranged between
approximately 11,700 Btu/kWh and 12,400 Btu/kWh for each unit. Each unit has a
CE pulverized coal-fired boiler and a GE steam turbine and generator.
Potomac River Units 3, 4 and 5 are identical coal-fired electric
generating units that have been in commercial operation since 1954, 1956 and
1957, respectively. Each unit consists of a single boiler and tandem compound
steam turbine generator with nameplate capacity ratings of 110 MW. The units
have actual maximum capacity ratings of approximately 102 MW and can be
dispatched down to 35 MW. The annual average net heat rates are approximately
10,000 Btu/kWh for each unit. Each unit has a CE pulverized coal-fired boiler
and a GE steam turbine and generator.
In addition, the Potomac River Facility has certain common facilities
shared by all units such as river water pumping stations, fuels receiving,
storage and handling systems, water treatment systems, warehouses, maintenance
shops, chemistry laboratory, administrative offices, groundwater monitoring
wells, and electrical switchyard.
The Plant Site
- --------------
The Potomac River Facility is located on a 25-acre site at Bashford
Lane and North Royal Street along the Potomac River in Alexandria, Virginia. SE
Mid-Atlantic will lease the plant site from Pepco under a 99-year lease
agreement. The site is easily accessible and provides adequate access to
necessary utilities and rail transportation. The site is in a suburban area
bordered on the east by the Potomac River, on the north by an office park and
residential properties, and on the southwest by the Norfolk Southern Railroad,
with residential properties beyond the railroad. On the basis of our
observations and the historical operations of the Potomac River Facility, we are
of the opinion that the site is suitable for the Potomac River Facility's
continued operation.
A-23
Description of the Facility
- ---------------------------
Mechanical Equipment and Systems
Steam Generators
The Potomac River Units 1 and 2 steam generators consist of identical
CE natural circulation units with tubular air preheaters and tangentially-fired
burners. Each boiler includes a superheater, economizer, coal pulverizers, coal
feeders, and a sootblowing system. The boilers have a maximum continuous rating
of 800,000 lb/hr of superheated steam at 875 psig and 925(degree) F. The boilers
are designed to fire pulverized coal as the primary fuel and to fire No. 2 fuel
oil for start-up, flame stabilization, and as alternate fuel to replace mill
capacity when needed. Each boiler contains four type "TV" vertically adjustable
tangentially-fired burner units, with each burner unit containing four coal
burners, eight gas torches, three oil burners, and two electrically ignited
pilot oil torches.
Potomac River Units 1 and 2 each have four Raymond Bowl Mills with
integral exhausters, feed control, and fineness regulation. Two forced draft
fans per boiler discharge the primary and secondary air through the
corresponding tubular air preheaters. Two induced draft fans per boiler are
provided to draw flue gas from the boiler, maintain a slight negative pressure
in the boiler, and discharge to the inlet of the ESPs.
The Potomac River Units 3, 4 and 5 steam generators consist of
identical CE controlled circulation units with tubular air preheaters and
tangentially-fired burners. Each boiler includes a superheater, reheater,
economizer, circulating pumps, coal pulverizers, coal feeders, and a sootblowing
system. The boilers have a maximum continuous rating of 725,000 lb/hr of
superheated steam at 1,875 psig and 1,050 (degree)F. The boilers are designed to
fire pulverized coal as the primary fuel and to fire No. 2 fuel oil for start-
up, flame stabilization and as an alternate fuel to replace mill capacity when
needed. Each boiler contains four type "T" vertically adjustable tangential
fired burner units, with each burner unit containing four coal burners, eight
gas torches, four oil burners, and four pilot oil torches.
Each of Potomac River Units 3, 4 and 5 has four Raymond bowl Mills
with integral exhausters, feed control, and fineness regulation. Two forced
draft fans per boiler discharge the primary and secondary air through the
corresponding tubular air preheater. Two induced draft fans per boiler are
provided to draw flue gas from the boiler, maintain a slight negative pressure
in the boiler, and discharge to the inlet of the ESPs.
Steam Cycle and Heat Rejection Systems
Each Potomac River Unit 1 and 2 boiler provides steam to a single GE
straight condensing 1,800 rpm steam turbine. Each turbine is rated at 80,000 kW
at an inlet throttle flow of 577,600 lb/hr of steam at 850 psig, 925 (degrees)F
and 1.0 inch Hg absolute backpressure. The low-pressure section of the steam
turbine exhausts into a two-pass surface condenser where the steam is condensed
by rejection of heat into the circulating water.
Circulating water for each Potomac River Unit 1 and 2 condenser is
obtained through an intake structure and intake canal located on the Potomac
River. The intake structure consists of gates, traveling screens, and two 50-
percent capacity circulating water pumps. The pumps discharge to the condenser,
and after passing through the condenser, the circulating water is discharged to
the river through a discharge structure and discharge canal.
Feedwater for each Potomac River Unit 1 and 2 is provided by two 100-
percent capacity condensate pumps, two 100-percent capacity condensate booster
pumps, and three 50-percent capacity boiler feed pumps. There are five stages
of feedwater heating including a deaerator.
Each Potomac River Unit 3, 4 and 5 boiler provides steam to a single
GE tandem-compound double flow reheat 3,600 rpm steam turbine. Each turbine is
rated at 100,000 kW at an inlet throttle flow of 725,000 lb/hr of steam at 1,800
psig, 1,050 (degrees)F reheat and 1.0 inch Hg absolute backpressure. The low-
pressure section of the steam turbine exhausts into a two-pass surface condenser
where the steam is condensed by rejection of heat into the circulating water.
Circulating water for each Potomac River Unit 3, 4, and 5 condenser is
obtained through an intake structure and intake canal located next to those of
Units 1 and 2. The intake structure consists of two traveling screens,
A-24
two trash racks, one screen wash pump, and two 50-percent capacity circulating
water pumps. The pumps discharge to the condenser and after passing through the
condenser, the circulating water is discharged to the Potomac River through a
discharge structure and discharge canal.
Feedwater for each Potomac River Units 3, 4, and 5 is provided by two
100-percent capacity condensate pumps, two 100-percent capacity condensate
booster pumps, and three 50-percent capacity boiler feed pumps. There are five
stages of feedwater heating including a deaerator.
Fuel Handling System
Bituminous coal for Potomac River Units 1, 2, 3, 4 and 5 is delivered
by approximately 50 loaded coal cars per train. In 1984, installation of a new
rotary car dumper increased car capacity from 90 tons to 120 tons. Pepco
installed four trunion wheel assemblies in 1998, due to extensive wear on the
coal car dumper. The coal handling system can handle 700 tons of coal per hour.
As coal cars are emptied by rotary car dumper into a double receiving hopper
beneath the dumper, two belt feeders discharge coal onto separate belt
conveyors. These conveyors discharge to either a Pennsylvania Bradpactor
breaker (crusher) or a by-pass. The Pennsylvania Bradpactor replaced the old
Bradford breaker in 1987. Coal discharged through the breaker is placed onto a
horizontal belt feeder to be routed over station conveyors. By-pass or breaker
material is discharged to either an inclined boom belt conveyor (and onto the
coal pile) or the weightometer-equipped inclined belt conveyors. The two
inclined belt conveyors discharge the coal onto separate bunker conveyors. Coal
to the bunker conveyors flows through to one of the four Raymond Bowl Mills on
each unit. The coal handling system is equipped with a coal dust suppression
system, added in 1998, to eliminate fugitive coal dust from coal going to the
storage pile. In 1985, a stocking-out boom and conveyor was added to the
existing system. Coal from the 140,000-ton storage pile is reclaimed into a
double receiving hopper and placed two belt feeders. The belt feeders discharge
onto separate belt conveyors. Two underground No. 2 fuel oil storage tanks of
25,000 gallons each supply the five units with start-up fuel.
Ash Handling Systems
The pneumatic ash handling system of the Potomac River Facility is
comprised of four subsystems, including a bottom ash system A serving Potomac
River Units 1, 2 and 3; a bottom ash system B serving Potomac River Units 4 and
5; a fly ash system A serving Potomac River Units 1, 2 and 3; and a fly ash
system B serving Potomac River Units 4 and 5. Each subsystem contains one
continuous primary collector, one intermittent secondary collector with bag
filters, one vacuum pump, one pressure blower, two (fly ash) heat exchangers,
two (fly ash) silos with wet and dry unloading equipment; and one (bottom ash)
silo with wet unloading equipment. Hot precipitators for all five units were
installed in 1979.
Capacity of the bottom ash vacuum system is 15 tons per hour ("tph")
while capacity of the bottom ash pressure system is 25 tph. Two continuous
mixer/unloaders, each rated at 150 tph, unload the bottom ash to a belt conveyor
and into railroad cars.
Capacity of the fly ash vacuum system is 43 tph, while capacity of the
fly ash pressure system is 75 tph. Two continuous mixer/unloaders, each rated
at 150 tph, in fly ash silo A and two hydromixers in fly ash silo B, unload the
fly ash produced by the supplemental hot-side ESPs. The fly ash unloaders were
replaced in 1998 by two dustless pugmill type unloaders.
Make-Up Water System
Boiler make-up water for the Potomac River Facility is generated from
the City of Alexandria water supply using a demineralizer. Capacity of the
demineralizer is 5,000 gallons per hour. Demineralized water is either used
directly in the plant or stored in three demineralizer water storage tanks with
a total capacity of 150,000 gallons.
Additional Structures and Systems
Potomac River Units 1 and 2 compressed air is supplied by one service
air compressor and one instrument air compressor. Potomac River Units 3, 4 and
5 use one service air compressor with two receiver banks. The units operate in
parallel with the Potomac River Units 1 and 2 service air compressor.
A-25
Two motor-driven fire pumps take suction from the service water
header, while the emergency diesel-driven fire pump takes suction from the
Potomac River. An area wash pump and jockey pump augment the system. A CO\2\
fire protection system protects the lube oil room, the lube oil tanks, and the
underground No. 2 fuel oil (ignition) tanks.
Each unit at the Potomac River Facility has a 109-foot, brick-lined
radial brick chimney.
All the units at the Potomac River Facility share other significant
structures and systems such as the fuel oil tanks, coal handling equipment,
warehouses, administrative buildings, circulating water, intake structure,
demineralized water storage banks, water treatment system, fuel oil storage and
handling facilities, drainage and sewage treatment facilities, and the fire
protection system. A new administration building was constructed at the south
end of the plant in 1990.
Electrical and Control Systems
Each of the Potomac River Units 1 and 2 1,800 rpm steam turbines
drives a GE hydrogen-cooled generator rated 94,117 kVA at 0.85 power factor and
13.8 kV. Each of the Potomac River Units 3, 4, and 5 3,600 rpm steam turbines
drives a GE hydrogen-cooled generator rated 150,882 kVA at 0.85 power factor and
13.8 kV.
Each generator is connected through an isolated phase bus duct to its
main generator step-up transformer. A total of ten main generator step-up
transformers, two per unit, are provided at the Potomac River Facility. Potomac
River Units 1 and 2 use three-phase outdoor oil-filled units rated 13.8-69 kV,
48/60 MVA with self/forced air-cooling. Potomac River Units 3, 4, and 5 use
three-phase outdoor oil-filled units rated 13.8-69 kV, 90 MVA with forced
oil/forced air-cooling.
In addition to the main generator step-up transformer, each generator
is connected to a three-phase outdoor type station service transformer rated
2.3-13.8 kV, 6/7.5 MVA with self/forced air-cooling.
Fed from the 69 kV switchyard, the four reserve station service
transformers, rated 2.3-69 kV, 6.75 MVA with self/forced air cooling remain in
service under normal operating conditions to avoid overloading the station
service transformers.
Auxiliary power is divided into two voltage classes. Medium voltage
equipment is operated at 2,300 volts while the low voltage equipment is operated
at 480 V.
AC and DC Critical Systems
Should the ac feed to any of the ten 220 volt lighting buses be lost,
an auto throwover switch will supply 125 volt emergency dc lighting.
The Potomac River Facility is equipped with an uninterruptable power
supply system designed to supply AC and DC power to critical motors, control
systems and computer systems associated with the plant.
Plant Control System
There are three main control rooms at the Potomac River Facility: one
for Potomac River Units 1 and 2; one for Potomac River Units 3 and 4; and one
for Potomac River Unit 5.
The control room for Potomac River Units 1 and 2 provides for separate
operation of each unit using a Leeds & Northrup ("L&N") DCS which was
retrofitted to Potomac River Unit 1 in 1994 and to Potomac River Unit 2 in 1993.
The control room for Potomac River Units 3 and 4 provides for separate operation
of each unit using an L&N DCS which was retrofitted to Potomac River Unit 3 in
1991 and to Potomac River Unit 4 in 1990. The L&N DCS was retrofitted to
Potomac River Unit 5 in 1992. These computerized systems include combustion
control, feedwater control, and data acquisition.
Further updates to the controls were initiated in 1998 with the
addition of two TV cameras for each boiler for flame observation and updated
control room operator screens for Potomac River Units 1, 2 and 5. Controls
A-26
for the demineralizer system, bottom and fly ash systems, extraction valves,
steam seal regulators, ash/silo unloading system, precipitators, sootblowers,
turbine control and boiler control remain as original plant equipment
Environmental Controls and Equipment
Air Emissions
The Potomac River Facility is permitted for air emissions within the
limits established in the permits. The key pollutants which must be controlled
include particulate matter, SO\2\, NO\X\ and opacity. The basic strategies and
air pollution control technologies employed at the Potomac River Facility to
control these pollutants include: (i) purchasing fuels of the required sulfur
content in order to control emissions of SO\2\; and (ii) utilizing cold-side and
hot-side ESPs on all five units.
Potomac River Units 1 and 2 are equipped with Research-Cottrell cold-
side ESPs. Each precipitator consists of four units of 15 ducts each. Each
precipitator is guaranteed to have a collection efficiency of 95 percent when
handling 325,000 cfm of gas flow at 350 (degrees)F.
Potomac River Units 3, 4, and 5 are equipped with Research-Cottrell
cold-side ESPs. Each precipitator consists of two units guaranteed to have a
collection efficiency of 97 percent when handling 300,000 cfm of gas flow at
250 (degrees)F.
Supplemental hot-side ESPs, manufactured by Western Precipitation
Division of Joy, were added to all five units in 1979. The system operates at a
collection efficiency of 99.5 percent when handling 585,000 cfm of gas flow at
650 (degrees)F and 22,500 pounds of fly ash per hour.
All five units at the Potomac River Facility are equipped with CEMs as
required by state and federal regulations. These monitors measure and record
emission levels for opacity, SO\2\, NO\X\, CO\2\, as well as volumetric flow.
The Potomac River Facility's CEMs availability has been greater than the 95
percent level required by the USEPA.
Wastewater/Solid Waste Disposal
Solid waste at the Potomac River Facility consists primarily of the
coal processing and combustion by-products generated by all five units. Bottom
ash from each of the five units is collected and transported to the bottom ash
storage silo where it is loaded into trucks for disposal off-site.
Fly ash from each of the five units is collected and transported to
one of two fly ash storage silos where it is loaded into trucks for transport to
Brandywine.
Certain plant drains and storm drains discharge to the Potomac River.
Eight sumps collect storm runoff, coal pile runoff, precipitator runoff, and ash
handling area runoff for discharge to the clarifier. Clarifier effluent and
demineralizer regeneration waste is neutralized in the neutralization tank prior
to discharge into the Potomac River. All sanitary waste from the Potomac River
Facility is discharged to the City of Alexandria sewage system.
Off-Site Requirements
Fuel Supply
All five units of the Potomac River Facility burn bituminous coal
delivered by Norfolk-Southern Railroad from mines primarily located in West
Virginia, which is in the northern Appalachian coal mining region. Coal is
purchased pursuant to two coal contracts. These contracts are short-term
contracts which, with certain extension options, will expire on May 31, 2002.
Minimum quality parameters and minimum tonnages are specified, and both
contracts have provisions to purchase additional tonnage at a discount to the
current spot market price. In addition to the contracts, coal may be purchased
on the spot market depending on quantity requirements and market conditions.
A-27
No. 2 distillate fuel oil is purchased pursuant to one-year contracts
with each of three vendors. The oil is delivered to the Potomac River Facility
by truck.
Electrical Interconnection
The Potomac River Facility's electric output is interconnected to the
grid through the Potomac River Facility's switchyard. Potomac River Units 1
through 4 are connected to one of two 69 kV buses. Potomac River Unit 5 is
connected to both 69 kV buses. The two 69 kV buses are connected to the two
Blue Plains 230 kV buses through four transformers. Additionally, the two 69 kV
buses feed 16 69 kV substations.
Water Supply
Raw cooling water for each unit of the Potomac River Facility is
obtained from the Potomac River. Water for other uses within the Potomac River
Facility is obtained from the City of Alexandria water supply. Screening,
filtering, treatment, pumping and storage facilities are available for
processing the city water for various uses in the Potomac River Facility.
Review of Technology
- --------------------
The design and construction of electric utility generating units using
pulverized coal or No. 2 distillate oil to fire steam boilers has been common
for many years. The Potomac River Facility was designed utilizing the standard
technologies available at the time it was built. Where it has proven
economically desirable, or where regulatory changes have required, new
technologies have been "backfit" into the Potomac River Facility to improve
operations, environmental compliance, and efficiencies. Major examples of this
include the installation of new hot-side ESPs in 1979 and replacement of the
control systems of Potomac River Units 1, 2, 3, 4 and 5.
In general, Potomac River Units 1 and 2 have been normally cycled,
which is common for smaller, coal-fired units of this vintage. The Potomac
River Units 3, 4 and 5 have been normally base-loaded.
Based on our review, we are of the opinion that the Potomac River
Facility has been designed and constructed with good engineering practices and
generally accepted industry practices, and the technologies in use at the
Potomac River Facility are sound, proven conventional methods of electric
generation. If operated and maintained as proposed by SE Mid-Atlantic, the
Potomac River Facility should be capable of meeting the currently applicable
environmental permit requirements. Furthermore, all off-site requirements of
the Potomac River Facility have been adequately provided for, including fuel
supply, water supply, ash and wastewater disposal, and electrical
interconnection.
Estimated Useful Life
- ---------------------
We have reviewed the quality of equipment installed at the Potomac
River Facility, the general plans for operating and maintaining the facility and
the historical performance of the Potomac River Facility. On the basis of this
review and assuming that: (1) the units are operated and maintained by SE PJM
Management in accordance with the policies and procedures as presented by SE
Mid-Atlantic, (2) all required renewals and replacements are made on a timely
basis as the units age, and (3) coal and oil burned by the units are within the
expected range with respect to quantity and quality, we are of the opinion that
the Potomac River Facility should have a useful life extending well beyond the
term of the Certificates.
THE PRODUCTION SERVICE CENTER
The Production Service Center ("PSC") is a 145,000-square foot
facility situated on approximately 69 acres of land located 9 miles from
Washington, D.C. in Upper Marlboro, Maryland on property that is zoned "light
industrial". The PSC is within one hour's drive of all of the Generating
Facilities. The PSC was established in 1985 and has served since then as the
headquarters for Pepco's generation unit. It is expected that the PSC will
serve the same purpose for SE Mid-Atlantic.
A-28
The PSC facility provides: (i) office space for administrative and
engineering functions; (ii) classrooms and supporting equipment for training;
and (iii) a large machine shop for repairing power plant equipment. The machine
shop occupies approximately 67,000-square feet of the facility. With a ceiling
height of 48 feet and two 35-ton cranes spanning an area 64 feet wide and 450
feet long, the machine shop area is capable of performing work on all but the
very largest pieces of equipment that exist in the Generating Facilities. In
addition to the large lathes, boring mills and grinding equipment that are used
for repairing turbine rotors and stationary components, there is a welding shop,
a motor cleaning and repair shop, including baking ovens, a blast cleaning room,
a disassembly and inspection area, a mill roll weld-cladding area, a warehouse
area, plus numerous smaller machine tools.
The training facilities consist of several classrooms for formal
training, shops for "hands-on" skills training, and a boiler simulator. The
classrooms may be used for skills training such as operating and maintenance
procedures or for required training such as safety. The training shops contain
small-scale equipment for training in machine tool operation, balancing of
rotating equipment, alignment of equipment, electrical repairs, and welding.
The boiler simulator is a computerized simulation of the supercritical boiler
control systems at the Chalk Point and Morgantown Facilities. With this
simulator, and another similar unit at the Dickerson Facility, boiler operators
can be trained to operate the boilers at their respective plants utilizing
simulated operating conditions, parameters and events as programmed into the
simulator by the trainer.
The administrative and engineering office areas were in the process of
being renovated when Pepco announced its decision to divest its generating unit.
The renovations were halted to allow the new owner flexibility in organizing the
facility.
THE PINEY POINT PIPELINE
SE Mid-Atlantic will acquire the Piney Point Pipeline which supplies
No. 6 residual fuel oil to the Chalk Point and Morgantown Facilities. The Piney
Point Pipeline and barge unloading facilities were constructed in 1971 by
Steuart Petroleum and the Piney Point Pipeline was purchased by Pepco in 1976.
It connects the deepwater barge unloading facilities on the Potomac River in
Piney Point, Maryland with the two generating facilities.
The Piney Point Pipeline consists of 51.5 miles of thermally
insulated, buried hot oil pipeline, four pumping stations, and five isolation
valve stations. There are 30.1 miles of 16-inch outside diameter pipe that run
from the Piney Point Oil Terminal to the Ryceville Pumping Station, and 21.4
miles of 12-inch outside diameter pipe that run from the Morgantown Facility to
the Ryceville Pumping Station to the Chalk Point Facility. There are two river
crossings at which there is double walled piping with nitrogen blanketing in the
void space between the inner and outer pipes. Cathodic protection and leak
monitoring systems are installed on the piping.
The four pumping stations are located at the Piney Point Oil Terminal,
Ryceville Pumping Station, and at the Chalk Point and Morgantown Facilities.
There are four electric driven pumps, one back-up diesel driven pump, and oil
heaters at each of the Ryceville Pumping Station and the Piney Point Oil
Terminal, and single pumps at both the Chalk Point and Morgantown Facilities.
There is a manual isolation valve station at milepost 15, and two automatic
isolation valve stations at each of Swanson Creek and Wicomico River.
Storage tanks include two 500,000-barrel tanks for No. 6 residual oil
at the Piney Point Oil Terminal, and flushing oil tanks with capacities of
96,000 barrels at the Morgantown Facility, 20,000 barrels at the Chalk Point
Facility, and 54,000 barrels at the Ryceville Pumping Station. Flushing oil is
No. 2 distillate fuel oil that is used to fill the Piney Point Pipeline when it
is not pumping No. 6 residual oil.
The Piney Point Pipeline has a design pressure of 600 psig and design
temperature of 175 (degrees)F. The normal operating conditions are 350 to 375
psig with one pump operating, and 550 psig with two pumps operating, at a
temperature of 110 to 165 (degrees)F.
Day-to-day operations of the Piney Point Pipeline are performed by ST
Services (formerly Steuart Petroleum) under a contract that expires on May 31,
2001. SE Mid-Atlantic has the option to extend the contract for an additional
five years.
A-29
The Piney Point Pipeline has been out of service since an April 2000
oil release (see the section entitled "Environmental Assessment -- The Piney
Point Pipeline"). Pepco is in discussions with the U.S. Department of
Transportation regarding testing procedures prior to proceeding with work to
restore the Piney Point Pipeline to service. Restoration of the Piney Point
Pipeline would include installation of state of the art monitoring equipment for
early leak detection. Approval of a Spill Prevention Control and Countermeasure
("SPCC") plan in connection with the restoration is required by the U.S.
Department of Transportation, the USEPA, and the Maryland Department of the
Environment ("MDE"). While the Piney Point Pipeline is out of service, Pepco
has been delivering No. 6 oil to the Chalk Point Facility by truck. Chalk Point
Units 3 and 4 are dual-fuel facilities which utilize gas or No. 6 oil. Based on
historical and projected capacity factors and fuel usage, supply of fuel oil by
truck is expected to be sufficient while the Piney Point Pipeline is out of
service. The Morgantown Facility uses No. 6 oil as a supplement fuel for flame
stabilization and on-line mill repair work. Oil can be delivered by truck to
the Morgantown Facility as required.
THE ASH STORAGE FACILITIES
SE Mid-Atlantic will acquire the Ash Storage Facilities which receive
and store the solid waste materials such as sludges, bottom ash and fly ash
produced from the combustion of coal at the generating facilities. These three
facilities are the Faulkner, Brandywine and Westland Ash Storage Facilities.
Designed and engineered using methods to protect the environment, each site has
its own National Pollutant Discharge Elimination System ("NPDES") Permit that
requires extensive ground and surface water monitoring on a periodic basis
through the life of the facility. During the course of developing and operating
these sites, sedimentation, erosion control and runoff water collection and
control plans are followed.
Brandywine
Brandywine was developed to store the ash byproducts from the Chalk
Point Facility and, since 1986, it has been storing ash byproducts from the
Potomac River Facility as well. It has been in operation since 1970, and is
located on approximately 232 acres of land in the rural town of Brandywine in
Prince George's County, Maryland. It is bounded on the northwest, west, and
southwest by the Mataponi Creek. Numerous gravel mines surround the Brandywine
area.
The J. E. Grainer Company, Inc. originally designed the site utilizing
107 acres in five phases. Phases I-IV were old gravel pits that were filled
with ash, restored to their original topography and vegetatively stabilized from
1970 to 1974. These were "Cellular Fills" wherein at the end of each working
day, cover material was placed over the cellular fill area. There was no
special emphasis on the compaction of the ash. Phase V was structurally filled
from 1975 to 1978.
An additional 232-acre property was purchased in 1978. GAI
Consultants, Inc. re-engineered the property by dividing it into five areas
known as areas A, B, C, D, and E. These areas were filled as follows: Area A in
1970 to 1974; Area B in 1978 to 1980; Area C in 1981 to 1985; Area D (originally
phase V) in 1975 to 1978; and Area E in 1985 to 1992. Additional re-engineering
in 1989 resulted in being able to raise the elevations of Areas A, B, C, and E
by 20 feet.
Brandywine is operated eight hours per day, five days per week.
Covered, contracted dump trucks are loaded with ash and weighed at the Chalk
Point and Potomac River Facilities. The ash is transported by public highway
approximately 16 miles from the Chalk Point Facility and 30 miles from the
Potomac River Facility to Brandywine where it is unloaded in the active storage
area, spread out, watered, and compacted to a one-foot thick layer utilizing a
vibrating roller. Both the on-site hauling roads and active fill areas are
watered for dust control and to improve compaction of the fill. When the
permitted elevation of ash is reached, the ash is covered with two to three feet
of soil and vegetated. Preparation of new ash storage areas is accomplished by
stripping back topsoil and compacting the subgrade soils.
Leachate from the storage area is collected by drainpipes placed on
the prepared subsoil. The drainpipes are covered by a two to three-foot thick
cover of bottom ash, which serves as a drainage blanket. Fly ash is then placed
on top of the drainage blanket. Leachate from the collection system drains to
on-site ponds where the water is treated to meet the NPDES requirements prior to
discharge. In addition to the NPDES permit, Faulkner has
A-30
permits for erosion and sediment and for groundwater appropriation. The site is
permitted as a "pozzolan" storage facility and therefore is not subject to the
same regulations as a Subtitle D landfill.
The amount of ash delivered to Brandywine depends on the ash content
and amount of coal being fired at the Chalk Point and Potomac River Facilities,
and on the amount of ash that can be marketed to third parties. With the
additional 20 feet of elevation available above the original Areas A, B, C, and
E, Brandywine is projected to have approximately 16 years of active life
remaining at expected ash production rates.
Faulkner
Faulkner was developed to store the ash byproducts from the Morgantown
Facility. It has been in operation since 1970, and is located on approximately
276 acres of land in a rural area on the western edge of the Zekiah Swamp in
south-central Charles County, Maryland. Faulkner has been developed in five
phases: I, II, III, IV, and the Curtis phase. The first four phases utilized
132 acres of the property and were completed in 1989 and 1990. The Curtis phase
development began in 1989 to 1990 and should be completed in 2000.
Faulkner is operated eight hours per day, five days per week. Covered,
contracted dump trucks are loaded with ash and weighed at the Morgantown
Facility. The ash is transported by public highway approximately six miles to
Faulkner where it is unloaded in the active storage area, spread out, watered
and compacted to a one-foot thick layer utilizing a vibrating roller. Both the
on-site hauling roads and active fill areas are watered for dust control and to
improve compaction of the fill. When the permitted elevation of ash is reached,
the ash is covered with two to three feet of soil and vegetated. Preparation of
new ash storage areas is accomplished by stripping back topsoil and compacting
the subgrade soils.
Leachate from the storage area is collected by drainpipes placed on
the prepared subsoil. The drainpipes are covered by a two to three-foot thick
cover of bottom ash, which serves as a drainage blanket. Fly ash is then placed
on top of the drainage blanket. Leachate from the collection system drains to
on-site ponds where the water is treated to meet the NPDES requirements prior to
discharge. In addition to the NPDES permit, Faulkner has permits for erosion
and sediment and for groundwater appropriation. The site is permitted as a
"pozzolan" storage facility and therefore is not subject to the same regulations
as a Subtitle D landfill. There are approximately 6.5 million tons of ash in
storage at Faulkner, with approximately 198,000 tons being added each year. The
amount of ash delivered to Faulkner depends on the ash content and amount of
coal being fired at the Morgantown Facility, and on the amount of ash that can
be marketed to third parties. At expected ash production rates, Faulkner is
projected to have approximately 23 years of active life remaining.
Westland
Westland was developed to store the ash byproducts from the Dickerson
Facility. It has been in operation since 1978, and is located on land adjacent
to the Dickerson Facility, east of the Potomac River in a rural area of western
Montgomery County, Maryland. Westland is being developed in three phases.
Phase I, known as Area C, was completed in 1988 and had approximately 2 million
cubic yards of storage capacity. Phase II encompasses Area B, which was started
in 1987 and has approximately 5.6 million cubic yards of storage capacity that
is expected to be filled in approximately 2007. Development of Phase III, which
is Area A, is expected to commence when Phase II nears completion. Area A will
store approximately 5.8 million cubic yards of fly ash. The three areas cover a
total of approximately 300 acres.
Westland is operated eight hours per day, five days per week.
Covered, contracted dump trucks are loaded with ash and weighed at the Dickerson
Facility. The ash is transported approximately two miles to Westland where it
is unloaded in the active storage area, spread out, watered, and compacted to a
one-foot thick layer utilizing a vibrating roller. Both the on-site hauling
roads and active fill areas are watered for dust control and to improve
compaction of the fill. When the permitted elevation of ash is reached, the ash
is covered with two to three feet of soil and vegetated. Preparation of new ash
storage areas is accomplished by stripping back topsoil and compacting the
subgrade soils.
A-31
Leachate from the storage area is collected by drainpipes placed on
the prepared subsoil. The drainpipes are covered by a two to three-foot thick
cover of bottom ash, which serves as a drainage blanket. Fly ash is then placed
on top of the drainage blanket. Leachate from the collection system drains to
on-site ponds where the water is treated to meet the NPDES requirements prior to
discharge. In addition to the NPDES permit, Westland has permits for erosion
and sediment and for groundwater appropriation. The site is permitted as a
"pozzolan" storage facility and therefore is not subject to the same regulations
as a Subtitle D landfill. There are approximately two million tons of ash in
storage at Westland, with approximately 200,000 tons being added each year. The
amount of ash delivered to Westland depends on the ash content and amount of
coal being fired at the Dickerson Facility, and on the amount of ash that can be
marketed to third parties. At expected ash production rates, Westland is
projected to have approximately 48 years of active life remaining.
ENVIRONMENTAL ASSESSMENTS
Environmental Site Assessments
- ------------------------------
We have reviewed Phase I environmental site assessments ("ESAs") for
each of the generating stations, the ash storage facilities, the PSC, and the
Ryceville Pumping Station and Piney Point Oil Terminal prepared by an
environmental consultant (the "Environmental Consultant") to determine the
consistency of their assessment with industry standards. This section
summarizes certain significant findings presented in those reports.
The Phase I ESA reports, dated between December 13 and 16, 1999
consisted of site reconnaissance, interviews, review of facility files, and
review of relevant government agency files, including files from the MDE and the
Virginia Department of Environmental Quality ("VADEQ"). Additionally, we have
reviewed comments from the Environmental Consultant regarding their follow-up
site visits to the Generating Facilities, Ash Storage Facilities, the PSC, and
the Ryceville Pumping Station associated with the Piney Point Pipeline conducted
between March 9 and 10, 2000. The Environmental Consultant stated that "no
environmental conditions other than those noted during the initial site
reconnaissance conducted in June 1999, were observed."
Phase II ESAs that typically identify the nature and extent of
potential contamination issues through soil and groundwater investigations were
not specifically performed. Rather, the Environmental Consultant and Pepco
relied on existing groundwater and surface water sampling data (as available)
for preparation of estimated cost projections to mitigate numerous potential
site contamination issues identified at the facilities during Phase I ESAs. We
understand these cost projections were based on (1) identifying remediation
scenarios and their estimated range of costs; (2) risk profiling of each issue
by estimating probability of occurrence of each environmental issue and the
likelihood that regulatory action would be required; and (3) developing a model
of projected costs based on the previous assumptions. SE Mid-Atlantic has also
prepared cost projections for the significant environmental remedial issues.
The total projected costs for environmental concerns relating to potential site
contamination issues are estimated by SE Mid-Atlantic to be approximately
$12,500,000, which includes a contingency for currently unknown site
contamination issues, if any, that may potentially develop in the future. The
estimated costs for potential environmental projects have been included as
capital expenditures and operation and maintenance expenses in the Projected
Operating Results presented later in this Report.
The Chalk Point Facility
Prior to initial development of the power generating station in the
mid-1960s, the historical use of the approximately 1,160-acre subject property
was agricultural or undeveloped land. As of the date of the Environmental
Consultant's investigation, the majority of the subject property was
undeveloped, with other portions consisting of the power plant facilities.
Prior to 1970, on-site disposal of fly ash and bottom ash from coal combustion
occurred on the property. On-site land disposal areas also contain asbestos-
containing building materials ("ACBM") and construction debris. The
Environmental Consultant reported a 1998 study identifying that leachate from an
unlined coal pile has impacted on-site groundwater with elevated metals,
sulfate, and low pH in groundwater.
A-32
The Dickerson Facility
Prior to initial development of the power generating station in the
late 1950s, the historical use of the approximately 1,012-acre subject property
was undeveloped land. As of the date of the Environmental Consultant's
investigation, the majority of the subject property was undeveloped woodlands
and fields, with other portions consisting of the power plant facilities. Prior
to 1970, fly and bottom ash from coal combustion was used for fill material in
five areas within the property limits, and there are two areas used for land
disposal which were identified by the Environmental Consultant. Analysis of
water extracted from monitoring wells indicates groundwater has been impacted by
coal pile leachate with elevated metals, sulfates, dissolved solids and low pH
levels. Pepco has been monitoring groundwater quality since 1993, and submitted
a detailed monitoring plan to the MDE in 1997.
The Morgantown Facility
Prior to the development of the power generating facilities in the
1967, the 632-acre subject property had been used for a housing development and
for farming. The subject property includes heavily wooded areas, nature trails,
farming land, a tenant's house and farm buildings, as well as the power
generation building, fuel unloading dock for barge transport, ash handling and
coal storage facilities. Groundwater and soil contamination from the historical
coal pile handling and storage area have been under remediation since a consent
order was issued by the MDE in 1996.
The Potomac River Facility
Prior to the development of the power generation facility in 1946, the
28-acre subject property was occupied by the Potomac River Clay Works and the
American Chlorophyll Company. Historical documents indicate that an on-site
refuse pond was associated with the activities of the American Chlorophyll
Company. The report contained information regarding a fill site on the southern
edge of the subject property. According to interviews conducted by the
Environmental Consultant with Pepco personnel, an area outside the fence line
may contain fill and demolition or construction debris. Rejects from the coal
sorting process are potentially buried in these unlined areas. There are two
25,000-gallon fuel oil underground storage tanks on-site which have had spills
associated with tank overfill. It is not known whether the secondary
containment vaults were constructed with a soil floor.
The Production Service Center
Prior to construction of the PSC in approximately 1985, the historical
use of the approximately 70-acre subject property was undeveloped land and as a
gravel-pit mining operation between approximately the 1940s through some portion
of the 1970s. As of the date of the Environmental Consultant's investigation,
the subject property consisted of the PSC building (including offices, a machine
shop, and hazardous waste storage areas), training areas, and undeveloped
woodlands. The Environmental Consultant concluded that their investigation
revealed no recognized environmental conditions at the subject property.
The Piney Point Pipeline
The ESA evaluated potential site contamination issues at the Piney
Point Pipeline, which consists of the 6.8-acre Ryceville Pumping Station
property, the 51.5-mile underground oil pipeline, the Mile Post 15 valve housing
station, and the pumping equipment at the Piney Point Oil Terminal property.
The Piney Point Pipeline includes a 30.25-mile underground run of 16-inch pipe
between the Piney Point Oil Terminal to the Ryceville Pumping Station and 11.5-
mile and 9.75-mile underground pipe runs from the pumping station to the Chalk
Point and Morgantown Facilities, respectively. Prior to use as a pumping
station, the historical use of the 6.8-acre subject property was undeveloped
woodlands and fields. As a result of their site reconnaissance, interviews, and
review of Pepco records, the Environmental Consultant reported no significant
history of spills or leaks at the Ryceville Pumping Station, along the pipeline
route, at the valve station, or at the area of the Pepco pumping equipment at
the Piney Point Oil Terminal. The Environmental Consultant concluded that no
recognized environmental conditions were observed at the Ryceville Pumping
Station. A significant oil spill occurred from the Piney Point Pipeline and was
detected on April 7, 2000. Under the terms of the Asset Purchase Agreement,
Pepco is obligated to indemnify Southern Energy and its affiliates for all
environmental liability relating to the release of fuel oil from the Piney Point
Pipeline.
