<PAGE>
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JUNE 29, 2000
REGISTRATION NO. 333-
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------------
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
--------------------------
AES RED OAK, L.L.C.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C> <C>
DELAWARE 4930 54-1889658
(State of Organization) (Primary Standard Industrial (I.R.S. Employer Identification
Classification Number) No.)
</TABLE>
--------------------------
1001 NORTH 19TH STREET
ARLINGTON, VIRGINIA 22209
(703) 522-1315
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
------------------------------
PATTY ROLLIN
1001 NORTH 19TH STREET
ARLINGTON, VIRGINIA 22209
(703) 522-1315
(Names and addresses, including zip codes, and telephone numbers,
including area codes, of agents for service)
------------------------------
IT IS RESPECTFULLY REQUESTED THAT THE COMMISSION SEND COPIES OF ALL NOTICES,
ORDERS AND COMMUNICATIONS TO:
MICHAEL B. BARR
HUNTON & WILLIAMS
1900 K STREET, NW
WASHINGTON, DC 20006
(202) 955-1500
(202) 778-2201 (FACSIMILE)
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: AS SOON AS
PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES EFFECTIVE AND ALL OTHER
CONDITIONS TO THE PROPOSED EXCHANGE OFFER DESCRIBED HEREIN HAVE BEEN SATISFIED
OR WAIVED.
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. / / ______
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
MAXIMUM MAXIMUM
TITLE OF EACH CLASS AMOUNT TO BE OFFERING PRICE AGGREGATE AMOUNT OF
OF SECURITIES TO BE REGISTERED REGISTERED PER BOND OFFERING PRICE REGISTRATION FEE
<S> <C> <C> <C> <C>
8.54% Senior Secured Exchange Bonds
Series A Due 2019................... $224,000,000 100% $224,000,000 $59,136
9.20% Senior Secured Exchange Bonds
Series B Due 2029................... $160,000,000 100% $160,000,000 $42,240
</TABLE>
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT WILL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT WILL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT WILL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A),
MAY DETERMINE.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>
The information in this prospectus is not complete and may be changed. We cannot
and will not exchange the bonds until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell the exchange bonds and it is not a solicitation of an offer to buy the
exchange bonds in any state where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED JUNE 29, 2000
PROSPECTUS
[LOGO]
AES RED OAK, L.L.C.
<TABLE>
<S> <C>
$224,000,000 $160,000,000
OFFER TO EXCHANGE ALL OUTSTANDING OFFER TO EXCHANGE ALL OUTSTANDING
8.54% SENIOR SECURED BONDS SERIES A DUE 2019 9.20% SENIOR SECURED BONDS SERIES B DUE 2029
FOR FOR
8.54% SENIOR SECURED EXCHANGE BONDS SERIES A DUE 2019 9.20% SENIOR SECURED EXCHANGE BONDS SERIES B DUE 2029
</TABLE>
---------------------
INTEREST PAYABLE FEBRUARY 28, MAY 31, AUGUST 31 AND NOVEMBER 30
o The exchange offer will expire at 5:00 p.m. New York City time on
______, 2000, unless otherwise extended. The exchange offer will
not be extended beyond _______________, 2000.
o All outstanding bonds that are validly tendered and not validly
withdrawn prior to the expiration of the exchange offer will be
exchanged for an equal principal amount of exchange bonds that are
registered under the Securities Act of 1933.
o The exchange of outstanding bonds for exchange bonds will not be a
taxable event for U.S. federal income tax purposes.
o We do not intend to list the exchange bonds on any national
securities exchange or NASDAQ.
YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE [__] OF
THIS PROSPECTUS BEFORE PARTICIPATING IN THE EXCHANGE OFFER OR INVESTING IN THE
EXCHANGE BONDS ISSUED IN THE EXCHANGE OFFER.
We are not making this exchange offer in any state or jurisdiction
where it is not permitted.
--------------------------------------------------------------------------------
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED THE EXCHANGE BONDS TO BE DISTRIBUTED IN
THE EXCHANGE OFFER, NOR HAVE ANY OF THESE ORGANIZATIONS DETERMINED THAT THIS
PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
--------------------------------------------------------------------------------
The date of this prospectus is ____________, 2000.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUMMARY.............................................3
RISK FACTORS..................................................21
USE OF PROCEEDS...............................................28
CAPITALIZATION................................................29
CALCULATION OF EARNINGS TO FIXED CHARGES DEFICIENCY...........29
THE EXCHANGE OFFER............................................30
SELECTED FINANCIAL DATA.......................................38
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION...39
OUR BUSINESS..................................................41
OUR MANAGEMENT................................................43
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................45
SUMMARY OF PRINCIPAL PROJECT CONTRACTS........................46
ROLE OF THE INDEPENDENT ENGINEER..............................77
DESCRIPTION OF THE EXCHANGE BONDS.............................79
SUMMARY OF THE PRINCIPAL FINANCING DOCUMENTS..................86
PLAN OF DISTRIBUTION.........................................119
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS..............119
EXPERTS......................................................120
LEGAL MATTERS................................................120
WHERE YOU CAN FIND MORE INFORMATION..........................120
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS...................F-1
ANNEX A-GLOSSARY OF TERMS....................................A-1
ANNEX B-INDEPENDENT TECHNICAL REVIEW.........................B-1
ANNEX C-INDEPENDENT MARKET ASSESSMENT........................C-1
</TABLE>
--------------------------
This prospectus is part of a registration statement we filed with the
Securities and Exchange Commission. You should rely only on the information or
representations provided in this prospectus. We have not authorized any person
to provide information other than that provided in this prospectus. We are not
making an offer of these securities in any jurisdiction 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 page of this
prospectus.
Unless otherwise indicated:
o the 8.54% Senior Secured Bonds Series A due 2019 and
the 9.20% Senior Secured Bonds Series B due 2029, each issued
on March 15, 2000, are collectively referred to in this
prospectus as the outstanding bonds;
o the 8.54% Senior Secured Exchange Bonds Series A due
2019, or Series A exchange bonds, and the 9.20% Senior Secured
Exchange Bonds Series B due 2029, or Series B exchange bonds,
offered under this prospectus are collectively referred to in
this prospectus as the exchange bonds; and
o the outstanding bonds and the exchange bonds are
collectively referred to as the bonds.
Each broker-dealer that receives exchange bonds for its own account
under the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of exchange bonds. The letter of transmittal 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, or the Securities Act. This prospectus, as it may be
amended or supplemented from time to time, may be used by a broker-dealer in
connection with resales of exchange bonds received in exchange for outstanding
bonds where the outstanding bonds were acquired by the broker-dealer as a result
of market-making activities or other trading activities. We have agreed that,
starting on the expiration date of the exchange offer and ending on the close of
business 270 days after the expiration date, we will make this prospectus
available to any broker-dealer for use in connection with any resale. See "PLAN
OF DISTRIBUTION."
<PAGE>
PROSPECTUS SUMMARY
This summary highlights selected information from this prospectus but
does not contain all of the information that is important to you. To understand
all of the terms of the exchange offer and the exchange bonds and to attain a
more complete understanding of our business and financial condition, you should
read carefully this entire prospectus. For an explanation of specific technical
terms used in this prospectus, please read "ANNEX A: GLOSSARY OF TECHNICAL
TERMS."
AES RED OAK, L.L.C.