A-33
The Ash Storage Facilities
Brandywine
Prior to initial development of Brandywine in the 1960s, the
historical use of the property was reportedly a gravel surface mine,
agricultural, and undeveloped land. As of the date of the Environmental
Consultant's investigation, the subject property consisted of ash fill areas,
leachate-collection and stormwater runoff ponds, various support facilities, and
undeveloped woodlands. Groundwater monitoring conducted at the property
indicates impacts to groundwater (exceeding the USEPA Drinking Water Regulation
standards) from certain metals and other general water quality parameters, due
to the leachate from older ash fill areas. The Environmental Consultant noted
that the monitoring results are reported to the MDE.
Faulkner
Prior to initial development of Faulkner in 1970, the historical use
of the property was reportedly agricultural and undeveloped land. As of the
date of the Environmental Consultant's investigation, the subject property
consisted of ash fill areas, leachate-collection and stormwater runoff ponds,
various support facilities, buffer acreage consisting of the Brinsfield
Property, and undeveloped woodlands. Groundwater monitoring is conducted at the
property to monitor impacts from ash storage. The Environmental Consultant
reported impacts to surface water and groundwater quality within the boundaries
of the subject property, but not outside the boundary. The Environmental
Consultant noted that Pepco plans to design and install passive water treatment
systems at the subject property to protect surface water quality and to prevent
additional groundwater contamination.
Westland
Prior to initial development of Westland in 1978, the historical use
of the property was reportedly agricultural and undeveloped land. As of the
date of the Environmental Consultant's investigation, the subject property
consisted of ash fill areas, leachate-collection and stormwater runoff ponds,
various support facilities, and deserted farm structures. Monitoring conducted
at the property indicates groundwater has been impacted due to the leachate from
older ash fill areas. Elevated levels of sulfate, chloride, dissolved solids
and manganese have been recorded in one of the monitoring wells. The
Environmental Consultant also noted that the stream adjacent to the southwest
boundary of the Property is stained from high concentrations of iron
precipitates, which would indicate the potential that leachate has impacted the
soil and groundwater of the area. The Environmental Consultant did not indicate
whether water quality results have been reported to the MDE.
Summary
Based on our review, we are of the opinion that the environmental site
assessments of the sites for the Generating Facilities were conducted in a
manner consistent with industry standards, using comparable industry protocols
for similar studies with which we are familiar.
Status of Permits and Approvals
- -------------------------------
The Generating Facilities must be operated in accordance with
applicable environmental laws, regulations, policies, codes and standards.
Tables 1 through 4 identify the key permits and approvals required for the
operation of the Generating Facilities. This section includes a summary of the
permits required for the operation of the Generating Facilities. Based on our
review, we are of the opinion that the major permits and approvals required to
operate the Generating Facilities have been obtained and are currently valid or
are in the process of being renewed, and we are not aware of any technical
circumstances that would prevent the renewal of any permit. The compliance of
the Generating Facilities with these permits is discussed in the section
entitled "Operating History -- Regulatory Compliance".
A-34
Table 1
Status of Key Permits and Approvals Required for Operation
Chalk Point Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
====================================================================================================================================
1. Hazardous Waste Generator USEPA/MDE Issued ID No. Large quantity generator of hazardous wastes.
ID Number 050399 700 007 H Waste manifest system must be followed when
disposing hazardous waste.
- -----------------------------------------------------------------------------------------------------------------------------------
2. Spill Prevention Control USEPA/MDE Prepared Required for prevention of oil spills from
and Countermeasure ("SPCC") equipment and storage tanks.
Plan
- ------------------------------------------------------------------------------------------------------------------------------------
3. Oil Spill Response Plan USEPA/ USCG/ MDE Prepared Required to have cleanup equipment in place
and plan for response to oil spill.
- ------------------------------------------------------------------------------------------------------------------------------------
4. Emergency Response Plan USEPA/MDE/ Prepared Part of operating procedures for plant.
Local fire department
- ------------------------------------------------------------------------------------------------------------------------------------
5. Phase II Acid Rain Title USEPA/MDE Issued 1/1/00; Stack CEMs data used to demonstrate
IV Permit Expires 12/31/04 compliance with allowance allocations.
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
6. Title V Operating Permit MDE Applied for 12/2/96; Incorporates all emission sources at plant.
Deemed complete 1/21/97 Operating under permit shield since
application deemed complete, which is typical
of other facilities.
- ------------------------------------------------------------------------------------------------------------------------------------
7. Wetland MDE Issued 6/5/00; Required for construction in wetland.
Expires 4/11/03
- ------------------------------------------------------------------------------------------------------------------------------------
8. NPDES Permit MDE Issued 9/1/96; NPDES permit includes coal pile, ash ponds
Expires 8/31/01 and stormwater ponds. Application for
renewal must be made six months prior to
expiration.
- ------------------------------------------------------------------------------------------------------------------------------------
9. Oil Transfer License MDE Issued 6/15/99; Applies to pipeline or trucks. Required for
Expires 6/1/01 bringing more than 100 gal of oil into the
state.
- ------------------------------------------------------------------------------------------------------------------------------------
10. Oil Operations Permit MDE Issued 5/27/98;
Expires 5/27/03
- ------------------------------------------------------------------------------------------------------------------------------------
11. Groundwater Appropriation Maryland Department of Issued 8/1/90;
Natural Resources ("MDNR") Expires 8/1/02
- ------------------------------------------------------------------------------------------------------------------------------------
12. Surface Water MDE Issued 2/1/94; Required for withdrawal of water from river.
Appropriation Expires 2/1/06
- ------------------------------------------------------------------------------------------------------------------------------------
13. Stormwater Pollution MDE Prepared Describes how pollution of stormwater runoff
Prevention Plan will be avoided.
- ------------------------------------------------------------------------------------------------------------------------------------
14. NO\X\ Budget Rule Consent MDE Issued 9/13/99 Allows for rolling over of emissions
Order allowances from 2000 to 2001.
- ------------------------------------------------------------------------------------------------------------------------------------
15. Consent Order MDE Issued 7/9/92 Covers installation of CEMs and documentation
of compliance.
- ------------------------------------------------------------------------------------------------------------------------------------
16. Consent Agreement MDE Issued 6/21/72 Establishes opacity limit at 20% for Chalk
Point Unit 3.
- ------------------------------------------------------------------------------------------------------------------------------------
17. NO\X\ RACT Consent VADEQ Issued 7/10/98 Establishes NO\X\ emission limits under RACT
Agreement for NO\X\ non-attainment.
- ------------------------------------------------------------------------------------------------------------------------------------
18. Faulkner NPDES Permit MDE Issued 2/1/97; Includes requirements for treatment of runoff
Expires 1/31/02 and groundwater monitoring and protection.
Application for renewal must be made six
months prior to expiration.
- ------------------------------------------------------------------------------------------------------------------------------------
19. Faulkner Pollution MDE Prepared Required by NPDES permit.
Prevention Plan
====================================================================================================================================
A-35
Table 2
Status of Key Permits and Approvals Required for Operation
Dickerson Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
====================================================================================================================================
1. Hazardous Waste Generator USEPA/MDE Issued ID Nos. Large quantity generator of hazardous wastes.
ID Number MDD 000731596 Waste manifest system must be followed when
disposing hazardous waste.
- ------------------------------------------------------------------------------------------------------------------------------------
2. SPCC Plan USEPA/MDE Approved 10/21/98 Required if oil spills could reach navigable
waters. Approval of SPCC and Facility
Response Plan.
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
3. Phase II Acid Rain Permit MDE Issued 1/1/00; Permit for Phase II of the SO\2\ allowance
Expires 12/31/04 program under Clean Air Act Title IV.
- ------------------------------------------------------------------------------------------------------------------------------------
4. Title V Operating Permit MDE Submitted 12/2/96; Incorporates all emission sources. Permit
Deemed complete 1/21/97 pending. Operating under permit shield since
application deemed complete, which is typical
of other facilities.
- ------------------------------------------------------------------------------------------------------------------------------------
5. Opacity Consent Order MDE Issued 4/24/00; To bring units into compliance with opacity.
Expires 12/1/03 Outlines the requirements for testing and
potential conversion to wet ESPs. Compliance
deadline 7/1/03.
- ------------------------------------------------------------------------------------------------------------------------------------
6. NO\X\ Budget Rule Consent MDE Issued 9/13/99 Allows for rolling over of emissions from
Order year 2000 to 2001.
- ------------------------------------------------------------------------------------------------------------------------------------
7. NPDES Permit MDE Issued 8/1/96; Discharges of once-through cooling water,
Expires 7/31/01 runoff, sewage treatment effluent, backwash,
treatment plant effluent, metal cleaning
wastes. Discharge to Potomac River and
tributaries. Application for renewal must be
made six months prior to expiration.
- ------------------------------------------------------------------------------------------------------------------------------------
8. Groundwater Appropriation MDNR Issued 2/1/92; Withdrawal of potable well water.
Expires 2/1/04
- ------------------------------------------------------------------------------------------------------------------------------------
9. Surface Water MDNR Issued 1/1/91 Withdrawal of up to 550 million gallons per
Appropriation day.
- ------------------------------------------------------------------------------------------------------------------------------------
10. Oil Operations Permit MDE Issued 12/30/96; For oil and diesel fuel storage
Expires 12/30/01
- ------------------------------------------------------------------------------------------------------------------------------------
11. Oil Transfer License MDE Issued 6/10/98; Transfer of oil in tanker trucks or by
Expires 6/1/01 pipeline.
- ------------------------------------------------------------------------------------------------------------------------------------
12. Sewage Sludge MDE Issued 10/17/97; Transportation of sewage sludge.
Utilization Permit Expires 1/15/02
- ------------------------------------------------------------------------------------------------------------------------------------
13. Emergency Response Plan USEPA/MDE Prepared Requires coordination with local fire and
police departments.
- ------------------------------------------------------------------------------------------------------------------------------------
14. Westland NPDES Permit MDE Issued 7/1/95; Includes requirements for treatment of runoff
Expires 6/30/00 and groundwater monitoring and protection.
Renewal application submitted. It is typical for facilities to operate under
Operating under prior permit. expired permits provided timely renewal
application is made.
- ------------------------------------------------------------------------------------------------------------------------------------
15. Westland Pollution MDE Prepared Required by NPDES permit.
Prevention Plan
====================================================================================================================================
A-36
Table 3
Status of Key Permits and Approvals Required for Operation
Morgantown Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
====================================================================================================================================
1. Hazardous Waste Generator USEPA/MDE Issued ID No. Large quantity generator of hazardous
ID Number 050399 700 007 H wastes. Waste manifest system must be
followed when disposing hazardous waste.
- ------------------------------------------------------------------------------------------------------------------------------------
2. SPCC Plan USEPA/MDE Prepared Required for prevention of oil spills from
equipment and storage tanks
- ------------------------------------------------------------------------------------------------------------------------------------
3. Oil Spill Response Plan USEPA/ USCG/ MDE Prepared Required to have cleanup equipment in place
and plan for response to oil spill
- ------------------------------------------------------------------------------------------------------------------------------------
4. Emergency Response Plan USEPA/MDE/ Prepared Part of operating procedures for plant.
Local fire department
- ------------------------------------------------------------------------------------------------------------------------------------
5. Phase II Acid Rain Title USEPA/MDE Effective 1/1/00 Stack CEMs data used to demonstrate
IV Permit compliance with allowance allocations
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
6. Title V Operating Permit MDE Applied for 12/2/96; Incorporates all emission sources at plant.
Deemed complete 1/21/97 Operating under permit shield since
application deemed complete, which is
typical of other facilities.
- ------------------------------------------------------------------------------------------------------------------------------------
7. NPDES Permit MDE Application for renewal NPDES permit includes coal pile, ash ponds
submitted 8/6/99; draft permit and stormwater ponds. It is typical for
received from the MDE. Plant facilities to operate under expired permits
operating under previous permit provided timely renewal application is made.
- ------------------------------------------------------------------------------------------------------------------------------------
8. Oil Transfer License MDE Issued 6/1/00; Applies to pipeline or trucks. Required for
Expires 6/1/01 bringing more than 100 gallons of oil into
the state.
- ------------------------------------------------------------------------------------------------------------------------------------
9. Oil Operations Permit MDE Issued 4/9/99;
Expires 4/9/04
- ------------------------------------------------------------------------------------------------------------------------------------
10. Groundwater Appropriation MDE Issued 6/1/98, 7/1/97, 12/1/97;
Expires 9/1/07
- ------------------------------------------------------------------------------------------------------------------------------------
11. Surface Water MDE Issued 8/1/97; Required for withdrawal of water from river.
Appropriation Expires 12/1/09
- ------------------------------------------------------------------------------------------------------------------------------------
12. Tidal Wetlands License MDE Issued 8/14/96
- ------------------------------------------------------------------------------------------------------------------------------------
13. Conditional Approval for MDE Issued 3/4/85
Use of Waste Oil
- ------------------------------------------------------------------------------------------------------------------------------------
14. Stormwater Pollution MDE Prepared Describes how pollution of stormwater runoff
Prevention Plan will be avoided
- ------------------------------------------------------------------------------------------------------------------------------------
15. NO\X\ Budget Rule Consent MDE Issued 9/13/99 Allows for rolling over of emissions
Order allowances from 2000 to 2001.
- ------------------------------------------------------------------------------------------------------------------------------------
16. NO\X\ RACT Consent VADEQ Issued 7/10/98 Establishes NO\X\ emission limits under RACT
Agreement for NO\X\ non-attainment.
- ------------------------------------------------------------------------------------------------------------------------------------
17. Consent Order MDE Issued 7/9/92 Covers installation of CEMs and documentation
of compliance.
- ------------------------------------------------------------------------------------------------------------------------------------
18. Consent Order MDE Issued 6/10/96 Requires corrective action for groundwater
contamination at plant.
- ------------------------------------------------------------------------------------------------------------------------------------
19. Brandywine NPDES Permit MDE Issued 3/1/97; Includes requirements for treatment of runoff
Expires 2/28/02 and groundwater monitoring and protection.
Application for renewal must be made six
months prior to expiration.
- ------------------------------------------------------------------------------------------------------------------------------------
20. Brandywine Pollution MDE Prepared Required by NPDES permit.
Prevention Plan
====================================================================================================================================
A-37
Table 4
Status of Key Permits and Approvals Required for Operation
Potomac River Facility
====================================================================================================================================
Permit or Approval Responsible Agency Status Comments
- ------------------------------------------------------------------------------------------------------------------------------------
Federal
====================================================================================================================================
1. Hazardous Waste Generator USEPA/VADEQ Issued ID No. Large quantity generator of hazardous
ID Number VAD 000731588 wastes. Waste manifest system must be
followed when disposing hazardous waste.
- ------------------------------------------------------------------------------------------------------------------------------------
2. SPCC Plan and Emergency USEPA/VADEQ Approval received 6/14/96 Required if oil spills could reach navigable
Response Plan waters. Approval of SPCC and Facility
Response Plan.
- ------------------------------------------------------------------------------------------------------------------------------------
3. NPDES Permit USEPA Issued 4/20/00; Discharges of cooling water, ash clarifier,
Expires 4/20/05 neutralization wastewater, and misc. drains
to the Potomac River. Application for
renewal must be made six months prior to
expiration.
- ------------------------------------------------------------------------------------------------------------------------------------
4. Storm Water Multi-Sector USEPA Issued 1/16/98; For discharges of storm water associated
General Permit Expires 10/1/00 with industrial activities.
Renewal application submitted.
Operating under prior permit.
- ------------------------------------------------------------------------------------------------------------------------------------
State
- ------------------------------------------------------------------------------------------------------------------------------------
5. Phase II Acid Rain Permit VADEQ Issued 1/1/98; Permit for Phase II of the SO\2\ allowance
Expires 12/31/02 program under Clean Air Act Title IV.
- ------------------------------------------------------------------------------------------------------------------------------------
6. Title V Operating Permit VADEQ Deemed Complete 3/4/98 Incorporates all emission sources. Permit
pending. Operating under permit shield
since application deemed complete, which
is typical of other facilities.
- ------------------------------------------------------------------------------------------------------------------------------------
7. NO\X\ RACT Consent Agreement VADEQ Issued 7/10/98 Establishes reasonably available control
technology standards for the Potomac River
Facility.
- ------------------------------------------------------------------------------------------------------------------------------------
8. VOC RACT Permit VADEQ Issued 5/8/00 Required control of VOCs by optimizing
combustion through a digital control system.
====================================================================================================================================
OPERATION AND MAINTENANCE
Operation of the Generating Facilities
- --------------------------------------
SE Mid-Atlantic will operate the Generating Facilities. SE PJM
Management, an indirect wholly-owned subsidiary of Southern Energy, will hire
Pepco personnel in connection with the acquisition of the Generating Facilities
and will provide all operations, maintenance and general management personnel to
SE Mid-Atlantic. SERI, a direct wholly-owned subsidiary of Southern Energy,
will provide executive personnel and administrative services to SE Mid-Atlantic.
SE Mid-Atlantic will not have any employees of its own. As part of the purchase
of the Generating Facilities, SE PJM Management will be assigned the labor
contracts for the non-exempt personnel at the Generating Facilities. SE PJM
Management expects to retain the services of most of the existing exempt
personnel, and to fill out the remainder of the required staff via internal and
external recruiting methods. SE PJM Management intends to initially adopt
Pepco's current operating practices and procedures, including its Generation
Engineering and Maintenance Services ("GEMS") department, and then to
coordinate, combine, and improve them over time to maximize the production
capabilities of the Generating Facilities while minimizing their operating and
maintenance costs.
A-38
Operating Programs and Procedures
- ---------------------------------
The Chalk Point Facility
We have reviewed the general application of the various Pepco
operations and maintenance ("O&M") programs and procedures within the Chalk
Point Facility, including: preventive, corrective and predictive maintenance
plans; operating procedures; and maintenance procedures. We did not review all
aspects of these plans and procedures, but verified that all of the usual and
necessary plans, procedures and documentation normally required to operate a
facility of this type were in place. SE Mid-Atlantic has advised that it will
be accepting all of the Pepco O&M programs and procedures in kind. Following is
a brief description of the key programs and procedures in place at the Chalk
Point Facility.
The computerized maintenance management system utilized by Pepco is
the Power Plant Maintenance Information System ("PPMIS") which was developed in
the 1980s. This system provides the generating facilities with the ability to
initiate and track corrective and preventive maintenance job orders, plan and
schedule routine maintenance activities, maintain equipment maintenance and
spare parts usage histories, and manage available labor resources. SE Mid-
Atlantic intends on replacing the PPMIS system with a newer and more functional
system such as the MAXIMO maintenance management system which is used at
generating stations owned by its affiliated companies. In addition to the PPMIS
system, major outages are scheduled by plant and GEMS personnel utilizing a
Primavera scheduling program.
The predictive maintenance program includes the capability for either
facility or GEMS personnel to perform common predictive maintenance functions
such as vibration analysis and trending, infrared thermography to sense hot
spots in electrical and other equipment, and lube oil sample analysis. The
Chalk Point Facility is also using a streamlined Reliability Centered
Maintenance program in which key pieces of equipment will be analyzed and
specific maintenance plans developed for the most efficient maintenance of the
equipment.
The Chalk Point Facility maintains an appropriate collection of
operating, maintenance and administrative procedures which have been developed
in coordination with the PSC's Generation Training and Procedures Department.
These procedures include normal operating and maintenance procedures, as well as
emergency response procedures for operating events or the exceedance of
environmental limits.
Working with the GEMS staff, several reliability and performance
improvement programs have been established at the Chalk Point Facility.
Principle among these programs are a reliability improvement program to
determine the root cause of equipment failures, a boiler tube failure reduction
program, a boiler waterwall tubing survey and inspection program, a high energy
piping inspection program, and a pulverizer maintenance and performance program.
The plant staffing is projected to consist of approximately 205 on-
site personnel. Since 1998, the Chalk Point Facility has utilized a multi-
skilled craft concept for most operating and maintenance positions. With this
concept, each plant technician has both a primary skill and a secondary skill,
with levels of proficiency within each skill. The Chalk Point Facility has five
operating teams that work on 12-hour shifts, and a separate CT team. As part of
the multi-skilled technician program, approximately 30 percent of the time spent
on shift is dedicated to maintenance. Maintenance disciplines are divided
between mechanical and electrical/instruments/controls.
Major maintenance is scheduled on a three-year cycle for the steam
generators and an 8- to 10-year cycle for the steam turbines. Overhaul
durations are typically 8 to 10 weeks, depending upon the scope of work to be
performed. In years when there is no major maintenance scheduled for a unit, a
two-week "mini-outage" is performed on the steam generator and auxiliaries. The
CTs are maintained on the basis of factored starts as recommended by the
manufacturer.
The Dickerson Facility
We have reviewed general application of the various Pepco operations
and maintenance programs and procedures within the Dickerson Facility, including
preventive, corrective and predictive maintenance plans;
A-39
operating procedures; and maintenance procedures. We did not review all aspects
of these plans and procedures, but verified that all of the usual and necessary
plans, procedures and documentation normally required to operate a facility of
this type were in place. SE Mid-Atlantic has advised that it will be adopting
all of the Pepco O&M programs and procedures in kind. Following is a brief
description of the key programs and procedures in place at the Dickerson
Facility.
The computerized maintenance management system utilized by Pepco is
the PPMIS which was developed in the 1980s. This system provides the generating
facilities with the ability to initiate and track corrective and preventive
maintenance job orders, plan and schedule routine maintenance activities,
maintain equipment maintenance and spare parts usage histories, and manage
available labor resources. SE Mid-Atlantic intends on replacing the PPMIS
system with a newer and more functional system such as the MAXIMO maintenance
management system which is used at generating stations owned by its affiliated
companies. In addition to the PPMIS system, major outages are scheduled by
plant and GEMS personnel utilizing a Primavera scheduling program.
The predictive maintenance program includes the capability for either
facility or GEMS personnel to perform common predictive maintenance functions
such as vibration analysis and trending, infrared thermography to sense hot
spots in electrical and other equipment, and lube oil sample analysis. The
Dickerson Facility is also using a streamlined Reliability Centered Maintenance
program in which key pieces of equipment will be analyzed and specific
maintenance plans developed for the most efficient maintenance of the equipment.
The Dickerson Facility maintains an appropriate collection of
operating, maintenance and administrative procedures which have been developed
in coordination with the PSC's Generation Training and Procedures Department.
These procedures include normal operating and maintenance procedures, as well as
emergency response procedures for operating events or the exceedance of
environmental limits.
Working with the GEMS staff, several reliability and performance
improvement programs have been established at the Dickerson Facility. Principle
among these programs are a reliability improvement program to determine the root
cause of equipment failures, a boiler tube failure reduction program, a boiler
waterwall tubing survey and inspection program, a high energy piping inspection
program, and a pulverizer maintenance and performance program.
The plant staff is projected to consist of approximately 156 on-site
personnel. Since 1998, the Dickerson Facility has utilized a multi-skilled
craft concept for most operating and maintenance positions. With this concept,
each plant technician has both a primary skill and a secondary skill, with
levels of proficiency within each skill. The Dickerson Facility has four
operating teams that work on 12-hour shifts and a separate CT team. As part of
the multi-skilled technician program, approximately 30 percent of the time spent
on shift is dedicated to maintenance. Maintenance disciplines are divided
between mechanical and electrical/instruments/controls.
Major maintenance is scheduled on a three-year cycle for the steam
generators and an 8- to 10-year cycle for the steam turbines, with consideration
being given to extending the low pressure turbines to 12-year cycles. Overhaul
durations are typically 8 to 10 weeks, depending upon the scope of work to be
performed. In years when there is no major maintenance scheduled for a unit, a
two-week "mini-outage" is performed on the steam generator and auxiliaries. The
CTs are maintained on the basis of factored starts as recommended by the
manufacturer.
The Morgantown Facility
We have reviewed general application of the various Pepco operations
and maintenance programs and procedures within the Morgantown Facility,
including preventive, corrective and predictive maintenance plans; operating
procedures; and maintenance procedures. We did not review all aspects of these
plans and procedures, but verified that all of the usual and necessary plans,
procedures and documentation normally required to operate a facility of this
type were in place. SE Mid-Atlantic has advised that it will be adopting all of
the Pepco O&M programs and procedures in kind. Following is a brief description
of the key programs and procedures in place at the Morgantown Facility.
A-40
The computerized maintenance management system utilized by Pepco is
the PPMIS which was developed in the 1980s. This system provides the generating
facilities with the ability to initiate and track corrective and preventive
maintenance job orders, plan and schedule routine maintenance activities,
maintain equipment maintenance and spare parts usage histories, and manage
available labor resources. SE Mid-Atlantic intends on replacing the PPMIS
system with a newer and more functional system such as the MAXIMO maintenance
management system which is used at generating stations owned by its affiliated
companies. In addition to the PPMIS system, major outages are scheduled by
plant and GEMS personnel utilizing a Primavera scheduling program.
The predictive maintenance program includes the capability for either
facility or GEMS personnel to perform common predictive maintenance functions
such as vibration analysis and trending, infrared thermography to sense hot
spots in electrical and other equipment, and lube oil sample analysis. The
Morgantown Facility is also using a streamlined Reliability Centered Maintenance
program in which key pieces of equipment will be analyzed and specific
maintenance plans developed for the most efficient maintenance of the equipment.
The Morgantown Facility maintains an appropriate collection of
operating, maintenance and administrative procedures which have been developed
in coordination with the PSC's Generation Training and Procedures Department.
These procedures include normal operating and maintenance procedures, as well as
emergency response procedures for operating events or the exceedance of
environmental limits.
Working with the GEMS staff, several reliability and performance
improvement programs have been established at the Morgantown Facility.
Principle among these programs are a reliability improvement program to
determine the root cause of equipment failures, a boiler tube failure reduction
program, a boiler waterwall tubing survey and inspection program, a high energy
piping inspection program, and a pulverizer maintenance and performance program.
The plant staff is projected to consist of approximately 152 on-site
personnel. Since 1998, the Morgantown Facility has utilized a multi-skilled
craft concept for most operating and maintenance positions. With this concept,
each plant technician has both a primary skill and a secondary skill, with
levels of proficiency within each skill. The Morgantown Facility has five
operating teams that work on 12-hour shifts. As part of the multi-skilled
technician program, approximately 30 percent of the time spent on shift is
dedicated to maintenance. Maintenance disciplines are divided between
mechanical and electrical/instruments/controls.
Major maintenance is scheduled on a three-year cycle for the steam
generators and an 8- to 10-year cycle for the steam turbines, with consideration
being given to extending the low pressure turbines to 12-year cycles. Overhaul
durations are typically 8 to 10 weeks, depending upon the scope of work to be
performed. In years when there is no major maintenance scheduled for a unit, a
two-week "mini-outage" is performed on the steam generator and auxiliaries. The
CTs are maintained on the basis of factored starts as recommended by the
manufacturer.
The Potomac River Facility
We have reviewed general application of the various Pepco operations
and maintenance programs and procedures within the Potomac River Facility,
including preventive, corrective and predictive maintenance plans; operating
procedures; and maintenance procedures. We did not review all aspects of these
plans and procedures, but verified that all of the usual and necessary plans,
procedures and documentation normally required to operate a facility of this
type were in place. SE Mid-Atlantic has advised that it will be adopting all of
the Pepco O&M programs and procedures in kind. Following is a brief description
of the key programs and procedures in place at the Potomac River Facility.
The computerized maintenance management system utilized by Pepco is
the PPMIS which was developed in the 1980s. This system provides the generating
facilities with the ability to initiate and track corrective and preventive
maintenance job orders, plan and schedule routine maintenance activities,
maintain equipment maintenance and spare parts usage histories, and manage
available labor resources. SE Mid-Atlantic intends on replacing the PPMIS
system with a newer and more functional system such as the MAXIMO maintenance
management system which is used at generating stations owned by its affiliated
companies. In addition to the PPMIS system, major outages are scheduled by
plant and GEMS personnel utilizing a Primavera scheduling program.
A-41
The predictive maintenance program includes the capability for either
facility or GEMS personnel to perform common predictive maintenance functions
such as vibration analysis and trending, infrared thermography to sense hot
spots in electrical and other equipment, and lube oil sample analysis. The
Potomac River Facility is also using a streamlined Reliability Centered
Maintenance program in which key pieces of equipment will be analyzed and
specific maintenance plans developed for the most efficient maintenance of the
equipment.
The Potomac River Facility maintains an appropriate collection of
operating, maintenance and administrative procedures which have been developed
in coordination with the PSC's Generation Training and Procedures Department.
These procedures include normal operating and maintenance procedures, as well as
emergency response procedures for operating events or the exceedance of
environmental limits.
Working with the GEMS staff, several reliability and performance
improvement programs have been established at the Potomac River Facility.
Principle among these programs are a reliability improvement program to
determine the root cause of equipment failures, a boiler tube failure reduction
program, a boiler waterwall tubing survey and inspection program, a high energy
piping inspection program, and a pulverizer maintenance and performance program.
The plant staff is projected to consist of approximately 150 on-site
personnel. Since 1998, the Potomac River Facility has utilized a multi-skilled
craft concept for most operating and maintenance positions. With this concept,
each plant technician has both a primary skill and a secondary skill, with
levels of proficiency within each skill. The Potomac River Facility has four
operating teams that work on 12-hour shifts. As part of the multi-skilled
technician program, approximately 30 percent of the time spent on shift is
dedicated to maintenance. Maintenance disciplines are divided between
mechanical and electrical/instruments/controls.
Major maintenance is scheduled on a three-year cycle for the steam
generators and an 8- to 10-year cycle for the steam turbines, with consideration
being given to extending the low pressure turbines to 12-year cycles. Overhaul
durations are typically 8 to 10 weeks, depending upon the scope of work to be
performed. In years when there is no major maintenance scheduled for a unit, a
two-week "mini-outage" is performed on the steam generator and auxiliaries. The
CTs are maintained on the basis of factored starts as recommended by the
manufacturer.
The Production Service Center
One of the Pepco assets being acquired by SE Mid-Atlantic is the PSC.
In addition to the capabilities contained in the PSC facility such as the
machine shop, training areas and offices, the staff of the PSC provides numerous
services to the generating facilities. As the headquarters of Pepco's
generating unit, the PSC staff has developed programs and procedures that have
been implemented at all the generating facilities. Thus while each generating
facility is unique, they all share many similar practices. Following is a brief
description of the services provided by the PSC and how they are integrated into
the operations of the generating facilities.
Two of the general areas of services provided by the PSC are (i)
Training and Procedures and (ii) GEMS. The Generation Training and Procedure
Department utilizes its own in-house capabilities and staff to provide
qualification training in operations and maintenance, as well as safety,
environmental and other compliance training. Generation facility technicians
are provided with a full range of training and must pass qualification tests
before progressing to the next level. Currently, a program is in place wherein
approximately 600 of 700 bargaining unit plant technicians have been trained and
qualified for both a primary and a secondary job skill, of which one skill must
be in operations. Augmenting the classroom training are a number of specialty
training shops at the PSC, and the boiler control simulators at the PSC and at
the Dickerson Facility. Organizational training such as supervisory development
and equal employment opportunity training has not been conducted by the
Generation Training and Procedures Department in the past since a corporate
Pepco department conducted such training. However, it is anticipated that SE
Mid-Atlantic will provide this type of training through the PSC in the future.
The Generation Training and Procedures Department is also responsible
for coordinating the development and maintenance of operating, maintenance and
administrative procedures for SE Mid-Atlantic. Pepco has had a comprehensive
procedures program that is administered by the PSC. Virtually all maintenance,
operations and administrative functions have had procedures written for them
which are currently being entered into a computer
A-42
database. Other than certain facility specific operating procedures, all
procedures must be approved by the PSC. Administrative procedures have generally
been based on overall Pepco corporate procedures, utilizing only the applicable
sections of the corporate procedures. Approximately 75 percent of all procedures
are written by the "process owners" who are responsible for the work to be
performed.
The GEMS organization provides engineering, technical, and project
management services and skilled craftspeople to the generating facilities, and
is responsible for the central maintenance shop located in the PSC facility.
The GEMS staff of approximately 162 people is divided into a Major Machinery
Engineering Division, an Outage Management Services Division, a Performance and
Technical Services Division, a Production Services Division and a Clean Air Act
Projects group. As part of the "matrix" approach employed by Pepco, several of
the GEMS staff are assigned to specific generating facilities while
administratively remaining on the GEMS staff. GEMS provides the generating
facilities with centralized discipline engineering, centralized maintenance
planning, outage, project and contractor management, engineering oversight,
materials analysis, non-destructive examination services, quality control and
assurance, equipment condition monitoring, chemistry process consultation and
annual water chemistry reviews at each generating facility as required by state
law, field mechanical repair services, shop and field component machining,
repairing, balancing and fabrication, and motor repairs. In addition to the
services provided by the GEMS staff, various contractors and engineering
consultants are utilized as required to supplement the GEMS staff, particularly
during periods of heavy workload such as during major projects and heavy
maintenance overhauls. Approximately 20 percent of the craft labor hours
expended for major maintenance and projects in the generating facilities is
supplied by the GEMS Central Maintenance and the facilities' workforces, with
the remainder supplied by contractors.
Among the programs established by GEMS and implemented at the
generating facilities are predictive maintenance techniques such as vibration
analysis, oil sample analysis and infrared testing, a high energy piping
inspection and repair program, a furnace waterwall tube mapping program for
determining the wastage rates of waterwall tubing, a boiler tube failure
prevention program, a root cause analysis program for determining the causes of
equipment problems and developing potential solutions, a reliability improvement
program and performance monitoring and improvement programs. The day-to-day
responsibilities for maintaining these programs are generally shared between
GEMS and generation facility personnel, with the GEMS staff providing overall
program development and coordination, and the generation facility personnel
implementing the programs within their respective facilities. While we did not
review all of these programs and procedures, our discussions at the generating
facilities indicated that the operators of the facilities were familiar with the
programs and were actively involved in implementing them in a consistent manner
across all the facilities.
Summary
- -------
Based on our review, we are of the opinion that, by combining the
demonstrated experience of the existing Pepco personnel and programs and the
experience of the Southern Energy operating subsidiaries, SE Mid-Atlantic should
have sufficient capability to operate the Generating Facilities effectively.
The operating programs and procedures which are currently in place are
consistent with generally accepted practices in the industry, and the Generating
Facilities have incorporated organizational structures that are comparable to
other facilities using similar technologies.
OPERATING HISTORY
Performance
- -----------
For each of the Generating Facilities, we have prepared operating
summaries which include reported equivalent availability factor and net capacity
factor.
Equivalent availability factor is defined by the North American
Electric Reliability Council ("NERC") as the number of hours during a period in
which the unit is available to operate, less the sum of (1) the equivalent
planned and unplanned derated hours during the period and (2) the equivalent
seasonal derated hours during the period, all divided by the number of hours in
the period. The equivalent availability factor is an index of the maximum
production (MWh) that the facility was capable of producing during the period.
A-43
Net capacity factor is defined by NERC as the net electrical
generation produced during a period divided by the product of the unit's net
rated capacity and the number of hours in the period. The net capacity factor
is an index of the actual production (MWh) attained by the facility during the
period.
The Chalk Point Facility
Operating summaries for the past six years of operation of the Chalk
Point Facility are shown in Table 5 and are based on data provided by Pepco.
Based on the operating history, a review of the operations and maintenance
practices and procedures, and general observations of the plants, we are of the
opinion that the Chalk Point Facility should be capable of achieving the
projected annual average net capacities, annual availability factors, and net
heat rates assumed in the Projected Operating Results. The historical and
projected values are summarized in Table 5.
Table 5
Operating History
Chalk Point Facility
Unit 1 Unit 2 Unit 3 Unit 4 CT 1 CT 2 CTs 3-4(2) CTs 5-6(2) SMECO
------ ------ ------ ------ ---- ---- ---------- ---------- -----
Net Capability Rating (MW) (1)
1994 341 342 612 612 18 30 170 214 84
1995 341 342 612 612 18 30 170 214 84
1996 341 342 612 612 18 30 170 214 84
1997 341 342 612 612 18 30 170 214 84
1998 341 342 612 612 18 30 170 214 84
1999 341 342 612 612 18 30 170 214 84
Projected 341 342 612 612 18 30 170 214 84
Net Generation (GWh)
1994 1,793 1,570 1,545 1,100 1 2 59 131 35
1995 1,789 2,144 455 790 1 1 85 156 49
1996 1,945 1,618 461 412 1 1 51 76 20
1997 1,642 1,992 536 413 2 1 76 115 38
1998 2,128 1,969 1,289 654 3 3 96 117 55
1999 2,360 2,291 1,444 1,319 2 0 72 128 42
Annual Net Heat Rate (Btu/kWh)
1994 9,687 9,621 11,832 12,341 18,466 19,057 13,626 12,503 13,449
1995 9,775 9,705 13,484 12,799 17,367 28,905 13,801 12,190 13,036
1996 9,755 9,656 13,127 13,262 12,580 24,995 14,279 12,397 14,222
1997 9,897 9,855 12,811 13,198 12,831 32,364 14,054 12,528 14,309
1998 9,629 9,805 12,060 12,016 13,119 16,427 13,351 11,946 12,967
1999 9,481 9,451 11,215 11,811 12,609 28,655 13,988 12,951 13,411
Projected (3) 9,460 9,466 10,553 10,641 12,289 13,291 13,185 11,684 12,484
Net Capacity Factor (%)
1994 60.0 52.3 28.8 20.5 0.6 0.5 3.8 6.7 4.6
1995 59.9 71.5 8.5 14.7 0.7 0.2 5.5 8.0 6.4
1996 64.9 53.8 8.6 7.7 0.3 0.2 3.2 3.9 2.6
1997 55.0 66.4 10.0 7.7 1.1 0.2 4.9 5.9 5.0
1998 71.2 65.7 24.1 12.2 1.8 1.2 6.2 6.1 7.2
1999 79.0 76.4 26.9 24.6 1.2 0.1 4.4 6.5 5.3
Equivalent Availability Factor (%)
1994 76.3 65.7 78.4 70.9 99.5 63.1 90.0 90.3 87.0
1995 74.7 89.3 66.8 86.0 98.7 94.1 82.4 80.0 95.0
1996 90.5 71.3 89.8 91.0 96.0 83.2 99.1 88.6 83.7
1997 75.3 84.1 96.2 93.1 81.0 86.5 97.3 92.5 92.3
1998 85.7 79.8 91.9 64.8 91.0 79.0 97.5 88.4 98.6
1999 86.7 83.8 81.0 93.9 98.0 51.4 74.9 98.5 73.8
Projected 88.0 86.0 90.0 88.0 88.0 88.0 91.0 87.0 92.0
Coal Use (Tons x 1000)
1994 674 576
1995 638 766
1996 716 586
1997 600 724
1998 775 732
1999 847 817 9 8
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Table 5
Operating History
Chalk Point Facility
Unit 1 Unit 2 Unit 3 Unit 4 CT 1 CT 2 CTs 3-4(2) CTs 5-6(2) SMECO
------ ------ ------ ------ ---- ---- ---------- ---------- -----
Oil Use (Gallons x 1000)(4)
1994 98,739 57,681 116 205 1,269 3,869 1,219
1995 18,972 21,274 129 130 829 2,202 590
1996 26,831 20,324 42 96 1,547 2,747 520
1997 32,431 18,989 156 147 850 1,653 588
1998 93,786 47,884 266 390 331 163 253
1999 666 710 93,913 71,789 171 55 328 90 196
Gas Use (Mcf x 1000)
1994 2,608 4,010 596 1,050 294
1995 2,932 6,067 1,020 1,530 531
1996 1,489 1,857 489 543 202
1997 1,468 2,138 907 1,155 443
1998 780 382 1,185 1,319 644
1999 27 65 1,803 4,379 929 1,557 512
____________________
(1) Summer ratings for CTs.
(2) Represents arithmetic mean for full load and annual net heat rate, and net capacity and equivalent availability factor.
(3) Represents annual average for 2001 based on levels of full- and part-load operation as projected by Hagler Bailly. Projected
decreases in annual average heat rates compared to historical heat rates result for some units due to an increase in full-load
operation projected by Hagler Bailly.
(4) No. 2 oil is used by CTs 1 through 6 and the SMECO Unit. No. 6 oil is used by Chalk Point Units 3 and 4.
The Dickerson Facility
Operating summaries for the past six years of operation of the
Dickerson Facility units are shown in Table 6 and are based on data provided by
Pepco. Based on the operating history, a review of the operations and
maintenance practices and procedures, and general observations of the plants, we
are of the opinion that the Dickerson Facility should be capable of achieving
the projected annual average net capacities, annual availability factors, and
net heat rates assumed in the Projected Operating Results. The historical and
projected values are summarized in Table 6.
Table 6
Operating History
Dickerson Facility
Unit 1 Unit 2 Unit 3 CT D1 CT H1 CT H2
------ ------ ------ ----- ----- -----
Net Capability Rating (MW) (1)
1994 182 182 182 13 139 139
1995 182 182 182 13 139 139
1996 182 182 182 13 139 139
1997 182 182 182 13 139 139
1998 182 182 182 13 139 139
1999 182 182 182 13 139 139
Projected 182 182 182 13 139 139
Net Generation (GWh)
1994 918 1,051 1,149 0 104 89
1995 1,185 1,036 1,243 1 143 170
1996 1,130 1,163 954 0 49 65
1997 965 1,151 1,185 0 69 63
1998 1,233 1,187 1,313 1 16 86
1999 1,250 1,081 1,055 1 73 89
A-45
Table 6
Operating History
Dickerson Facility
Unit 1 Unit 2 Unit 3 CT D1 CT H1 CT H2
------ ------ ------ ----- ----- -----
Annual Net Heat Rate (Btu/kWh)
1994 9,789 9,491 9,329 22,526 12,110 11,935
1995 9,660 9,558 9,376 19,132 11,957 11,987
1996 9,584 9,449 9,428 18,603 12,557 12,526
1997 9,661 9,574 9,411 17,900 12,475 13,703
1998 9,580 9,526 9,395 15,870 12,210 12,381
1999 9,701 9,728 9,584 19,735 13,521 13,378
Projected (2) 9,686 9,632 9,558 13,455 11,466 11,466
Net Capacity Factor (%)
1994 57.6 65.9 72.1 0.3 8.0 6.8
1995 74.3 65.0 77.9 0.5 11.0 13.1
1996 70.7 72.7 59.7 0.6 3.8 4.9
1997 60.6 72.2 74.3 0.6 5.3 4.9
1998 77.3 74.4 82.4 1.0 1.2 6.6
1999 78.4 67.8 66.2 1.2 5.7 6.9
Equivalent Availability Factor (%)
1994 72.6 81.2 88.2 97.1 86.7 76.4
1995 89.9 80.6 93.7 99.4 98.1 96.6
1996 91.3 91.3 74.6 98.6 59.0 95.4
1997 77.6 91.5 91.2 93.5 61.3 61.9
1998 89.8 87.3 95.8 94.7 7.3 79.2
1999 86.1 73.7 75.2 86.1 52.2 96.8
Projected 90.0 90.0 90.0 93.0 89.0 89.0
Coal Use (Tons x 1000)
1994 349 390 419
1995 437 380 447
1996 417 424 346
1997 257 422 427
1998 452 431 473
1999 456 396 379
Oil Use (Gallons x 1000)
1994 65 1,540 2,230
1995 87 1,412 1,549
1996 86 1,709 1,417
1997 96 892 852
1998 127 4 464
1999 192 239 334 185 84 300
Gas Use (Mcf x 1000)
1994 1,013 730
1995 1,470 1,767
1996 365 590
1997 708 726
1998 184 943
1999 949 1,117
___________
(1) Summer ratings for CTs.
(2) Represents annual average for 2001 based on levels of full- and part-load operation as projected by Hagler Bailly. Projected
decreases in annual average heat rates compared to historical heat rates result for some units due to an increase in full-load
operation projected by Hagler Bailly.
The Morgantown Facility
Operating summaries for the past six years of operation of the
Morgantown Facility are shown in Table 7 and are based on data provided by
Pepco. Based on the operating history, a review of the operations and
maintenance practices and procedures, and general observations of the plants, we
are of the opinion that the
A-46
Morgantown Facility should be capable of achieving the projected annual average
net capacities, annual availability factors, and net heat rates assumed in the
Projected Operating Results. The historical and projected values are summarized
in Table 7.
Table 7
Operating History
Morgantown Facility
Unit 1 Unit 2 CTs 1-2 CTs 3-6
------ ------ ------- -------
Net Capability Rating (MW) (1)
1994 582 582 32 216
1995 582 582 32 216
1996 582 582 32 216
1997 582 582 32 216
1998 582 582 32 216
1999 582 582 32 216
Projected 582 582 32 216
Net Generation (GWh)
1994 3,711 2,540 6 71
1995 2,818 3,820 3 41
1996 3,614 3,545 1 55
1997 3,640 3,244 3 55
1998 3,365 4,422 8 59
1999 4,019 3,367 4 45
Annual Net Heat Rate (Btu/kWh)
1994 9,431 9,268 16,719 13,721
1995 9,635 9,346 18,172 15,884
1996 9,635 9,404 23,622 20,919
1997 9,610 9,239 19,824 21,627
1998 9,180 9,270 16,490 13,442
1999 8,945 8,973 17,955 14,533
Projected (2) 8,892 9,241 14,800 12,935
Net Capacity Factor (%)
1994 72.8 49.8 1.8 3.5
1995 55.2 74.9 0.9 2.0
1996 70.7 69.3 0.5 2.7
1997 71.4 63.6 0.8 2.7
1998 66.0 86.7 2.5 2.9
1999 78.8 66.0 1.4 2.1
Equivalent Availability Factor (%)
1994 90.4 63.7 90.5 91.4
1995 66.4 88.9 91.5 83.1
1996 95.8 92.0 83.3 95.5
1997 87.8 77.4 92.2 91.0
1998 74.5 96.3 99.9 93.7
1999 82.5 69.7 99.3 77.9
Projected 87.0 87.0 91.0 89.0
Coal Use (Tons x 1000)
1994 1,234 843
1995 992 1,323
1996 1,325 1,266
1997 1,339 1,151
1998 1,173 1,559
1999 1,359 1,137
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Table 7
Operating History
Morgantown Facility
Unit 1 Unit 2 CTs 1-2 CTs 3-6
------ ------ ------- -------
Oil Use (Gallons x 1000)
1994 669 7,023
1995 378 4,654
1996 246 8,316
1997 366 8,582
1998 896 5,675
1999 1,468 2,239 576 4,688
____________________
(1) Summer ratings for CTs.
(2) Represents annual average for 2001 based on levels of full- and part-load operation as projected by Hagler Bailly. Projected
decreases in annual average heat rates compared to historical heat rates result for some units due to an increase in full-load
operation projected by Hagler Bailly.
The Potomac River Facility
Operating summaries for the past six years of operation of the Potomac
River Facility units are shown in Table 8 and are based on data provided by
Pepco. Based on the operating history, a review of the operations and
maintenance practices and procedures, and general observations of the plants, we
are of the opinion that the Potomac River Facility should be capable of
achieving the projected annual average net capacities, annual availability
factors, and net heat rates assumed in the Projected Operating Results. The
historical and projected values are summarized in Table 8.
Table 8
Operating History
Potomac River Facility
Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
------ ------ ------ ------ ------
Net Capability Rating (MW)
1994 88 88 102 102 102
1995 88 88 102 102 102
1996 88 88 102 102 102
1997 88 88 102 102 102
1998 88 88 102 102 102
1999 88 88 102 102 102
Projected 88 88 102 102 102
Net Generation (GWh)
1994 227 181 563 569 569
1995 154 179 547 530 562
1996 132 183 371 488 492
1997 206 228 525 566 345
1998 267 235 592 482 620
1999 301 373 692 689 649
Annual Net Heat Rate (Btu/kWh)
1994 13,220 13,068 9,997 9,932 10,006
1995 13,424 13,159 10,318 10,175 10,229
1996 14,320 13,596 10,384 10,299 10,536
1997 13,829 13,144 10,508 10,328 10,518
1998 13,543 12,763 10,398 10,286 10,290
1999 13,297 12,791 10,111 10,119 10,241
Projected (1) 12,893 12,503 10,130 10,229 10,195
A-48
Table 8
Operating History
Potomac River Facility
Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
------ ------ ------ ------ ------
Net Capacity Factor (%)
1994 29.4 23.4 63.1 63.7 63.7
1995 20.0 23.2 61.2 59.3 62.9
1996 17.1 23.7 41.4 54.5 54.9
1997 26.7 29.6 58.7 63.4 38.6
1998 34.0 30.5 66.3 54.0 69.3
1999 39.1 48.4 77.5 77.1 72.6
Equivalent Availability Factor (%)
1994 94.3 80.8 94.2 94.3 95.3
1995 95.8 97.8 97.1 88.4 97.0
1996 87.9 89.3 72.7 93.1 96.6
1997 93.9 90.9 94.6 95.9 62.2
1998 96.7 80.7 93.0 76.2 97.2
1999 80.2 89.2 96.5 94.7 91.2
Projected 91.0 90.0 90.0 89.0 90.0
Coal Use (Tons x 1000)
1994 113 89 219 220 223
1995 77 88 216 206 221
1996 71 94 150 195 202
1997 108 114 214 227 141
1998 135 114 242 194 250
1999 150 180 267 265 252
____________________
(1) Represents annual average for 2001 based on levels of full- and part-load
operation as projected by Hagler Bailly. Projected decreases in annual
average heat rates compared to historical heat rates result for some units
due to an increase in full-load operation projected by Hagler Bailly.
Summary
A summary of the 1999 operating data as provided by Pepco is shown by
dispatch type in Table 9.
Table 9
1999 Operating Data (1)
Baseload (2) Cycling (3) Peaking (4)
---------------------- ---------------------- ----------------------
Net Capability Rating (MW) 2,699 1,400 1,055
Net Generation (GWh) 17,453 3,438 457
Annual Net Heat Rate (Btu/kWh) 8,945-10,241 11,215-13,297 12,600-28,665
Net Capacity Factor (%)(5) 74 28 5
Equivalent Availability Factor (%)(6) 81 87 83
____________________
(1) As reported by Pepco.
(2) Includes Chalk Point Units 1 and 2, Dickerson Units 1, 2 and 3, Morgantown Units 1 and 2, and Potomac
River Units 3, 4 and 5.
(3) Includes Chalk Point Units 3 and 4 and Potomac River Units 1 and 2.
(4) Includes Chalk Point CTs 1 through 6, the SMECO Unit, Dickerson CTs D1, H1 and H2, and Morgantown CTs 1
through 6.
(5) Represents weighted average calculated using summer ratings for CTs.
(6) Represents weighted average by net generation.
A-49
Regulatory Compliance
- ---------------------
The Generating Facilities are currently subject to various state and
federal regulations with respect to NO\X\ emissions including Reasonably
Available Control Technology ("RACT") requirements, Title IV of the Clean Air
Act limits, and Title I Ozone Transport Commission requirements.
The location of the Generating Facilities in designated ozone non-
attainment areas triggered RACT requirements. A NO\X\ averaging plan is used to
comply with the requirements. This entails over-controlling at certain units to
cover the other generating unit requirements. A consent agreement with the VADEQ
dated July 10, 1998 (the "VADEQ RACT Consent Agreement") requires that the RACT
averaging plan does not result in any greater emissions during the ozone season
(May through September) than would have occurred with unit-by-unit RACT
controls.
The Clean Air Act Title IV imposes additional NO\X\ requirements.
Chalk Point Units 1 and 2 and Morgantown Units 1 and 2 are Phase I affected
units and are required to meet boiler specific annual emission limits. SE Mid-
Atlantic has requested interim alternate emission limits ("AELs") from the USEPA
for Chalk Point Units 1 and 2 and has received proposed interim AELs from the
USEPA for Morgantown Units 1 and 2. Potomac River Units 1 through 5 elected
early participation into the program and can defer lower emissions limits until
2008. Dickerson Units 1 through 3 are subject to Phase II limits and have
installed low-NO\X\ burners along with a request for interim AELs from the
USEPA.
The Title I ozone transport requirements targets NO\X\ emissions
during the ozone season (May through September). The Maryland generating units
will be subject to allowance requirements beginning in 2000. Under a consent
order, Pepco is allowed to roll over 3,000 tons of year 2000 allowance deficits
into the 2001 ozone season without penalty. Maryland has adopted regulations
allocating allowances to individual units consistent with federal Title I ozone
transport requirements. The Virginia units will be subject to allowance
requirements beginning in 2003. No allowance requirements are in effect until
2003 because Virginia did not sign the September 1994 Memorandum of
Understanding among Eastern Regional Ozone Transport Commission states.
The Generating Facilities are subject to Phase II of the federal Acid
Rain Program of the Clean Air Act and, beginning in 2000, SE Mid-Atlantic must
possess SO\2\ allowances equal to the actual emissions. Each of the Generating
Facilities was allocated a set of SO\2\ allowances for the years 2000 to 2009
and a second set for the years 2010 and beyond.
SE Mid-Atlantic will be required to obtain SO\2\ and NO\X\ allowances
for actual SO\2\ and NO\X\ emissions in excess of allocations for the year 2000
and beyond. Future cost of allowances will be market dependent and could be
higher or lower than the current values for such allowances. For the purpose of
the Projected Operating Results, we have assumed the present spot market price
of SO\2\ allowances of approximately $150 per ton and have assumed that it would
increase annually at the rate of inflation. For NO\X\ allowances, the current
spot market is approximately $600 per ton with prices fluctuating from
approximately $500 to $7,500 per ton during 1999 and 2000. The cost of NO\X\
allowances will be impacted in 2003 by the ratcheting of allowances associated
with the USEPA's ozone reduction program and the associated installations of
selective catalytic reduction by many plants. For the purpose of the Projected
Operating Results, we have assumed a NO\X\ allowance price of $1,000 per ton
through 2002, $2,300 in 2003, $2,000 in 2004 and $1,700 in 2005. After 2005, the
NO\X\ allowance price has been assumed to increase at the rate of inflation.
In addition to the air and wastewater disposal requirements discussed
herein for each of the Generating Facilities, there are a number of other
environmental requirements with which the Generating Facilities must comply such
as "right-to-know" laws, hazardous waste management, chemical reporting, etc.
While we did not undertake a detailed environmental assessment of such
requirements at the Generating Facilities, it appears that the Generating
Facilities have maintained proactive compliance programs and are in material
compliance with such requirements.
Certain future requirements relative to the revised particulate matter
of 2.5 microns or less ("PM\2.5\") standard, regulation of mercury emissions,
regional haze, regional visibility, water intake structure regulations, and
A-50
potential ratcheting of the SO\2\ allowance program beyond the year 2009 may
affect the Generating Facilities in the future by imposing more stringent
requirements than those in effect at the present time.
The USEPA is presently collecting particulate ambient data to classify
the attainment status of areas in association with the PM\2.5\ standard.
Monitoring data is expected to be complete between 2001 and 2004. Allowing time
for data analysis, the USEPA will likely designate areas as attainment/non-
attainment between 2002 and 2004. State Implementation Plan revisions for
PM\2.5\ would be due at the earliest 2005. In addition, PM\2.5\ is viewed as a
regional problem (i.e., particulate non-attainment in one county may be caused
by distant sources). Because of the extended compliance schedule, future
emission reduction requirements that may be imposed on the Generating
Facilities, if any, cannot now be determined.
Section 316(b) of the Clean Water Act, provides that cooling water
intake structures must "reflect the best technology available for minimizing
adverse environmental impact." Although the USEPA issued a final regulation
under section 316(b) in 1976, the regulation was challenged in Court and
subsequently withdrawn by the USEPA. Since then there has been no regulation
governing cooling water intake structures. Because of legal action, the USEPA
and certain environmental organizations entered a consent decree in 1995 that
provided for the USEPA to issue cooling water intake regulations. Delays by the
USEPA resulted in additional legal action and in April of 2000, a court order
was issued that established new deadlines for proposal of regulation for
existing facilities by July 20, 2001. Until such regulations are issued, the
requirements that may be imposed on the Generating Facilities, if any, cannot
now be determined.
In November of 1999, the USEPA issued notices of violation to owners
and operators of 32 coal-fired electric generating plants, charging that over
many years of operation these plants had been changed or modified in ways that
resulted in increased emission of pollutants and that the plants did not obtain
federal prevention of significant deterioration permits and did not comply with
New Source Performance Standards applicable to new and modified sources. None of
the Generating Facilities are the subject of the USEPA action. While we cannot
predict the result of future reviews of the Generating Facilities, if any, by
the USEPA, given: (1) the age of the Generating Facilities; (2) the renewals and
replacements undertaken; and (3) that those planned for the future are intended
to allow the Generating Facilities to operate in a more dependable and reliable
manner than their original design capacity, we have assumed that the Generating
Facilities are not subject to New Source Review. Should the USEPA determine that
any renewals and replacements undertaken at the Generating Facilities are
subject to New Source Review and New Source Performance Standards, the cost to
comply could be substantial.
In April of 2000 the USEPA determined that regulation of fossil fuel
combustion wastes as hazardous wastes under Subtitle C of the Resource
Conservation and Recovery Act ("RCRA") is not warranted. This determination
covers the following wastes:
. Large-volume coal combustion wastes generated at electric utility
and independent power producing facilities that are co-managed
together with certain other coal combustion wastes;
. Coal combustion wastes generated at non-utilities;
. Coal combustion wastes generated at facilities with fluidized bed
combustion technology;
. Petroleum coke combustion wastes;
. Wastes from the combustion of mixtures of coal and other fuels
(i.e., co-burning of coal with other fuels where coal is at least
50 percent of the total fuel);
. Wastes from the combustion of oil; and
. Wastes from the combustion of natural gas.
While these wastes remain exempt from Subtitle C, the USEPA also
determined to establish national regulations under Subtitle D for coal
combustion wastes that are disposed in landfills or surface impoundments or used
to fill surface or underground mines. No schedule for developing the regulations
was proposed and the impact on the Generating Facilities, if any, cannot be
determined.
SE Mid-Atlantic has considered the possibility of future regulatory
changes such as described above, and an allowance for the cost of such changes
has been included in the Projected Operating Results as capital
A-51
expenditures, as described later in the Report. It should be noted that actual
implementation of the specific future actions assumed in the Projected Operating
Results depends upon the specific economic conditions at that time.
The Chalk Point Facility
Air Compliance
The major permit regulating the Chalk Point Facility's air emissions
is the Title V Operating Permit. The Title V application for the Chalk Point
Facility was submitted to the MDE December 12, 1996. The MDE has not yet issued
the Title V permit but the MDE did issue the Chalk Point Facility a letter of
completeness, dated January 21, 1997, stating that the plant could continue
operation subject to the permits in effect at that time. The Chalk Point
Facility is included in the VADEQ RACT Consent Agreement relative to NO\X\
emission rates. The VADEQ RACT Consent Agreement also addresses the Potomac
River, Dickerson and Morgantown Facilities under a NO\X\ averaging plan. The
VADEQ RACT Consent Agreement sets NO\X\ emission limits intended to address RACT
requirements. The VADEQ RACT Consent Agreement also implements NO\X\ emission
reductions designed to bring northern Virginia and neighboring regions into full
attainment with the national ambient air quality standard for ozone. The permits
and VADEQ RACT Consent Agreement contain specific emission limits and monitoring
requirements as well as other conditions that must be complied with during the
operation of the plant. In addition to the VADEQ RACT Consent Agreement, the
Chalk Point Facility must also meet an MDE RACT limit. Table 10 presents the key
emission limits for the Chalk Point Facility.
Table 10
Air Emission Limits
Chalk Point Facility
SO\2\(1) NO\X\ Particulate Opacity (%)(3)
-------------------- --------------------------- --------------------- --------------------
Unit 1
Coal(4)(6) 3.5 lb/MMBtu 0.73 lb/MMBtu 0.03 gr/DSCF 10
Natural Gas 0.73 lb/MMBtu 0.03 gr/DSCF 10
Unit 2
Coal(4)(6) 3.5 lb/MMBtu 0.76 lb/MMBtu 0.03 gr/DSCF 10
Natural Gas 0.76 lb/MMBtu 0.03 gr/DSCF 10
Unit 3
No. 6 Oil(5) 2.0% 0.32 lb/MMBtu 0.05 gr/DSCF (7) 20
No. 2 Oil 0.3% 0.32 lb/MMBtu 0.05 gr/DSCF 20
Natural Gas 0.32 lb/MMBtu 0.05 gr/DSCF 20
Unit 4
No. 6 Oil 0.8 lb/MMBtu 0.30 lb/MMBtu 0.02 gr/DSCF 10
No. 2 Oil 0.3% 0.30 lb/MMBtu 0.02 gr/DSCF 10
Natural Gas 0.30 lb/MMBtu 0.02 gr/DSCF 10
CTs 1 & 2
Natural Gas 0.3% 42 ppmvd(2) 10
No. 2 Oil 0.3% 57 ppmvd(2) 10
CTs 3 & 4
Natural Gas 0.8% 25 ppmvd(2) 5 lb/hr 10
No. 2 Oil 0.8% 38 ppmvd(2) 34 lb/hr 10
CTs 5 & 6
Natural Gas 0.8% 25 ppmvd(2) 5 lb/hr 10
No. 2 Oil 0.8% 57 ppmvd(2) 10 lb/hr 10
_____________________
(1) Percentages represent maximum permitted percentage of sulfur in fuel.
(2) Corrected to 15% O\2\.
(3) Six-minute average.
(4) Units share common stack.
(5) No. 6 fuel oil, natural gas.
(6) AEL petition submitted to the USEPA.
(7) Also required to meet a particulate limit of 0.10 lb/MMBtu.
A-52
Table 11 presents the 1998 and 1999 annual averages of SO\2\ and NO\X\
emissions for the Chalk Point Facility.
Table 11
Annual Average Air Emissions
Chalk Point Facility
(lb/MMBtu)
Unit 1998 1999 Current Projected
SO\2\ NO\X\(1) SO\2\ NO\X\(1) SO\2\ NO\X\(1) SO\2\ NO\X\(1)
------------ ------------- ------------ ------------- ------------ ------------- ----- --------
Unit 1 1.99 0.70 1.83 0.76 1.90 0.50 (2) 1.90 0.05 (4)
Unit 2 1.99 0.69 1.83 0.87 1.90 0.50 (2) 1.90 0.05 (4)
Unit 3 0.89 0.32 0.83 0.37 0.83 0.27 (3) 0.83 0.15 (5)
Unit 4 0.67 0.20 0.51 0.22 0.68 0.27 (3) 0.68 0.15 (5)
CT 1 1.20 1.20 1.20 0.15 (5)
CT 2 1.20 1.20 1.20 0.15 (5)
CT 3 0.01 0.06 0.00 0.06 0.00 0.06 0.00 0.06
CT 4 0.01 0.05 0.01 0.05 0.01 0.06 0.00 0.06
CT 5 0.00 0.05 0.00 0.05 0.00 0.07 0.00 0.07
CT 6 0.00 0.20 0.00 0.05 0.00 0.06 0.00 0.06
_____________________
(1) During ozone season, May through September.
(2) Represents capability with gas reburn. Gas reburn presently not being
utilized because the current cost of emission allowances is lower than
assumed herein, making it more economic to purchase allowances than to burn
natural gas.
(3) Based on oil-firing.
(4) Based on the installation in 2002 of low-NO\X\ burners with the capability
of achieving an emission rate of 0.22 lb/MMBtu and the installation in 2006
of selective catalytic reduction with the capability of achieving an
emission rate of 0.05 lb/MMBtu.
(5) Based on natural gas-firing.
The Chalk Point Facility is subject to Phase II of the federal Acid
Rain Program under the Clean Air Act and beginning in the year 2000, the owner
must possess SO\2\ allowances equal to actual emissions. The Chalk Point
Facility was allocated a number of allowances by the USEPA as part of the Acid
Rain Program for years 2000 to 2009 and for years 2010 and beyond. As part of
the Asset Purchase Agreement, SE Mid-Atlantic will acquire 37,717 tons per year
of SO\2\ allowances per year through 2009 and 30,498 tons per year thereafter.
Actual annual SO\2\ emissions for the Chalk Point Facility during 1998 and 1999
were 55,414 and 57,634 tons, respectively. The exact number of allowances that
will be required in the future will depend largely on the future use of the
units and the sulfur content of the fuel burned. Based on the capacity factors
projected by Hagler Bailly in its Base Case, the Chalk Point Facility is
projected to have a deficit of approximately 12,200 tons of SO\2\ allowances in
2001.
Chalk Point Units 1 and 2 are subject to Title IV requirements of the
Clean Air Act to meet the presumptive NO\X\ emission limit of 0.50 lb/MMBtu but,
as allowed under Title IV, requested and received from the USEPA interim AELs
and the opportunity to demonstrate it could not meet the presumptive limit.
Final AEL petitions of 0.73 and 0.76 lb/MMBtu for Chalk Point Units 1 and 2,
respectively, were submitted to the USEPA on June 30, 1999 and are under review
by the USEPA. The Chalk Point Facility is also subject to the provisions of the
VADEQ RACT Consent Agreement which includes provisions allowing the calculation
of a "bubble RACT" limit. The RACT limits in the VADEQ RACT Consent Agreement
were accepted by the MDE as RACT for Maryland by a letter dated August 2, 1996.
The Clean Air Act also requires reduction of NO\X\ emissions. In 1994,
NO\X\ emission budgets were established to achieve reductions beginning in 1999
with further reductions in 2003. The Chalk Point Facility was allocated a number
of NO\X\ emission allowances for the years 2000 to 2002 and 2003 and beyond. As
part of the Asset Purchase Agreement, SE Mid-Atlantic will acquire 5,159 tons
per year of NO\X\ allowances for the Chalk Point Facility for the years 2000
through 2002 and 2,551 tons per year for 2003 and each year thereafter. Actual
annual ozone
A-53
season NO\X\ emissions for the Chalk Point Facility in 1998 and 1999 were 10,919
and 12,434 tons, respectively. SE Mid-Atlantic's strategy for compliance with
NO\X\ requirements includes a number of options. The actual option, or
combination of options, utilized will depend upon a number of factors including
future regulatory requirements and the costs of allowances. For the purposes of
the Projected Operating Results, SE Mid-Atlantic has assumed specific options to
achieve the emissions rates shown in Table 11. These assumptions consist of
installation of low-NO\X\ burners for Chalk Point Units 1 and 2 in 2002,
selective catalytic reduction for Chalk Point Units 1 and 2 in 2006, fuel
switching, and the purchase of additional allowances. Chalk Point Units 1 and 2
were retrofitted with SOFA, burner modifications and tuning, and gas reburn
capability in the spring of 2000, although gas reburn is not currently being
utilized because the current cost of emission allowances is lower than assumed
herein, making it more economic to purchase allowances than to burn natural gas.
Chalk Point Units 3 and 4 will fire natural gas for compliance in the future
beginning in 2001. The exact number of allowances that will be required in the
future will depend to a large extent on the future utilization rates. Based on
the summer fuel consumption projected by Hagler Bailly in its Base Case and the
assumed reduction in emissions rates due to the additional emissions controls as
shown in Table 11, the Chalk Point Facility is projected to have a deficit of
less than 100 tons of NO\X\ allowances in 2001.
Wastewater Compliance
Chalk Point Units 1 and 2 are permitted to withdraw a maximum of 1,100
million gallons per day ("mgd") of water from the Patuxent River for once-
through condenser cooling. Chalk Point Units 3 and 4 use natural draft cooling
towers for condenser cooling. Up to 43 mgd of water is used for makeup of Chalk
Point Units 3 and 4 losses due to evaporation and for process water uses
throughout the Chalk Point Facility. Process wastewater originates from boiler
blowdown, neutralized demineralizer regenerant, coal pile runoff, cooling tower
blowdown, ash hopper overflows, plant drains and oil/water separator effluent.
These wastewater streams are directed to a settling basin before discharge to
the cooling water canal. The NPDES permit for the Chalk Point Facility includes
limitations on temperature and total residual oxidants for cooling water and
limitations on total suspended solids, oil and grease and pH for discharge from
the sediment pond. Sanitary sewage is treated by a small on-site sewage
treatment plant and the sludge is hauled off-site for disposal. The wastewater
discharge compliance history of the Chalk Point Facility can be categorized as
good. It is not presently operating under any consent orders resulting from
Notices of Violation ("NOVs").
The Dickerson Facility
The major permit regulating the Dickerson Facility's air emissions is
the Title V Operating Permit. The Title V application was submitted on December
2, 1996, and deemed complete January 21, 1997. The MDE has not yet issued the
permit. The permit will contain specific emission limits and monitoring
requirements as well as other conditions that must be complied with during the
operation of the plant. Table 12 presents the key emission limits for Dickerson
Units 1 through 3 and CTs H1 and H2.
Table 12
Key Air Emission Limits
Dickerson Facility
SO\2\(1) NO\X\ Particulate Opacity
--------------------- ----------------------- --------------------- --------------------
Units 1-3 2.8 lb/MMBtu 0.60 lb/MMBtu (2) 0.03 gr/DSCF 10%
CTs H1 & H2
Natural Gas 34 lb/hr 42 ppmvd(3) 21 lb/hr
No. 2 Oil 0.3%, 579 lb/hr 77 ppmvd(4) 27 lb/hr
_____________________
(1) Percentage represents maximum permitted percentage of sulfur in fuel.
(2) Interim AELs requested in demonstration period petition.
(3) Corrected to 15 percent O\2\.
(4) Depending on nitrogen content of fuel.
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Table 13 presents the 1998 and 1999 annual averages of SO\2\ and NO\X\
emissions for the Dickerson Facility.
Table 13
Annual Average Air Emissions
Dickerson Facility
(lb/MMBtu)
Unit 1998 1999 Current Projected
SO\2\ NO\X\(1) SO\2\ NO\X\(1) SO\2\ NO\X\(1) SO\2\ NO\X\(1)(2)
------------- -------------- ------------- -------------- ------------- -------------- ------------- --------------
Unit 1 1.98 0.68 1.78 0.65 1.78 0.50 1.78 0.36
Unit 2 3.44 0.68 2.09 0.63 2.09 0.50 2.09 0.36
Unit 3 2.08 0.68 1.90 0.57 1.90 0.50 1.90 0.36
CT H1 0.00 0.14 0.00 0.13 0.00 0.13 0.00 0.13
CT H2 0.01 0.12 0.01 0.12 0.01 0.12 0.00 0.12
_____________________
(1) During ozone season, May through September.
(2) Based on the installation of SOFA on Dickerson Units 1, 2, and 3 in 2002,
2003, and 2003, respectively, with the capability of achieving an emission
rate of 0.36 lb/MMBtu.
The Dickerson Facility is currently operating under a consent order
for opacity. Pepco is to complete a conversion of the Dickerson Unit 3 ESP to an
experimental wet ESP technology by the end of 2000. If successful, wet ESPs will
be installed on all three units by June 2003. In the event that the Dickerson
Facility cannot comply with the opacity requirements using the wet ESP
technology, an alternative would be to install a baghouse. Pepco agreed to pay
$200,000 in fines for violations prior to the consent order.
Dickerson Units 1, 2, and 3 are subject to Title IV of the Clean Air
Act to meet the presumptive NO\X\ emission limit of 0.50 lb/MMBtu, but as
allowed under Title IV, filed an AEL demonstration period petition with the
USEPA on April 28, 2000, for the opportunity to demonstrate it could not meet
the presumptive limit. Interim AELs requested in the petition are 0.60 lb/MMBtu
for Dickerson Units 1, 2, and 3. The petition is currently under review by the
USEPA. The Dickerson Facility is also subject to the VADEQ RACT Consent
Agreement, which includes provisions allowing the calculation of a "bubble RACT"
limit. The RACT limits in the VADEQ RACT Consent Agreement were accepted by the
MDE as RACT for Maryland by a letter dated August 2, 1996.
The Dickerson Facility is subject to the Acid Rain Program as Phase II
affected units relative to SO\2\ emissions. As such, the Acid Rain Program
requires that affected emission sources possess sufficient SO\2\ allowances to
cover their actual emissions beginning in the year 2000. Pepco was allocated a
number of allowances by the USEPA as part of the Acid Rain Program for years
2000 to 2009 and for years 2010 and beyond. As part of the Asset Purchase
Agreement, SE Mid-Atlantic acquired Pepco's originally allocated SO\2\
allowances for the Dickerson Facility equal to 19,352 tons per year up through
year 2009 and 19,393 tons per year thereafter. Actual annual SO\2\ emissions for
Dickerson Units 1 through 3 during 1998 and 1999 were 40,091 and 30,637 tons,
respectively. The exact number of allowances that will be required in the future
will depend to a large extent on the future utilization rates. Based on the
capacity factors projected by Hagler Bailly in its Base Case, the Dickerson
Facility is projected to have a deficit of approximately 17,900 tons of SO\2\
allowances in 2001. SE Mid-Atlantic's strategy for compliance with SO\2\
allowance requirements consists of a combination of burning lower sulfur coal,
operational changes, fuel switching and the purchasing of additional allowances.
Use of lower sulfur coal will require injection of SO\3\ to improve the ESP
collection efficiency.
The Dickerson Facility is also subject to NO\X\ allowance requirements
under the Ozone Transport Rule. Sufficient allowances are required to cover
NO\X\ emissions during the ozone season, which is May through September. Pepco
was allocated 1,693 tons of allowances for each year from 2000 through 2002 and
1,520 tons of allowances each year thereafter. Actual annual NO\X\ emissions for
the Dickerson Facility during the 1998 and 1999 ozone season were 5,983 and
5,391 tons, respectively. SE Mid-Atlantic's strategy for compliance with NO\X\
requirements includes a number of options. The actual option, or combination of
options, utilized will depend upon a
A-55
number of factors including future regulatory requirements and the costs of
allowances. For the purposes of the Projected Operating Results, SE Mid-Atlantic
has assumed specific options to achieve the emissions rates shown in Table 13.
These assumptions consist of installation of SOFA for Dickerson Units 1, 2 and 3
in 2002, 2003, and 2003, respectively, and the purchasing of additional
allowances. During 1998 and 1999, the burner tips were replaced and the units
modified to control air distribution to the boiler. The exact number of
allowances that will be required in the future will depend to a large extent on
the future utilization rates. Based on the summer fuel consumption projected by
Hagler Bailly in its Base Case and the assumed reduction in emissions rates due
to the additional emissions controls as shown in Table 13, the Dickerson
Facility is projected to have a deficit of approximately 2,300 tons of NO\X\
allowances in 2001.