We were formed to develop, construct, own, lease, operate and maintain
a gas-fired electric generating power plant in the Borough of Sayreville,
Middlesex County, New Jersey. We are a development stage company and currently
have no operating revenues. All of the equity interests in our company is owned
by AES Red Oak, Inc., a wholly owned subsidiary of The AES Corporation. The AES
Corporation will provide funds to AES Red Oak, Inc. so that AES Red Oak, Inc.
can make an equity contribution to us to fund our project costs. AES Red Oak,
Inc. currently has no operations outside of its activities in connection with
our project and does not anticipate undertaking any unrelated operations. AES
Red Oak, Inc. also owns all of the equity interest in AES Sayreville, L.L.C.,
which will provide development, construction management, and operations and
maintenance services to us. AES Sayreville has no operations outside of its
activities in connection with our project. AES Red Oak, Inc. has no assets other
than its membership interests in us and AES Sayreville. The AES Corporation will
supply AES Sayreville with personnel and services necessary to carry out its
obligations to us. The AES Corporation is a public company and files reports,
proxy statements and other information, including financial reports, with the
SEC. See "WHERE YOU CAN FIND MORE INFORMATION."
We own all of the equity interests in AES Red Oak Urban Renewal
Corporation, or AES URC, which was organized as an urban renewal corporation
under New Jersey law so that portions of our project can be designated as
redevelopment areas or projects in order to provide real estate tax and
development benefits for our project. AES URC has no operations outside of its
activities in connection with our project.
The following organizational chart illustrates the relationship among
us, AES Red Oak, Inc., AES Sayreville, The AES Corporation, and AES URC:
[GRAPHIC]
OUR FACILITY
Upon completion of construction, our facility will consist of an
approximately 830 megawatt (net) gas-fired combined cycle electric generating
facility. We expect our facility to become operational on or about December 31,
2001, although we cannot assure you of this. We will sell all of our facility's
capacity, and provide fuel conversion and ancillary services, to Williams Energy
Marketing & Trading Company under a long-term power purchase agreement. We will
not receive material revenues under the power purchase agreement or otherwise
before our facility becomes operational. After the expiration of the 20-year
term of the power purchase agreement, we expect to operate our facility
3
<PAGE>
as a merchant plant. A merchant plant is an electric generation facility with no
dedicated long term power purchase agreement.
Our facility will be located on property that we own in the Borough
of Sayreville, Middlesex County, New Jersey. Our facility will be designed,
engineered, procured and constructed for us by Raytheon Engineers and
Constructors, Inc. under a fixed-price, turnkey construction agreement.
Raytheon Engineers is a wholly owned subsidiary of the Morrison Knudsen
Company, which recently acquired Raytheon Engineers from the Raytheon
Company. Among other components, our facility will use three Siemens
Westinghouse model 501F combustion turbines, three heat recovery steam
generators and one multicylinder steam turbine. Under a maintenance services
agreement, Siemens Westinghouse Power Corporation will provide us with
specific combustion turbine maintenance services and spare parts in respect
of each combustion turbine until sixteen years after execution of the
agreement or the twelfth planned outage of the combustion turbine, whichever
is earlier, unless we exercise our right to cancel the agreement after the
first major outage of the combustion turbines which will be after
approximately the sixth year of operation of the facility. Under the power
purchase agreement, Williams Energy or its affiliates will supply fuel
necessary to allow us to provide capacity, fuel conversion and ancillary
services to Williams Energy. AES Sayreville will provide development,
construction management, and operations and maintenance services for our
facility under an operations agreement. We will provide installation,
operation and maintenance of facilities necessary to interconnect our
facility to Jersey Central Power & Light Company's transmission system under
an interconnection agreement.
-------------------------
We are a Delaware limited liability company with principal executive
offices located at 1001 North 19th Street, Arlington, Virginia, 22209, c/o The
AES Corporation. Our telephone number is (703) 522-1315.
4
<PAGE>
SUMMARY OF THE TERMS OF THE EXCHANGE BONDS
This exchange offer relates to the exchange of up to $224,000,000
principal amount of Series A exchange bonds and up to $160,000,000 principal
amount of Series B exchange bonds each for an equal principal amount of
outstanding bonds. The form and terms of the exchange bonds are substantially
identical to the form and terms of the outstanding bonds, except the exchange
bonds will be registered under the Securities Act. Therefore, the exchange bonds
will not bear legends restricting their transfer. The exchange bonds will
evidence the same debt as the outstanding bonds, which they are replacing, and
both the outstanding bonds and the exchange bonds are governed by the same
indenture.
ISSUER: AES Red Oak, L.L.C.
SECURITIES OFFERED: The exchange bonds will be offered in two series:
o $224,000,000 aggregate principal amount of
8.54% Senior Secured Exchange Bonds Series A
due 2019; and
o $160,000,000 aggregate principal amount of
9.20% Senior Secured Exchange Bonds Series B
due 2029.
INTEREST: We will pay interest on the bonds quarterly in
arrears on each February 28, May 31, August 31 and
November 30 to the registered owners on the
immediately preceding record date.
PRINCIPAL REPAYMENT: We will pay principal on the bonds in installments
quarterly on each February 28, May 31, August 31 and
November 30, commencing August 31, 2002, for Series A
bonds and February 28, 2019 for Series B bonds, to
the registered owners on the immediately preceding
record date as described under "DESCRIPTION OF THE
EXCHANGE BONDS--Payment of Interest and Principal."
FINAL MATURITY DATE: Series A bonds, November 30, 2019.
Series B bonds, November 30, 2029.
RATINGS: The outstanding bonds have been and the exchange
bonds, when issued, are expected to be rated "BBB-"
by Standard and Poor's Rating Group, or Standard &
Poor's, and "Baa3" by Moody's Investors Services,
Inc., or Moody's.
SUMMARY OF
COVERAGE RATIOS: You will find projected coverage ratios with respect
to the bonds in the projections included in the
independent technical review, which we have attached
as Annex B, and these ratios are subject to the
qualifications, limitations and exclusions set forth
in the independent technical review. The following
projected ratios reflect the base case assumptions
set forth in the independent technical review.
<TABLE>
<CAPTION>
SERIES A BONDS SERIES B BONDS SERIES B BONDS
-------------- -------------- --------------
(POWER PURCHASE AGREEMENT (POWER PURCHASE AGREEMENT (POST-POWER PURCHASE
TERM ONLY) TERM ONLY) AGREEMENT TERM ONLY)
<S> <C> <C> <C>
Debt Service Coverage
Minimum................... 1.55 1.55 6.37
Average................... 1.57 1.57 7.13
Interest Coverage
Minimum................... 1.69 1.69 12.33
Average................... 2.47 2.78 35.01
</TABLE>
Because the term of the power purchase agreement
extends beyond the maturity date of the Series A
bonds, no post-power purchase agreement coverage
ratio has been provided for the Series A bonds.
5
<PAGE>
As set forth in the independent technical review,
these projections are subject to risks, uncertainties
and other factors which could cause actual results to
differ materially from those stated. We cannot assure
that these projected coverage ratios will be
achieved. See "ANNEX B: INDEPENDENT TECHNICAL REVIEW"
and "RISK FACTORS" regarding reliance on projections
and underlying assumptions
OPTIONAL REDEMPTION: We may redeem any of the bonds, in whole or in part,
at any time at a redemption price equal to:
o 100% of the principal amount; plus
o accrued interest; plus
o a make-whole premium that is calculated
using a discount rate equal to the interest
rate on comparable U.S. Treasury securities
plus 50 basis points.
MANDATORY
REDEMPTION: We must redeem the bonds, in whole or in part, at a
redemption price equal to 100% of the principal
amount plus accrued interest if:
o we receive casualty proceeds, eminent domain
proceeds or specific performance liquidated
damages from Raytheon Engineers under the
construction agreement; and
o specified additional conditions are
satisfied.