Wastewater Compliance
An NPDES Permit regulates the Dickerson Facility's wastewater
effluents. The Dickerson Facility is permitted to discharge once-through cooling
water, runoff, sewage treatment effluent, backwash and other miscellaneous
wastewater into the Potomac River and tributaries. The cooling water temperature
increase and maximum heat rejection are limited under the terms of the permit
along with residual chlorine and pH. The other discharges are limited with
respect to suspended solids, oil and grease, biochemical oxygen demand and fecal
coliform depending upon the source of the effluent. The wastewater discharge
compliance history of the Dickerson Facility can be categorized as good. It is
not presently operating under any consent orders resulting from NOVs.
The Morgantown Facility
Air Compliance
The major permit regulating the Morgantown Facility's air emissions is
the Title V Operating Permit. The Title V application for the Morgantown
Facility was submitted to the MDE December 19, 1997. The MDE has not yet issued
the Title V permit, but the MDE did issue the Morgantown Facility a letter of
completeness, dated January 21, 1997, stating that the plant could continue
operation subject to the permits in effect at that time. The Morgantown Facility
is subject to the terms of the VADEQ RACT Consent Agreement relative to NO\X\
emission rates. The VADEQ RACT Consent Agreement also addresses the Potomac
River, Dickerson and Chalk Point Facilities under a NO\X\ averaging plan. The
VADEQ RACT Consent Agreement sets NO\X\ emission limits intended to address
reasonably available control technology requirements. The VADEQ RACT Consent
Agreement also implements NO\X\ emission reductions designed to bring northern
Virginia and neighboring regions into full attainment with the national ambient
air quality standard for ozone. The permits and VADEQ RACT Consent Agreement
contain specific emission limits and monitoring requirements as well as other
conditions that must be complied with during the operation of the plant. Table
14 presents the key emission limits for the Morgantown Facility. In addition to
the VADEQ RACT Consent Agreement, the Morgantown Facility must meet an MDE RACT
limit.
A-56
Table 14
Air Emission Limits
Morgantown Facility
NO\X\(2) Particulate Opacity
SO\2\(1) (lb/MMBtu) (lb/MMBtu) (%)(3)
------------ ---------- ----------- -------
Unit 1
Coal 3.5 lb/MMBtu 0.64 0.14 20
No. 6 Oil 2.0% 0.64 0.14 20
No. 2 Oil 3.0% 0.64 0.14 20
Unit 2
Coal 3.5 lb/MMBtu 0.66 0.14 20
No. 6 Oil 2.0% 0.66 0.14 20
No. 2 Oil 3.0% 0.66 0.14 20
CTs 1 & 2
No. 2 Oil(3) 0.3% 1.20 0.283 20
CTs 3 through 6
No. 2 Oil(3) 0.3% 1.20 0.10 20
____________________
(1) One-hour average. Percentages represent maximum permitted percentage of
sulfur in fuel.
(2) Final AELs proposed by the USEPA.
(3) Six-minute average.
(4) Good operating practice for NO\X\ emissions.
Table 15 presents the 1998 and 1999 annual averages of SO\2\ and NO\X\
emissions for the Morgantown Facility.
Table 15
Annual Average Air Emissions
Morgantown Facility
(lb/MMBtu)
1998 1999 Current Projected
Unit SO\2\ NO\X\(1) SO\2\ NO\X\(1) SO\2\ NO\X\(1) SO\2\ NO\X\(1)(2)
- ---- ------------ ------------- ------------ ------------- ------------ ------------- ------------ ----------------
Unit 1 2.11 0.59 2.17 0.64 2.17 0.45 2.17 0.13
Unit 2 2.07 0.60 2.12 0.60 2.12 0.45 2.12 0.13
CTs 1-6 1.20 1.20 1.20 1.20
_____________________
(1) During ozone season, May through September.
(2) Based on the installation of low-NO\X\ burners and SOFA with the capability
of achieving an emissions rate of 0.45 lb/MMBtu in 1994 and 1995, oil/coal
co-firing with the capability of achieving an emissions rate of 0.36
lb/MMBtu in 2002, and the installation of selective catalytic reduction or
non-selective catalytic reduction for Morgantown Units 1 and 2 in 2006 and
2008, respectively, with the capability of achieving an emission rate of
0.13 lb/MMBtu.
The Morgantown Facility is subject to Phase II of the federal Acid
Rain Program under the Clean Air Act and beginning in the year 2000, the owner
must possess SO\2\ allowances equal to actual emissions. The Morgantown Facility
was allocated a number of allowances by the USEPA as part of the Acid Rain
Program for years 2000 to 2009 and for years 2010 and beyond. As part of the
Asset Purchase Agreement, SE Mid-Atlantic will acquire 33,111 tons per year of
SO\2\ allowances per year through 2009 and 33,178 tons per year thereafter.
Actual annual SO\2\ emissions for the Morgantown Facility during 1998 and 1999
were 79,906 and 75,520 tons, respectively. The exact number of allowances that
will be required in the future will depend largely on the future use of the
units and the sulfur content of the fuel burned. Based on the capacity factors
projected by Hagler Bailly in its Base Case, the Morgantown Facility is
projected to have a deficit of approximately 51,500 tons of SO\2\ allowances in
2001. SE Mid-Atlantic's
A-57
strategy for compliance with SO/2/ allowance requirements consists of a
combination of burning lower sulfur coal, operational changes, fuel switching
and the purchasing of additional allowances.
Morgantown Units 1 and 2 are subject to Title IV requirements to meet
the presumptive NO\X\ emission limit of 0.45 lb/MMBtu but, as allowed under
Title IV of the Clean Air Act, requested and received from the USEPA interim
AELs and the opportunity to demonstrate it could not meet the presumptive limit.
Final AEL limits of 0.63 and 0.64 lb/MMBtu for Morgantown Units 1 and 2,
respectively, were proposed to be issued by the USEPA in November 2000. The
Morgantown Facility is also subject to the provisions of the VADEQ RACT Consent
Agreement, which includes provisions allowing the calculation of a "bubble RACT"
limit. The RACT limits in the VADEQ RACT Consent Agreement were accepted by the
MDE as RACT for Maryland by a letter dated August 2, 1996.
The Clean Air Act also requires reduction of NO\X\ emissions. In 1994,
NO\X\ emission budgets were established to achieve reductions beginning in 1999
with further reductions in 2003. As part of the Asset Purchase Agreement, SE
Mid-Atlantic will acquire 5,057 tons per year of NO\X\ allowances for the
Morgantown Facility for the years 2000 to 2002 and 2,596 tons per year for 2003
and beyond. Actual annual ozone season NO\X\ emissions for the Morgantown
Facility during 1998 and 1999 were 10,513 and 10,363 tons, respectively. SE Mid-
Atlantic's strategy for compliance with NO\X\ requirements includes a number of
options. The actual option, or combination of options, utilized will depend upon
a number of factors including future regulatory requirements and the costs of
allowances. For the purposes of the Projected Operating Results, SE Mid-Atlantic
has assumed specific options to achieve the emissions rates shown in Table 15.
These assumptions consist of installation of low-NO\X\ burners and SOFA, which
was installed in Morgantown Units 1 and 2 in 1994 and 1995, respectively,
selective catalytic and non-catalytic reduction for Morgantown Units 1 and 2 in
2006 and 2008, respectively, oil/coal co-firing with boiler tuning in 2002, and
the purchase of additional allowances. The exact number of allowances that will
be required in the future will depend to a large extent on the future
utilization rates. Based on the summer fuel consumption projected by Hagler
Bailly in its Base Case and the assumed reduction in emissions rates due to the
additional emissions controls as shown in Table 15, the Morgantown Facility is
projected to have a deficit of approximately 2,700 tons of NO\X\ allowances in
2001.
Wastewater Compliance
Morgantown Units 1 and 2 are permitted to withdraw a maximum of 2,400
mgd of water from the Potomac River for once-through condenser cooling and plant
process water. Process wastewater originates from boiler blowdown, neutralized
demineralizer regenerant, coal pile runoff, ash hopper overflows, plant drains
and oil/water separator effluents. These wastewater streams are directed to a
primary settling basin for pH adjustment and then to a secondary settling pond
before discharge to the cooling water canal. The draft NPDES permit for the
Morgantown Facility includes limitations on temperature and total residual
oxidants for the cooling water, limitations on copper and iron for chemical
cleaning wastes, and limitations on total suspended solids, oil and grease and
pH for discharge from the secondary settling pond. Sanitary sewage is treated by
a small on-site sewage treatment plant and the sludge is hauled off-site for
disposal. The wastewater discharge compliance history of the Morgantown Facility
can be categorized as good. It is not presently operating under any consent
orders resulting from NOVs.
The Potomac River Facility
Air Compliance
The major permit regulating the Potomac River Facility's air emissions
is the Title V Operating Permit. The Title V application was submitted and
deemed complete on March 4, 1998. The VADEQ has not yet issued the permit. The
permit will contain specific emission limits and monitoring requirements as well
as other conditions that must be complied with during the operation of the
plant. Table 16 presents the key emission limits for the Potomac River Facility.
A-58
Table 16
Air Emission Limits
Potomac River Facility
SO\2\ NO\X\ Particulate Opacity
Unit (lb/MMBtu) (lb/MMBtu)(1) (lb/hr/DSCF) (%)
------------------- --------------------- ------------------------- --------------------- ----------------------
Units 1-2 1.52 0.77 114 20
Units 3-5 1.52 0.86 115 20
____________________
(1) NO\X\ RACT as outlined in the VADEQ RACT Consent Agreement.
Table 17 presents the 1998 and 1999 annual averages of SO\2\ and NO\X\
for the Potomac River Facility.
Table 17
Annual Average Air Emissions
Potomac River Facility
(lb/MMBtu)
1998 1999 Current Projected
SO\2\ NO\X\(1) SO\2\ NO\X\(1) SO\2\ NO\X\(1) SO\2\ NO\X\(1)(2)
Unit ------------ ------------- ------------ ------------- ------------ ------------- ------------ -----------------
Unit 1 1.06 0.40 1.09 0.41 1.10 0.41 1.10 0.41
Unit 2 1.03 0.39 1.10 0.37 1.10 0.37 1.10 0.37
Unit 3 1.11 0.42 1.10 0.44 1.10 0.44 1.10 0.17
Unit 4 1.13 0.40 1.10 0.44 1.10 0.44 1.10 0.17
Unit 5 1.15 0.45 1.10 0.44 1.10 0.44 1.10 0.17
____________________
(1) During ozone season, May through September.
(2) Based on installation of low-NO\X\ burners and SOFA for Potomac River Units
3, 4 and 5 in 2007, 2007, and 2008, respectivelly, with the capability of
achieving an emissions rate of 0.17 lb/MMBtu. Combustion optimization has
been employed with Potomac River Units 1 and 2. No further retrofits are
planned for Potomac River Units 1 and 2.
The Potomac River Facility is subject to the Acid Rain Program as a
Phase II affected unit relative to SO\2\ emissions. As such, the Acid Rain
Program requires that affected emission sources possess sufficient SO\2\
allowances to cover their actual emissions beginning in the year 2000. Pepco was
allocated a number of allowances by the USEPA as part of the Acid Rain Program
for years 2000 to 2009 and for years 2010 and beyond. As part of the Asset
Purchase Agreement, SE Mid-Atlantic acquired Pepco's originally allocated SO\2\
allowances for the Potomac River Facility equal to 13,344 tons per year through
year 2009 and 12,049 tons per year thereafter. Annual SO\2\ emissions from the
plant during 1998 and 1999 were 15,026 and 17,627 tons, respectively. The exact
number of allowances that will be required in the future will depend to a large
extent on the fuel used and the future utilization rates of the Potomac River
Facility. Based on the capacity factors projected by Hagler Bailly in its Base
Case, the Potomac River Facility is projected to have a deficit of approximately
4,800 tons of SO\2\ allowances in 2001. SE Mid-Atlantic's strategy for
compliance with SO\2\ allowance requirements consists of a combination of
burning lower sulfur coal, operational changes, fuel switching and allowance
purchases.
The Potomac River Facility is subject to Title IV requirements of the
Clean Air Act to meet the presumptive NO\X\ emission limit of 0.40 lb/MMBtu.
Under Title IV, the Potomac River Facility submitted an early election
compliance plan for NO\X\ and is required to achieve 0.45 lb/MMBtu by the year
2000 deadline and, assuming renewal of the Phase II permit in 2002, can defer
the requirement to meet the more stringent Phase II limit of 0.40 lb/MMBtu until
2008. The Potomac River Facility is also subject to the provisions of the VADEQ
RACT Consent Agreement, which includes provisions allowing the calculation of a
"bubble RACT" limit.
A-59
The Potomac River Facility is located in a severe non-attainment area
for ozone. The Clean Air Act called for Virginia to develop a State
Implementation Plan ("SIP") and reach compliance by November 15, 1999. The VADEQ
did not submit a SIP acceptable to the USEPA and the attainment deadline was
missed. The VADEQ subsequently submitted a revised SIP that included proposed
NO\X\ emission limits for the Potomac River Facility and on September 29, 2000,
issued a state operating permit to the Potomac River Facility that allocates
1,019 tons of NO\X\ allowances which cannot be exceeded without the facility
purchasing additional allowances to cover the excess emissions. The compliance
date for meeting the limit is May 1, 2003, the beginning of the ozone season.
The permit allows the trading of emissions from other generating units as a
means to meet the emission limit for the Potomac River Facility.
The Potomac River Facility is also subject to NO\X\ allowance
requirements under the Ozone Transport Rule although, because the State of
Virginia is disputing certain provisions in Federal Court and because the
current SIP has a compliance date of May 1, 2003, no NO\X\ allocations have been
assigned effective prior to that date. However, the draft VADEQ permit for the
Potomac River Facility includes allocation of NO\X\ emissions in the amount of
1,019 tons of allowances for 2003 and each year thereafter. Sufficient
allowances are required to cover NO\X\ emissions during the ozone season of May
through September. Actual annual NO\X\ emissions for Potomac River during the
1998 and 1999 ozone season were 2,830 and 3,314 tons, respectively. SE Mid-
Atlantic's strategy for compliance with NO\X\ requirements includes a number of
options. The actual option, or combination of options, utilized will depend upon
a number of factors including future regulatory requirements and the costs of
allowances. For the purposes of the Projected Operating Results, SE Mid-Atlantic
has assumed specific options to achieve the emissions rates shown in Table 17.
These assumptions consist of installation of low-NO\X\ burners and SOFA for
Potomac River Units 3, 4, and 5 in 2007, 2007, and 2008, respectively, and the
purchase of additional allowances. The exact number of allowances that will be
required in the future will depend to a large extent on the future utilization
rates. Based on the summer fuel consumption projected by Hagler Bailly in its
Base Case and the assumed reduction in emissions rates due to the additional
emissions controls as shown in Table 17, the Potomac River Facility is projected
to have a deficit of approximately 100 tons of NO\X\ allowances in 2003.
Wastewater Compliance
An NPDES Permit regulates the Potomac River Facility's wastewater
effluents. The permit allows for discharges of cooling water, ash clarifier
water, neutralization wastewater and miscellaneous wastewater to the Potomac
River. The cooling water maximum heat rejection is limited under the terms of
the permit along with residual chlorine. The other discharges are limited with
respect to suspended solids, oil and grease, and pH. The wastewater discharge
compliance history of the Potomac River Facility can be categorized as good. It
is not presently operating under any consent orders resulting from NOVs.
The Piney Point Pipeline
The MDE, in 1995, issued an Oil Operations Permit for the Ryceville
Pumping Station and in 1998 issued a license to transfer oil into the State. The
Piney Point Pipeline and associated pumping station are subject to an Oil
Operations Permit issued by the MDE in 1995. The oil operations permit requires
completion of a plan for notification, containment and cleanup of oil spills.
The Piney Point Pipeline and associated pumping station are also subject to the
Oil Pollution Act whereby an oil spill emergency response plan must be prepared.
The plan prepared by Pepco includes the Piney Point Pipeline and associated
pumping station as well as oil storage and transfer facilities located at the
power plants. The Oil Operations Permit requires that in case of an oil spill, a
written report must be submitted to the MDE describing the circumstances of the
spill and cleanup.
On April 7, 2000, an oil spill was detected in the Piney Point
Pipeline near the Chalk Point Facility. A press release from the U.S. Coast
Guard reported that the spill into Swanson Creek and the Patuxent River amounted
to 110,000 gallons of fuel oil. Clean up efforts began immediately and the MDE
announced in May of 2000 that initial cleanup efforts were complete and that the
transition to long-term restoration had begun. Pepco has stated that cleanup
cost amount to more than $50,000,000 as of June 2000. Under the terms of the
Asset Purchase Agreement, Pepco is obligated to indemnify Southern Energy and
its affiliates for all environmental liability relating to the release of fuel
oil from the Piney Point Pipeline.
A-60
The Ash Storage Facilities
Brandywine
Brandywine receives ash from the Chalk Point and Potomac River
Facilities. It has been used by Pepco since the 1960's and is permitted by the
MDE under its NPDES program. Coal ash, stored on-site, is designated as a
pozzolanic material (inert silica material that can be used to make concrete)
under Maryland regulations and is exempt from landfill permit requirements and
landfill regulations. However, the current NPDES permit for the site requires
monitoring of groundwater at 10 well locations around the site. Leachate,
stormwater runoff and truck wash water is collected and treated in a series of
surface ponds before discharge. The NPDES permit establishes discharge limits
for pH, total suspended solids, turbidity and iron and requires monitoring (but
with no limits) for copper, selenium, sulfates and total hardness. The six
groundwater wells and three surface water locations must also be monitored for
pollutants and the results reported to the MDE. The wastewater discharge
compliance history of Brandywine with respect to its permitted discharges can be
categorized as good. It is not presently operating under any consent orders
resulting from NOVs.
Faulkner
Faulkner receives ash from the Morgantown Facility. It has been
operating since 1970 and is permitted by the MDE under its NPDES program. Coal
ash, stored on-site, is designated as a pozzolanic material (inert silica
material that can be used to make concrete) under Maryland regulations and is
exempt from landfill permit requirements and landfill regulations. However, the
current NPDES permit for the site requires monitoring of groundwater at 10 well
locations around the site. Leachate, stormwater runoff and truck wash water is
collected and treated in a series of surface ponds before discharge. The NPDES
permit establishes discharge limits for pH, total suspended solids and iron and
requires monitoring (but with no limits) for lead, copper, selenium, sulfates
and total hardness. The groundwater wells and four surface water locations must
also be monitored for pollutants and the results reported to the MDE. In 1996,
the MDE made a determination that groundwater contamination from the site
resulted in discharges to waters of the State that were not authorized by the
NPDES permit. Pepco has proposed corrective action to correct the problem and is
negotiating with the MDE to determine the type and extent of the corrective
action. The wastewater discharge compliance history of Faulkner with respect to
its permitted discharges can be categorized as good. It is not presently
operating under any consent orders resulting from NOVs. However, a consent
agreement is expected to result from negotiations with the MDE related to
groundwater contamination.
Westland
Westland receives ash from the Dickerson Facility. It has been
developed in phases with phase II beginning operation in 1987 with a 20-year
life. Phase III will begin development shortly before Phase II is near
completion. The ash is deposited into the storage area where it is spread,
watered and compacted. The site is permitted by the MDE under its NPDES program.
Coal ash, stored on-site, is designated as a pozzolanic material (inert silica
material that can be used to make concrete) under Maryland regulations and is
exempt from landfill permit requirements and landfill regulations. However, the
current NPDES permit for the site specifies requirements for coverage of
completed storage cells and re-vegetation. Leachate and stormwater runoff is
collected and treated in a series of surface ponds before discharge. The NPDES
permit establishes discharge limits for pH (or alternatively liner
specifications), and requires monitoring of total suspended solids and iron with
no maximum limits.
The MDE has also issued a water appropriation permit in association
with the ash site. The permit allows for withdrawal of up to 500 gallons per day
of well water for sanitary and potable use, and for truck washing. The
wastewater discharge compliance history of Westland with respect to its
permitted discharges can be categorized as good. It is not presently operating
under any consent orders resulting from NOVs.
Summary
Based on our plant visits and review of documents, data and monitoring
reports, we are of the opinion that the Generating Facilities appear to be
operating in material compliance with applicable environmental permits,
approvals, consent orders, laws, rules and regulations.
A-61
PROJECTED OPERATING RESULTS
We have reviewed the historical operating information, estimates and
projections of electrical generating capacity, fuel consumption, and capital and
operating costs of the Generating Facilities made available to us by SE Mid-
Atlantic. On the basis of such data, we have prepared the Projected Operating
Results. The Projected Operating Results are presented for each calendar year
beginning January 1, 2001 through December 30, 2028, the term of the
Certificates. SE Mid-Atlantic's generation from the Generating Facilities has
been assumed to be sold directly to the market at rates which have been
estimated by Hagler Bailly. Expenses for the plants consist primarily of the
costs of fuel, including transportation, as estimated by Hagler Bailly, and
operations and maintenance expenses, as estimated by SE Mid-Atlantic. The Fixed
Charges have been reported by Credit Suisse First Boston. Projected revenues and
expenses have been set forth in the Projected Operating Results presented in
Exhibit A-1. The Projected Operating Results have been prepared using
assumptions and considerations set forth in this Report and the footnotes to
Exhibit A-1.
Annual Operating Revenues
- -------------------------
Revenues from Electricity Sales
All net energy generated by the Generating Facilities has been assumed
to be sold to the market at market electricity rates. Market electricity rates
were estimated by Hagler Bailly in 2000 dollars and have been adjusted for
inflation. For the purposes of the Projected Operating Results, the general
inflation rate has been assumed to be 2.6 percent per year based on an October
10, 2000 projection prepared by Blue Chip Economic Indicators.
Annual Operating Expenses
- -------------------------
Fuel Costs
All of the Generating Facilities purchase fuel on a short-term basis
at rates which are at or near market rates. Hagler Bailly has projected long-
term fuel prices. For the purposes of the Projected Operating Results, we have
assumed fuel prices equal to the projection prepared by Hagler Bailly in 2000
dollars and adjusted for inflation.
Operating and Maintenance Costs
For the purposes of developing the Projected Operating Results,
operating and maintenance expenses for the Generating Facilities have been
estimated by SE Mid-Atlantic. These estimates include annual costs for payroll,
materials and supplies, outside services, including contractors, and variable
operating and maintenance expenses. SE Mid-Atlantic's estimate of operating and
maintenance expenses include the costs of ash disposal, net of ash sold. SE Mid-
Atlantic has assumed that 9 percent of the ash generated by the Generating
Facilities will be sold for the term of the Certificates. In general, SE Mid-
Atlantic has projected that the cost of operating and maintaining the Generating
Facilities will decrease over the next few years as efficiencies are
implemented. All operation and maintenance expenses have been provided in 2000
dollars and have been assumed to escalate at the general rate of inflation.
Although we have not reviewed each individual expense constituting SE
Mid-Atlantic's estimate of operating and maintenance expenses and capital
expenditures and the methodology used to develop the estimates, we have reviewed
the combined projection of operating and maintenance expenses and capital
expenditures in comparison to the costs of similar plants with which we are
familiar. Based on our review, we are of the opinion that SE Mid-Atlantic's
estimate of the costs of operating and maintaining the Generating Facilities,
including provision for capital expenditures and major maintenance, is within
the range of the costs of similar plants with which we are familiar.
Emissions Allowances
Under the terms of the Asset Purchase Agreement with Pepco, SE Mid-
Atlantic will acquire the SO\2\ and NO\X\ allowances associated with the
Generating Facilities. We have included the cost of allowances as an
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additional operating expense for the Generating Facilities. Based on the assumed
emission rates as estimated by SE Mid-Atlantic, the capacity factors projected
by Hagler Bailly, and the SO\2\ allowances acquired from Pepco, there is
projected to be a deficit of approximately 86,400 tons of SO\2\ allowances in
2001. The SO\2\ allowance price has been assumed to be $150 per ton in 2000
dollars and have been assumed to increase at the rate of inflation.
Based on the assumed emission rates as estimated by SE Mid-Atlantic,
the capacity factors and summer generation projected by Hagler Bailly, and the
NO\X\ allowances acquired from Pepco, there is projected to be a deficit of
approximately 500 tons of NO\X\ allowances in 2001. Based on the capacity
factors projected by Hagler Bailly, SE Mid-Atlantic is projected to have excess
allowances in some years and a shortfall in others. NO\X\ allowance prices have
been assumed to be $1,000 per ton through 2002, $2,300 in 2003, $2,000 in 2004
and $1,700 in 2005. After 2005, the NO\X\ allowance price has been assumed to
increase at the rate of inflation.
It should be noted that Hagler Bailly has assumed SO\2\ and NO\X\
allowance prices that are significantly higher than those assumed in the
Projected Operating Results. In the event that the actual allowance prices are
as assumed by Hagler Bailly, the projected minimum and average Fixed Charge
coverage ratios would decrease by approximately 0.12 and 0.26, respectively.
General and Administrative and Other Expenses
SE Mid-Atlantic has estimated certain general and administrative costs
which have been included in the Projected Operating Results. These costs
include, among other things, support services such as power marketing, computer
systems and services, human resources, and accounting. These expenses have been
assumed to increase at the general rate of inflation.
In addition, SE Mid-Atlantic has estimated other expenses, which have
also been included in the Projected Operating Results. Property taxes have been
estimated by SE Mid-Atlantic through 2001 and have been assumed to escalate at
the rate of inflation thereafter. SE Mid-Atlantic's property tax estimate
reflects exemptions beginning in 2001 for machinery used to generate
electricity.
Capital Expenditures
- --------------------
SE Mid-Atlantic has estimated the capital costs of improvements to the
Generating Facilities. These capital expenditures include the cost of certain
environmental control equipment assumed by SE Mid-Atlantic to be added at
certain of the Generating Facilities. These improvements include the
installation of: (1) low-NO\X\ burners at Chalk Point Units 1 and 2 in 2002; (2)
selective catalytic reduction at Chalk Point Units 1 and 2 in 2006 and 2008,
respectively; (3) SOFA systems at Dickerson Units 1, 2 and 3 in 2002, 2003, and
2003, respectively; (4) selective catalytic reduction at Morgantown Units 1 and
2 in 2006 and 2008, respectively; and (5) low-NO\X\ burners and SOFA systems at
Potomac River Units 3, 4 and 5 in 2007, 2007, and 2008, respectively.
Annual Fixed Charges
- --------------------
We have included Fixed Charges, as reported by Credit Suisse First
Boston, through the term of the Certificates. Semi-annual payments are due each
June 30 and December 30 beginning June 30, 2001 and have been assumed to be
accrued over the six months prior to each due date. The final payment on the
Certificates is scheduled to be made on December 30, 2028.
Fixed Charge Coverage
- ---------------------
On the basis of our studies and analyses of the Generating Facilities
and the assumptions set forth in this Report, we are of the opinion that, for
the Base Case Projected Operating Results, the projected revenues from the sale
of electricity are adequate to pay annual operating and maintenance expenses
(including capital expenditures and major maintenance), fuel expense, and other
operating expenses. Such revenues provide an annual coverage on the Certificates
of at least 2.72 times the annual Fixed Charge requirement (including Rent) in
each year during the term of the Certificates and a weighted average coverage of
5.05 times the annual Fixed Charge requirement (including Rent) over the term of
the Certificates. The weighted average coverages have been calculated as the
total net operating
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revenues less capital expenditures over the term of the Certificates divided by
the total Fixed Charges over the term of the Certificates. Annual Fixed Charge
coverages for the term of the Certificates are presented in Exhibit A-1.
Contribution from the Leased Facilities
- ---------------------------------------
The Leased Facilities consist of Dickerson Units 1, 2 and 3 and
Morgantown Units 1 and 2. The Leased Facilities are projected by Hagler Bailly
to generate approximately 52 percent of the electricity sales over the term of
the Certificates. Based upon the electricity revenue and fuel costs for the
Leased Facilities estimated by Hagler Bailly, the variable operating and
maintenance costs of the Leased Facilities as estimated by SE Mid-Atlantic, and
the various other assumptions used in the Projected Operating Results as
described herein, the Leased Facilities are estimated to provide approximately
48 percent of the projected gross operating margin of the Generating Facilities
over the term of the Certificates, or an average of approximately $393,000,000
per year over the term of the Certificates. The gross operating margin has been
calculated as the difference between electricity revenue and the fuel and
variable operating and maintenance cost, including the cost of emissions
allowances.
Sensitivity Analyses
- --------------------
Due to the uncertainties necessarily inherent in relying on
assumptions and projections, it should be anticipated that certain circumstances
and events may differ from those assumed and described herein and that such will
affect the results of our Base Case Projected Operating Results for the
Generating Facilities. In order to demonstrate the impact of certain
circumstances on the Base Case Projected Operating Results, certain sensitivity
analyses have been developed. 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 Generating Facilities. The sensitivities are not
presented in any particular order with regard to the likelihood of any case
actually occurring. In addition, no assurance can be given that all relevant
sensitivities have been presented, that the level of each sensitivity is the
appropriate level for testing purposes, or that only one (rather than a
combination of more than one) of such variations or sensitivities could impact
the Generating Facilities in the future.
These sensitivity analyses present the Projected Operating Results
assuming, respectively, that: (a) the market prices, energy sales, and fuel
prices are reduced according to the "Low Gas Price" scenario prepared by Hagler
Bailly; (b) the market prices, energy sales, and fuel prices are reduced
according to the "Capacity Overbuild" case prepared by Hagler Bailly; (c) the
market prices are reduced such that the Fixed Charge coverage on the Lease is
equal to 1.00 in all years; (d) the availability of the Generating Facilities is
reduced by 5 percentage points; (e) the heat rates of the Generating Facilities
are 5 percent higher than that assumed in the Base Case; and (f) the non-fuel
related operating expenses of the Generating Facilities are 10 percent higher
than that assumed in the Base Case. The sensitivity analyses are presented as
Exhibits A-2 through A-7 to this Report. For the purposes of (a) and (b), Hagler
Bailly has prepared additional projections of dispatch and market prices. Based
on discussions with Hagler Bailly, market sales and market prices have been
assumed to be the same as the Base Case for the purposes of (d), (e), and (f).
Summary Comparison of Projected Operating Results
- -------------------------------------------------
A summary of the Fixed Charge coverages for the Base Case Projected
Operating Results and each sensitivity case is presented in Table 18.
A-64
Table 18
Projected Fixed Charge Coverage
Base Case Sensitivity Cases
A B C D E F
----- ----- ----- ----- ----- -----
Capacity
Year Low Gas Overbuild Breakeven Increased
Ending Market Price Market Price Market Reduced Increased Heat Operating
Dec 31, Scenario Scenario Prices (1) Availability Rate Expenses
- ------------- --------------- ------------- ---------- ------------ -------------- ----------
2001 2.80 2.48 2.80 1.00 2.65 2.69 2.70
2002 2.77 2.52 2.51 1.00 2.61 2.65 2.65
2003 2.72 2.36 1.95 1.00 2.55 2.57 2.59
2004 3.12 2.47 2.44 1.00 2.89 2.94 2.94
2005 3.10 2.44 2.53 1.00 2.87 2.91 2.91
2010 3.33 2.69 3.25 1.00 3.10 3.16 3.16
2015 4.72 3.72 4.65 1.00 4.36 4.46 4.43
2020 5.73 4.55 5.63 1.00 5.30 5.42 5.39
2025 41.56 33.10 41.09 1.00 38.43 39.33 39.02
Minimum(2) 2.72 2.36 1.95 1.00 2.55 2.57 2.59
Average(3) 5.05 4.08 4.87 1.00 4.68 4.78 4.76
____________________
(1) Represents coverage on the Fixed Charges assuming the market electricity
price is set such that the total operating revenue results in a Fixed
Charge coverage of 1.00 in all years.
(2) Represents minimum coverage during any year over the term of the
Certificates.
(3) Represents the weighted average coverage over the term of the Certificates.
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
USED IN THE PROJECTION OF OPERATING RESULTS
In the preparation of this Report and the opinions that follow, we
have made certain assumptions with respect to conditions which may exist or
events which may occur in the future. While we believe these assumptions to be
reasonable for the purpose of this Report, they are dependent upon future
events, and actual conditions may differ from those assumed. In addition, we
have used and relied upon certain information provided to us by sources which we
believe to be reliable. While we believe the use of such information and
assumptions to be reasonable for the purposes of our Report, we offer no other
assurances thereto and some assumptions may vary significantly due to
unanticipated events and circumstances. To the extent that actual future
conditions differ from those assumed herein or provided to us by others, the
actual results will vary from those projected herein. This Report summarizes our
work up to the date of the Report. Thus, changed conditions occurring or
becoming known after such date could affect the material presented to the extent
of such changes.
The principal considerations and assumptions made by us in developing
the Base Case Projected Operating Results and the principal information provided
to us by others include the following:
1. As Independent Engineer, we have made no determination as to the
validity and enforceability of any contract, agreement, rule, or regulation
applicable to the Generating Facilities and its operations. However, for
purposes of this Report, we have assumed that all such contracts,
agreements, rules, and regulations will be fully enforceable in accordance
with their terms and that all parties will comply with the provisions of
their respective agreements.
2. Our review of the design of the Generating Facilities was based on
information developed by Pepco and SE Mid-Atlantic.
3. SE Mid-Atlantic will maintain the Generating Facilities in
accordance with good engineering practice, will perform all required major
maintenance in a timely manner, and will not operate the equipment to cause
it to exceed the equipment manufacturers' recommended maximum ratings.
A-65
4. SE PJM Management will employ qualified and competent operations,
maintenance and general management personnel and will provide such
personnel to SE Mid-Atlantic, which will generally operate the Generating
Facilities in a sound and businesslike manner.
5. Inspections, overhauls, repairs and modifications are planned for
and conducted in accordance with manufacturers' recommendations, and with
special regard for the need to monitor certain operating parameters to
identify early signs of potential problems.
6. All licenses, permits and approvals, and permit modifications
necessary to operate the Generating Facilities have been, or will be,
obtained on a timely basis and any changes in required licenses, or permits
and approvals will not require reduced operation of, or increased costs to,
the Generating Facilities.
7. The CPI-U and general inflation will increase at a rate of 2.6
percent per year based on an October 10, 2000 projection prepared by Blue
Chip Economic Indicators.
8. SE Mid-Atlantic will operate the Generating Facilities at the load
levels projected by Hagler Bailly, resulting in the annual average heat
rates assumed in the Projected Operating Results.
9. The quantities of market electricity sales and market prices of
electricity for the Generating Facilities will be as projected by Hagler
Bailly.
10. The price of SO\2\ allowances will be $150 per ton in 2000
dollars and will increase at the rate of inflation. The price of NO\X\
emissions allowances will be $1,000 per ton through 2002, $2,300 per ton in
2003, $2,000 per ton in 2004, and $1,700 per ton in 2005 and will increase
thereafter at the rate of inflation.
11. The cost of fuel of the Generating Facilities will be as
projected by Hagler Bailly.
12. The non-fuel operating and maintenance expenses, including the
cost of major maintenance, will be consistent with the projection provided
by SE Mid-Atlantic in 2000 dollars, and will increase at the assumed change
in the general inflation rate, except as noted otherwise in this Report.
13. The assumed quantity of emissions allowances will be allocated to
SE Mid-Atlantic through the term of the Lease.
14. The Generating Facilities will continue to sell quantities of ash
equal to historic quantities at prices equal to those under the existing
contracts, as estimated by SE Mid-Atlantic.
15. There will be no additional capital improvements to the
Generating Facilities other than those assumed in the Projected Operating
Results
16. The Fixed Charges will be as reported by Credit Suisse First
Boston.
CONCLUSIONS
Set forth below are the principal opinions we have reached after our
review of the Generating Facilities. For a complete understanding of the
estimates, assumptions, and calculations upon which these opinions are based,
the Report should be read in its entirety. On the basis of our review and
analyses of the Generating Facilities and the assumptions set forth in this
Report, we are of the opinion that:
1. The sites for the Generating Facilities are suitable for the
Generating Facilities' continued operation.
2. The Generating Facilities have been designed and constructed with
good engineering practices and generally accepted industry practices, and
the technologies in use at the Generating Facilities are sound, proven
conventional methods of electric generation. If operated and maintained as
proposed by SE Mid-Atlantic, the Generating Facilities should be capable of
meeting the currently applicable
A-66
environmental permit requirements. Furthermore, all off-site requirements
of the Generating Facilities have been adequately provided for, including
fuel supply, water supply, ash and wastewater disposal, and electrical
interconnection.
3. The Generating Facilities should have a useful life extending well
beyond the term of the Certificates.
4. The environmental site assessments of the sites for the Generating
Facilities were conducted in a manner consistent with industry standards,
using comparable industry protocols for similar studies with which we are
familiar.
5. The major permits and approvals required to operate the Generating
Facilities have been obtained and are currently valid or are in the process
of being renewed, and we are not aware of any technical circumstances that
would prevent the renewal of any permit.
6. By combining the demonstrated experience of the existing Pepco
personnel and programs and the experience of the Southern Energy operating
subsidiaries, SE Mid-Atlantic should have sufficient capability to operate
the Generating Facilities effectively. The operating programs and
procedures which are currently in place are consistent with generally
accepted practices in the industry, and the Generating Facilities have
incorporated organizational structures that are comparable to other
facilities using similar technologies.
7. Based on the operating history, a review of the operations and
maintenance practices and procedures, and general observations of the
plants, the Generating Facilities should be capable of achieving the
projected annual average net capacities, annual availability factors, and
net heat rates assumed in the Projected Operating Results.
8. The Generating Facilities appear to be operating in material
compliance with applicable environmental permits, approvals, consent
orders, laws, rules and regulations.
9. SE Mid-Atlantic's estimate of the costs of operating and
maintaining the Generating Facilities, including provision for capital
expenditures and major maintenance, is within the range of the costs of
similar plants with which we are familiar.
10. For the Base Case Projected Operating Results, the projected
revenues from the sale of electricity are adequate to pay annual operating
and maintenance expenses (including capital expenditures and major
maintenance), fuel expense, and other operating expenses. Such revenues
provide an annual coverage on the Certificates of at least 2.72 times the
annual Fixed Charge requirement (including Rent) in each year during the
term of the Certificates and a weighted average coverage of 5.05 times the
annual Fixed Charge requirement (including Rent) over the term of the
Certificates.
Respectfully submitted,
/s/ R. W. BECK, INC.
A-67
[THE ORIGINAL REPORT EXHIBITS HAVE BEEN REDACTED AND
REPLACED BY THE UPDATE LOCATED BEFORE THE REPORT]
A-68
Appendix B
Independent Market Expert Report
for the Mirant Mid-Atlantic
Assets in the PJM Region
Revised Report
Prepared by:
PA Consulting Services Inc.
(formerly PHB Hagler Bailly, Inc.)
1881 Ninth Street, Suite 302
Boulder, Colorado 80302
303-449-5515
Contact:
Todd Filsinger
Revised April 10, 2001
Executive Summary
S.1 Introduction
PA Consulting Services Inc. (PA) was retained by Mirant Corporation (Mirant)
to provide an Independent Market Expert Report (the Report) in connection with
the acquisition of certain electric generating facilities and related assets
from Potomac Electric Power Company (PEPCO). These assets are owned or leased by
Mirant Mid-Atlantic, LLC and its subsidiaries and affiliates and are referred to
herein as the "Mirant Mid-Atlantic Assets." The Mirant Mid-Atlantic Assets are
located in Maryland and Virginia and are in the Pennsylvania-New Jersey-Maryland
Interconnection LLC (PJM) electricity market. This Report assesses the future
prices for electric energy and capacity in the PJM electricity market and
presents the results of PA'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
predominant. Nevertheless, in both types of markets, new generating capacity
will be developed based on the revenue streams determined through competition.
The type of market that exists in a given region will determine the composition
of the revenue streams and will affect the mix and timing of new generating
units. However, 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.
Many of the vertically integrated utilities are divesting their generation
assets, and the 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 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.
Executive Summary . S-2
- --------------------------------------------------------------------------------
S.3 Forecasting Methodology
PA 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
Supply & Demand
Fundamental Analysis
. What is the average level of prices given the units in the market, fuel
prices, future demand, and changes in technology?
Volatility
Volatility
. What is the likely pattern of electricity prices?
. What is the likely pattern of fuel prices?
Dispatch
Dispatch
. Given the volatility in prices how can plants respond to these prices and
capture margins?
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.
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
Annual Trend
Annual Trend
. How do prices change, on average, with changes in fundamental drivers?
. Comes from the fundamental analysis
Structure
Structure
. What are the predictable pattern in prices?
. Comes from statistical analysis of price data
Fluctuations
Fluctuations
. How does uncertainty manifest itself in prices?
. Comes from traded options data
MVP(SM) uses a real options approach to value electric generating capacity,
thereby capturing 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). However,
unlike most option analyses, 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. A unit may also have constraints placed upon its
operation that limits 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.
Executive Summary . S-4
- --------------------------------------------------------------------------------
PA'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
. compensation for capacity, which represents the additional margin necessary
to keep an economic amount of capacity in the market
PA uses a detailed chronological production-costing model to simulate energy
price formation in the market area of interest. From the energy price analysis,
PA 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 PA'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 1.45% per year from 2001 through 2020./1/
Fuel prices. 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-Central region where the Mirant Mid-
Atlantic Assets are located. PA also has modeled near-term fuel prices (gas and
oil) based on recent actual spot prices and futures prices through December
2003, trending back to the long-term consensus view by 2005. Table S-1 displays
the price projection for gas in PJM-Central for this analysis.
__________________
1. MAAC Annual Electric Control and Planning Area Report, 2000
Executive Summary . S-5
- --------------------------------------------------------------------------------
------------------------------------------------------------------------------
Table S-1
Delivered Fuel Prices (real 2000 $/MMBtu)/1/
------------------------------------------------------------------------------
Fuel 2001/2/ 2005 2010 2015 2020
------------------------------------------------------------------------------
Natural Gas-PJM Central 5.55 2.92 3.07 3.15 3.22
------------------------------------------------------------------------------
Fuel Oil No. 2-PJM Central 7.14 4.56 4.65 4.85 5.02
------------------------------------------------------------------------------
Fuel Oil No. 6 PJM Central 4.63 2.98 3.03 3.16 3.27
------------------------------------------------------------------------------
1. The prices shown represent the prices for existing units. New units are
assumed not to pay LDC charges of $0.05/MMBtu to $0.10/MMBtu.
2. The 2001 delivered price is based on average daily NYMEX closing prices
from September 13, 2000 to December 12, 2000.
------------------------------------------------------------------------------
Capacity additions and retirements. PA estimates capacity additions and
retirements based on three main principles. First, near term (2001 through 2003)
capacity additions are based upon PA's investigation of new capacity addition
announcements through a review of publicly available sources of new capacity
addition information. These sources include newspapers, trade journals,
developer and utility web sites and contacts, industry news publications, etc.
PA has developed a database that tracks the status of new capacity additions and
evaluates the probability of announced projects actually being constructed.
Second, capacity additions from 2004 through 2020 are based on economic analyses
of generic new units, and units that are not competitive are retired in
accordance with the methodology described in further detail in Chapter 4.
PA's Base Case results incorporate PA's best estimate of new capacity additions
and retirements. The capacity and online dates for specific projects are
identified in Chapter 4. These unit assumptions are based on PA's best estimate
at the time the analyses are prepared. Due to deregulation of the electric
industry, changes in economic conditions, the volatile nature of the industry,
and the lead times associated with building new plants, these assumptions are
likely to deviate from what actually transpires. Individual unit characteristics
such as online dates, capacities, and even the projects themselves may change.
Projects may be canceled or new ones may be added.
The assumed capacity additions and retirements included in this analysis are
summarized in Table S-2.
Executive Summary . S-6
- --------------------------------------------------------------------------------
------------------------------------------------------------------------------
Table S-2
Capacity Additions and Retirements
------------------------------------------------------------------------------
Capacity Capacity Capacity
Additions Additions Retirements
Region 2001-2003 (MW) 2004-2020 (MW) 2001-2020 (MW)
------------------------------------------------------------------------------
PJM 5,730 20,940 6,431
------------------------------------------------------------------------------
S.5 Results and Conclusions
Using the assumptions presented in Chapter 4, PA developed a Base Case for each
region that reflects PA's best assessment of future market conditions. It should
be recognized that these cases will vary to the extent the input assumptions
change, and such assumptions should be reviewed with the same rigor as the
resulting forecast. The Base Case is described below:
. The Base Case incorporates the actual spot and futures gas and oil prices
through December 2003. Prices then decrease linearly to the consensus
forecast price in year 2005. This method is discussed in further detail in
Chapter 4.
In addition to the Base Case, PA developed three other sensitivity cases. These
sensitivity cases are intended to provide an indication as to how changes in
certain input parameters such as fuel prices and new capacity additions affect
forecasted price results. These sensitivities are not intended to be bounding,
or worst case scenarios. Their purpose is to determine the impact of an assumed
change on the price forecast results. The magnitude of the changes in input
parameters may be greater than or less than those assumed in the sensitivities.
However, the sensitivity cases can be used to provide some indication as to how
the assumed change in the input parameter affects the forecasted price value.
The three sensitivity cases evaluated are as follows:
. The Low Fuel Case evaluates the effects of lower gas and oil prices
represented as a $0.50/MMBtu reduction in the 2001 gas and oil prices with
escalation remaining unchanged (coal prices are not changed).
. The High Fuel Case evaluates the effects of higher gas and oil prices
throughout the study period. Gas and oil prices are held at the 2001 NYMEX
value throughout the study period.
. The Overbuild Case evaluates an over-exuberance of merchant plant
development in the regions reviewed. The merchant plant capacity added in
the overbuild case is listed in Table S-3.
Executive Summary . S-7
- --------------------------------------------------------------------------------
--------------------------------------------------------------------------
Table S-3
Overbuild Case Merchant Plant Capacity Additions (MW)/1/
--------------------------------------------------------------------------
Region 2001 2002 2003 2004
--------------------------------------------------------------------------
PJM 1,296 3,232 1,202 4,160
--------------------------------------------------------------------------
1. Capacity additions in 2001-2003 are the same as in the Base Case.
--------------------------------------------------------------------------
The all-in market price combines the energy price with the price received by
generators for other relevant generation services and energy products in the
market. The all-in price reflects PA's estimate of the total market price that
generators will recover in PJM-Central. The all-in price results of the study
are summarized in Figure S-3.
Figure S-3
PJM-Central Estimated All-In Price Forecasts/1/ ($/MWh)
[GRAPH]
1. Results are expressed in real 2000 dollars.
Contents
Executive Summary ........................................................................................... S-1
Chapter 1 Introduction
1.1 Background................................................................................. 1-1
1.2 Asset Description.......................................................................... 1-1
1.3 Structure of the Report.................................................................... 1-1
Chapter 2 PJM Market Structure
2.1 Introduction............................................................................... 2-1
2.2 Competitive Power Markets.................................................................. 2-1
2.2.1 Reliability and Competitive Markets............................................... 2-2
2.3 PJM (MAAC Region).......................................................................... 2-5
2.3.1 Market Structure in PJM........................................................... 2-6
Chapter 3 Approach to Market Price Forecasting
3.1 Introduction............................................................................... 3-1
3.2 Issues in Forecasting Market Prices........................................................ 3-1
3.2.1 Economic Equilibrium and Market Price Forecasting................................. 3-1
3.2.2 Capacity and Energy Markets....................................................... 3-2
3.2.3 Forecasting Generation Service Prices............................................. 3-5
3.3 Approach to Market Price Forecasting....................................................... 3-6
3.3.1 Market Characteristics............................................................ 3-7
3.3.2 Predicting Energy Prices and Dispatch............................................. 3-8
3.3.3 Predicting Prices Related to Capacity:
The Capacity Compensation Simulation Model........................................ 3-8
3.3.4 Market Entry and Exit............................................................. 3-9
3.3.5 Volatility Analysis............................................................... 3-10
Chapter 4 Assumptions
4.1 Introduction............................................................................... 4-1
4.2 General Assumptions........................................................................ 4-1
4.3 Pricing Areas.............................................................................. 4-1
4.4 Fuel Prices................................................................................ 4-1
4.4.1 Natural Gas....................................................................... 4-2
4.4.2 Fuel Oil.......................................................................... 4-6
4.4.3 Coal.............................................................................. 4-9
ii
4.5 Demand and Energy Forecasts............................................................... 4-11
4.6 Electricity Imports....................................................................... 4-12
4.7 Existing Generation Units................................................................. 4-12
4.7.1 Fossil Units..................................................................... 4-12
4.7.2 Hydroelectric Units.............................................................. 4-17
4.7.3 Nuclear Units.................................................................... 4-17
4.8 Capacity Compensation Simulation Model Input Assumptions.................................. 4-20
4.8.1 Existing Units Going-Forward Costs............................................... 4-20
4.8.2 Capacity Additions through 2003.................................................. 4-20
4.8.3 Capacity Additions Post 2003..................................................... 4-21
Chapter 5 Market Price Forecasts
5.1 Introduction.............................................................................. 5-1
5.2 Market Conditions......................................................................... 5-3
5.3 Price Forecasts for the PJM Market........................................................ 5-5
5.3.1 Base Case........................................................................ 5-5
5.3.2 Sensitivity Cases Analysis....................................................... 5-7
Appendices
A Pricing Areas
B Methodology for Coal Price Forecasting
C Transfer Capability
D Dispatch Curves
E New Capacity Additions
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Chapter 1
Introduction
1.1 Background
PA Consulting Services Inc. (PA) was retained by Mirant Corporation (Mirant)
to provide an Independent Market Expert Report (the Report) in connection with
the acquisition of certain electric generating facilities and related assets
from Potomac Electric Power Company (PEPCO). These assets are owned or leased by
Mirant Mid-Atlantic, LLC and its subsidiaries and affiliates and are referred to
herein as the "Mirant Mid-Atlantic Assets." The Mirant Mid-Atlantic Assets are
located in Maryland and Virginia and are in the Pennsylvania-New Jersey-Maryland
Interconnection LLC (PJM) electricity market. This Report assesses the future
prices for electric energy and capacity in the PJM electricity market and
presents the results of PA's analysis.
1.2 Asset Description
The generating facilities total approximately 5,200 MW (net) of generation in
the PJM-Central transmission areas. This generation includes approximately 4,100
MW of steam energy (70% of the steam generation is coal-powered, the remaining
30% has dual fuel capability), approximately 1,100 MW of combustion turbines
(30% of generation are powered by distillate fuel, and the remaining is powered
by gas).
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 four cases: the Base Case and
three sensitivity cases.
Introduction . 1-2
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. Appendix A illustrates the pricing areas for the Northeast Power
Coordinating Council (NPCC) and the MidAtlantic Area Council (MAAC).
. Appendix B supplements the fuel forecast presentation in Chapter 4 with
further details concerning regional coal pricing trends.
. Appendix C details regional energy transfer capabilities.
. Appendix D displays Dispatch Curves in PJM for 2001 and 2010.
. Appendix E identifies cumulative capacity additions and retirements.
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Chapter 2
PJM Market Structure
2.1 Introduction
In this chapter, PA examines the current and projected development of wholesale
power markets in PJM. Over the past two decades, the structure of the electric
power industry has been increasingly shaped by the emergence of a prevailing
market trend in the networked industries, namely the introduction of competition
in formerly regulated markets. This chapter sets the background for the
restructuring initiatives underway in the target markets examined in this study.
2.2 Competitive Power Markets
Much of the recent progress toward implementing competition in electricity
markets is due to a series of legislative and regulatory decisions rendered over
the past two decades. The legislative and regulatory framework behind the
development of competitive wholesale electricity markets in the United States
can be largely traced to the 1978 Public Utilities Regulatory Policies Act
(PURPA). This act spurred the growth of the non-utility generation industry and
increased wholesale competition, albeit on a limited scale due to transmission
ownership issues and other market access constraints. The 1992 Energy Policy Act
expanded wholesale competition by mandating transmission owners to provide "open
access" for all system users. Transmission access rights were further
strengthened in 1996 with Federal Energy Regulatory Commission (FERC) Open
Access Rule, Order No. 888 (Order 888). This order called for transmission
owners to offer "comparable service" to all customers through the application of
a pro forma transmission tariff. Order 888 also encouraged the creation of
Independent System Operators (ISOs), whose role in operating and managing
regional transmission assets is described in greater detail in this chapter.
However, even before Order 888 was drafted, the creation of ISOs and the
establishment of formalized competitive markets were already underway in
California and the Northeast.
Compared to other countries, which have adopted national plans for transitioning
to competitive power markets, the restructuring process in the United States has
progressed piecemeal, with significant differences between various regions. This
is largely due to the division of authority over various aspects of the electric
power industry between state and federal legislative and regulatory bodies.
The debate over retail access and other measures to implement market competition
has raised a number of fundamental market transition issues. Three of the
principle issues common
PJM Market Structure . 2-2
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throughout the country are (1) the assessment and allocation of stranded costs,
(2) the elimination of market power, and (3) the method for guaranteeing fair
and impartial access to the transmission system. These issues are briefly
discussed below.
Stranded costs can be defined as the positive excess of the net book value of
generation assets and power purchase costs over the market value of the assets.
The introduction of competition in formerly regulated electricity markets
presents a significant financial burden for utilities with generating assets or
power purchase contracts, which may now be priced out of the market. A large
number of utilities throughout the United States are faced with losses due to
the adoption of market pricing before they have had a chance to recover the cost
of their prior investments through their rate base. In order to ensure the
support of the utility industry in the restructuring agenda, many state utility
commissions and legislative bodies have agreed to allow utilities to recover
either all or part of their stranded costs through a number of different
recovery mechanisms. These recovery vehicles are designed to support the
introduction of competition while still allowing the affected utilities to
recover a specified portion of their expected losses over a fixed period of
time. However, the cost recovery method varies from state to state.
Despite two decades of Independent Power Producer (IPP) development, the
majority of the generation assets in the United States continue to be owned and
operated by vertically integrated investor-owned utilities. Within regional
electricity markets, the concentration of generating assets is often controlled
by a small number of incumbent utilities. The removal of regulation and the
introduction of market-based pricing into such markets raise concerns over the
potential abuse of market power. To relieve these concerns, federal and state
regulatory bodies have taken various measures to eliminate the threat of market
power. The principal means of dealing with market power has been the unbundling
of generation, transmission, and distribution assets. This is often followed by
the mandated sale of a certain amount of generation assets by the traditional
utilities to non-affiliated companies or the transfer of assets to an
unregulated subsidiary. Such generation auctions and negotiated sales have
resulted in the transfer of billions of dollars of generation assets in the past
few years, changing the face of the generation industry in many regions of the
country. The impact of current and future unbundling and generation ownership
transfers must be considered when analyzing long-term conditions in regional
power markets.
In addition to the recovery of stranded costs and elimination of market power,
the ability to reach newly opened markets through the high voltage transmission
grid at a fair price is a fundamental requirement for introducing true
competition. Thus, the issue of transmission access is at the core of the
restructuring movement.
2.2.1 Reliability and Competitive Markets
Much of the development of competitive market structures and system operations
in recent years has involved the balancing of system reliability concerns with
the desire to allow the market to drive the development of the electricity
industry. This balancing of market forces and reliability concerns is evident in
the transmission industry. The high-voltage transmission system and the
PJM Market Structure . 2-3
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corresponding bulk power markets in the United States were originally developed
to ensure reliability of supply rather than to support commercial transactions
and power trading. Stemming from the Northeast blackout of 1965, the utility
industry organized regional reliability councils to coordinate reliability
practices in the United States and parts of Canada and Mexico. The continental
United States is divided into 10 regional reliability councils whose policies
are, in turn, coordinated by the North American Electric Reliability Council
(NERC). The reliability councils are voluntary organizations that establish
guidelines for all member utilities and suppliers. Two of the principle
guidelines established by each council concern:
. Minimum operating reserves. Operating reserves represent generating units
that are maintained in a spinning or fast-start condition so that they can
rapidly respond to an outage at another unit or some other emergency
condition.
. Maximum area control error. Area control error is a measure of the
difference between actual and scheduled power flows. It is controlled to
maintain the standard operating frequency of the alternating current power
supply system and to prevent damage to generators and other equipment
connected to the grid.
The ten regional reliability councils are part of larger interconnected and
synchronized electric power systems. There are three synchronized electricity
networks in the United States:
. The Eastern Interconnection [ECAR, MAAC, MAIN, MAPP, NPCC (excluding
Quebec), SERC, SPP, and FRCC]
. The Western Interconnection (WSCC)
. Electric Reliability Council of Texas (ERCOT).
These systems are interconnected through limited DC ties, but their AC systems
operate independently of one another.
PJM Market Structure . 2-4
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Power Pools
While the regional reliability councils provide standards and guidelines, they
do not provide actual electricity dispatch, scheduling or other transmission
system operation services. In order to capture the economies of scale associated
with load and resource pooling as well as joint-dispatch and transmission
operations, utilities in a number of regions voluntarily established power
pools, the first of which, the PJM Power Pool, was established in 1927. Power
pools attempt to capture the benefits associated with being part of a larger
generation and transmission system, including improved reliability through
coordinated maintenance planning and shared operating reserves, as well as the
blending of load profiles and generating resources. Pools vary widely throughout
the United States in terms of the degree to which they provide coordination and
services.
While pooling arrangements were beneficial for reliability, it is possible that
they are not suitable for supporting and developing truly competitive
electricity markets. Due to their limited membership and strict membership
criteria, external marketers, power producers, and eventually regulatory bodies
viewed power pools as barriers to competition. Through Order 888, FERC is
actively encouraging the formation of ISOs that replace the power pool
organization in scheduling, dispatching and operating the regional transmission
system. The purpose of the ISO is to provide independent grid management through
a process in which all system users are treated equally. Many of the utilities
in the most tightly coordinated power pools in the United States were among the
first to file ISO applications with the FERC, but the ISO trend is now
progressing through the industry as an increasing number of states enact
legislation implementing retail access.
Independent System Operators
The creation of an ISO entails the transfer of management and operational
control of the transmission system to an independent administrator that has no
financial interest in the operation of the generating facilities using that
network. As interstate transmission organizations, new ISOs will fall under the
regulatory jurisdiction of FERC and must seek FERC approval for their
operations. The FERC regulations provide a strong motivation for establishing
ISOs, since a retail provider affiliated with an investor-owned utility which
has not satisfied the FERC-ISO criteria cannot compete for customers outside its
franchised service territory unless it maintains rates based on cost of service.
In connection with the approval process, FERC has created a list of criteria to
which ISOs must adhere. Two of the fundamental criteria of the proposed ISO
framework are the need to establish an independent governance structure for each
ISO and the application of a postage-stamp tariff for an entire ISO region which
would eliminate the payment of a transmission fee to each control area that is
involved in a transaction ("pancaking"). Independent governance of each ISO is
critical to the ability of such ISO to execute transactions in an unbiased
manner, applying the same service standards and prices to both incumbent
utilities and new market entrants. The application of a system-wide tariff is
also critical for competition. It establishes a level playing
PJM Market Structure . 2-5
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field in terms of transportation costs for all generators within an ISO's
territory, and it reduces the "pancaking" effect of wheeling power through such
ISO's territory.
The role of the ISO in a functioning spot market is critical to the efficient
operation of competitive markets. The spot market may be operated by either the
ISO or by a separate Market Operator (or Power Exchange). The spot market is
designed to provide a balancing function in which excess generation capacity is
matched to demand not already covered under existing bilateral contracts. This
balancing market allows wholesale suppliers and customers to hedge their
existing bilateral contracts with purchases from the spot market, while also
providing the ISO with a source for regulating capacity and emergency supply
through various market mechanisms. The specific characteristics of the regional
ISO and power markets will have a direct financial and operational impact on the
affected generating assets.
Several ISOs are already operating or under review by FERC, while several others
are in the development stage. However, only a few of these ISOs currently
incorporate a spot market function. There are currently five functioning ISOs in
the United States:
. California ISO (CA-ISO),
. PJM-ISO
. New England ISO (NE-ISO),
. ERCOT-ISO/1/
. New York ISO (which officially assumed control of the New York Power Pool
grid on November 18, 1999)
The Midwest ISO (MISO) was also conditionally approved by FERC in September 1998
and is expected to begin operations by the end of 2001. The Alliance RTO filed
for FERC approval as an ISO in June 1999. In addition, the Entergy Corporation
has proposed the creation of a for-profit transmission subsidiary (Transco), to
operate and manage its transmission assets in a manner similar to an ISO.
While each of the individual power pools are developing individually and have
different products, the final resulting economies will likely be similar. Thus,
PA approaches all regions with the same fundamental analysis (see Chapter 3).
The following section describes the structure of the PJM.
2.3 PJM (MAAC Region)
The PJM Power Pool was the first centrally dispatched power pool in the United
States and is currently the largest, handling about 8% of the electricity in the
United States with a combined capacity of over 56,000 MW. In addition, it is one
of the largest power pools in the world.
________________
1. ERCOT is not under FERC jurisdiction; the Texas Public Utility Commission
approved the ISO proposal.
PJM Market Structure . 2-6
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PJM covers all or part of the states of Pennsylvania, New Jersey, Maryland,
Delaware, Virginia, and the District of Columbia.
FERC Order 888 required public utilities that are members of tight power pools
such as the PJM Power Pool 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 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 was certified as an ISO by FERC on November 25, 1997, and it began
operations on April 1, 1998. PJM'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, PJM manages the PJM
Open Access Transmission Tariff (the first power pool open access tariff
approved by FERC), which provides comparative pricing and access to the
transmission system. PJM also operates the PJM Interchange Energy Market, which
is the region's spot market (power exchange, or PX) for wholesale electricity.
PJM also provides ancillary services for its transmission customers and performs
transmission planning for the region.
The PJM Bid-Based Energy Market was initiated on April 1, 1997, and Locational
Marginal Pricing (LMP) took effect on April 1, 1998. The PJM Capacity Credit
Market was launched on October 15, 1998. In 1999, PJM introduced market-based
prices for energy and certain ancillary services and in July of 1999 established
a market for Fixed Transmission Rights (FTRs).
2.3.1 Market Structure in PJM
The PJM wholesale market structure includes the following markets for the
services of generators:
. Energy Market
Day-Ahead Market
Balancing Market (Real Time)
. Energy Imbalance and Operating Reserves Market
. Regulation Market
. Capacity Credit Market
. Fixed Transmission Rights and the FTR auction.
PJM Market Structure . 2-7
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Until just recently, payments for providing regulation were grounded in
cost-based formulas. PJM has now implemented new market-based pricing for the
Regulation ancillary service. Payments for providing operating reserves are
included in daily energy market reconciliation.
Load Serving Entities (LSEs) have the obligation to provide or acquire installed
capacity, regulation, and operating reserves. In addition to PJM market
purchases, bilateral transactions are also allowed. 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 Power Exchange as follows:
. Locational Marginal Prices (LMPs) are determined based on the applicable
energy bids.
. Regulation prices that generators receive are based on their Unit
Regulation Offer and estimated opportunity cost for being available for
regulation.
. 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).
Energy Market
On June 1, 2000, PJM implemented a new system for its interchange Energy Market.
PJM's Energy Market has been converted from a Real-time transaction market into
a dual settlement operation. The new market is split into essentially two
pieces: The Day-Ahead Market and the Balancing (Real-time) market.
The Day-Ahead Market. The advantage of this new system is that it allows
participants to achieve greater price certainty by being able to buy and sell
energy and capacity at binding day-ahead (future) prices. It also allows for the
scheduling of congestion charges a day in advance. Bilateral agreements will
also be able to schedule congestion charges in the day-Ahead Market. The
congestion charges can be calculated by taking the difference in LMP between the
load bus and generation bus.
LSEs submit hourly demand schedules for the next day. All bids and offers must
be made by noon the day before the day of operations. By 16:00, all prices are
posted and the real-time market bidding is then opened. At 18:00, the real-time
and Regulations markets are closed.
PJM Market Structure . 2-8
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Generators must submit their schedules if they are capacity resources, unless
they are self-scheduled or have planned outages. All other generators can bid
into the market as they wish. The PJM ISO will calculate, based on bids, offers
and market conditions, the LMPs for each hour of the day.
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 the generation level. The bid curve is specified
by up to 10 price-quantity pairs.
The Balancing Market (real-time). After all bids and offers are settled and the
marginal prices have been calculated, generators that were not used can bid into
this market at new prices. Prices are again determined by market conditions.
Essentially because the actual demand that will occur in real time is not known
the previous day, scheduled generation will often differ from actual generation
dispatch and so the balancing market corrects for the differences.
LSEs will pay balancing prices for any unscheduled demand and receive revenue
for demand less than the scheduled quantity from the Day-Ahead Market.
Generators will be paid for generation above their scheduled obligations at
balancing prices and must pay for any generation not used. Transmission
customers pay for congestion charges for any quantity deviations.
Transmission customers may submit external bilateral transaction schedules and
may indicate willingness to pay congestion charges into either the Day-Ahead
Market or Balancing Market. In the Day-Ahead Market, a transaction shall
indicate willingness to pay congestion charges by submitting the transaction as
an `up to' congestion bid.
In the past, bids into the market were capped at cost. Thus, generators bidding
into the 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 online. The no load
cost bid, also mostly fuel costs, was capped at the costs incurred to maintain a
generator at minimum load after it had 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, and in June of 2000, the spot market was switched
to the Two-Settlement Market. Generators continue to provide three-part bids,
but these bids are not necessarily capped at cost. While bids are no longer
capped at cost, they are subject to a $1,000/MWh ceiling cap. The PJM PX bidding
rules allow generators to submit different energy bids for each hour, and
generators can submit a new set of bids daily. However, a generator's start-up
and no-load bids, once submitted, remain in effect for six months at a time.
PJM Market Structure . 2-9
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PJM also uses the energy bids to determine in real time the LMPs for each point
of energy injection/withdrawal on the system for each hour. LMPs reflect the
costs associated with the out-of-order dispatch due to transmission congestion.
Congestion occurs when the transmission system becomes constrained, and some
generating capacity is dispatched while other generating capacity with lower
bids is not dispatched. The result is that the market-clearing prices may differ
from location to location. LMPs are quoted in dollars per megawatt-hour ($/MWh)
and are based on bids for generation, actual loads, scheduled bilateral
transactions, and transmission congestion.
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 reliable system operation. PJM
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. PJM currently requires approximately 1,100 MW of
spinning reserves, an amount that provides for 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 requirement for primary reserves
is approximately 1,700 MW (including 1,100 MW of spinning reserve), and the
requirement for thirty-minute reserves is approximated based on an amount equal
to 10% of the forecast daily peak load.
Regulation Market
PJM has just created a market for providing regulation of the system. For these
units made available to meet performance standards and the short-term load
fluctuations in the PJM control area they are now able to realize benefits above
just their opportunity costs for being a regulating generator. To be eligible
for regulation, generators must be within the PJM control area. Information
about your regulating status, capability, limits, and price (capped at $100/MWh)
applicable for the entire 24 hour period for which it is submitted, must be made
by 6:00 p.m. through the Two-Settlement Market User Interface (MUI). The offer
of the last unit needed to fulfill the MW regulation requirement (the marginal
unit) will set the market price for that hour.
The PJM Regulation Requirement is 1.1% of the day-ahead peak load forecast for
the op-peak period and the valley load forecast for the off-peak period. LSEs
may fulfill their regulation obligations by self-scheduling their own resources,
entering into contractual arrangements with other market participants, or
purchasing regulation from the regulation market just described. Regulation
obligation for each LSE is determined by its load ratio share.
PJM Market Structure . 2-10
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Capacity Credit Market
To ensure that sufficient capacity is available in the market to meet
reliability standards, PJM requires LSEs to own or contract with the owner of
generation capacity to cover their peak demand and reserve margins.
There are two capacity obligations. An LSE's installed capacity obligation is
determined two years in advance by PJM 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.
The amount of capacity each generator can supply is determined by a twelve-month
rolling average of availability, calculated two months in advance of the period
for which the capacity is supplied. Availability statistics are kept by PJM.
These statistics are averaged over the past twelve months and applied to the
"planned-for" obligation two months hence.
External resources may be designated as resources to meet the capacity
requirement. These resources, however, must: (1) be rated on 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 PJM for scheduling and
dispatch. Should the resource not be made available to PJM, it adversely affects
the resource's availability rating.
If an LSE fails to meet its capacity requirement, a penalty will be assessed.
The PJM Capacity Credit Market allows Market Participants to buy and sell
Capacity Credits through a process that establishes a market-clearing price.
Capacity acquired in the Capacity Credit Market satisfies the "accounted-for"
obligation. The PJM Capacity Credit Market consists of both the Daily and
Monthly Markets. 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, i.e.,
the bids are for the following day. Currently, a mandatory aspect to the
Day-Ahead Market is in effect. If a participant does not submit adequate "bids
to buy" or "offers to sell" to cover its projected deficient or excess, PJM will
submit a corresponding "bid" or "offer" to cover the projected position.
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. PJM 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 position of a participant for the
market day estimated at 10:05 a.m. on the day the market is run. If a
participant has a deficient position, PJM will only accept buy bids up to the
deficiency amount. If a participant has an excess
PJM Market Structure . 2-11
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position, PJM 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.
Monthly Market Operation. In addition to the Daily Market, 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.
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 that the market accepts bids. PJM 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. There are currently two Multi-Monthly Markets, a
seven-month and a twelve-month. Multi-Monthly Market bids are accepted on a
scheduled day approximately four months prior to the beginning of the
multi-monthly period.
Fixed Transmission Rights
Fixed Transmission Rights (FTRs) are available to all PJM Firm Transmission
Service customers (Network Integration Service or Firm Point-to-Point Service),
since these customers pay the embedded cost of 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 Transmission customers to rebates of congestion charges paid by the
Firm Transmission Service customers. FTRs 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.
In July of 1999, the first financially binding FTR auction was held in PJM.
Participants are now able to view all prices and constraints on the internet at
the eFTR. Prices are set on the first of every month and their values are
determined based on day-ahead Locational Marginal Prices between generation and
load busses. Each monthly period has an auction for both the trading of FTRs for
on-peak and off-peak periods in the week. On-peak times are from 7:00 a.m. to
11:00 p.m., Monday through Friday, and off-peak times include all other hours
and weekends.
- --------------------------------------------------------------------------------
Chapter 3
Approach to Market Price Forecasting
3.1 Introduction
This chapter discusses PA's approach to forecasting market prices for the
services of generating 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 market prices. The third section summarizes the
methodology used for estimating market prices for electricity in this analysis.
3.2 Issues in Forecasting Market Prices
This section discusses several issues that form the basis for PA's approach to
market price forecasting. The first of these issues is the concept of economic
equilibrium and how it suggests that the market will react to returns on equity
(or lack thereof). The second has to do with the components of revenue that are
present in our forecasts. Each of these topics is addressed below.
3.2.1 Economic Equilibrium and Market Price Forecasting
A fundamental tenet of PA's market price forecasting approach is that markets
are attempting to adjust to economic equilibrium conditions. By economic
equilibrium, we mean that the market will attempt to exploit or capture excess
margins through entry (e.g., when the return on equity is above market), and
will attempt to increase margins where they are below market through exit. In
other words, excess returns should not persist because someone will enter to
capture a portion of the above market return.
While the concept of economic equilibrium is sound in principle, actual markets
may not follow economic equilibrium exactly. Many industries have shown cycling
returns, where high returns are followed by excess entry resulting in low
returns which are followed by a disincentive to invest which results in high
returns. While such cycling and overshooting is often a characteristic of
commodity markets, these markets are, in general, attempting to adjust to a
level commensurate with economic equilibrium -- that is, they cycle around the
price level suggested by economic equilibrium.
To explore the implication of such "disequilibrium" conditions, we generally
construct an overbuild scenario where excess entry is presumed to occur. Excess
entry is presumed to occur early in the study period, as the impacts on
generation assets are likely to be most severe in this
Approach to Market Price Forecasting . 3-2
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timeframe. Subsequent to this period of capacity abundance, we then examine how
the market might return to economic equilibrium.
3.2.2 Capacity and Energy Markets
One must consider the institutions that define the electric market in order to
make market price forecasting relevant. Some electric markets, such as those in
the Northeastern United States (New York, PJM, New England) and England and
Wales, provide separate compensation for energy and capacity. Generators have
the opportunity to recover their variable costs and going-forward costs/1/ from
the energy market and in the capacity market. This market structure encourages
generating capacity and provides for fair market compensation.
Other electric markets, such as Australia, New Zealand and many regions of the
United States, are energy only markets where the market does not separately pay
generators for their installed capacity./2/ In theory, an energy only market
leads to economically efficient capacity levels in the long run. As long as
prices rise sufficiently to allow the generators in the market to recover their
variable costs and going-forward costs, the average energy price should cover
the costs of new capacity, even if there is no separate capacity payment
delivered from either a traded capacity market or administered by the market
operator.
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 structure of U.S. electricity markets is evolving and new forms of market
organization have been adopted in areas such as California and the Northeast and
are proposed for the Midwest and ERCOT. These structures will continue to evolve
as electricity 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.
__________________
1. Going-forward costs are those costs that a generator cannot avoid if they
remain in the market, such as fixed operation and maintenance (O&M), property
taxes, employee benefits, and incremental capital expenditures. These costs do
not include a return on capital or debt service, as these costs are deferrable
on capital that is already committed to the marketplace (e.g., sunk).
2. 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.
Approach to Market Price Forecasting . 3-3
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Although no region in the United States has a fully mature market today, there
is an emerging worldwide consensus on what a competitively restructured
electricity industry should look like. Principle facets of the market should
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, RTO, or a TRANSCO
. some form of "congestion or locational pricing" (either zonal or nodal)
to deal with transmission congestion in a market-based fashion
. formation of a power exchange with, at a minimum, an hourly spot
market.
In addition, a competitive market should allow for effective competition among
generators, with minimal abuse of market power./3/
Relationship between Energy Markets and Compensation for Capacity
The United States is currently experimenting with both markets that have fixed
reserve margin requirements coupled with capacity markets and those that
implicitly price capacity through high on-peak energy prices. 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.
In electric markets, such as PJM, New York, or New England, where load-serving
entities are required (by administrative rule) to own or contract to for 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 have been developed to support trading of this
capacity, typically in the form of daily, monthly or annually traded capacity,
for which generators are compensated for being available to produce if and when
required. In such markets, generators attempt to cover their total going-forward
costs through a combination of revenue from energy, capacity, and ancillary
service markets as well as through sale of options and forwards on a bilateral
basis.
In market structures without an explicit capacity market (such as California),
generators must place greater weight on recovering their going-forward costs
from the energy market. Were capacity to trade in a market with a capacity
obligation for significant amounts of revenue, one
___________________
3. Ideally, the wholesale market would be competitive with no presence of market
power. However, electricity is not quite a pure commodity, as it must be
produced in real time with no inventory. This leads to the circumstance that
location matters in electricity as it does in real estate. Such a spatial market
cannot avoid the periodic presence of market power, but such occurrences should
be, ideally, minimal.
Approach to Market Price Forecasting . 3-4
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would expect that a market without a capacity market would have more volatile
prices than one that has a capacity market.
How Are Generators Compensated for Capacity in an Energy-Only Market?