In addition, we must redeem the bonds, in whole or in
part, at a redemption price equal to 100% of the
principal amount plus accrued interest when we
receive proceeds under the guaranty provided by The
Williams Companies, Inc. as security for obligations
of Williams Energy under our power purchase agreement
if we terminate the power purchase agreement as a
result of an event of default by Williams Energy. See
"DESCRIPTION OF THE EXCHANGE BONDS--Mandatory
Redemption."
RESALE OF THE EXCHANGE
BONDS: We believe that beneficial interests in the exchange
bonds may be offered for resale, resold and otherwise
transferred by most owners of the exchange bonds
without further compliance with the registration and
prospectus delivery requirements of the Securities
Act so long as:
o you are acquiring the exchange bonds in the
ordinary course of your business;
o you are not participating, and have no
arrangement or understanding with any person
to participate, in the distribution of the
exchange bonds; and
o you are not an affiliate, insider or a
related party of ours.
This belief is based upon existing interpretations of
the staff of the SEC's Division of Corporation
Finance described in several no-action letters issued
to third parties unrelated to us and subject to
important restrictions described in "THE EXCHANGE
OFFER--Purpose and Effect of the Exchange Offer." We
do not intend to seek our own no-action letter. If
our belief is wrong and you transfer an exchange bond
without delivering a prospectus meeting the
requirements of the Securities Act or without an
exemption from those requirements, you may incur
liability under the Securities Act. We do not and
will not assume or indemnify you against this
liability. We cannot assure you that the staff of the
SEC's Division of Corporation Finance would make a
similar determination about the exchange bonds as it
has in no-action letters regarding similar exchanges
of the securities of other companies.
Only broker-dealers that acquired the outstanding
bonds as a result of market-making or other trading
activities may participate in the exchange offer.
Each broker-dealer that receives
6
<PAGE>
exchange bonds for its own account in the exchange
offer must acknowledge that it will deliver a
prospectus in connection with any resale of those
exchange bonds. This prospectus, as it may be amended
or supplemented from time to time, may be used by a
broker-dealer in connection with those resales.
Broker-dealers that acquired outstanding bonds
directly from us may not rely on the interpretations
of the SEC referred to above. Accordingly, in order
to sell their bonds, broker-dealers that acquired
outstanding bonds directly from us must comply with
the registration and prospectus delivery
requirements, including being named as a selling
security holder in any resale prospectus.
EQUITY CONTRIBUTION: We have entered into an equity subscription agreement
with AES Red Oak, Inc. under which AES Red Oak, Inc.
has agreed to contribute as base equity the amount of
$41,556,431 to us to fund project costs. In addition,
AES Red Oak, Inc. will be obligated to contribute up
to an additional $14,193,600 in contingent equity to
fund construction period contingencies. AES Red Oak,
Inc.'s obligation under the equity subscription
agreement to contribute base equity must be supported
by a letter of credit or insurance company bond
which are required to be issued respectively, by
a financial institution and insurance company rated
at least "A" by Standard & Poor's and "A2" by
Moody's. AES Red Oak, Inc. has provided an insurance
bond issued by an insurance company meeting the
required ratings criteria to support its base equity
contribution obligations. AES Red Oak, Inc.'s
obligation under the equity subscription agreement to
contribute contingent equity is supported by a
guaranty of The AES Corporation. AES Red Oak, Inc.
will fund base equity amounts available under the
equity subscription agreement when all funds in the
construction account have been exhausted, during the
continuation of an event of default under the
indenture, or on the commercial operation date,
whichever occurs first.
The commercial operation date is the date on which
initial startup testing at our facility has been
successfully completed and all necessary approvals,
permits, and authorizations have been obtained to
allow us to begin selling energy and capacity, and
must occur prior to June 30, 2003 under the power
purchase agreement. We have the option of treating a
portion or all of the base equity contribution and
contingent equity contribution as affiliate
subordinated debt. Subject to the conditions set
forth in the equity subscription agreement and the
collateral agency agreement, any portion of the
contingent equity commitment that remains available
to fund construction period contingencies, but that
has not been required to be funded upon commercial
operation of our facility, may be canceled.
RANKING: Other than the bonds, which have an aggregate
principal amount of $384 million, we do not have any
outstanding long-term debt. The bonds will:
o rank equally in right of payment with all
other present and future senior debt; and
o rank senior in right of payment to all
subordinated debt.
COLLATERAL: The bonds will rank equally with all of our other
senior debt and will be secured by a lien on and
security interest in the collateral. The indenture
accounts, the debt service reserve account and the
debt service reserve letter of credit (other than to
the extent of the letter of credit provider's right
to specific proceeds) will constitute separate
collateral solely for the benefit of the holders of
the bonds. Additionally, the collateral for the
benefit of holders of senior debt (including holders
of the bonds) will include:
o all of our revenues and those of AES URC, if
any;
o the project accounts, other than the debt
service reserve account;
o all of our real and personal property,
including ownership interests in AES URC and
the real and personal property interests of
AES URC;
o proceeds of insurance, condemnation and
liquidated damages payments, if any;
7
<PAGE>
o all project contracts;
o all ownership interests in our company; and
o the equity contribution and all rights under
the equity subscription agreement.
LIMITED RECOURSE: All obligations in connection with the bonds will be
ours alone. The bondholders will have no claim
against or recourse to the holders of our member
interests or any of our affiliates or any of their
incorporators, stockholders, directors, officers or
employees for the repayment of the bonds, except to
the extent of their obligations under the project and
financing agreements, including the equity
contribution and the pledge of AES Red Oak, Inc.'s
ownership interests in our company.
DEBT SERVICE
RESERVE ACCOUNT: We will be required to fund or provide for the
funding of a debt service reserve account on the
earlier of the commercial operation date or the
guaranteed provisional acceptance date under the
construction agreement in an amount sufficient on
that date, and thereafter, to pay principal and
interest due on the bonds on the next two payment
dates. We may satisfy this requirement by providing a
letter of credit in lieu of funding the debt service
reserve account. We have arranged to satisfy this
requirement by obtaining a letter of credit issued by
Dresdner Bank AG, New York Branch in an amount equal
to the amount required to be in the debt service
reserve account plus six months of interest on the
maximum amount of the letter of credit. We may
replace that letter of credit with one issued by
another financial institution rated at least "A" by
Standard & Poor's and "A2" by Moody's.
CHANGE IN CONTROL: While the bonds are outstanding, the indenture
requires The AES Corporation to maintain directly or
indirectly at least 51% of both of the voting and
economic interests in our company. If The AES
Corporation desires to reduce its voting or economic
interest in our company below 51%, either we must
receive confirmation of the then current ratings of
the bonds or the holders of at least 66-2/3% in
aggregate principal amount of the bonds must approve
the change in ownership.
OTHER PRINCIPAL
COVENANTS: The indenture contains limitations on, among other
actions:
o incurring additional indebtedness;
o granting liens on our property;
o paying dividends or otherwise making
distributions with respect to equity and
paying subordinated indebtedness issued by
our affiliates;
o entering into transactions with affiliates;
o amending, terminating or assigning project
contracts; and
o fundamental changes or disposition of
assets.
See "SUMMARY OF PRINCIPAL FINANCING
DOCUMENTS--Indenture--Negative Covenants."
FORM, DENOMINATION
AND REGISTRATION
OF BONDS: Exchange bonds will be issued in fully registered
form without coupons in denominations of U.S.
$100,000 and any integral multiple of U.S. $1,000 in
excess thereof and will be represented by one or more
global bonds, each registered in the name of a
nominee of DTC.
8
<PAGE>
Beneficial interests in the global bonds will be
shown on, and transfers of the beneficial interests
will be effected only through, the book-entry records
maintained by DTC and its direct and indirect
participants, including the Euroclear Systems and
Clearstream Banking, societe anonyme.