As mentioned above, one would expect that price volatility would be higher in a
market that does not provide a meaningful stream of revenue as a capacity
payment. This is because the marginal plants (e.g., the last few generators
needed to support reliability) would need to increase their bids above their
costs in order to earn a sufficient margin when they are called upon to generate
to cover their going-forward costs. In low load hours, however, there is an
abundance of capacity present in the marketplace, and prices are more likely to
be driven to marginal cost.
Volatility in the spot market affects pricing in the forward market and for
options. Because of the volatility in spot prices, marginal generators, who
might not be expected to run but for a few hours, may be able to sell call
options for power with high strike prices. These options may, or may not,
actually be "in the money," but market participants may be willing to buy these
call options as a hedge against the possibility of even higher market prices.
These contracting mechanisms, fostered from volatile spot prices, provide the
means for some of the marginal plants to recover their going forward costs. They
also provide the mechanism for the market to secure an economic level of
reserves to meet peak demand. In addition to option contracts and energy prices
being set above the marginal cost of the price setting plant, generators can
also be compensated for capacity through ancillary services.
Price Volatility and Capacity Markets
Even in markets with capacity obligations and a traded capacity market, energy
prices have been quite volatile. This price volatility stems from an intrinsic
characteristic of electricity: because there is no inventory, electricity must
be produced in real time. This means that errors in forecasting demand or plant
commitment, failures in equipment, and market perceptions amplify price
movements. This has led to electricity having the most volatile spot prices of
any commodity traded.
Approach to Market Price Forecasting . 3-5
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3.2.3 Forecasting Generation Service Prices
Irrespective of where the debate on the future and viability of capacity markets
lies, PA produces forecasts of generation service prices by examining two
components of value in our fundamental analysis:
. Energy based on a production-cost model with prices reflecting marginal
cost in each hour.
. Compensation for capacity, which represents the additional margin
necessary to keep an economic amount of capacity in the market. This
compensation for capacity is not the same as a capacity price in a
traded capacity 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 option 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, the sum of the compensation for capacity and the market
price for energy will ultimately reflect what customers are willing to pay for
both energy services and reliability. It is PA's belief that the majority of the
compensation for capacity actually arises through energy prices that are higher
than marginal cost (and hence our energy price forecast) for some substantial
portion of hours.
Actual market price results support this belief. Figure 3-1 presents a graph of
market prices in the PJM market in February 2000. This month was selected since
it is one of the lowest load months in PJM, and prices should not be reflecting
much in the way of a "scarcity premium" associated with insufficient generation
to cover demand.
What is abundantly clear is that generators do not simply bid their marginal
cost of generation under all circumstances -- were it the case that such bidding
strategies were employed, one would expect that the price results in Figure 3-1
would be closely clustered around the line representative of marginal cost.
Rather, there is considerable dispersion in the data, particularly in the higher
load hours where marginal generation has a greater ability to support a price
above marginal cost.
The terms "compensation for capacity" and "energy price" as used in this report
reflect the prices needed by the marginal units to recover their variable and
going-forward costs. These prices together form the all-in price received by
generators to meet all of their going-forward costs. Compensation for capacity
and energy prices are inversely related; as one rises the other falls, so that
the all-in price remains somewhat in balance.
Approach to Market Price Forecasting . 3-6
- --------------------------------------------------------------------------------
Figure 3-1
Price vs. Load - PJM West, February 2000
[GRAPH]
3.3 Approach to Market Price Forecasting
Projecting electric market prices (and generation product sales) requires PA to
consider not only price formation in the market, but also the issues of market
entry and exit. Figure 3-2 provides a graphical view of PA's process for
producing electric market price forecasts. 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 PA's approach to each
of these steps.
Approach to Market Price Forecasting . 3-7
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Figure 3-2
Approach to Developing Compensation for Capacity and Energy Prices
Compensation
for
Capacity
Market Capacity
Characteristics Compensation
and Energy
Price
Energy Entry,
Price, Exit
Dispatch
3.3.1 Market Characteristics
The first step is to understand the nature and parameters of the market and the
generation assets that participate in that market. PA uses a variety of data
sources to characterize the market. These include:
. Published data. This data identifies the generating units, consumer
demand and load, and production capacities of existing plants.
. Fuel price forecasts.
. Planned additions. PHB identifies new additions that are assumed to be
online prior to 2003 based on a detailed review of the announced plans
of developers (tracked in the PA IPP Database) and utilities (contained
in planning council reports). Capacity additions after 2002 are tested
in the entry and exit logic.
. Retirements of nuclear plants. PA reviews the experience of nuclear
power plant operators (tracked in the PA 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).
Approach to Market Price Forecasting . 3-8
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3.3.2 Predicting Energy Prices and Dispatch
PA uses a detailed chronological production-cost model to simulate energy price
formation in the market area of interest based on short-run marginal costs.
From the energy price analysis, PA determines the net energy margins (price
minus variable cost) for each generating unit in the market. These margins,
along with estimates of "going-forward costs," are used in the Capacity
Compensation Simulation Model to predict the additional margins related to the
provision of capacity.
3.3.3 Predicting Prices Related to Capacity:
The Capacity Compensation 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 the projection
of market prices. First, if generators bid their short-run marginal costs into
an energy market, only inframarginal plants (those not on the margin) earn a
contribution toward their going-forward costs. Plants at the top of the supply
curve receive little, if any, contributions toward their going-forward costs. In
addition, 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.
PA predicts a value for compensation of capacity using PA's proprietary Capacity
Compensation Simulation Model. This model presumes that the market will retain a
sufficient amount of capacity to meet economic reliability targets. In other
words, PA simulates a capacity market consisting of a supply curve and a demand
curve for reliability (or capacity) services. PA assumes a competitive market,
and that the market-clearing compensation for capacity is determined by the
intersection of the supply and demand curves. PA constructs supply and demand
curves for each year in the simulation time horizon.
The supply curve is developed based on all of the generators in the market. For
each generating unit, the net of going-forward costs and energy market margins,
expressed on a per-kilowatt basis, are calculated. These net costs 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 contribution that the market would support in that year. The
capacity contribution forecast is the capacity payment derived for each year of
the study period. A sample supply and demand curve for a hypothetical year is
shown in Figure 3-3.
Approach to Market Price Forecasting . 3-9
- --------------------------------------------------------------------------------
Figure 3-3
Example Supply and Demand Curve
[GRAPH]
3.34 Market Entry and Exit
It is necessary to assess the feasibility and timing of new capacity additions
as well as the exit of uneconomic existing capacity. PA'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, PA'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
Approach to Market Price Forecasting . 3-10
- --------------------------------------------------------------------------------
simulations and compensation for capacity determined from the Capacity
Compensation Simulation approach. For each increment of new capacity, a "Go" or
"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 specific 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 Compensation Simulation is then performed. Results
for energy and capacity compensation are combined in the DCF model to determine
whether the new unit is a "Go" or "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 "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, combining the
results of the energy and capacity compensation. If the operating profit (loss)
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 loss. Although the
decision criterion is somewhat subjective, it is interpreted conservatively.
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.
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 enables the
introduction of new units. Since the addition of new units is "lumpy," the
iteration generally stops with new generators earning a small increment above
their cost of debt and equity. The addition of one more new unit 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 deficiency after the most recent new unit addition. This approach reflects a
game theoretic concept of market equilibrium.
3.3.5 Volatility Analysis
The standard method for valuing specific electric generating units uses
discounted cash flows constructed from production-cost models. By 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. Further, production-cost models may underestimate the volatility of
electricity prices. This is illustrated by a comparison of historical prices
from the spot market (Figure 3-4) with forecast prices from a production-cost
model (Figure 3-5). 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.
Approach to Market Price Forecasting . 3-11
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Figure 3-4
PJM Hourly Energy Prices, Summer 1999
[GRAPH]
Figure 3-5
PJM Hourly Energy Prices, Production-Cost Model, Summer 1999
[GRAPH]
Approach to Market Price Forecasting . 3-12
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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 underestimate the effects of price volatility, we present the
following simplified example of a power system dispatch 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)
. sub-optimal dispatch decisions by the system operator
. bidding behavior (i.e., the generator submits a bid which departs
from marginal cost).
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 3-6a. 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,
PA will approximate the continuous distribution of demand with the discrete
distribution shown in Figure 3-6b.
Approach to Market Price Forecasting . 3-13
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Figure 3-6
Two Different Approaches to Modeling Hourly Demand
Figure 3-6a Figure 3-6b
[GRAPH]
Production-Cost Model Simulation Results
Based on the representation of expected demand, shown in Figure 3-6a, and the
target generator's cost curves, a conventional production-cost model will
simulate the system hourly dispatch as shown in Figure 3-7.
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.
Approach to Market Price Forecasting . 3-14
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Figure 3-7
Dispatch Results Simulated by a Conventional Production-cost Model
Production cost model assumes demand is certain
--------
Hourly $20.50/MW
System
Marginal
------------ Price ----------
------ Hourly (SMP) Hourly $100.00*
Base Commit, -------- Target
Case Dispatch of Unit
Input Region ----------- Margin
------ ------------ Hourly ----------
Target Unit
Regional Generation 200 MW
Demand: (G)
30,000 MW -----------
-------------------------------------
*Assumes target unit production cost = $20/MWh
Real World Results
Now, consider what actually happens in the real world when demand uncertainty
manifests itself. Representing the possible states of the demand variable as
shown in Figure 3-6b, and combining that with the target generating unit's cost
characteristics, yields the results shown in Table 3-1. Because the operator has
the flexibility to adjust the output of the plant to avoid losses and capture
margins, the expected value of the margin is greater than the result captured in
the production-cost model.
Approach to Market Price Forecasting . 3-15
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- -------------------------------------------------------------------------------------------------------------
Table 3-1
Possible Target Generating Unit Profit Levels
- -------------------------------------------------------------------------------------------------------------
Target Generating Unit
System Marginal --------------------------------------------------------
Demand Price Sales Average Cost Profit Margin Profit
Likelihood (MW) ($ per MWh) (MWh) ($ per MWh) ($ per MWh) ($)
- -------------------------------------------------------------------------------------------------------------
10% 28,000 $19.50 0 $20.00 ($0.50) $ 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 insights into the value of volatility. 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 presumes 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 can provide
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 (is
Approach to Market Price Forecasting . 3-16
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"at the money") will have higher volatility value than a plant with similar
flexibility, but which has lower or higher operating cost.
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
PA has developed a proprietary market valuation process, MVP(SM), to estimate
the value of electric generation units based upon the level of prices and their
volatility. As shown in Figure 3-8, MVP 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 3-8
PA's Market Valuation Process (MVP(SM))
------------------- ----------------------
Characterize Examine How
Electric and Fuel + Generator Responds = MVP
Price Volatility to Price outcomes Value
------------------- ----------------------
------------------- ----------------------
Assumptions Simulate
and Market + Market with = - DCF
Characteristics Production Value
------------------- Cost Model =======
--------------------- MVP Value
Incremental to
DCF Analysis
Note that MVP 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 integrates the two approaches to create a better estimate of the value a
generating unit by accounting for both volatility effects and changes in the
fundamental drivers of electricity prices.
Approach to Market Price Forecasting . 3-17
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MVP 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 options on the spread between electricity
prices and the variable cost of production (which is largely fuel). Unlike most
option analysis, 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 focuses on the ability of the
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. PA
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 energy market 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.
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, PA 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
PA's Capacity Compensation Simulation Model to develop the annual capacity
contribution.
4.2 General Assumptions
The following general assumptions were 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 2000 real dollars. All results are in
2000 real dollars unless specified otherwise.
4.3 Pricing Areas
Transmission areas for the NPCC and MAAC regions are defined in Appendix A.
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.
________________________
1. MULTISYM is a product developed by Henwood Energy Services, Inc. (HESI).
Assumptions . 4-2
- --------------------------------------------------------------------------------
4.4.1 Natural Gas
The primary inputs into the analysis were forecasts2 from The Energy Information
Administration (EIA),3 The Gas Research Institute (GRI),4 The WEFA Group (WEFA)
and Standard and Poor's (S&P). Table 4-1 outlines the Henry Hub projection from
each of the four source forecasts as well as the consensus forecast of natural
gas prices at the Henry Hub.
- ------------------------------------------------------------------------------
Table 4-1
Henry Hub Projections (real 2000$/MMBtu)
- ------------------------------------------------------------------------------
2000 2005 2010 2015 2020 Average Annual
Growth Rate
- ------------------------------------------------------------------------------
EIA 2.56 2.76 3.06 3.19 3.31 1.29%
- ------------------------------------------------------------------------------
GRI 2.44 2.15 2.09 1.97 1.85 -1.37%
- ------------------------------------------------------------------------------
S&P 2.61 2.24 2.36 2.57 2.75 0.26%
- ------------------------------------------------------------------------------
WEFA 2.65 2.50 2.70 2.79 2.86 0.38%
- ------------------------------------------------------------------------------
Consensus 2.56 2.41 2.55 2.63 2.69 0.25%
- ------------------------------------------------------------------------------
While the projections above represent industry standard market information on
long-run equilibrium price, the natural gas market can exhibit extended periods
where supply and demand are not in balance and prices can fluctuate
significantly. The recent unprecedented price levels indicate that the market is
currently in just such a period of transition. Figure 4-1 shows historical gas
prices for the Henry Hub for 1999 and 2000. Gas prices have increased
substantially in recent months.
As a result of the recent gas price increase, PA has modeled near-term prices
based on recent actual spot prices and futures prices through December 2003,
decreasing linearly to the long-term consensus view in 2005. Table 4-2 displays
the near-term price projection.
__________________
2. EIA, Annual Energy Outlook 2000, December 1999; GRI 2000 Baseline Projection,
November 1999; The WEFA Group, Natural Gas Outlook 2000, April 2000; S&P Platt's
US Energy Outlook, Fall-Winter 1999-2000.
3. The EIA does not explicitly forecast a Henry Hub price. The EIA Henry Hub
projection is an estimate based on the EIA lower-48 wellhead price forecast and
the historic relationship between that wellhead price and the Henry Hub price.
4. The GRI forecast includes price projections only through 2015. The 2020 price
is an estimate based on the 2015 price and the GRI price escalation pattern from
2010 through 2015.
Assumptions . 4-3
- --------------------------------------------------------------------------------
Figure 4-1
Henry Hub Gas Prices 1999-2000
[GRAPH]
--------------------------------------------------------------------------
Table 4-2
Henry Hub Projections Using NYMEX Prices/1/
(real 2000 $/MMBtu)
--------------------------------------------------------------------------
Year Henry Hub Projection/2/
--------------------------------------------------------------------------
2001 4.81
--------------------------------------------------------------------------
2002 4.19
--------------------------------------------------------------------------
2003 3.84
--------------------------------------------------------------------------
2004 3.13
--------------------------------------------------------------------------
1. Based on average daily closing prices from 9/13/00 to 12/12/00.
2. Real 2000 $/MMBtu.
--------------------------------------------------------------------------
Assumptions . 4-4
- --------------------------------------------------------------------------------
Regional prices throughout the United States were projected based on this
consensus Henry Hub forecast. For all regions modeled, the delivered price is
the sum of the Henry Hub projection, the projected regional basis differential,
and other natural gas supply costs including all taxes.
Basis Differentials
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.
Regional market prices for natural gas are based on this Henry Hub forecast and
historic (1994-1999) and projected spot price differentials. Projected changes
in the basis differentials are a result of increased integration of natural gas
supply centers, changes in regional demand levels and increased deliverability
in some areas resulting from new pipeline construction. Table 4-3 presents the
NPCC/MAAC reference hub assignments used in the analysis.
- -------------------------------------------------------------------------------------------------------------------
Table 4-3
Reference Hub Assignments for Differential Analysis
- -------------------------------------------------------------------------------------------------------------------
Region Reference Hub GRI Region
- -------------------------------------------------------------------------------------------------------------------
PJM East NY Citygate Middle Atlantic
- -------------------------------------------------------------------------------------------------------------------
PJM West Pittsburgh Citygate/CNG North Middle Atlantic
- -------------------------------------------------------------------------------------------------------------------
PJM Central Average of PJM East and PJM West Middle Atlantic
- -------------------------------------------------------------------------------------------------------------------
New York-East/1/ NY Citygate Middle Atlantic
- -------------------------------------------------------------------------------------------------------------------
New York-West Pittsburgh Citygate/CNG North Middle Atlantic
- -------------------------------------------------------------------------------------------------------------------
NEPOOL/2/ Boston Citygate New England
- -------------------------------------------------------------------------------------------------------------------
1. Includes In-City and Long Island transmission areas.
2. Comprised of Maine, Southeast, and West transmission areas.
- --------------------------------------------------------------------------------
Additional Natural Gas Supply Costs
In addition to the regional commodity cost, natural gas price inputs also
include an additional liquidity premium of $0.05/MMBtu ($2000) designed to
account for the fact that units are not necessarily located at a major trading
hub. As a result, units are likely to pay some premium over prices available at
major pipeline intersections. This premium is expected to remain constant over
the forecast horizon in the Northeast.
As electric industry deregulation pressures generators to reduce costs, new
gas-fired applications will be located so as to minimize fuel costs. As a
result, new capacity will have an incentive to
Assumptions . 4-5
- --------------------------------------------------------------------------------
locate on the interstate pipeline system in order to avoid both Local
Distribution Company (LDC) charges and operating pressure concerns. Therefore,
it is assumed that new plants will be sited to take advantage of direct
connections to interstate pipeline systems. Existing units in the model are
assumed to incur LDC charges of $0.10/MMBtu in 2000, declining to $0.05/MMBtu by
2020. In addition, New York City units pay an additional tax on all natural gas
consumed.
Some baseload gas-fired plants, however, may incur fixed costs 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./5/ The total delivered price of natural gas in each market
region is presented in Table 4-4.
- -------------------------------------------------------------------------------------------------------------------
Table 4-4
NPCC/MAAC Delivered Natural Gas Price (real 2000 $/MMBtu)/1/
- -------------------------------------------------------------------------------------------------------------------
Pricing Area 2001/2/ 2005 2010 2015 2020 Average Annual Growth
Rate
- -------------------------------------------------------------------------------------------------------------------
PJM East 5.53 2.93 3.07 3.15 3.22 -0.05%
- -------------------------------------------------------------------------------------------------------------------
PJM West 5.39 2.82 2.96 3.05 3.11 -0.13%
- -------------------------------------------------------------------------------------------------------------------
PJM Central 5.55 2.92 3.07 3.15 3.22 -0.08%
- -------------------------------------------------------------------------------------------------------------------
New York-East/3/ 5.62 2.97 3.12 3.20 3.26 -0.05%
- -------------------------------------------------------------------------------------------------------------------
New York-West 5.32 2.78 2.92 3.00 3.07 -0.11%
- -------------------------------------------------------------------------------------------------------------------
New York-InCity 5.75 3.04 3.19 3.27 3.34 -0.04%
- -------------------------------------------------------------------------------------------------------------------
NEPOOL/4/ 5.78 3.05 3.19 3.28 3.34 -0.14%
- -------------------------------------------------------------------------------------------------------------------
1. The prices shown represent the prices for existing units. New units are
assumed not to pay LDC charges of $0.05/MMBtu to $0.10/MMBtu.
2. The 2001 delivered price is based on average daily NYMEX closing prices from
September 13, 2000 to December 12, 2000.
3. Includes the Long Island transmission area.
4. Comprised of Maine, Southeast, and West transmission areas.
- --------------------------------------------------------------------------------
_____________________________
5. EIA, Challenges of Electric Power Industry Restructuring for Fuel Suppliers,
September 1998, p. 65.
Assumptions . 4-6
- --------------------------------------------------------------------------------
Natural Gas Price Seasonality
Natural gas prices exhibit significant and predictable seasonal variation.
Consumption increases in the winter as space heating demand increases and falls
in the summer. Prices follow this pattern as well; the seasonal pattern is most
striking in cold weather locations. Dispatch prices in the model reflect the
seasonal effects based on five-year historic price patterns exhibited at the
regional market centers.
4.4.2 Fuel Oil
The fuel oil forecast methodology is described below for No. 2 Fuel Oil and No.
6 Fuel Oil. Prices are developed based on a consensus of crude oil by major
forecasters as presented in Table 4-5./6/ These widely used sources present a
broad perspective on the potential changes in commodity fuel markets. Each
forecast was equally weighted in an effort to arrive at an unbiased consensus
projection of fuel prices.
- -------------------------------------------------------------------------------------------------------------------
Table 4-5
Crude Oil Price Projection (real 2000$/bbl)
- -------------------------------------------------------------------------------------------------------------------
2000 2005 2010 2015 2020 Average Annual Growth
Rate
- -------------------------------------------------------------------------------------------------------------------
EIA 21.92 21.19 21.72 22.27 22.80 0.20%
- -------------------------------------------------------------------------------------------------------------------
GRI 18.42 18.42 18.42 18.42 18.42 0.00%
- -------------------------------------------------------------------------------------------------------------------
S&P 21.14 16.50 17.32 19.31 20.72 -0.10%
- -------------------------------------------------------------------------------------------------------------------
WEFA 24.22 18.74 18.84 19.80 20.81 -0.76%
- -------------------------------------------------------------------------------------------------------------------
Consensus 21.42 18.71 19.07 19.95 20.68 -0.18%
- -------------------------------------------------------------------------------------------------------------------
As is the case with natural gas, today's oil markets are in a period of
transition as OPEC wrestles with its production targets. As a result, PA has
modeled near-term prices to reflect recent actual oil prices and futures prices
through December 2003, rather than the long-run equilibrium price. In this case,
prices return to the long-run consensus in 2005. The near-term price projection
is shown in Table 4-6.
_____________________
6. The source forecasts are as follows: 2000 Annual Energy Outlook, EIA; 2000
Baseline Projection, GRI; 2000 Natural Gas Outlook, WEFA; Standard & Poor's
World Energy Service U.S. Outlook, Fall-Winter 1999-2000.
Assumptions . 4-7
- --------------------------------------------------------------------------------
---------------------------------------------------------------------
Table 4-6
Crude Oil Price Projection Using NYMEX Prices/1/
---------------------------------------------------------------------
Year Price Projection/2/
---------------------------------------------------------------------
2001 29.73
---------------------------------------------------------------------
2002 25.72
---------------------------------------------------------------------
2003 23.56
---------------------------------------------------------------------
2004 21.13
---------------------------------------------------------------------
1. Based on average daily closing prices from 9/13/00 to 12/12/00.
2. Real 2000 $/MMBtu.
----------------------------------------------------------------------
No. 2 Fuel Oil
Prices for No. 2 Fuel Oil were derived from EIA data on historical
delivered-to-utility prices for the period 1994 through 1998, on a regional
basis. Fuel costs are comprised of commodity costs and transportation costs.
Each region in the analysis was assigned to a reference terminal as shown in
Table 4-7. The commodity component is calculated by escalating the historic
reference terminal prices at the escalation rate implicit in the crude oil
forecast (outlined in Table 4-5).
- -----------------------------------------------------------------------------
Table 4-7
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
- -----------------------------------------------------------------------------
1. Includes In-City and Long Island transmission areas.
2. Comprised of Maine, Southeast, and West transmission areas.
- -----------------------------------------------------------------------------
Assumptions . 4-8
- --------------------------------------------------------------------------------
Transportation costs are calculated as the five-year average premium for
delivered fuel oil in each region above the market center price for the terminal
assigned to that region. This transportation cost is held fixed over the
forecast horizon. This methodology captures both the commodity and
transportation components of delivered costs. Representative final delivered
prices for No. 2 Fuel Oil are listed in Table 4-8.
- ------------------------------------------------------------------------------------------------------------------
Table 4-8
NPCC/MAAC Delivered No. 2 Fuel Oil Price (real 2000 $/MMBtu)
- ------------------------------------------------------------------------------------------------------------------
Pricing Area 2001/1/ 2005 2010 2015 2020 Average Annual Growth
Rate
- ------------------------------------------------------------------------------------------------------------------
PJM East 6.91 4.42 4.50 4.70 4.86 -0.17%
- ------------------------------------------------------------------------------------------------------------------
PJM West 7.14 4.57 4.65 4.86 5.03 -0.17%
- ------------------------------------------------------------------------------------------------------------------
PJM Central 7.14 4.56 4.65 4.85 5.02 -0.18%
- ------------------------------------------------------------------------------------------------------------------
New York-East/2/ 7.52 4.98 5.07 5.27 5.44 -0.15%
- ------------------------------------------------------------------------------------------------------------------
New York-West 7.52 4.98 5.07 5.27 5.44 -0.15%
- ------------------------------------------------------------------------------------------------------------------
NEPOOL/3/ 7.16 4.50 4.59 4.80 4.97 -0.18%
- ------------------------------------------------------------------------------------------------------------------
1. The 2001 delivered price is based on average daily NYMEX closing prices
from September 13, 2000 to December 12, 2000.
2. Includes In-City and Long Island transmission areas.
3. Comprised of Maine, Southeast, and West transmission areas.
- --------------------------------------------------------------------------------
No. 6 Fuel Oil
Prices for No. 6 Fuel Oil were derived using an identical methodology as that
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, all
regions were assigned to the New York Harbor reference terminal. As a result,
commodity prices for all regions were based on 1% sulfur residual oil at New
York Harbor and are therefore the same. Transportation costs for each region,
however, do vary.
The transportation costs for each region were based on an analysis of historic
New York Harbor prices and delivered residual oil at electric generating
stations in the region. Transportation costs equal the five-year average premium
for delivered No. 6 Fuel Oil above the New York Harbor price. This
transportation cost is held fixed over the forecast horizon. Final delivered
prices for No. 6 Fuel Oil are listed in Table 4-9.
Assumptions . 4-9
- --------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------
Table 4-9
NPCC/MAAC Delivered No. 6 Fuel Oil Price (real 2000 $/MMBtu)
- ------------------------------------------------------------------------------------------------------------------
Average Annual
Pricing Area 2001/1/ 2005 2010 2015 2020 Growth Rate
- ------------------------------------------------------------------------------------------------------------------
PJM East 4.48 2.88 2.94 3.06 3.17 -0.17%
- ------------------------------------------------------------------------------------------------------------------
PJM West 4.64 2.98 3.04 3.17 3.28 -0.17%
- ------------------------------------------------------------------------------------------------------------------
PJM Central 4.63 2.98 3.03 3.16 3.27 -0.17%
- ------------------------------------------------------------------------------------------------------------------
New York-East/2/ 4.83 3.27 3.32 3.45 3.55 -0.15%
- ------------------------------------------------------------------------------------------------------------------
New York-West 4.83 3.27 3.32 3.45 3.55 -0.15%
- ------------------------------------------------------------------------------------------------------------------
NEPOOL/3/ 4.52 2.88 2.93 3.06 3.17 -0.17%
- ------------------------------------------------------------------------------------------------------------------
1. The 2001 delivered price is based on average daily NYMEX closing prices
from September 13, 2000 to December 12, 2000.
2. Includes In-City and Long Island transmission areas.
3. Comprised of Maine, Southeast, and West transmission areas.
- --------------------------------------------------------------------------------
4.4.3 Coal
PA developed a forecast of marginal delivered coal prices and the corresponding
SO\\2\\ allowance prices. The SO\\2\\ prices are presented in Section 4.7.1. PA
developed a base case forecast of annual average marginal delivered coal prices
(in real dollars) for the period 2001 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, PA has provided marginal delivered coal
prices. These prices reflect PA's projection of a particular unit's marginal
coal selection and market pricing for that coal, as well as the rate for
transportation for such marginal purchases. If a particular unit purchases some
higher-priced 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 prices at the
mine (on a FOB/7/ basis), and (2) transportation rates. Because individual units
within a plant sometimes burn different coals, coal selection and delivered
pricing was developed on a unit-by-unit basis.
__________________
7. "Free on Board," indicating that the price includes the costs of loading coal
onto a train, truck, or barge.
Assumptions . 4-10
- --------------------------------------------------------------------------------
The projected coal selection for individual units reflects differing
requirements for compliance with emissions regulations over time, as well as
economics. To determine the selected coal, PA considered the use of flue gas
desulfurization equipment (scrubbers), requirements to comply with Phase I
and/or Phase II of the Clean Air Act Amendments of 1990, and requirements for
compliance with New Source Performance Standards and State Implementation Plan
limits, along with the variable costs of different methods of compliance. While
a unit's historical coal selection was an important factor in the projections,
substitutions of coal types were projected for some units over time as delivered
price economics (including allowance prices) are expected to change.
FOB mine prices 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 total factor productivity improvements are
reflected in projected price decreases. Real prices are expected to decrease
over the forecast period for all of the major coal types, but the rate of
decrease varies based on considerations specific to each coal type such as
supply and expected depletion of reserves, market demand, and the sulfur content
of the coals.
In general, prices for low sulfur coals decline the least, and prices for mid
sulfur coals decline the most. Low and mid sulfur coals currently receive a
price premium relative to high-sulfur coals based on their lower sulfur content.
However, higher SO\\2\\ allowance prices are expected to reduce demand for the
mid-sulfur coals at unscrubbed plants, which will reduce the price difference
between mid and high sulfur coals over time.
Projected transportation rates are based on available delivery options at each
plant for the coal types selected for each unit. Transportation modes included
rail, barge, truck transportation, and conveyor transportation for minemouth
plants. Rates for different transportation modes in different regions of the
country are projected to vary at different rates over time. In cases where a
multi-mode movement of coal is required (such as a combination rail and vessel
movement), the rate for each mode of transportation is projected separately, and
the total transportation rate is the sum of these separately escalated
components.
In addition, potential future changes in transportation options were considered.
In some cases, for example, PA 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.
Region-specific coal forecast discussions are provided in greater detail in
Appendix B.
Assumptions . 4-11
- --------------------------------------------------------------------------------
4.5 Demand and Energy Forecasts
The projected average annual demand and energy growths by region for the period
2001 through 2020 are summarized in Table 4-10.
--------------------------------------------------------------------
Table 4-10
Projected Average Annual Load Growth Rates
--------------------------------------------------------------------
Region Average Annual Growth Rate
--------------------------------------------------------------------
Demand Energy
--------------------------------------------------------------------
New York 0.8% 0.9%
--------------------------------------------------------------------
NEPOOL 1.5% 1.5%
--------------------------------------------------------------------
PJM 1.4% 1.5%
--------------------------------------------------------------------
Annual demand and energy forecast values are based on the following sources:
NPCC
. NPCC Load, Capacity, Energy, Fuels, and Transmission Report,
Forecast Data as of January 1, 2000, April 1, 2000
New York Power Pool
. Northeast Power Coordinating Council Load, Load, Capacity,
Energy, Fuels, and Transmission Report, Forecast Data as of
January 1, 2000, Data Submitted April 1, 2000.
. Report of the Member Electric Systems of the New York Power Pool
Load and Capacity Data, 2000
PJM/MAAC
. 2000 MAAC Regional Reliability Council, EIA-411; MAAC Annual
Electric Control and Planning Area Report, 2000.
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.
Assumptions . 4-12
- --------------------------------------------------------------------------------
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 to 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.
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, the NY-ISO, and the NE-ISO are set
to $0/MWh. Line losses between all pricing areas are assumed to be 2%.
4.7 Existing Generation Units
4.7.1 Fossil Units
Each of the 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 and maintenance (O&M) cost
. emission costs.
Assumptions . 4-13
- --------------------------------------------------------------------------------
Summer and Winter Capabilities
Summer and winter capability values were obtained from the following sources.
PJM/MAAC
. 2000 MAAC Regional Reliability Council, EIA-411; MAAC Annual
Electric Control and Planning Area Report, 2000
NPCC
. NPCC Load, Capacity, Energy, Fuels, and Transmission Report,
Forecast Data as of January 1, 2000, April 1, 2000
New York Power Pool
. Northeast Power Coordinating Council Load, Load, Capacity,
Energy, Fuels, and Transmission Report, Forecast Data as of
January 1, 2000, Data Submitted April 1, 2000
. Report of the Member Electric Systems of the New York Power Pool
Load and Capacity Data, 2000.
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 10 years of the filing of the report. Full load heat rate values were
established according to the 1995 Form EIA-860./8/ This is the most recent year
the report was published. PA 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 PA based on typical
characteristics by unit type.
__________________________
8. EIA Form EIA-860, 1995.
Assumptions . 4-14
- --------------------------------------------------------------------------------
Scheduled and Forced Outage Rates
The scheduled maintenance outage rates and equivalent forced outage rates for
all fossil units were estimated by PA based on historical data for comparable
units contained in the GADS database./9/
Variable Operation and Maintenance Costs
Each generating unit's variable operation and maintenance cost is represented by
PA'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 $5/MWh for peaking units
(includes combustion turbine units, internal combustion units, and jet engines).
Sulfur Dioxide Emission Costs
For purposes of the market projections PA has projected SO\\2\\ emission costs.
These are derived for purposes of the market study only.
Title IV of the Clean Air Act created a cap-and-trade program for SO\\2\\
emissions from electric generating plants. The program was implemented in two
phases. Phase I, which was implemented beginning January 1, 1995, covered a
selected list of generating units emitting the largest quantities of SO\\2\\.
SO\\2\\ emission allowances were allocated to these plants based on each unit's
historical average utilization, and an average emission rate of 2.5 lbs.
SO\\2\\/MMBtu. Phase II, which began on January 1, 2000, covered all SO\\2\\
emitters and allocated SO\\2\\ emission allowances based on a lower average
emission rate about 1.2 lbs. SO\\2\\/MMBtu. The total quantity of SO\\2\\
emission allowances issued annually by the EPA is equal to the total national
SO\\2\\ emission cap established by Congress. One allowance provides the right
to emit one ton of SO\\2\\.
SO\\2\\ allowances can be banked for use in future years or traded. Therefore,
utilities can choose to reduce their emissions below the target levels and
over-comply. If they over-comply, they can either save their excess allowances
for future use or sell them. Other utilities can choose to operate their plants
above the target emission levels and become net buyers of allowances.
PA estimated the SO\\2\\ allowance price by determining the allowance price
needed to achieve the Phase II cap once the current allowance bank of more than
10 million tons has been depleted. The forecast assumes that the operators of
generating plants will choose the lowest cost compliance option available to
them given the allowance price. Therefore, a combination of strategies will be
used to meet the Phase II cap. Some units will use low capital and high variable
cost solutions, such as switching to lower sulfur coals or using the same coal
but reducing the loading on the units. Other units will install scrubbers, which
is a high capital, low variable cost
______________________
9. North American Electricity Reliability Council, Generating Availability Data
System (GADS), Equipment Availability Report (1994-1998).
Assumptions . 4-15
- --------------------------------------------------------------------------------
solution. The allowance price is the cost of removing the last or marginal ton
of SO\\2\\. Both capital and variable costs are included in the estimates of
SO\\2\\ removal costs. However, the dispatch decision is based only on variable
costs. Therefore, a unit that chooses to install a scrubber may actually have
its variable costs decline and its utilization increase. A plant that switches
to a low sulfur coal may have its variable costs (including the cost of
allowances) increase and its utilization decline.
PA's forecast of SO\\2\\ allowance prices is shown in Table 4-11. The price of
SO\\2\\ allowances starts at $165 per ton in 2001, and increases to $420 per ton
by 2006, with the largest annual increase occurring in 2002.
- --------------------------------------------
Table 4-11
SO\\2\\ Cost Curves (2000$/ton)
- --------------------------------------------
Year SO\\2\\
- --------------------------------------------
2001 $165
- --------------------------------------------
2002 $287
- --------------------------------------------
2003 $316
- --------------------------------------------
2004 $347
- --------------------------------------------
2005 $382
- --------------------------------------------
2006-2020 $420
- --------------------------------------------
The relatively low current prices for SO\\2\\ allowances (below our expected
long-term value of allowances, on a discounted basis) reflects the accumulation
of a large bank of SO\\2\\ allowances, which resulted from over-compliance with
Phase I of the Clean Air Act SO\\2\\, and a number of political and regulatory
uncertainties (including the outcome of the New Source Review litigation, the
Supreme Court's ruling on EPA's proposed fine particulate regulations, and
proposed regional haze regulations) that could reduce the value of SO\\2\\
allowances. PA expects that the outcome of these uncertainties will be known by
2002. Assuming that these issues are resolved in a manner that essentially
preserves the current market-based regulatory system for SO\\2\\ (rather than
moving toward command-and-control policies), and that additional regulations do
not suppress SO\\2\\ prices, one would expect SO\\2\\ allowance prices to
increase substantially from 2001 to 2002.
The SO\\2\\ allowance price trajectories for 2001 and 2003-2005 reflect PA's
expectation that, since SO\\2\\ allowances are a relatively risky investment
(due to the regulatory and political uncertainties mentioned above), they will
generally escalate at a discount rate consistent with such risky investments.
For this forecast, PA has assumed a 10% expected annual real rate of return on
holding "banked" allowances during these periods, which produces our price
trajectories for 2001 and 2003 to 2005.
The real cost of SO\\2\\ allowances is projected to plateau at $420 per ton for
2006 and later years. This price level is determined by the marginal cost of
installing scrubbers at existing plants./10/ PA estimates that this price level
will be reached in 2006 because the "bank" of SO\\2\\ allowances will
___________________
10. This assumes a continuation of current regulations under the 1990 Clean Air
Act Amendments. As noted above, some proposals under consideration by EPA (such
as controls on fine particulates) could change these regulations.
Assumptions . 4-16
- --------------------------------------------------------------------------------
be almost fully depleted by 2006. (Only a small "bank" will remain, for
transactional liquidity purposes.)
Development of NO\X\ Control Costs and Emission Rates
For purposes of the market projections PA has projected NO\X\ allowances. The
forecast of NO\X\ allowance prices is shown in Table 4-12. This forecast
includes both an estimate of NO\X\ compliance costs for units in the Ozone
Transport Region (OTR) for 2001-2002, and an estimate of the NO\X\ control costs
for all of the units affected by EPA's NO\X\ State Implementation Plan (SIP)
Call from 2003 forward.
- ----------------------------------------------------
Table 4-12
NO\X\ Cost Curves (real 2000 $/ton)
- ----------------------------------------------------
Year NO\X\
- ----------------------------------------------------
2001 $1,000
- ----------------------------------------------------
2002 $1,000
- ----------------------------------------------------
2003-2020 $4,000
- ----------------------------------------------------
The OTR includes 12 states, primarily in the Northeast. With some exceptions,
affected NO\X\ emission sources in this region were required to reduce NO\X\
emissions either by 55%, or to 0.2 lbs. NO\X\/MMBtu (whichever is a lesser
reduction) by May 1, 1999./11/ The region affected by the EPA's NO\X\ SIP Call
includes 19 states in the eastern half of the United States (i.e., most of the
states east of the Mississippi River)./12/
PA's forecast of NO\X\ allowance prices assumes that plants will purchase NO\X\
allowances when their marginal cost (not their average cost) of abatement
exceeds the expected price of emission allowances. Unlike SO\\2\\ allowances,
NO\X\ allowances are for a single season only./13/ Therefore, the forecasted
allowance price for each year is based on the marginal cost of installing
controls sufficient to meet the relevant NO\X\ emissions cap in that year. The
allowance price is determined by the marginal cost of installing the highest-
cost technology required to meet the emissions cap. Under the OTR regulations,
the highest-cost technology required to meet the emissions cap is Selective Non-
Catalytic Reduction (SNCR). The highest-cost technology required to meet the
tighter cap in the EPA's proposed SIP call regulations is Selective Catalytic
Reduction (SCR).
_________________________
11. Sources in the state of Maryland were exempted from these emission reduction
requirements until May 1, 2000. A portion of the Ozone Transport Region is
subject to slightly stricter requirements (to reduce emissions either by 65%, or
to 0.2 lbs. NO\X\/MMBtu).
12. Georgia, Missouri and Wisconsin were recently exempted from the SIP Call
region, but we have assumed for modeling purposes that Georgia will be subject
to the NO\X\ program in 2004 and that Missouri and Wisconsin will be affected in
2005.
13. Although it is possible to bank NO\X\ allowances under both the OTR
regulations and the regulations proposed in EPA's NO\X\ SIP Call, the conditions
for banking allowances are so onerous that they are likely to be uneconomic in
most cases. Therefore, any banking that occurs is unlikely to have a significant
effect on NO\X\ allowance prices.
Assumptions . 4-17
- --------------------------------------------------------------------------------
For each unit subject to these regulations, generating costs were estimated
assuming that NO\X\ emission costs were equal to the tons of NO\X\ emitted after
installation of applicable control technologies, multiplied by the price of
allowances represented by the NO\X\ forward-price forecast. The resulting NO\X\
emission costs were added to the variable cost of each generating unit and
included in the development of the energy price forecast. Any capital
expenditure incurred was included in the generating unit's fixed costs and in
the capacity compensation simulation.
The NO\X\ allowance price forecast begins at the 2001 ozone season/14/ price,
which is approximately $1,000/ton (see Table 4-12). The price is expected to
remain at $1,000/ton in 2002, and then rise to approximately $4,000/ton in 2003
as the tighter NO\X\ regulations proposed in the SIP call go into effect.
The $4,000/ton NO\X\ allowance price is expected to remain constant in real
terms after 2003, as gradual reductions in the NO\X\ emissions cap are expected
to offset any improvements in technology. This assumption reflects the fact that
EPA's suggested SIP standards include provisions for a slight decline in NO\X\
allowances over time. EPA proposed to have the number of NO\X\ allowances
granted to plants decline as their utilization goes down. Therefore, assuming
that most states adopt EPA's suggested language, the NO\X\ emissions budget
should decline slowly over time. Although this is not expected to cause an
increase in NO\X\ allowance prices (since most coal-fired units reach their
maximum utilization by 2003), NO\X\ allowance prices are expected to remain
sufficiently high to justify the installation of additional NO\X\ control
equipment needed to meet the slowly tightening NO\X\ cap.
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 inflows.
4.7.3 Nuclear Units
PA 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, PA utilized two proprietary PA
databases of nuclear power information: the Nuclear Power Experience (NPE), and
the Operating Plant
____________________
14. The ozone season, for purposes of assessing NO\X\ costs, is defined as
May 1 through September 30.
Assumptions . 4-18
- --------------------------------------------------------------------------------
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
all U.S. 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 the
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, PA 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, PA 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,
PA 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 the 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. PA 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 40 years. PA has
conducted studies showing that generating power stations begin to require
life extension costs between 30 and 40 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
Assumptions . 4-19
- --------------------------------------------------------------------------------
than one station. In addition, the utility is more likely to be committed
to operating its nuclear power generation.
. 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 U.S. units.
In addition to the operating experience assessment, PA estimated the annual
going-forward costs (fixed O&M, property taxes, and annualized incremental
capital costs) associated with each unit. For this assessment, Table 4-13
summarizes the project retirement dates for the nuclear units in PJM.
------------------------------------------------------------
Table 4-13
PJM Nuclear Unit Retirements
------------------------------------------------------------
Unit Capacity Retirement Year
------------------------------------------------------------
Oyster Creek 619 2009
------------------------------------------------------------
Peach Bottom 3 1,093 2013
------------------------------------------------------------
Three Mile 786 2014
------------------------------------------------------------
Peach Bottom 2 1,093 2014
------------------------------------------------------------
Salem 1 1,106 2016
------------------------------------------------------------
Salem 2 1,106 2020
------------------------------------------------------------
Susquehana 1 1,090 2022
------------------------------------------------------------
Limerick 1 1,134 2024
------------------------------------------------------------
Calvert Cliff 1 835 2024
------------------------------------------------------------
Calvert Cliff 2 840 2024
------------------------------------------------------------
Susquehana 2 1,094 2024
------------------------------------------------------------
Hope Creek 1,031 2026
------------------------------------------------------------
Limerick 2 1,115 2029
------------------------------------------------------------
Assumptions . 4-20
- --------------------------------------------------------------------------------
4.8 Capacity Compensation Simulation Model Input Assumptions
4.8.1 Existing Units Going-Forward Costs
PA 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/15/
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
U.S. 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 2003
A critical step in simulating the regional capacity market is to ascertain the
number and timing of capacity additions for the near term (2001 to 2003). To
this end, PA 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 to construct
___________________
15. OPRI is a division of Resource Data International Inc.
Assumptions . 4-21
- --------------------------------------------------------------------------------
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, PA
completed a number of separate tasks. PA performed a literature search in an
effort to identify articles referring to planned power plant development in the
regions. Also, PA's experts analyzed PA's IPP Database to determine the number
of plants currently under development 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 PA's analysis and investigation, a baseline on-line scenario was
developed which reflects PA's estimate of the plants that realistically will be
constructed in the target region through the year 2003. Units that go on line in
2001 and 2002 are identified by the project name. These are units that PA
believes will be constructed with a high probability. Some of the units that go
on line in 2003 are not referred to by a specific project name. Generic units
are used to represent new capacity expected to come on line in the year 2003.
There is greater uncertainty associated with identifying specific units that
will go on line in 2003 and 2004. PA evaluated the announced capacity that was
not currently included as base case capacity on an annual basis for the years
2000 through 2003. Based on region specific analyses and knowledge of potential
project developments, PA determined a best estimate of new capacity that will go
on line in the year 2003. New capacity additions for the years 2001 through 2003
are summarized in Table 4-14.
4.8.3 Capacity Additions Post 2003
The validity of capacity additions post 2003 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 Tables
4-15 and 4-16. The first year in which new generic capacity is added to the
model is 2004. Capital costs are assumed to decrease at 1% per annum (real 2000
$). Table 4-17 indicates the assumed schedule and effect of technology
improvement on new unit heat rates.
Assumptions . 4-22
- --------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------
Table 4-14
Capacity Additions, 2001-2003
- -----------------------------------------------------------------------------------------------------------------
Size Unit On-Line
Developer (Plant) (MW)/1/ Type Fuel Type Year
- -----------------------------------------------------------------------------------------------------------------
NEPOOL
- -----------------------------------------------------------------------------------------------------------------
Power Dev Corp (Milford) 544 CC Natural Gas 2001
- -----------------------------------------------------------------------------------------------------------------
Calpine (Westbrook) 540 CC Natural Gas 2001
- -----------------------------------------------------------------------------------------------------------------
PG&E Gen (Lake Road) 792 CC Natural Gas 2001
- -----------------------------------------------------------------------------------------------------------------
ANP (Blackstone) 550 CC Natural Gas 2001
- -----------------------------------------------------------------------------------------------------------------
PPL Global (Wallingford) 250 CT Natural Gas 2001
- -----------------------------------------------------------------------------------------------------------------
ANP (Bellingham) 580 CC Natural Gas 2001
- -----------------------------------------------------------------------------------------------------------------
Exelon (Fore River) 750 CC Natural Gas 2002
- -----------------------------------------------------------------------------------------------------------------
FPL Energy (Johnston) 500 CC Natural Gas 2002
- -----------------------------------------------------------------------------------------------------------------
AES (Londonderry) 720 CC Natural Gas 2002
- -----------------------------------------------------------------------------------------------------------------
Exelon (New Boston 3) 15 GT Natural Gas 2002
- -----------------------------------------------------------------------------------------------------------------
Power Dev Corp/El Paso Energy (Meriden-Berlin) 520 CC Natural Gas 2002
- -----------------------------------------------------------------------------------------------------------------
Exelon (Mystic 8) 750 CC Natural Gas 2002
- -----------------------------------------------------------------------------------------------------------------
Exelon (Mystic 9) 750 CC Natural Gas 2002
- -----------------------------------------------------------------------------------------------------------------
Consolidated Edison (Newington) 525 CT Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Exelon (Medway) 450 CT Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Generic 520 CC Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
New York
- -----------------------------------------------------------------------------------------------------------------
NYPA (CT 1) 260 CT Natural Gas 2001
- -----------------------------------------------------------------------------------------------------------------
NYPA (CT 1) 260 CT Natural Gas 2001
- -----------------------------------------------------------------------------------------------------------------
PG&E Generating (Athens) 1,080 CC Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Exelon (Heritage) 800 CC Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Exelon (Torne Valley) 800 CC Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Generic 345 CT Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Generic 345 CT Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Generic 345 CT Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Generic 520 CC Natural Gas 2003
- -----------------------------------------------------------------------------------------------------------------
Assumptions . 4-23
- --------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------
Table 4-14 (cont.)
Capacity Additions, 2001-2003
- ------------------------------------------------------------------------------------------------------------------
Size Unit On-Line
Developer (Plant) (MW)/1/ Type Fuel Type Year
- ------------------------------------------------------------------------------------------------------------------
PJM
- ------------------------------------------------------------------------------------------------------------------
TM Power Ventures (Chesapeak 2) 177 CT Natural Gas 2001
- ------------------------------------------------------------------------------------------------------------------
Williams (Hazleton) 250 CC Natural Gas 2001
- ------------------------------------------------------------------------------------------------------------------
AES (Ironwood) 705 CC Natural Gas 2001
- ------------------------------------------------------------------------------------------------------------------
PSEG Energy (Kearney 1-4) 164 GT Natural Gas 2001
- ------------------------------------------------------------------------------------------------------------------
Conectiv (Hay Road) 550 CC Natural Gas 2002
- ------------------------------------------------------------------------------------------------------------------
PSEG Power (Bergen 2) 546 CC Natural Gas 2002
- ------------------------------------------------------------------------------------------------------------------
Orion (Liberty ) 520 CC Natural Gas 2002
- ------------------------------------------------------------------------------------------------------------------
PSEG Energy (Mantua Creek) 800 CC Natural Gas 2002
- ------------------------------------------------------------------------------------------------------------------
AES (Red Oak) 816 CC Natural Gas 2002
- ------------------------------------------------------------------------------------------------------------------
PSEG Energy (Linden 1) 601 CC Natural Gas 2003
- ------------------------------------------------------------------------------------------------------------------
PSEG Energy (Linden 2) 601 CC Natural Gas 2003
- ------------------------------------------------------------------------------------------------------------------
1. Summer rating.
- ------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------
Table 4-15
New CC Generating Characteristics (real 2000$)
- ------------------------------------------------------------------------------------------------------------------
Capital Cost Fixed O&M Variable O&M Size
($/kW) ($/kW-yr) ($/MWh) (MW)
- ------------------------------------------------------------------------------------------------------------------
NEPOOL $610 $11.50 $2.00 520
- ------------------------------------------------------------------------------------------------------------------
New York $610 $11.50 $2.00 520
- ------------------------------------------------------------------------------------------------------------------
PJM $590 $11.50 $2.00 520
- ------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Table 4-16
New CT Generating Characteristics (real 2000$)
- -------------------------------------------------------------------------------------------------------------------
Capital Cost Fixed O&M Variable O&M Size
($/kW) ($/kW-yr) ($/MWh) (MW)
- -------------------------------------------------------------------------------------------------------------------
NEPOOL $430 $ 6.00 $5.00 345
- -------------------------------------------------------------------------------------------------------------------
New York $430 $ 6.00 $5.00 345
- -------------------------------------------------------------------------------------------------------------------
PJM $410 $ 6.00 $5.00 345
- -------------------------------------------------------------------------------------------------------------------
Assumptions . 4-24
- --------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------
Table 4-17
Full Load Heat Rate Improvement (Btu/kWh)/1/
- ------------------------------------------------------------------------------------------------------------------
1999-2003 2004-2008 2009-2013 2014-2018 2019+
- ------------------------------------------------------------------------------------------------------------------
Combined Cycle 6,700 6,566 6,435 6,306 6,180
- ------------------------------------------------------------------------------------------------------------------
Combustion Turbine 10,400 (W) 10,192 (W) 9,988 (W) 9,788 (W) 9,593 (W)
10,700 (S) 10,487 (S) 10,427 (S) 10,070 (S) 9,871 (S)
- ------------------------------------------------------------------------------------------------------------------
1. Degradation of 2% for CC units and 3% for CT units was assumed, but is not reflected in the rates above.
- ------------------------------------------------------------------------------------------------------------------
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 20-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 and 40% equity for
combined cycle units, and 50% debt and 50% equity for combustion
turbine units.
. Debt interest rate is assumed to be 9.1%. Debt terms and project lives
are 20 years with mortgage-style amortization for combined cycle units
and 15 years for combustion turbine units.
- --------------------------------------------------------------------------------
Chapter 5
Market Price Forecasts
5.1 Introduction
PA developed four cases that reflect our best assessment of future market
conditions and sensitivities on some of these conditions for the PJM market. It
should be recognized that these cases 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 in the market./1/
The energy price forecast presents the marginal cost of generating electricity
in the electricity markets. The additional compensation for capacity needed to
maintain a minimum amount of capacity in the market is factored in to 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
that form the all-in market price will always 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 option 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.
Market Price Forecasts . 5-2
- --------------------------------------------------------------------------------
The PJM wholesale electric market requires LSEs to directly contract for
capacity through the Capacity Credit Market. While this mechanism provides 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. Additional compensation
may be obtained by selling out of the PJM market. The ability to capture
additional revenue is dependent upon the experience and the risk management
protocols of the trading operation.
In each year the value of the additional compensation for capacity captured
through these market mechanisms cannot be greater than 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. Thus, the total
compensation for capacity is capped in each year by the carrying cost of a new
combustion turbine.
The four cases are outlined below:
. The Base Case incorporates the actual spot and futures gas and oil
prices through December 2003. Prices then decrease linearly to the
consensus forecast price in year 2005. This method is discussed in
further detail in Chapter 4.
. The Low Fuel Case evaluates the effects of lower gas and oil prices
represented as a $0.50/MMBtu reduction in the 2001 gas and oil prices
with the same real escalation rates used in the base case.
. The High Fuel Case evaluates the effects of higher gas prices
throughout the study period. Gas prices are held at the 2001 NYMEX
value throughout the study period.
. The Overbuild Case evaluates an exuberance of merchant plant
development. The merchant plant capacity added in the Overbuild Case
is listed in Table 5-1.
Market Price Forecasts . 5-3
- --------------------------------------------------------------------------------
----------------------------------------------------------------------
Table 5-1
Overbuild Case Merchant Plant Capacity Additions (MW)/1/
----------------------------------------------------------------------
Region 2001 2002 2003 2004
----------------------------------------------------------------------
NEPOOL 3,256 4,005 1,495 1,040
----------------------------------------------------------------------
New York 520 0 4,235 2,080
----------------------------------------------------------------------
PJM 1,296 3,232 1,202 4,160
----------------------------------------------------------------------
1. Capacity additions in 2001-2003 are the same as in the Base Case.
----------------------------------------------------------------------
These sensitivities were developed to exhibit the variance from the Base Case in
the resulting forecast given the change in these significant input variables. It
should be noted that other variables could also change and affect the final
results and the above sensitivity cases may not present all the risk factors to
be considered.
This chapter provides a description of the current market conditions, and a
summary of the results of the four cases. The energy price forecasts for
PJM-Central represent the average annual system marginal cost of energy in these
markets. In addition, the compensation for capacity was derived for the entire
PJM market region. The compensation for capacity forecasts are an estimation of
the total compensation for capacity that generators need to receive over and
above the system marginal cost energy price in order to keep a minimum amount of
generation in the market. It should be noted that not all generators will
receive the full capacity compensation outlined herein. Finally, an all-in
market price forecast is provided which combines the energy price and the
compensation for capacity (assuming a 100% load factor). The all-in price
reflects PA's estimate of the total market price that generators must receive to
keep the market in equilibrium.
5.2 Market Conditions
The Mirant Mid-Atlantic assets located in the PJM-Central pricing area,
participate in the PJM wholesale electricity market, which covers the entire
MAAC transmission region. Figure 5-1 illustrates the load and resource balance
for PJM through the end of the study period. The Mirant Mid-Atlantic Assets make
up approximately 8.5% of the PJM installed capacity.
Peak demand in the PJM market is forecasted to grow at an annual compound rate
of approximately 1.5% per year from 2001 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 PA believes the
market will mature and the required reserve margins will be lowered.
Market Price Forecasts . 5-4
- --------------------------------------------------------------------------------
Figure 5-1
PJM Load and Resource Balance
[GRAPH]
Sources: 2000 MAAC Regional Reliability Council, EIA-411; MAAC Annual
Electric Control and Planning Area Report, 2000.
(1) Reserve Margin is assumed to be 18% in 2001, decreasing to 15% in 2002
through 2020. Net additions are net of retirements.
The existing capacity in PJM is initially sufficient to meet the system reserve
requirement. However, as demand grows and the market tightens, a gap forms
between existing and required system resources. This resource gap is addressed
by the addition of merchant plants through 2003. These assumed additions are
detailed in Chapter 4. After 2003 the model assumes that new units are brought
on-line as needed to meet the specified reserve requirement.
The transmission transfer capability between PJM and the surrounding
transmission areas is defined in Appendix C. 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 energy generation and capacity between gas/oil, coal, hydro,
and nuclear assets in PJM is illustrated in Figures 5-2 and 5-3. Coal dominates
the baseload generation in PJM, accounting for 52% of the total energy produced.
Nuclear units also comprise a large portion of the energy produced in PJM,
accounting for 39% of the total energy produced. On an installed capacity basis,
gas- and oil-fired generation units represent 37% of PJM's total installed
capacity, while coal represents 32% of PJM's total installed capacity. Nuclear
facilities account for 22% of PJM's installed capability.
Market Price Forecasts . 5-5
- --------------------------------------------------------------------------------
Figure 5-2
PJM Energy - Year 2001
Gas/Oil Hydro Other
6% 2% 1%
Nuclear Coal
39% 52%
Figure 5-3
PJM Capacity - Year 2001
Gas/Oil Hydro Other
37% 4% 5%
Nuclear Coal
22% 32%
Sources: Figure 5-2: PA Consulting Services Inc. Regional Modeling results.
Figure 5-3: 2000 Regional Reliability Council, EIA-411; MAAC Annual Electric
Control and Planning Area Report, 2000; and PA Consulting Services Inc.
5.3 Price Forecasts for the PJM Market
5.3.1 Base Case
This case models near-term fuel prices (gas and oil) based on recent actual spot
prices and futures prices through December 2003, decreasing linearly to the
long-term consensus view by 2005.
The all-in price represents a combined compensation for capacity and energy
price (assuming a 100% load factor). The compensation for capacity contribution
to the all-in price ranges between approximately $6.00/MWh and $7.90/MWh.
The Base Case compensation for capacity, energy, and all-in market price
forecasts are presented in Figure 5-4 and Table 5-2 for the PJM-Central pricing
area.
In addition to the fundamental numbers reported in Table 5-2, PA used monthly
average daytime electricity forwards for 2001-2003. The monthly electricity
price forwards for 2001-2003 used in the volatility forecast for the PJM region
are listed in Table 5-3. For the period 2004-2020, the volatility results were
calibrated to the fundamental results shown in Table 5-2.
Market Price Forecasts . 5-6
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Figure 5-4
PJM-Central Base Case Compensation for Capacity, Energy, and All-In Price
Forecasts/1/
[GRAPH]
Energy Prices ($/MWh)
All-In Prices ($/MWh)
Compensation for Capacity ($/kW-yr)
/1/ Results are expressed in real 2000 dollars.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Table 5-2
PJM-Central Base Case Forecasts/1/
- --------------------------------------------------------------------------------
Year Compensation for Capacity Energy Price All-In Price/2/
($/kW-yr) ($/MWh) ($/MWh)
- --------------------------------------------------------------------------------
2001/3/ 69.20 29.60 37.50
- --------------------------------------------------------------------------------
2002/3/ 52.60 27.60 33.60
- --------------------------------------------------------------------------------
2003/3/ 52.60 28.10 34.10
- --------------------------------------------------------------------------------
2004 52.70 25.90 31.90
- --------------------------------------------------------------------------------
2005 60.50 24.00 30.90
- --------------------------------------------------------------------------------
2006 65.50 24.20 31.60
- --------------------------------------------------------------------------------
2007 65.80 24.00 31.50
- --------------------------------------------------------------------------------
2008 65.40 24.10 31.60
- --------------------------------------------------------------------------------
2009 64.80 24.40 31.80
- --------------------------------------------------------------------------------
2010 64.30 24.80 32.20
- --------------------------------------------------------------------------------
2011 63.80 24.60 31.90
- --------------------------------------------------------------------------------
2012 63.30 24.50 31.70
- --------------------------------------------------------------------------------
2013 62.70 24.60 31.80
- --------------------------------------------------------------------------------
2014 62.20 24.60 31.70
- --------------------------------------------------------------------------------
2015 61.70 24.70 31.70
- --------------------------------------------------------------------------------
2016 61.20 24.70 31.70
- --------------------------------------------------------------------------------
2017 60.80 24.80 31.80
- --------------------------------------------------------------------------------
2018 60.30 25.00 31.80
- --------------------------------------------------------------------------------
2019 59.80 25.10 31.90
- --------------------------------------------------------------------------------
2020 59.30 25.40 32.10
- --------------------------------------------------------------------------------
1. Results are expressed in real 2000 dollars.
2. Calculated based on 100% load factor.
3. 2001-2003 volatility results are calibrated to the forwards prices versus the
model results presented herein.
- --------------------------------------------------------------------------------
Market Price Forecasts . 5-7
- --------------------------------------------------------------------------------
5.3.2 Sensitivity Cases Analysis
The all-in prices for the three sensitivity cases and the base case described in
Section 5.1 are shown in Figure 5-5 and Table 5-4 for the PJM-Central pricing
area. The Base Case projections decrease initially as new merchant plants come
on-line and gas prices decrease to the consensus forecast. The High Fuel Case
results in substantially higher all-in prices over time, as much as $14/MWh, as
more gas units move on the margin for a greater number of hours. The Low Fuel
Case results in lower all-in prices by $1/MWh to $2/MWh. The Overbuild Case
depresses prices in the 2004 to 2010 timeframe, after which the PJM region
recovers from the Overbuild Case.
Market Price Forecasts . 5-8
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Figure 5-5
PJM-Central Sensitivity Cases All-In Price Forecasts/1/ ($/MWh)
[GRAPH]
Base Case
High Fuel
Low Fuel
Overbuild
/1/ Results are expresses in real 2000 dollars.
- --------------------------------------------------------------------------------
-----------------------------------------------------------------
Table 5-4
PJM-Central Sensitivity Cases All-In Price Forecasts/1/ ($/MWh)
-----------------------------------------------------------------
Year Base Case High Fuel Low Fuel Overbuild
-----------------------------------------------------------------
2001 37.50 37.50 35.70 37.50
-----------------------------------------------------------------
2002 33.60 35.50 32.60 33.60
-----------------------------------------------------------------
2003 34.10 36.80 32.70 34.10
-----------------------------------------------------------------
2004 31.90 37.00 30.90 29.80
-----------------------------------------------------------------
2005 30.90 37.60 30.20 27.10
-----------------------------------------------------------------
2006 31.60 40.10 30.30 27.60
-----------------------------------------------------------------
2007 31.50 40.20 30.20 28.60
-----------------------------------------------------------------
2008 31.60 40.70 30.30 30.10
-----------------------------------------------------------------
2009 31.80 41.70 30.20 30.80
-----------------------------------------------------------------
2010 32.20 42.80 30.30 31.10
-----------------------------------------------------------------
2011 31.90 43.50 30.10 31.40
-----------------------------------------------------------------
2012 31.70 43.70 30.10 31.10
-----------------------------------------------------------------
2013 31.80 43.70 30.10 31.10
-----------------------------------------------------------------
2014 31.70 44.40 29.90 31.10
-----------------------------------------------------------------
2015 31.70 45.10 29.90 31.20
-----------------------------------------------------------------
2016 31.70 45.20 29.90 31.20
-----------------------------------------------------------------
2017 31.80 45.50 30.00 31.30
-----------------------------------------------------------------
2018 31.80 45.70 30.00 31.50
-----------------------------------------------------------------
2019 31.90 45.50 30.00 31.40
-----------------------------------------------------------------
2020 32.10 46.10 30.20 31.50
-----------------------------------------------------------------
/1/ Results are expressed in real 2000 dollars.
-----------------------------------------------------------------
Appendix A
Pricing Areas
NPCC/MAAC Pricing Areas
. NYPP-East . PJM-Central
. PJM-West . NYPP-West
. NYPP-In-City . NEPOOL-South East
. NYPP-Long Island . NEPOOL-Maine
. PJM-East . NEPOOL-West
[MAP]
Pricing Areas . A-2
- --------------------------------------------------------------------------------
NPCC/MAAC Utilities by Pricing Area
Pricing Area Utility
NEPOOL-Maine Bangor Hydro-Electric Company
Central Maine Power Company
Maine Cooperative
Maine Public Service Company
New England Power Pool Maine
NEPOOL-South East Boston Edison Company
Braintree Electric Light Department
Chicopee Municipal Lighting Plant
Commonwealth Energy System Companies
Eastern Utilities Associates Companies
Fitchburg Gas and Electric Light Company
Hingham Municipal Lighting Plant
Holyoke Gas and Electric
Hudson Light and Power Department
Ipswich Municipal Light Department
Middleborough Gas and Electric Department
Marblehead Municipal Light Department
Massachusetts Municipal Wholesale Electric Company
New England Electric System Operating Companies
North Attleborough Electric Department
Peabody Municipal Light Plant
Princeton Municipal Light Department
Shrewsbury Electric Lighting Plant
Sterling Municipal Light Department
Taunton Municipal Light Plant
Milford Power
NEPOOL-West Connecticut Municipal Electric Energy Cooperative
Great Bay Power Corporation
New Hampshire Electric Cooperative
Northeast Utilities Companies
The United Illuminating Company
UNITIL Power Corp. Companies
Vermont Group
Central Vermont Public Service Corp.
Green Mountain Power
Pricing Areas . A-3
- --------------------------------------------------------------------------------
Pricing Area Utility
NYPP-East Central Hudson Gas & Electric Corporation
Orange & Rockland Utilities, Inc.
City of Plattsburgh
NYPP-In-City Consolidated Edison Company of New York, Inc.
NYPP-Long Island Long Island Lighting Company
NYPP-West New York Power Pool
Village of Freeport
Jamestown Municipal Electric System
New York Power Authority
New York State Electric & Gas Corporation
Niagara Mohawk Power Corporation
Rochester Gas & Electric Corporation
PJM-Central Pennsylvania Power & Light Company
Baltimore Gas & Electric Company
Potomac Electric Power Company
Metropolitan Edison Company
Allegheny Electric Cooperative, Inc.
UGI Corporation
Southern Maryland Electric Cooperative
PJM-East PSEG Power LLC
Philadelphia Electric Company (PECO Energy)
General Public Utilities Corporation
Atlantic Electric
Delmarva Power & Light Company
Jersey Central Power & Light Company
CRSS Capital, Inc.
City of Dover
City of Vineland Electric Utility
Easton Utilities Commission (The)
U.S. Generating Company
PJM-West Pennsylvania Electric Company
A representational diagram of the transmission capability between the pricing
areas identified above is located in Appendix C (Transfer Capability).
- --------------------------------------------------------------------------------
Appendix B
Methodology for Coal Price Forecasting
The following details the methodology used for projecting pricing for Central
Appalachian, Northern Appalachian, Pittsburgh Seam, and other coals used in the
NPCC/MAAC region.
Central Appalachia. PA projects the use of 1.2-pound/1/ and 1.5-pound
Central Appalachian coals in MAAC and NPCC regions during the forecast period.
Both coal types have energy contents of 12,500 Btu per pound, and are both
priced on a FOB railcar basis.
PA projects that the real price for both of these types of coal will decline by
about 10% between 2000 and 2020 (an average annual decline of approximately
0.5%). This relatively slow rate of decline reflects expectations of high demand
for this coal, and significant depletion of reserves, offset by modest
productivity gains and continued strong price competition among Central
Appalachian coal producers.
Northern Appalachia and Pittsburgh Seam. PA projects the use of
1.8-pound, 3.8-pound, and 6.3-pound Northern Appalachian coals, and 2.4-pound
and 3.2-pound Pittsburgh Seam coals in MAAC and NPCC during the forecast period.
The energy contents of these coals ranges from 12,000 to 13,000 Btu/lb., with
most of the coal types being toward the higher end of this heat content range.
Real prices for all of these coal types decline during the forecast period.
Prices for the Northern Appalachian 3.8-pound coal decline most rapidly
(declining 19% over the forecast period or almost 1%/year), because we expect
that higher SO2 allowance prices will reduce the demand for this coal at
unscrubbed plants and therefore reduce the price premium this coal has
traditionally enjoyed relative to the Northern Appalachian high-sulfur coal. The
prices for the Pittsburgh Seam coals are expected to decline by about 12% over
the forecast period, as reserve depletion and limited potential for future
productivity gains at these longwall mining operations offset the effects of
reduced demand for these mid-sulfur coals.
Very high sulfur coals primarily serve generating units that are equipped with
scrubbers that remove SO2 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 1% per year in real terms.
____________________
1. 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.
Methodology for Coal Price Forecasting . B-2
- --------------------------------------------------------------------------------
Other. Several other coal types are expected to be used in the
projected in the MAAC and NPCC-U.S. regions. These include Central Pennsylvania
3.8-pound coal, waste coals (both bituminous and anthracite), and coals imported
from South America by ocean vessel.
The price of the Central Pennsylvania coal is expected to decline by about 7%
over the forecast period (a decline of slightly less than 0.5%/year). This
reflects decreased demand for this mid-sulfur coal, offset by very substantial
depletion of reserves.
Demand for waste coals is expected to remain relatively steady. The supply of
this coal is highly localized, and therefore competition to supply any
particular plant is limited. Real prices for this coal are expected to decline
by about 7% over the forecast period.
The prices for imported coal are largely driven by the competing coals available
at a given generating plant. This coal moves to a limited number of plants in
New England that have vessel-receiving capability. Prices for this coal were
projected on a delivered basis for individual plants, by assuming that the
delivered price of this coal was 10 cents per million Btu lower than the
delivered price of the cheapest domestic coal available to that plant.
Transportation costs. Transportation rates 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 costs for coal types not historically used at a
particular location were based on industry experience and analysis of economic
options at the unit. Projected escalation rates for coal transportation modes
are provided below.
Rail. Rail escalation rates were projected in real dollar terms and
differentiated according to origin region and whether particular plants were
captive to a single railroad or had access to competitive transportation
alternatives (including either more than one railroad or a railroad and another
mode of coal transportation such as barge or truck).
Rail rates for Central Appalachian coal moving to captive plants are expected to
remain flat in real terms during the forecast period. Rail rates for Central
Appalachian coal movements to competitively-served plants are expected to
decline by an average of 1%/year over the forecast period. Rail rates for
Northern Appalachian and Pittsburgh Seam coal moving to captive plants are
expected to decline by 0.5%/year in real terms during the forecast period. Rail
rates for Northern Appalachian and Pittsburgh seam coal movements to
competitively-served plants are expected to decline by an average of 1%/year
over the forecast period. These relatively low rates of decline reflect the
eastern railroads' historical success in maintaining duopoly pricing, despite
strong productivity gains.
Some generating plants in the Northeast which are currently captive to one
railroad are expected to achieve lower rates either through regulatory relief or
through constructing additional transportation facilities. These lower rate
levels are assumed to be achieved by 2005. After
Methodology for Coal Price Forecasting . B-3
- --------------------------------------------------------------------------------
achieving a lower rate level, rates for these plants decline at 1%/year, as is
the case for other competitively served plants in this region.
Vessel and barge. Vessel and barge rates are projected to decline
during the forecast period, on average, at a rate of 2% per year in real terms,
reflecting improved productivity in competitive markets.
Truck. Truck rates are projected to decline at an average annual rate
of 2.0%/year during the forecast period, reflecting low costs of entry and
continued strong competition among trucking firms.
- --------------------------------------------------------------------------------
Appendix C
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. The following table and figure identify
the bulk transfer capabilities between regions and subregions that have been
included in this report.
Transfer Capability . C-2
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
Table C-1
NPCC/MAAC Transmission Transfer Capability
- --------------------------------------------------------------------------------------------------------------------
From To Winter Capability (MW) Summer Capability (MW)
- --------------------------------------------------------------------------------------------------------------------
Can-Ontario ECAR 2,370 1,930
- --------------------------------------------------------------------------------------------------------------------
Can-Quebec NEPOOL-SE 525 1,800
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-SE Can-Quebec 1,670 1,370
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-SE NYPP-East 122 191
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-West NYPP-East 510 802
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-West NYPP-In-City 334 525
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-West NYPP-Long Island 84 132
- --------------------------------------------------------------------------------------------------------------------
NYPP-East NEPOOL-SE 200 154
- --------------------------------------------------------------------------------------------------------------------
NYPP-East NEPOOL-West 925 811
- --------------------------------------------------------------------------------------------------------------------
NYPP-In-City NEPOOL-West 575 443
- --------------------------------------------------------------------------------------------------------------------
NYPP-Long Island NEPOOL-West 150 116
- --------------------------------------------------------------------------------------------------------------------
ECAR Can-Ontario 2,230 1,680
- --------------------------------------------------------------------------------------------------------------------
Can-Nova Scotia Can-Quebec 400 400
- --------------------------------------------------------------------------------------------------------------------
Can-Nova Scotia NEPOOL-Maine 700 700
- --------------------------------------------------------------------------------------------------------------------
Can-Ontario Can-Quebec 309 309
- --------------------------------------------------------------------------------------------------------------------
Can-Ontario NYPP-West 1,850 1,850
- --------------------------------------------------------------------------------------------------------------------
Can-Quebec Can-Nova Scotia 1,050 1,050
- --------------------------------------------------------------------------------------------------------------------
Can-Quebec Can-Ontario 1,391 1,391
- --------------------------------------------------------------------------------------------------------------------
Can-Quebec NYPP-West 1,200 1,200
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-Maine Can-Nova Scotia 55 55
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-Maine NEPOOL-West 1,200 1,200
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-SE NEPOOL-West 3,600 3,600
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-West NEPOOL-Maine 1,450 1,450
- --------------------------------------------------------------------------------------------------------------------
NEPOOL-West NEPOOL-SE 3,600 3,600
- --------------------------------------------------------------------------------------------------------------------
Transfer Capability . C-3
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
Table C-1 (cont.)
NPCC/MAAC Transmission Transfer Capability
- --------------------------------------------------------------------------------------------------------------------
From To Winter Capability (MW) Summer Capability (MW)
- --------------------------------------------------------------------------------------------------------------------
NYPP-East NYPP-In-City 4,441 4,441
- --------------------------------------------------------------------------------------------------------------------
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 NYPP-East 4,441 4,441
- --------------------------------------------------------------------------------------------------------------------
NYPP-In-City PJM-East 2,750 2,750
- --------------------------------------------------------------------------------------------------------------------
NYPP-Long Island NYPP-East 1,306 1,306
- --------------------------------------------------------------------------------------------------------------------
NYPP-West Can-Ontario 1,850 1,850
- --------------------------------------------------------------------------------------------------------------------
NYPP-West Can-Quebec 1,500 1,500
- --------------------------------------------------------------------------------------------------------------------
NYPP-West NYPP-East 5,261 5,261
- --------------------------------------------------------------------------------------------------------------------
NYPP-West PJM-West 725 725
- --------------------------------------------------------------------------------------------------------------------
PJM-Central PJM-East 8,673 8,673
- --------------------------------------------------------------------------------------------------------------------
PJM-Central PJM-West 5,254 5,254
- --------------------------------------------------------------------------------------------------------------------
PJM-Central ECAR 400 400
- --------------------------------------------------------------------------------------------------------------------
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 NYPP-West 725 725
- --------------------------------------------------------------------------------------------------------------------
PJM-West PJM-Central 5,146 5,146
- --------------------------------------------------------------------------------------------------------------------
PJM-West ECAR 2,600 2,600
- --------------------------------------------------------------------------------------------------------------------
ECAR PJM-Central 494 494
- --------------------------------------------------------------------------------------------------------------------
ECAR PJM-West 2,000 2,000
- --------------------------------------------------------------------------------------------------------------------
SERC PJM-Central 1,700 1,700
- --------------------------------------------------------------------------------------------------------------------
Transfer Capability . C-4
- --------------------------------------------------------------------------------
Figure C-1
NPCC/MAAC Transmission Capability (MW)/1/
[GRAPHIC]
1. Capabilities represent Summer and (Winter) where applicable.
- --------------------------------------------------------------------------------
Appendix D
Dispatch Curves
The dispatch curves for 2001 and 2010 are shown in Figure D-1. These curves
order generation plants based upon short run variable cost (fuel and O&M). The
relative ranking of the Mirant Mid-Atlantic plants are included on the graphs.