GOVERNING LAW: The bonds, the indenture and the other principal
financing documents, other than the mortgages, are
governed by the laws of the State of New York. The
mortgages are governed by the laws of the State of
New Jersey.
INTERCREDITOR
ARRANGEMENTS: The collateral agency agreement requires the vote of
our senior creditors holding a majority of our debt
to direct specified actions of the collateral agent.
The initial collateral agent under the collateral
agency agreement is The Bank of New York. The
collateral agent is appointed by the senior creditors
to act on their behalf and may be directed to
exercise remedies following:
o an event of default and an acceleration of
the indebtedness under the debt service
reserve letter of credit and reimbursement
agreement under which the letter of credit
provider will provide to us a letter of
credit to fund the debt service reserve
account;
o an event of default and an acceleration of
the indebtedness under the power purchase
agreement letter of credit and reimbursement
agreement, under which the letter of credit
provider will provide to us a letter of
credit to serve as security for certain of
our obligations under the power purchase
agreement;
o an event of default and an acceleration of
the indebtedness under the working capital
agreement;
o an event of default and an acceleration of
the indebtedness under the indenture; or
o a bankruptcy event with respect to us or AES
URC.
In respect of matters voted on by the senior
creditors, The Bank of New York, as trustee, under
the indenture will vote all bonds according to the
votes of a majority of bondholders voting. See
"SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Collateral
Agency Agreement."
ACCOUNTS AND
FLOWS OF FUNDS: Following the commercial operation date, all of our
revenues will be deposited in accounts established
under the financing documents and held by The Bank of
New York, as trustee and collateral agent. In most
circumstances, operating revenues will be applied in
the following order:
o operating and maintenance costs, including
any working capital loans and commitment
fees;
o administrative fees, costs and expenses of:
- The Bank of New York as trustee and
collateral agent; and
- Dresdner Bank AG, acting through
its New York Branch, as working
capital agent, debt service reserve
letter of credit provider and power
purchase agreement letter of credit
provider;
o interest payments on:
9
<PAGE>
- the bonds,
- the debt service reserve letter of
credit loans; and
- the power purchase agreement letter
of credit loans, if any;
o principal payments on the bonds, the debt
service reserve letter of credit bonds, the
debt service reserve letter of credit term
loans, and the power purchase agreement
letter of credit loans, if any;
o principal payments on debt service reserve
letter of credit loans and replenishment of
the debt service reserve account;
o required deposits in the major maintenance
reserve account;
o non-dispatch payments to Williams Energy;
o fuel conversion volume rebate payments to
the account of Williams Energy;
o repayment of third-party subordinated debt;
o subordinated bonuses, if any, to Raytheon
Engineers; and
o subject to the restricted payments test,
permitted distributions to persons holding
ownership interests in our company or for
payments of affiliate subordinated debt.
Under circumstances involving an expiration, non-renewal or
replacement of the debt service reserve letter of credit, the
reduction in the credit rating of the issuing bank or
specified delays in repayment of the principal amount of debt
service reserve letter of credit loans, principal repayments
of drawings on the letter of credit will be made at the same
priority as principal on the bonds. Under some circumstances,
if no default or event of default under the indenture is
continuing, we may from time to time withdraw funds then
deposited in specified accounts established under the
financing documents so long as we provide to the collateral
agent acceptable credit support to ensure repayment of the
withdrawn funds. See "SUMMARY OF PRINCIPAL FINANCING
DOCUMENTS--Collateral Agency Agreement--Payments During
Operating Period" and "--Advances."
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PREPAYMENT OF
CONSTRUCTION
AGREEMENT: We have prepaid the fixed-price of the construction
agreement by requisitioning a portion of the proceeds
of the sale of the bonds to pay a discounted
fixed-price amount reduced by payments previously
made according to the schedule of payments set forth
in the construction agreement. As a condition to the
construction agreement prepayment, Raytheon Engineers
provided us with a letter of credit meeting certain
criteria set forth in the financing documents,
including being issued by a financial institution
rated at least "A" by Standard & Poor's and "A2" by
Moody's. The amount available to be drawn under the
letters of credit will be reduced from time to time
upon submission of a requisition by us specifying,
among other things, that the applicable portions of
work required to be completed under the construction
agreement have been completed in accordance with the
terms of the construction agreement. The collateral
agent will be entitled to draw on the letters of
credit upon the occurrence of certain events,
including, but not limited to, a default by Raytheon
Engineers or other events of default under the
financing documents.
INDEPENDENT ENGINEER: Stone & Webster Management Consultants, Inc., the
independent engineer, is responsible for confirming
the reasonableness of specific statements and
projections made in specified certificates required
to be provided by us to the collateral agent and
the trustee, including with respect to:
o satisfaction of specific requirements under
the construction agreement;
o the cost of and occurrence of the completion
of rebuilding, repairing or restoring our
facility following an event of loss or event
of eminent domain;
o under specified circumstances, the
calculation of debt service coverage ratios
and the consistency of assumptions made in
connection therewith;
o whether any termination, amendment or
modification of any project contract would
reasonably be expected to have a material
adverse effect; and
o specified tests required for the issuance of
additional debt.
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SUMMARY OF THE EXCHANGE OFFER
We summarize the terms of the exchange offer below. You should read the
discussion under the heading "THE EXCHANGE OFFER" beginning on page [ _____ ]
for further information regarding the exchange offer and resale of the exchange
bonds.
THE EXCHANGE OFFER: We are offering to exchange up to $384,000,000
aggregate principal amount of exchange bonds, which
have been registered under the Securities Act, for up
to $384,00,000 aggregate principal amount of
outstanding bonds, which we issued in two series on
March 15, 2000 in a private offering. In order for
your outstanding bonds to be exchanged, you must
properly tender them prior to the expiration of the
exchange offer. Except as set forth below under
"Conditions to the Exchange Offer," all outstanding
bonds that are validly tendered and not validly
withdrawn will be exchanged. We will issue exchange
bonds as soon as practicable after the expiration of
the exchange offer. Outstanding bonds may be
exchanged for exchange bonds only in integral
multiples of $1,000.
REGISTRATION RIGHTS
AGREEMENT: We sold the outstanding bonds on March 15, 2000 to
the initial purchasers of the outstanding bonds.
Simultaneously with that sale, we signed a
registration rights agreement with the initial
purchasers which requires us to conduct this exchange
offer.
You have the right pursuant to the registration
rights agreement to exchange your outstanding bonds
for exchange bonds with substantially identical
terms. This exchange offer is intended to satisfy
this right. After the exchange offer is complete, you
will no longer be entitled to any exchange or
registration rights with respect to outstanding bonds
you do not tender for exchange.
CONSEQUENCES OF FAILURE
TO EXCHANGE YOUR
OUTSTANDING BONDS: If you do not exchange your outstanding bonds for
exchange bonds pursuant to the exchange offer, you
will continue to be subject to the restrictions on
transfer provided in the outstanding bonds and the
indenture. In general, the outstanding bonds may not
be offered or sold unless registered under the
Securities Act, except pursuant to an exemption from,
or in a transaction not subject to, the Securities
Act and applicable state securities laws. We do not
intend to register any untendered outstanding bonds
under the Securities Act. To the extent that
outstanding bonds are tendered and accepted in the
exchange offer, the trading market for untendered
outstanding bonds and tendered but unaccepted
outstanding bonds will be adversely affected.
EXPIRATION DATE: The exchange offer will expire at 5:00 p.m., New York
City time, on ______, 2000, or a later date and time
to which we may extend it, in which case the term
"expiration date" will mean the latest date and time
to which the exchange offer is extended.
Notwithstanding the preceding sentence, we will not
extend the expiration date beyond ____________, 2000.
WITHDRAWAL OF TENDERS: You may withdraw your tender of outstanding bonds at
any time prior to the expiration date by delivering
written notice of your withdrawal to the exchange
agent in accordance with the withdrawal procedures
described in this prospectus. We will return to you,
without charge, promptly after the expiration or
termination of the exchange offer any outstanding
bonds that you tendered but that were not exchanged.
CONDITIONS TO
THE EXCHANGE OFFER: We will not be required to accept outstanding bonds
for exchange if the exchange offer would violate
applicable law or SEC interpretations or any legal
action has been instituted or threatened that would
impair our ability to proceed with the exchange
offer. The exchange offer is not conditioned upon any
minimum aggregate principal amount of outstanding
bonds being tendered. We reserve the right to
terminate the exchange offer if certain specified
conditions have not been satisfied and to waive any
condition or otherwise amend the terms of the
exchange offer in any respect. Please read the
section "THE EXCHANGE OFFER--
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Conditions to the Exchange Offer" on page [ ____ ]
for more information regarding the conditions to the
exchange offer.
PROCEDURES FOR
TENDERING OUTSTANDING
BONDS AND
REPRESENTATIONS: If your outstanding bonds are held through The
Depository Trust Company and you wish to participate
in the exchange offer, you may do so through one of
the following methods:
o DELIVERY OF A LETTER OF TRANSMITTAL. You
must complete and sign a letter of
transmittal in accordance with the
instructions contained in the letter of
transmittal and forward the letter of
transmittal by mail, facsimile transmission
or hand delivery, together with any other
required documents, to the exchange agent,
either with the outstanding bonds to be
tendered or in compliance with the specified
procedures for guaranteed delivery of the
outstanding bonds; or
o AUTOMATED TENDER OFFER PROGRAM OF THE
DEPOSITORY TRUST COMPANY. If you tender
under this program, you will agree to be
bound by the letter of transmittal that we
are providing with this prospectus as though
you had signed the letter of transmittal.
Under both methods, by signing or agreeing
to be bound by the letter of transmittal,
you will represent to us that, among other
things:
- any exchange bonds that you receive
are being acquired in the ordinary
course of your business;
- you have no arrangement or
understanding with any person or
entity to participate in any
distribution of the exchange bonds;
- you are not engaged in and do not
intend to engage in any
distribution of the exchange bonds;
- if you are a broker-dealer that
will receive exchange bonds for
your own account in exchange for
outstanding bonds, you acquired
those bonds as a result of
market-making activities or other
trading activities and you will
deliver a prospectus, as required
by law, in connection with any
resale of the exchange bonds; and
- you are not our "affiliate," as
defined in Rule 405 of the
Securities Act.
Please do not send your letter of transmittal or
certificates representing your outstanding bonds to
us. Those documents should only be sent to the
exchange agent. Questions regarding how to tender and
requests for information should be directed to the
exchange agent.
SPECIAL PROCEDURES FOR
BENEFICIAL OWNERS: If you own a beneficial interest in outstanding bonds
that are registered in the name of a broker, dealer,
commercial bank, trust company or other nominee, and
you wish to tender the outstanding bonds in the
exchange offer, you should contact the registered
holder promptly and instruct the registered holder to
tender on your behalf.
CONSEQUENCES OF NOT
COMPLYING WITH
EXCHANGE OFFER
PROCEDURES: You are responsible for complying with all exchange
offer procedures. You will only receive exchange
bonds in exchange for your outstanding bonds if,
prior to the expiration date, you deliver to the
exchange agent (1) the letter of transmittal,
properly completed and duly executed; (2) any other
documents or signature guarantees required by the
letter of transmittal; (3) certificates for the
outstanding bonds or a book-entry confirmation of a
book-
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entry transfer of the outstanding bonds into the
exchange agent's account at DTC.
Any outstanding bonds you hold and do not tender, or
which you tender but which are not accepted for
exchange, will remain outstanding. You will not have
any appraisal or dissenters' rights in connection
with the exchange offer.
You should allow sufficient time to ensure that the
exchange agent receives all required documents before
the expiration of the exchange offer. Neither we nor
the exchange agent has any duty to inform you of
defects or irregularities with respect to your tender
of outstanding bonds for exchange.
GUARANTEED DELIVERY
PROCEDURES: If you wish to tender your outstanding bonds and
cannot comply, prior to the expiration date, with the
applicable procedures for tendering outstanding bonds
described above and under "THE EXCHANGE
OFFER--Procedures for Tendering," you must tender
your outstanding bonds according to the guaranteed
delivery procedures described in "THE EXCHANGE
OFFER--Procedures for Tendering--Guaranteed Delivery
Procedures" beginning on page [ ____ ].
U.S. FEDERAL INCOME
TAX CONSIDERATIONS: The exchange of outstanding bonds for exchange bonds
in the exchange offer will not be a taxable event for
U.S. federal income tax purposes. Please read "UNITED
STATES FEDERAL INCOME TAX CONSIDERATIONS" on page
[ ____ ].
USE OF PROCEEDS: We will not receive any cash proceeds from the
issuance of exchange bonds. We intend to use the net
proceeds from the sale of the outstanding bonds,
together with an equity contribution of up to
approximately $55.75 million, to:
o fund the engineering, procurement,
construction, testing and commissioning of
our facility;
o pay legal, accounting and other related fees
and expenses in connection with the
financing and development of our project;
and
o pay project costs, including interest on the
bonds.
THE EXCHANGE AGENT: We have appointed The Bank of New York as exchange
agent for the exchange offer. You should direct
questions and requests for assistance, requests for
additional copies of this prospectus or the letter of
transmittal and requests for the notice of guaranteed
delivery to the exchange agent as follows: The Bank
of New York, 101 Barclay Street, Floor 7W, Attention:
Reorganization Department, New York, New York 10286;
(212) 815-2742. Eligible institutions may make
requests by facsimile at (212) 815-6339.
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SUMMARY OF RISK FACTORS
You should read the "Risk Factors" section of this prospectus as well
as the other cautionary statements contained in this prospectus before tendering
your outstanding bonds for exchange bonds or making an investment in the
exchange bonds. The following is a summary of the risks that are discussed in
detail in this prospectus:
OUR CASH FLOW AND OUR ABILITY TO SERVICE THE BONDS WILL BE ADVERSELY IMPACTED
IF:
o the commercial operations of our facility are significantly
delayed or are otherwise unable to generate sufficient cash
flow;
o the financial condition of parties that we depend on
deteriorates and cannot be replaced or those parties breach
their obligations to us;
o we encounter significant construction delays and any
liquidated damages, contingency funds, or insurance proceeds
available to us are insufficient to cover our financial needs;
o the insurance we have obtained is inadequate in the event of a
total loss or taking of our facility;
o unexpected events increase our expenses or reduce our
projected revenues once we are operational;
o compliance with environmental and other regulatory matters
cause significant delays or expenses; and
o we incur additional indebtedness as permitted under the
indenture or make drawings under letters of credit.
IN THE EVENT OF A DEFAULT, YOU MAY HAVE LIMITED OR NO RECOURSE BECAUSE:
o we are the sole legally responsible party in the event that
the proceeds from the bonds, the equity contribution and the
liquidation of the collateral are exhausted; and
o the collateral agency agreement contains provisions that may
limit the remedies that could be exercised in respect of the
events of default, other than a bankruptcy event of default,
unless and until the required senior parties have directed the
collateral agent to do so.