Dispatch Curves . D-2
- --------------------------------------------------------------------------------
Figure D-1
PJM Dispatch Curves for 2001 and 2010
PJM - 2001
[GRAPHIC]
Cumulative Capacity (MW)
Peak Demand = 51,267 MW With Reserve 18% = 60,495 MW
PJM - 2010
[GRAPHIC]
Cumulative Capacity (MW)
Peak Demand = 58,534 MW With Reserve 15% = 67,314 MW
- -----------------------
A Chalk Pt 1
B Chalk Pt 2
C Chalk Pt 3
D Chalk Pt 4
E Chalk Pt CT 1
F Chalk Pt CT 2
G Chalk Pt CT 3
H Chalk Pt CT 4
I Chalk Pt CT 5
J Chalk Pt CT 6
K Chalk Pt SMCT
L Dickerson 1
M Dickerson 2
N Dickerson 3
O Dickerson CT 1
P Dickerson CT 2-3
Q Morgantown 1
R Morgantown 2
S Morgantown CT 1-2
T Morgantown CT 3-6
U Potomac River 1
V Potomac River 2
W Potomac River 3
X Potomac River 4
Y Potomac River 5
- -----------------------
- --------------------------------------------------------------------------------
Appendix E
New Capacity Additions
For the first three years of the study period (2001-2003), identified merchant
plant projects are added to the system based on the estimated on-line date of
the project (see Chapter 4, Table 4-14). After this initial period, the market
entry and exit logic determines the amount and timing of new generation capacity
added to the system as well as the retirement of existing units. Starting in
2004, the market entry and exit logic, at a minimum, builds enough new capacity
to meet the estimated reserve requirements.
Table E-1 describes the timing and amount of market entry and exit (retirements)
for the Base Case for PJM.
New Capacity Additions . E-2
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Table E-1
Cumulative Capacity Additions in PJM (MW), 2004-2020
- --------------------------------------------------------------------------------
Cumulative
Combined Cycle Combustion Capacity
Year Plants Added Turbines Added Retirements Additions
- --------------------------------------------------------------------------------
2004 0 0 80 -80
- --------------------------------------------------------------------------------
2005 0 345 393 -128
- --------------------------------------------------------------------------------
2006 520 690 254 828
- --------------------------------------------------------------------------------
2007 520 690 146 1,892
- --------------------------------------------------------------------------------
2008 520 690 489 2,613
- --------------------------------------------------------------------------------
2009 520 345 0 3,478
- --------------------------------------------------------------------------------
2010 520 690 619 4,069
- --------------------------------------------------------------------------------
2011 1,040 0 0 5,109
- --------------------------------------------------------------------------------
2012 1,040 0 2 6,148
- --------------------------------------------------------------------------------
2013 1,040 0 0 7,188
- --------------------------------------------------------------------------------
2014 2,080 0 1,093 8,175
- --------------------------------------------------------------------------------
2015 2,600 345 1,879 9,241
- --------------------------------------------------------------------------------
2016 520 345 0 10,106
- --------------------------------------------------------------------------------
2017 1,560 690 1,106 11,250
- --------------------------------------------------------------------------------
2018 520 690 41 12,419
- --------------------------------------------------------------------------------
2019 1,040 0 41 13,418
- --------------------------------------------------------------------------------
2020 0 1,380 288 14,510
================================================================================
Total 14,040 6,900 6,431 14,510
================================================================================
1. 2001 through 2003 additions of 5,730 MW are shown separately in Chapter 4.
2. Retirements assumed to occur on January 1 of year.
- --------------------------------------------------------------------------------
MIRANT MID-ATLANTIC, LLC
Until October 4, 2001, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealers' obligation to
deliver a prospectus where acting as underwriters and with respect to their
unsold allotments or subscriptions.
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 20. Indemnification of Directors and Officers
Mirant Mid-Atlantic's Limited Liability Company Agreement provides that the
Company will indemnify its members, managers or officers to the full extent
permitted by the laws of the State of Delaware and may indemnify certain other
persons as authorized by the Delaware Company Limited Liability Act
Section 18-108 of the Delaware Company Limited Liability Act provides as
follows:
"Subject to such standards and restrictions, if any, as are set forth in
its limited liability company agreement, a limited liability company may,
and shall have the power to, indemnify and hold harmless any member or
manager or other person from and against any and all claims and demands
whatsoever."
Mirant Mid-Atlantic's Limited Liability Company Agreement limits the
personal liability of its members, managers or officers for monetary damages
arising out of any claims against them unless the party is guilty of
intentional misconduct, any knowing violation of the law or any transaction in
which such member, manager or officer receives a personal benefit in violation
or breach of the Delaware Company Limited Liability Act or the Mirant Mid-
Atlantic Limited Liability Company Agreement. Section 14.13 of the Limited
Liability Company Agreement provides as follows:
"14.13 Indemnification. The Company shall indemnify to the full extent
permitted by the Limited Liability Company Act of the State of Delaware or
any other applicable laws as now or hereinafter in effect any person made
or threatened to be made a party to any action, suit or proceeding, whether
civil, criminal, administrative or investigative, by reason of the fact
that such person or such person's testator or intestate is or was a Member,
Manager or officer of the Company or serves or served at the request of the
Company or any other enterprise as a Member, Manager or officer. Expenses,
including attorneys' fees, incurred by any such person in defending any
such action, suit or proceeding shall be paid or reimbursed by the Company
promptly upon receipt by it of an undertaking of or on behalf of such
person to repay such amounts if it shall ultimately be determined that such
person is not entitled to be indemnified by the Company. The rights
provided to any person by this Section shall be enforceable against the
Company by such person who shall be presumed to have relied upon it in
serving or continuing to serve as a Member, Manager or officer as provided
above. No amendment of this Section shall impair the rights of any person
arising at any time with respect to events occurring prior to such
amendment. For purposes of this Section, the term "Company" shall include
any predecessor of the Company and any constituent company (including any
constituent of a constituent) absorbed by the Company in a consolidation or
merger; the term "other enterprise," shall include any corporation, limited
liability company, partnership, joint venture, trust or employee benefit
plan; service "at the request of the Company" shall include service as a
Member, Manager, officer or employee of the Company which imposes duties
on, or involves services by, such Member, Manager, officer or employee with
respect to an employee benefit plan, its participants or beneficiaries; any
excise taxes assessed on a person with respect to an employee benefit plan
shall be deemed to be indemnifiable expenses; and action by a person with
respect to an employee benefit plan which such person reasonably believes
to be in the interest of the participants and beneficiaries of such plan
shall be deemed to be action not opposed to the best interests of the
Company. Notwithstanding the foregoing, no Member, Manager or officer shall
be indemnified against liability for any intentional misconduct, any
knowing violation of the law or any transaction in which such Member,
Manager or officer receives a personal benefit in violation or breach of
the Act or this Agreement."
The officers and directors of Mirant Mid-Atlantic, LLC, Mirant Mid-Atlantic
Management, Inc. (the managing member Mirant Mid-Atlantic, LLC) and Mirant
Corporation are covered by insurance policies maintained by Mirant Corporation
against certain liabilities for actions taken in their capacities as such,
including liabilities under the Securities Act of 1933, as amended.
II-1
Item 21. Exhibits and Financial Statement Schedules
3.1* Certificate of Formation of Southern Energy Mid-Atlantic, LLC
3.2* Limited Liability Company Agreement of Southern Energy Mid-Atlantic,
LLC, dated as of July 12, 2000
3.3* First Amendment to Limited Liability Company Agreement of Southern
Energy Mid-Atlantic, LLC, dated as of November 7, 2000
3.4* Second Amendment to Limited Liability Company Agreement of Mirant
Mid-Atlantic LLC, dated as of May 15, 2001
4.1* Form of 8.625% Series A Pass Through Certificate
4.2* Form of 9.125% Series B Pass Through Certificate
4.3* Form of 10.060% Series C Pass Through Certificate
4.4(a)* Pass Through Trust Agreement A between Southern Energy Mid-Atlantic,
LLC and State Street Bank and Trust Company of Connecticut, National
Association, as Pass Through Trustee, dated as of December 19, 2000
4.4(b)* Schedule identifying substantially identical agreements to Pass
Through Trust Agreement constituting Exhibit 4.4(a) hereto
4.5(a)* Participation Agreement (Dickerson L1) among Southern Energy Mid-
Atlantic, LLC, as Lessee, Dickerson OL1 LLC, as Owner Lessor,
Wilmington Trust Company, as Owner Manager, SEMA OP3, as Owner
Participant and State Street Bank and Trust Company of Connecticut,
National Association, as Lease Indenture Trustee and as Pass Through
Trustee, dated as of December 18, 2000
4.5(b)* Schedule identifying substantially identical agreements to
Participation Agreement constituting Exhibit 4.5(a) hereto
4.6(a)* Participation Agreement (Morgantown L1) among Southern Energy Mid-
Atlantic, LLC, as Lessee, Morgantown OL1 LLC, as Owner Lessor,
Wilmington Trust Company, as Owner Manager, SEMA OP1, as Owner
Participant and State Street Bank and Trust Company of Connecticut,
National Association, as Lease Indenture Trustee and as Pass Through
Trustee, dated as of December 18, 2000
4.6(b)* Schedule identifying substantially identical agreements to
Participation Agreement constituting Exhibit 4.6(a) hereto
4.7(a)* Facility Lease Agreement (Dickerson L1) between Southern Energy Mid-
Atlantic, LLC, as Lessee, and Dickerson OL1 LLC, as Owner Lessor,
dated as of December 19, 2000
4.7(b)* Schedule identifying substantially identical agreements to Facility
Lease Agreement constituting Exhibit 4.7(a) hereto
4.8(a)* Facility Lease Agreement (Morgantown L1) between Southern Energy Mid-
Atlantic, LLC, as Lessee, and Morgantown OL1 LLC, as Owner Lessor,
dated as of December 19, 2000
4.8(b)* Schedule identifying substantially identical agreements to Facility
Lease Agreement constituting Exhibit 4.8(a) hereto
4.9(a)* Indenture of Trust, Mortgage and Security Agreement (Dickerson L1)
between Dickerson OL1 LLC, as Owner Lessor, and State Street Bank and
Trust Company of Connecticut, National Association, as Lease
Indenture Trustee, dated as of December 19, 2000
4.9(b)* Schedule identifying substantially identical agreements to Indenture
of Trust, Mortgage and Security Agreement constituting Exhibit 4.9(a)
hereto
4.10(a)* Indenture of Trust, Mortgage and Security Agreement (Morgantown L1)
between Morgantown OL1 LLC, as Owner Lessor, and State Street Bank
and Trust Company of Connecticut, National Association, as Lease
Indenture Trustee, dated as of December 19, 2000
II-2
4.10(b)* Schedule identifying substantially identical agreements to Indenture
of Trust, Mortgage and Security Agreement constituting Exhibit
4.10(a) hereto
4.11(a)* Series A Lessor Note for Dickerson OL1 LLC
4.11(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.11(a) hereto
4.12(a)* Series A Lessor Note for Morgantown OL1 LLC
4.12(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.12(a) hereto
4.13(a)* Series B Lessor Note for Dickerson OL1 LLC
4.13(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.13(a) hereto
4.14(a)* Series B Lessor Note for Morgantown OL1 LLC
4.14(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.14(a) hereto
4.15(a)* Series C Lessor Note for Morgantown OL1 LLC
4.15(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.15(a) hereto
4.16* Registration Rights Agreement, between Southern Energy Mid-Atlantic,
LLC and Credit Suisse First Boston, acting for itself on behalf of
the Purchasers, dated as of December 18, 2000
4.17(a)* Supplemental Pass Through Trust Agreement A between Mirant Mid-
Atlantic, LLC and State Street Bank and Trust Company of
Connecticut, National Association, as Pass Through Trustee, dated as
of June 29, 2001
4.17(b)* Schedule identifying substantially identical agreements to
Supplemental Pass Through Trust Agreement constituting Exhibit
4.17(a) hereto
5.1* Opinion of Skadden, Arps, Slate, Meagher and Flom LLP as to the
legality of the Pass Through Certificates being registered hereby
10.1(a)* Asset Purchase and Sale Agreement between Potomac Electric Power
Company and Southern Energy, Inc. (currently known as Mirant
Corporation) dated as of June 7, 2000
10.1(b)* Amendment No. 1 to Asset Purchase and Sale Agreement between Potomac
Electric Power Company and Southern Energy, Inc. dated as of
September 18, 2000
10.1(c)* Amendment No. 2 to Asset Purchase and Sale Agreement between Potomac
Electric Power Company and Southern Energy, Inc. dated as of
December 19, 2000
10.2(a)* Interconnection Agreement (Dickerson) between Potomac Electric Power
Company and Southern Energy Mid-Atlantic, LLC dated as of December
19, 2000
10.2(b)* Schedule identifying substantially identical agreements to
Interconnection Agreement constituting Exhibit 10.2(a) hereto
10.3(a)* Easement, License and Attachment Agreement (Dickerson) between
Potomac Electric Power Company, Southern Energy Mid-Atlantic, LLC
and Southern Energy MD Ash Management, LLC (currently known as
Mirant MD Ash Management, LLC) dated as of December 19, 2000
10.3(b)* Schedule identifying substantially identical agreements to Easement,
License and Attachment Agreement constituting Exhibit 10.3(a) hereto
10.4(a)* Bill of Sale (Dickerson, Morgantown, Production Service Center and
Railroad Spur) between Potomac Electric Power Company and Southern
Energy Mid-Atlantic, LLC dated as of December 19, 2000
10.4(b)* Schedule identifying substantially identical documents to Bill of
Sale constituting Exhibit 10.4(a) hereto
II-3
10.5(a)* Facility Site Lease Agreement (Dickerson L1) between Southern Energy
Mid-Atlantic, LLC, Dickerson OL1 LLC and Southern Energy MD Ash
Management, LLC dated as of December 19, 2000
10.5(b)* Schedule identifying substantially identical agreements to Facility
Site Lease Agreement constituting Exhibit 10.5(a) hereto
10.6(a)* Facility Site Lease Agreement (Morgantown L1) between Southern
Energy Mid-Atlantic, LLC, Morgantown OL1 LLC and Southern Energy MD
Ash Management, LLC dated as of December 19, 2000
10.6(b)* Schedule identifying substantially identical agreements to Facility
Site Lease Agreement constituting Exhibit 10.6(a) hereto
10.7(a)* Facility Site Sublease Agreement (Dickerson L1) between Southern
Energy Mid-Atlantic, LLC and Dickerson OL1 LLC dated as of December
19, 2000
10.7(b)* Schedule identifying substantially identical agreements to Facility
Site Sublease Agreement constituting Exhibit 10.7(a) hereto
10.8(a)* Facility Site Sublease Agreement (Morgantown L1) between Southern
Energy Mid-Atlantic, LLC and Morgantown OL1 LLC dated as of December
19, 2000
10.8(b)* Schedule identifying substantially identical agreements to Facility
Site Sublease Agreement constituting Exhibit 10.8(a) hereto
10.9(a)* Amended and Restated Services and Risk Management Agreement between
Mirant Mid-Atlantic, LLC and Mirant Americas Energy Marketing L.P.
dated as of March 30, 2001
10.9(b)* Schedule identifying substantially identical agreement to Amended
and Restated Services and Risk Management Agreement constituting
Exhibit 10.9(a) hereto
10.10(a)* Master Power Purchase and Sale Agreement between Southern Energy
Mid-Atlantic, LLC and Southern Company Energy Marketing L.P. dated
as of December 18, 2000
10.10(b)* Schedule identifying substantially identical agreement to Master
Power Purchase and Sale Agreement constituting Exhibit 10.10(a)
hereto
10.11* Agency Agreement between Southern Energy Mid-Atlantic, LLC, Southern
Energy Chalk Point, LLC, Southern Energy Peaker, LLC and Southern
Energy Potomac River dated as of December 18, 2000
10.12* Capital Contribution Agreement between Southern Energy, Inc. and
Southern Energy Mid-Atlantic, LLC dated as of December 19, 2000
10.13* Promissory Note between Southern Energy Mid-Atlantic, LLC and
Southern Energy Peaker, LLC in the original principal amount of
$71,110,000 dated as of December 19, 2000
10.14* Promissory Note between Southern Energy Mid-Atlantic, LLC and
Southern Energy Potomac River, LLC in the original principal amount
of $152,165,000 dated as of December 19, 2000
10.15(a)* Shared Facilities Agreement (Dickerson) between Southern Energy Mid-
Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC, Dickerson OL3
LLC and Dickerson OL4 LLC dated as of December 18, 2000
10.15(b)* Shared Facilities Agreement (Morgantown) between Southern Energy
Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC,
Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC,
Morgantown OL6 LLC and Morgantown OL7 LLC dated as of December 18,
2000
II-4
10.16(a)* Assignment and Assumption Agreement (Dickerson) between Southern
Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC,
Dickerson OL3 LLC and Dickerson OL4 LLC dated as of December 19,
2000
10.16(b)* Assignment and Assumption Agreement (Morgantown) between Southern
Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC,
Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC,
Morgantown OL6 LLC and Morgantown OL7 LLC dated as of December 19,
2000
10.17(a)* Ownership and Operation Agreement (Dickerson) between Southern
Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC,
Dickerson OL3 LLC and Dickerson OL4 LLC dated as of December 18,
2000
10.17(b)* Ownership and Operation Agreement (Morgantown) between Southern
Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC,
Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC,
Morgantown OL6 LLC and Morgantown OL7 LLC dated as of December 18,
2000
10.18* Amended and Restated Revolving Promissory Note between Southern
Energy North America Generating, Inc. (currently known as Mirant
Americas Generation, Inc.) and Southern Energy Mid-Atlantic, LLC in
the original principal amount of up to $150,000,000 dated as of
April 27, 2001
10.19(a)* Administrative Services Agreement between Southern Energy Resources,
Inc. (currently known as Mirant Services, LLC) and Southern Energy
Mid-Atlantic, LLC dated as of December 19, 2000
10.19(b)* Schedule identifying substantially identical agreement to
Administrative Services Agreement constituting Exhibit 10.19(a)
hereto
10.20(a)* Management and Personnel Services Agreement between Southern Energy
PJM Management, LLC and Southern Energy Mid-Atlantic, LLC dated as
of December 19, 2000
10.20(b)* Schedule identifying substantially identical agreements to
Management and Personnel Services Agreement constituting Exhibit
10.20(a) hereto
10.21(a)* Guaranty Agreement (Dickerson L1) between Southern Energy, Inc. and
Dickerson OL1 LLC dated as of December 19, 2000
10.21(b)* Schedule identifying substantially identical agreements to Guaranty
Agreement constituting Exhibit 10.21(a) hereto
10.22(a)* Guaranty Agreement (Morgantown L1) between Southern Energy, Inc. and
Morgantown OL1 LLC dated as of December 19, 2000
10.22(b)* Schedule identifying substantially identical agreements to Guaranty
Agreement constituting Exhibit 10.22(a) hereto
10.23 Form of Energy and Capacity Sales Agreement between Mirant Mid-
Atlantic, LLC and Mirant Americas Energy Marketing, LP dated as of
August 1, 2001
10.24 Form of Energy and Capacity Sales Agreement between Mirant Chalk
Point, LLC and Mirant Americas Energy Marketing, LP dated as of
August 1, 2001
10.25 Form of Energy and Capacity Sales Agreement between Mirant Peaker,
LLC and Mirant Americas Energy Marketing, LP dated as of August 1,
2001
10.26 Form of Energy and Capacity Sales Agreement between Mirant Potomac
River, LLC and Mirant Americas Energy Marketing, LP dated as of
August 1, 2001
12.1* Statement regarding ratio of earnings to fixed charges
II-5
21.1* Schedule of Subsidiaries
23.1* Consent of PA Consulting Services Inc.
23.2 Consent of R.W. Beck, Inc.
23.3 Consent of Independent Public Accountants
24.1* Power of Attorney
25.1* Statement of Eligibility of State Street Bank and Trust Company of
Connecticut, National Association for the 8.625% Exchange Pass Through
Certificates, Series A, 9.125% Exchange Pass Through Certificates,
Series B and 10.060% Exchange Pass Through Certificates, Series C, on
Form T-1
99.1* Form of Letter of Transmittal
99.2* Form of Notice of Guaranteed Delivery
99.3* Form of Letters to Brokers, Dealers, Commercial Banks, Trust Companies
and Other Nominees
99.4* Form of Letter to Clients
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* Previously filed.
Item 22. Undertakings
(a) The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made, a
post-effective amendment to this registrant:
(i) To include any prospectus required by Section 10 (a) (3) of the
Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after
the effective date of the registration statement (or the most recent
post-effective amendment thereof) which, individually or in the
aggregate, represent a fundamental change in the information set forth
in the registration statement. Notwithstanding the foregoing, any
increase or decrease in volume of securities offered (if the total
dollar value of securities would not exceed that which was registered)
and any deviation from the low or high end of the estimated maximum
offering range may be reflected in the form of prospectus filed with
the Commission pursuant to Rule 424(b) if, in the aggregate, the
changes in volume and price represent no more than 20 percent change in
the maximum aggregate offering price set forth in the "Calculation of
Registration Fee" table in the effective registration statement; and
(iii) To include any material information with respect to the plan of
distribution not previously disclosed in this registration statement or
any material change to such information in this registration statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933 , each such post-effective amendment shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed
to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering.
(b) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the registrant pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the
Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid
II-6
by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities
being registered, the registrant will, unless in the opinion of its counsel
the matter has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Act and will be governed by the
final adjudication of such issue.
(c) The undersigned registrant hereby undertakes to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Item 4, 10(b), 11, or 13 of this form, within one business day of receipt of
such request, and to send the incorporated documents by first class mail or
other equally prompt means. This includes information contained in documents
filed subsequent to the effective date of the registration statement through
the date of responding to the request.
(d) The undersigned registrant hereby undertakes to supply by means of a
post-effective amendment all information concerning a transaction, and the
company being acquired involved therein, that was not the subject of and
included in the registration statement when it became effective.
II-7
SIGNATURES
Pursuant to the requirements of the Securities Act, the registrant has duly
caused this registration statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Atlanta, State of
Georgia, on the 7th day of August, 2001.
Mirant Mid-Atlantic, LLC
a Delaware limited liability company
By /s/ Gary J. Morsches
----------------------------------
Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed by the following persons in the
capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
** Chief Executive Officer of **
______________________________________ Mirant Mid-Atlantic, LLC,
Gary J. Morsches Director of Mirant Mid-
Atlantic Management,
Inc.* (Principal
Executive Officer)
** Vice President, Chief **
______________________________________ Financial Officer and
Gary J. Kubik Treasurer of Mirant Mid-
Atlantic, LLC (Principal
Financial Officer)
** Vice President and **
______________________________________ Controller of Mirant Mid-
Paul M. Lansdell Atlantic, LLC (Principal
Accounting Officer)
** Director of Mirant Mid- **
______________________________________ Atlantic Management,
John L. O'Neal Inc.*
** Director of Mirant Mid- **
______________________________________ Atlantic Management,
Michael L. Smith Inc.*
*Mirant Mid-Atlantic Management, Inc. is the managing member of Mirant Mid-
Atlantic, LLC
** By: /s/ Michelle H. Ancosky August 7, 2001
___________________________________
Name: Michelle H. Ancosky__________
Attorney-in-Fact
II-8
EXHIBIT INDEX
3.1* Certificate of Formation of Southern Energy Mid-Atlantic, LLC
3.2* Limited Liability Company Agreement of Southern Energy Mid-Atlantic,
LLC, dated as of July 12, 2000
3.3* First Amendment to Limited Liability Company Agreement of Southern
Energy Mid-Atlantic, LLC, dated as of November 7, 2000
3.4* Second Amendment to Limited Liability Company Agreement of Mirant
Mid-Atlantic, LLC, dated as of May 15, 2001
4.1* Form of 8.625% Series A Pass Through Certificate
4.2* Form of 9.125% Series B Pass Through Certificate
4.3* Form of 10.060% Series C Pass Through Certificate
4.4(a)* Pass Through Trust Agreement A between Southern Energy Mid-Atlantic,
LLC and State Street Bank and Trust Company of Connecticut, National
Association, as Pass Through Trustee, dated as of December 19, 2000
4.4(b)* Schedule identifying substantially identical agreements to Pass
Through Trust Agreement constituting Exhibit 4.4(a) hereto
4.5(a)* Participation Agreement (Dickerson L1) among Southern Energy Mid-
Atlantic, LLC, as Lessee, Dickerson OL1 LLC, as Owner Lessor,
Wilmington Trust Company, as Owner Manager, SEMA OP3, as Owner
Participant and State Street Bank and Trust Company of Connecticut,
National Association, as Lease Indenture Trustee and as Pass Through
Trustee, dated as of December 18, 2000
4.5(b)* Schedule identifying substantially identical agreements to
Participation Agreement constituting Exhibit 4.5(a) hereto
4.6(a)* Participation Agreement (Morgantown L1) among Southern Energy Mid-
Atlantic, LLC, as Lessee, Morgantown OL1 LLC, as Owner Lessor,
Wilmington Trust Company, as Owner Manager, SEMA OP1, as Owner
Participant and State Street Bank and Trust Company of Connecticut,
National Association, as Lease Indenture Trustee and as Pass Through
Trustee, dated as of December 18, 2000
4.6(b)* Schedule identifying substantially identical agreements to
Participation Agreement constituting Exhibit 4.6(a) hereto
4.7(a)* Facility Lease Agreement (Dickerson L1) between Southern Energy Mid-
Atlantic, LLC, as Lessee, and Dickerson OL1 LLC, as Owner Lessor,
dated as of December 19, 2000
4.7(b)* Schedule identifying substantially identical agreements to Facility
Lease Agreement constituting Exhibit 4.7(a) hereto
4.8(a)* Facility Lease Agreement (Morgantown L1) between Southern Energy Mid-
Atlantic, LLC, as Lessee, and Morgantown OL1 LLC, as Owner Lessor,
dated as of December 19, 2000
4.8(b)* Schedule identifying substantially identical agreements to Facility
Lease Agreement constituting Exhibit 4.8(a) hereto
4.9(a)* Indenture of Trust, Mortgage and Security Agreement (Dickerson L1)
between Dickerson OL1 LLC, as Owner Lessor, and State Street Bank and
Trust Company of Connecticut, National Association, as Lease
Indenture Trustee, dated as of December 19, 2000
4.9(b)* Schedule identifying substantially identical agreements to Indenture
of Trust, Mortgage and Security Agreement constituting Exhibit 4.9(a)
hereto
4.10(a)* Indenture of Trust, Mortgage and Security Agreement (Morgantown L1)
between Morgantown OL1 LLC, as Owner Lessor, and State Street Bank
and Trust Company of Connecticut, National Association, as Lease
Indenture Trustee, dated as of December 19, 2000
4.10(b)* Schedule identifying substantially identical agreements to Indenture
of Trust, Mortgage and Security Agreement constituting Exhibit
4.10(a) hereto
4.11(a)* Series A Lessor Note for Dickerson OL1 LLC
4.11(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.11(a) hereto
4.12(a)* Series A Lessor Note for Morgantown OL1 LLC
4.12(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.12(a) hereto
4.13(a)* Series B Lessor Note for Dickerson OL1 LLC
4.13(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.13(a) hereto
4.14(a)* Series B Lessor Note for Morgantown OL1 LLC
4.14(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.14(a) hereto
4.15(a)* Series C Lessor Note for Morgantown OL1 LLC
4.15(b)* Schedule identifying substantially identical notes to Lessor Notes
constituting Exhibit 4.15(a) hereto
4.16* Registration Rights Agreement, between Southern Energy Mid-Atlantic,
LLC and Credit Suisse First Boston, acting for itself on behalf of
the Purchasers, dated as of December 18, 2000
4.17(a)* Supplemental Pass Through Trust Agreement A between Mirant Mid-
Atlantic, LLC and State Street Bank and Trust Company of
Connecticut, National Association, as Pass Through Trustee, dated as
of June 29, 2001
4.17(b)* Schedule identifying substantially identical agreements to
Supplemental Pass Through Trust Agreement constituting Exhibit
4.17(a) hereto
5.1* Opinion of Skadden, Arps, Slate, Meagher and Flom LLP as to the
legality of the Pass Through Certificates being registered hereby
10.1(a)* Asset Purchase and Sale Agreement between Potomac Electric Power
Company and Southern Energy, Inc. (currently known as Mirant
Corporation) dated as of June 7, 2000
10.1(b)* Amendment No. 1 to Asset Purchase and Sale Agreement between Potomac
Electric Power Company and Southern Energy, Inc. dated as of
September 18, 2000
10.1(c)* Amendment No. 2 to Asset Purchase and Sale Agreement between Potomac
Electric Power Company and Southern Energy, Inc. dated as of
December 19, 2000
10.2(a)* Interconnection Agreement (Dickerson) between Potomac Electric Power
Company and Southern Energy Mid-Atlantic, LLC dated as of December
19, 2000
10.2(b)* Schedule identifying substantially identical agreements to
Interconnection Agreement constituting Exhibit 10.2(a) hereto
10.3(a)* Easement, License and Attachment Agreement (Dickerson) between
Potomac Electric Power Company, Southern Energy Mid-Atlantic, LLC
and Southern Energy MD Ash Management, LLC (currently known as
Mirant MD Ash Management, LLC) dated as of December 19, 2000
10.3(b)* Schedule identifying substantially identical agreements to Easement,
License and Attachment Agreement constituting Exhibit 10.3(a) hereto
10.4(a)* Bill of Sale (Dickerson, Morgantown, Production Service Center and
Railroad Spur) between Potomac Electric Power Company and Southern
Energy Mid-Atlantic, LLC dated as of December 19, 2000
10.4(b)* Schedule identifying substantially identical documents to Bill of
Sale constituting Exhibit 10.4(a) hereto
10.5(a)* Facility Site Lease Agreement (Dickerson L1) between Southern Energy
Mid-Atlantic, LLC, Dickerson OL1 LLC and Southern Energy MD Ash
Management, LLC dated as of December 19, 2000
10.5(b)* Schedule identifying substantially identical agreements to Facility
Site Lease Agreement constituting Exhibit 10.5(a) hereto
10.6(a)* Facility Site Lease Agreement (Morgantown L1) between Southern
Energy Mid-Atlantic, LLC, Morgantown OL1 LLC and Southern Energy MD
Ash Management, LLC dated as of December 19, 2000
10.6(b)* Schedule identifying substantially identical agreements to Facility
Site Lease Agreement constituting Exhibit 10.6(a) hereto
10.7(a)* Facility Site Sublease Agreement (Dickerson L1) between Southern
Energy Mid-Atlantic, LLC and Dickerson OL1 LLC dated as of December
19, 2000
10.7(b)* Schedule identifying substantially identical agreements to Facility
Site Sublease Agreement constituting Exhibit 10.7(a) hereto
10.8(a)* Facility Site Sublease Agreement (Morgantown L1) between Southern
Energy Mid-Atlantic, LLC and Morgantown OL1 LLC dated as of December
19, 2000
10.8(b)* Schedule identifying substantially identical agreements to Facility
Site Sublease Agreement constituting Exhibit 10.8(a) hereto
10.9(a)* Amended and Restated Services and Risk Management Agreement between
Mirant Mid-Atlantic, LLC and Mirant Americas Energy Marketing L.P.
dated as of March 30, 2001
10.9(b)* Schedule identifying substantially identical agreement to Amended
and Restated Services and Risk Management Agreement constituting
Exhibit 10.9(a) hereto
10.10(a)* Master Power Purchase and Sale Agreement between Southern Energy
Mid-Atlantic, LLC and Southern Company Energy Marketing L.P. dated
as of December 18, 2000
10.10(b)* Schedule identifying substantially identical agreement to Master
Power Purchase and Sale Agreement constituting Exhibit 10.10(a)
hereto
10.11* Agency Agreement between Southern Energy Mid-Atlantic, LLC, Southern
Energy Chalk Point, LLC, Southern Energy Peaker, LLC and Southern
Energy Potomac River dated as of December 18, 2000
10.12* Capital Contribution Agreement between Southern Energy, Inc. and
Southern Energy Mid-Atlantic, LLC dated as of December 19, 2000
10.13* Promissory Note between Southern Energy Mid-Atlantic, LLC and
Southern Energy Peaker, LLC in the original principal amount of
$71,110,000 dated as of December 19, 2000
10.14* Promissory Note between Southern Energy Mid-Atlantic, LLC and
Southern Energy Potomac River, LLC in the original principal amount
of $152,165,000 dated as of December 19, 2000
10.15(a)* Shared Facilities Agreement (Dickerson) between Southern Energy Mid-
Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC, Dickerson OL3
LLC and Dickerson OL4 LLC dated as of December 18, 2000
10.15(b)* Shared Facilities Agreement (Morgantown) between Southern Energy
Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC,
Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC,
Morgantown OL6 LLC and Morgantown OL7 LLC dated as of December 18,
2000
10.16(a)* Assignment and Assumption Agreement (Dickerson) between Southern
Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC,
Dickerson OL3 LLC and Dickerson OL4 LLC dated as of December 19,
2000
10.16(b)* Assignment and Assumption Agreement (Morgantown) between Southern
Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC,
Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC,
Morgantown OL6 LLC and Morgantown OL7 LLC dated as of December 19,
2000
10.17(a)* Ownership and Operation Agreement (Dickerson) between Southern
Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC,
Dickerson OL3 LLC and Dickerson OL4 LLC dated as of December 18,
2000
10.17(b)* Ownership and Operation Agreement (Morgantown) between Southern
Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC,
Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC,
Morgantown OL6 LLC and Morgantown OL7 LLC dated as of December 18,
2000
10.18* Amended and Restated Revolving Promissory Note between Southern
Energy North America Generating, Inc. (currently known as Mirant
Americas Generation, Inc.) and Southern Energy Mid-Atlantic, LLC in
the original principal amount of up to $150,000,000 dated as of
April 27, 2001
10.19(a)* Administrative Services Agreement between Southern Energy Resources,
Inc. (currently known as Mirant Services, LLC) and Southern Energy
Mid-Atlantic, LLC dated as of December 19, 2000
10.19(b)* Schedule identifying substantially identical agreement to
Administrative Services Agreement constituting Exhibit 10.19(a)
hereto
10.20(a)* Management and Personnel Services Agreement between Southern Energy
PJM Management, LLC and Southern Energy Mid-Atlantic, LLC dated as
of December 19, 2000
10.20(b)* Schedule identifying substantially identical agreements to
Management and Personnel Services Agreement constituting Exhibit
10.20(a) hereto
10.21(a)* Guaranty Agreement (Dickerson L1) between Southern Energy, Inc. and
Dickerson OL1 LLC dated as of December 19, 2000
10.21(b)* Schedule identifying substantially identical agreements to Guaranty
Agreement constituting Exhibit 10.21(a) hereto
10.22(a)* Guaranty Agreement (Morgantown L1) between Southern Energy, Inc. and
Morgantown OL1 LLC dated as of December 19, 2000
10.22(b)* Schedule identifying substantially identical agreements to Guaranty
Agreement constituting Exhibit 10.22(a) hereto
10.23 Form of Energy and Capacity Sales Agreement between Mirant Mid-
Atlantic, LLC and Mirant Americas Energy Marketing, LP dated as of
August 1, 2001
10.24 Form of Energy and Capacity Sales Agreement between Mirant Chalk
Point, LLC and Mirant Americas Energy Marketing, LP dated as of
August 1, 2001
10.25 Form of Energy and Capacity Sales Agreement between Mirant Peaker,
LLC and Mirant Americas Energy Marketing, LP dated as of August 1,
2001
10.26 Form of Energy and Capacity Sales Agreement between Mirant Potomac
River, LLC and Mirant Americas Energy Marketing, LP dated as of
August 1, 2001
12.1* Statement regarding ratio of earnings to fixed charges
21.1* Schedule of Subsidiaries
23.1* Consent of PA Consulting Services Inc.
23.2 Consent of R.W. Beck, Inc.
23.3 Consent of Independent Public Accountants
24.1* Power of Attorney
25.1* Statement of Eligibility of State Street Bank and Trust Company of
Connecticut, National Association for the 8.625% Exchange Pass Through
Certificates, Series A, 9.125% Exchange Pass Through Certificates,
Series B and 10.060% Exchange Pass Through Certificates, Series C, on
Form T-1
99.1* Form of Letter of Transmittal
99.2* Form of Notice of Guaranteed Delivery
99.3* Form of Letters to Brokers, Dealers, Commercial Banks, Trust Companies
and Other Nominees
99.4* Form of Letter to Clients
- --------
* Previously filed.