THE SUCCESS OF OUR PROJECT AND FUTURE OPERATIONS MAY BE IMPAIRED BECAUSE:
o we may incur problems relating to start-up, commissioning and
performance; and
o following the expiration of the power purchase agreement, our
facility is expected to become a merchant facility and we may
not be able to find adequate purchasers or otherwise compete
effectively in the merchant market.
UNDUE RELIANCE SHOULD NOT BE PLACED ON PROJECTIONS AND FORWARD-LOOKING
STATEMENTS BECAUSE:
o projections and their underlying assumptions are subject to
significant uncertainties and actual results often differ,
perhaps materially, from those projected; and
o forward-looking statements are based on current expectations
and our knowledge of facts as of the date of this prospectus
and are subject to various risks and uncertainties that are
outside of our control.
FAILURE OF A MARKET IN THE EXCHANGE BONDS TO DEVELOP COULD AFFECT THE LIQUIDITY
AND PRICE OF YOUR EXCHANGE BONDS:
o a lack of liquidity could mean that few, if any, buyers are
available to purchase your exchange bonds; and
o a lack of liquidity and prospective purchasers could mean that
you might only be able to sell your bonds at a price below
your cost.
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SUMMARY OF INDEPENDENT TECHNICAL REVIEW
Stone & Webster Management Consultants, Inc., with the assistance of
Stone & Webster Engineering Corporation, has prepared the independent technical
review concerning specific technical, environmental and economic aspects of our
facility. We have attached the independent technical review as Annex B to this
prospectus. The Independent technical review includes, among other things, a
conceptual design review of our facility, a review of the significant project
contracts and a review of financial projections, including annual revenues,
expenses and debt service coverage for our facility during the period the bonds
are scheduled to remain outstanding. We retained Stone & Webster to prepare the
independent technical review because it is a leading consulting engineering firm
which devotes a substantial portion of its resources to providing services
related to the technical, environmental and economic aspects of power projects.
Neither we, nor any of our affiliates, are affiliated with Stone & Webster.
For purposes of reviewing the projected operating results, Stone &
Webster relied on specific assumptions regarding material contingencies and
other matters that are not within our control or that of Stone & Webster or any
other person. Each of these assumptions is described in the independent
technical review. These assumptions are inherently subject to significant
uncertainties, and actual results may differ, perhaps materially, from those
projected. See "RISK FACTORS."
Subject to the information contained, and the assumptions and
qualifications made, in the independent technical review, Stone & Webster
expressed the opinions that:
1. The facility design, as specified in the construction
agreement, is in accordance with standard industry practice.
Raytheon Engineers possesses the organization and personnel to
execute its obligations under the construction agreement, and
is familiar with the construction and maintenance of large
electrical generation facilities. The project construction
schedule proposed by Raytheon Engineers is achievable and is
consistent with the terms of the power purchase agreement.
2. Siemens Westinghouse possesses the organization and personnel
to execute its obligations under the maintenance services
agreement.
3. Stone & Webster views the W501FD technology as a refinement on
the W501F technology, which has been in operation since 1993,
and is typical of normal design improvements by manufacturers.
The 501FD technology is similar to the W501FA and W501FC
technology, but incorporates advances in low NOx combustion
technology, compressor and blade designs, and cooling
technology. There are approximately 25 W501F technology units
in operation, with over 500,000 hours of operating history and
additional 68 W501F technology units, which will be
operational prior to or concurrently with the project. The
W501FD design was introduced to the marketplace in 1998 and
the first W501FD units are scheduled to commence commercial
operations in the first half of 2000. Thirty-seven W501FD's
have been sold to date in the United States alone, and 38
W501FD units will be in operation prior to, or concurrently
with the project. Three W501FC units (LS Power's Whitewater
and Cottage Grove and Empire State Line Unit 2) have upgraded
their compressors to the 501FD design and these units have
been operating since mid-1999.
4. The steam turbine and electrical generator designs are
acceptable and in accordance with standard industry practice.
5. If designed and constructed in accordance with the
construction agreement and operated and maintained in
accordance with the maintenance services agreement and the
operations agreement, the facility should be capable of
meeting the net output contract requirements specified in the
projected operating results. The useful life of the project,
provided it is maintained as set forth in the project
contracts, should exceed the life of the bonds.
6. The liquidated damages provisions of the construction
agreement are reasonable. The one year warranty period is
acceptable based on the commercial terms of the construction
agreement in conjunction with the one year warranty in the
maintenance services agreement. These two agreements, although
independent, are complementary and afford the project a
greater degree of protection than is available from the
construction agreement alone. The performance testing plan, as
specified in the construction agreement, is acceptable,
customary, and should adequately demonstrate the project's
performance.
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7. Williams Energy possesses the organization and personnel to
execute its obligations under the power purchase agreement,
and is familiar with the provision of fuel to, and purchase of
electricity from, large electrical generation facilities.
8. The facility can feasibly be electrically integrated into the
Pennsylvania/New Jersey/Maryland, or PJM, power pool market,
and no known transmission limitations will inhibit the
feasible evacuation of the facility's full net capacity both
under summer and winter conditions.
9. Stone & Webster will independently verify the design of the
water pipeline when it becomes available. Stone & Webster does
not know of any reason why the Borough of Sayreville should be
unable to perform its obligations under the water supply
agreement.
10. AES Sayreville, as an affiliate of AES and with the assistance
of Siemens Westinghouse under the terms of the maintenance
services agreement, should be capable of operating and
maintaining the facility in accordance with standard industry
practices.
11. The technical requirements described in the project contracts
are comprehensive, reasonable, and achievable as well as
consistent within and between the various documents.
12. The Phase I environmental site assessments, conducted by an
independent environmental consultant that indicated no
significant environmental issues, were performed in accordance
with standard industry practice, and the results appear
reasonable.
13. A majority of the project's required permits have been
acquired and the project's permit acquisition plan for those
permits not yet required is reasonable.
14. AES Red Oak, L.L.C. filed for certification of the facility as
an exempt wholesale generator under the applicable rules of
the Federal Energy Regulatory Commission, or FERC, on
September 13, 1999. On November 4, 1999, FERC found that AES
Red Oak, L.L.C. is an exempt wholesale generator as defined in
section 32 of the Public Utility Holding Company Act of 1935,
or PUHCA.
15. Assuming the facility is constructed, operated, and maintained
in accordance with the terms of the construction agreement,
power purchase agreement, operations agreement, and
maintenance services agreement then it is reasonable to assume
that the facility will be able to operate in a manner
consistent with applicable permit limits for a period at least
equal to the term of the bonds.
16. The project's construction agreement price is competitive
relative to similar facilities and the project's proposed
operating and maintenance expenses are consistent with other
comparable projects.
17. The technical assumptions utilized in the ICF Resources
Incorporated's market assessment of PJM and the Red Oak
plant are reasonable.
18. Stone & Webster reviewed the technical and commercial
assumptions and the calculation methodology of the project
financial pro forma model. The technical assumptions assumed
in the projected operating results are reasonable and are
consistent with the project contracts. The financial pro forma
model fairly presents, in Stone & Webster's judgment,
projected revenues and projected expenses under the base case
assumptions. Therefore, the projected operating results are a
reasonable forecast of our financial results under the base
case assumptions.
19. The principal amount of the bonds, when combined with the
equity contributions and interest earned during the
construction period, should be sufficient to pay the costs of
constructing the facility and interest on the bonds through
the end of the construction period.
20. The projected revenues from the sale of capacity and energy
are more than adequate to pay the annual operating and
maintenance expenses, including provisions for major
maintenance, other operating expenses, and debt service based
on Stone & Webster's studies and analyses of the project and
the assumptions set forth in the independent technical review.
The average and minimum debt service coverage ratios for the
full term of the bonds are 3.16x and 1.55x, respectively. The
average and minimum debt service coverage ratios during the
term of the power purchase agreement are 1.57x and 1.55x,
respectively. The average and minimum debt service coverage
ratios during the post-power purchase agreement period for the
debt are 7.13x and 6.37x, respectively.
21. Assuming deficiencies of up to 6% for heat rate and 4% for
capacity, the average minimum debt service coverage ratios
over the term of the bonds, after payment of the liquidated
damages due to a failure to achieve heat rate and capacity
guarantees, are projected to remain approximately the same as
the minimum debt service coverage ratios in the base case.
The independent technical review should be read by all prospective
investors in its entirety. Stone & Webster is subject to the informational
requirements of the Exchange Act, and in accordance therewith, files reports,
proxy statements and other information with the SEC.
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SUMMARY OF INDEPENDENT MARKET ASSESSMENT
ICF Resources Incorporated has prepared the independent lenders' market
assessment of PJM and the Red Oak plant, which we have attached as Annex C to
this prospectus. We have retained ICF Resources to forecast our facility's use
and future electric energy prices because ICF Resources is an independent
consulting firm which provides various energy-related consulting services,
including services related to the marketing and fuel supply aspects of power
projects. Neither we, nor any of our affiliates, is affiliated with ICF
Resources.
ICF Resources' report concludes, among other things:
o The PJM wholesale electricity markets present attractive
opportunities for new gas-fired plants, especially efficient,
low variable cost plants like our facility.
o The facility dispatch position on the supply curve will be
highly competitive and well below most coal plants in the
summer and shoulder seasons during the post-power purchase
agreement period, and during the term of the power purchase
agreement, due to the facility's high efficiency, low
production costs, and the influence of demand growth in
conjunction with unit retirements.
o Our facility has a physical hedge because when its fuel costs
increase, so does its revenues. This occurs to the extent gas
is used by competing marginal price-setting units.
o The PJM market, like many other markets in the U.S., is
rapidly approaching a potential shortage. As soon as next
year, additional capacity beyond what is already under
construction is required to maintain reliability of the
system. If weather conditions are more extreme, or outages are
greater than expected, the gap between supply and demand
requirements may be even wider. Plants like our facility,
which require a short lead time to be operational, are well
positioned to provide reliability support to the grid, and to
earn the associated capacity revenue credits.
o Furthermore, our facility is less significantly affected by
any overbuild which might occur in PJM as compared to more
transmission isolated regions because of the ability within
PJM to export to multiple neighboring regions.
ICF Resources' report, including the qualifications set forth in the
forward of the report, should be read by all prospective investors in its
entirety. We do not intend to update the facility utilization and price
forecast, except to the extent required under the indenture.
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SUMMARY OF PRINCIPAL PROJECT CONTRACTS
POWER PURCHASE AGREEMENT AND RELATED GUARANTEE
Under the terms of the power purchase agreement, we will, for a term
of 20 years beginning on the commercial operation date of our facility, sell
all of our facility's net capacity, and provide fuel conversion and ancillary
services to Williams Energy. Williams Energy is obligated to pay us for our
facility capacity, which payments are expected to be adequate to cover our
debt service obligations and our fixed operation and maintenance costs and,
at the same time, provide us a return on equity. Williams Energy will be
obligated to pay us whether or not it requires our facility to generate
energy and even if it is unable to take any energy, so long as our facility
is available for operation. Williams Energy is also obligated to supply us
with all of the fuel necessary to provide net capacity, ancillary services
and fuel conversion services to it.
The Williams Companies, Inc. has provided us with a guaranty of
Williams Energy's payment obligations to us under the power purchase
agreement and to pay damages if Williams Energy fails to pay us. The Williams
Companies, Inc.'s payment obligations under the guaranty are capped at an
amount equal to 125% of the sum of the principal amount of the bonds, plus
the maximum debt service reserve account required balance, plus the maximum
working capital facility amount. The Williams Companies, Inc. files quarterly
and annual audited reports with the SEC under the Exchange Act, which are
publicly available. Williams Energy does not issue separate audited financial
statements. We have provided to Williams Energy a letter of credit to ensure
specific payment obligations of ours under the power purchase agreement are
satisfied. The letter of credit is capped at $30 million prior to the
commercial operation date and will decrease after commercial operation has
been achieved to an amount equal to the lesser of (a) $10 million or (b) $30
million less all amounts drawn under the power purchase agreement letter of
credit and not repaid prior to commercial operation. Repayment obligations
with respect to drawings under the letter of credit will be a senior debt
obligation of ours.
CONSTRUCTION AGREEMENT AND RELATED GUARANTY
Under the construction agreement, Raytheon Engineers will design,
engineer, procure and construct our facility on a fixed-price, turnkey basis.
Raytheon Engineers' obligations under the construction agreement are
guaranteed by Raytheon Company. The contract price payable to Raytheon
Engineers has been prepaid by us in a discounted fixed-price amount. As a
condition to the prepayment, Raytheon Engineers provided us with a letter of
credit meeting certain criteria set forth in the financing documents. The
amount available to be drawn under the letter of credit will be reduced from
time to time upon submission of a requisition specifying, among other things,
that the applicable portion of the work required to be completed under the
construction agreement has been completed, subject to a 10% retainage by us.
See "Summary of Principal Project Contracts--Construction Agreement--Contract
Price and Payment" in the body of this prospectus. The contract price may be
adjusted as set forth in the construction agreement, including as a result of
unexpected or uncontrollable events or modifications to the scope of work to
be provided by Raytheon Engineers. Raytheon Engineers has guaranteed that our
facility will be mechanically complete and specific performance requirements
will be satisfied for provisional acceptance by us no later than 23 months
after Raytheon Engineers receives a full notice to proceed under the
construction agreement, subject to adjustment as set forth in the
construction agreement, if we have given full notice to proceed to Raytheon
Engineers prior to March 31, 2000. On March 15, 2000, we gave Raytheon
Engineers full notice to proceed and, as provided in the collateral agency
agreement, the contract price was prepaid by us on March 15, 2000.
If our facility does not satisfy the applicable completion
requirements by the date guaranteed by Raytheon Engineers and the failure is
not excused in accordance with the terms of the construction agreement,
Raytheon Engineers will be obligated to pay us liquidated damages in the
amounts specified in the construction agreement. Raytheon Engineers has
guaranteed specific availability levels for our facility and if those levels
are not demonstrated during a 30-day period before final acceptance of our
facility, we may withhold specified payments to Raytheon Engineers. Raytheon
Engineers has also guaranteed specific output and heat rate performance
levels for our facility. If the facility cannot meet these levels, Raytheon
Engineers may be required to pay us performance liquidated damages in the
amounts specified in the construction agreement. The total liability of
Raytheon Engineers for delays in completion, together with its liability for
any performance shortfalls, is limited in the aggregate to an amount equal to
34% of the contract price, with customary sublimits. The total aggregate cap
on liability of Raytheon Engineers under the construction agreement,
including the liquidated damages for performance shortfalls and delays, but
excluding specified indemnity obligations, is limited to an amount not to
exceed 100% of the contract price, as adjusted, for liability due to events
occurring prior to the date of our provisional acceptance of the facility and
40% of the contract price for liability due to events occurring after that
date, in each case over and above the amount of the contract.
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MAINTENANCE SERVICES AGREEMENT
Under a maintenance services agreement, Siemens Westinghouse will
provide us with specific combustion turbine parts, shop repairs of combustion
turbine parts and scheduled outage technical field assistance services. We will
pay for the parts, repairs and services on a monthly basis, in an amount to be
determined based on the number of equivalent baseload hours accumulated by our
facility. The maintenance services agreement includes specific warranties
applicable to the combustion turbine parts and shop repairs provided under the
agreement, and if a combustion turbine part supplied fails to conform to the
applicable warranty, Siemens Westinghouse either must replace that
non-conforming part at its cost and expense, if the non-conformity arose during
the applicable warranty period, or credit us for the purchase of future
combustion turbine parts, if the non-conformity arose after the applicable
warranty period but before to the expiration of the expected useful life of that
combustion turbine part. The maintenance services agreement will remain in
effect in respect of a combustion turbine until sixteen years from the date of
execution of the agreement or after the twelfth planned outage of the turbine,
whichever occurs first, unless we exercise our right to cancel the agreement
after the first major outage of the combustion turbines which will be after
approximately the sixth year of operation of the facility.
OPERATIONS AGREEMENT AND SERVICES AGREEMENT
Under an operations agreement, AES Sayreville will provide
development and construction management services and, after the commercial
operation date, operating and maintenance services for our facility for a
period of 32 years. AES Sayreville will be responsible for, among other
things, preparing plans and budgets related to start-up and commercial
operation of our facility, providing qualified operating personnel, making
repairs, purchasing consumables and spare parts, not otherwise provided under
the maintenance services agreement, and providing other services as needed
according to industry standards. AES Sayreville will be compensated for these
services on a cost plus fixed-fee basis. The fixed-fee portion of the
payments will be subordinated to the payment of other operation and
maintenance costs, debt service on senior debt and deposits into the debt
service reserve and major maintenance reserve account. Under a services
agreement between AES Sayreville and The AES Corporation, The AES Corporation
will provide to AES Sayreville all of the personnel and services necessary
for AES Sayreville to comply with its obligations under the operations
agreement.
INTERCONNECTION AGREEMENT
Under an interconnection agreement, we and Jersey Central Power & Light
Company will install, operate and maintain the facilities necessary to
interconnect our facility to Jersey Central Power's transmission system. We will
be responsible for all of the costs of construction and operation and
maintenance of the interconnection facilities. Jersey Central Power is required
to complete its portion of the interconnection facilities and specific
transmission system reinforcements necessary to permit dispatch of the full
output of our facility within 540 days from our issuance of the notice to
proceed under the interconnection agreement. Under the Energy Policy Act of
1992, transmission owners are required to provide open access to their
transmission systems on terms at least as favorable as they provide to
themselves and their affiliates.
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RISK FACTORS
BEFORE TENDERING YOUR OUTSTANDING BONDS FOR EXCHANGE BONDS OR INVESTING
IN THE EXCHANGE BONDS, YOU SHOULD BE AWARE THAT THERE ARE VARIOUS RISKS INVOLVED
IN YOUR INVESTMENT. WE HAVE DISCUSSED BELOW THE MATERIAL RISKS THAT YOU SHOULD
CONSIDER IN MAKING YOUR INVESTMENT DECISION. YOU SHOULD CONSIDER CAREFULLY THESE
RISK FACTORS, TOGETHER WITH ALL OF THE OTHER INFORMATION INCLUDED IN THIS
PROSPECTUS, IN EVALUATING AN INVESTMENT IN THE EXCHANGE BONDS.
IF THE COMMENCEMENT OF COMMERCIAL OPERATION OF OUR FACILITY IS SIGNIFICANTLY
DELAYED, OR WE ARE OTHERWISE UNABLE TO GENERATE SUFFICIENT CASH FLOW, WE MAY NOT
BE ABLE TO PAY OUR OPERATING EXPENSES OR SERVICE THE BONDS.
Construction of our facility currently is scheduled to be completed by
23 months after financial closing unless the date is extended under the
construction agreement. We will not receive any material revenues unless and
until our facility achieves commercial operation. Once our facility commences
operation, principal and interest on the bonds will be payable principally from
revenues received by us under the power purchase agreement. Operation and
maintenance expenses of our facility plus working capital loans generally are
payable before payment of debt service with respect to the bonds. No
representation or assurance can be made that our facility will be successfully
constructed or that, if our facility is successfully constructed, revenues will
be sufficient to pay the operation and maintenance expenses of our facility and
principal of and interest on the bonds. We have no assets other than our
facility, the project contracts and other assets and contract rights related to
our facility.
Until our facility commences commercial operation, debt service on the
bonds will be payable solely from funds on deposit in the construction account,
which deposits were made with a portion of the net proceeds from the issuance of
the bonds, any investment earnings, specific contingency and other funds held
under the collateral agency agreement and the indenture, insurance proceeds, if
any, and liquidated damages payable under the construction agreement. The
construction interest account under the indenture will contain an amount
sufficient to pay interest on the bonds only through two months following the
guaranteed provisional acceptance date under the construction agreement, without
giving effect to any extensions. Thus, if there is a prolonged delay beyond the
guaranteed provisional acceptance date in our facility's attaining commercial
operation, we cannot assure that sufficient sources of funds will be available
to make payments of principal of, premium, if any, and interest on the bonds.
During the term of the power purchase agreement, our ability to make
payments of principal of, premium, if any, and interest on the bonds will be
substantially a function of (i) the ability of our facility to operate at levels
which provide sufficient revenues from sales to Williams Energy after the
payment of all operation and maintenance expenses and specific other expenses
paid prior to debt service and (ii) the ability of Williams Energy to make
required payments under the power purchase agreement. Fixed payments under the
power purchase agreement may be reduced significantly or eliminated during
periods when our facility's availability or performance fails to meet required
levels under the power purchase agreement. With specific exceptions, fixed
payments will not be made by Williams Energy during unexpected or uncontrollable
events which prevent our facility from operating. Following the expiration of
the term of the power purchase agreement, our ability to make payments of
principal of, premium, if any, and interest on the bonds will be substantially a
function of:
o our ability to find purchasers of electric generating capacity
and energy from our facility;
o the availability of adequate market prices for capacity,
energy and ancillary services;
o our ability to procure sufficient quantities of fuel at
competitive prices; and
o the ability of our facility to operate at levels which provide
sufficient revenues from the sale of electric generating
capacity, energy and ancillary services to power purchasers
after the payment of all operation and maintenance expenses
and certain other expenses paid prior to debt service.
WE HAVE LIMITED SOURCES OF FUNDS TO COMPLETE THE PROJECT, AND THE HOLDERS OF THE
BONDS WILL HAVE LIMITED OR NO RECOURSE IN THE EVENT OF A DEFAULT.
Because we are a special-purpose company, our ability to make payments
of principal, of premium, if any, and interest on the bonds will be entirely
dependent on the performance of our obligations under the project contracts and
financing documents. Our obligations under the financing documents will be
obligations solely of ours, secured solely by the collateral described in this
prospectus. If we default in our obligations under the financing documents, we
cannot assure that realization on the collateral would provide sufficient funds
to repay all amounts due on the bonds.
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<PAGE>
None of our members nor any affiliate, incorporator, stockholder,
partner, officer, director or employee of ours or our affiliates will guarantee
the payment of the bonds or has any obligation with respect to the payment of
the bonds. Neither AES Red Oak, Inc. nor any of its affiliates has any
obligation to contribute sums in excess of the amounts required to be advanced
under the equity subscription agreement. If the proceeds of the bonds and the
equity contribution required under the equity subscription agreement are
insufficient to fund the successful development, construction, start-up and
testing of our facility, we may not have other sources of funds available to
complete our facility.
The bonds will be secured by liens on substantially all of our assets
that relate to our facility, including all of the project contracts. If an event
of default occurs under the indenture or other financing documents, we cannot
assure that an exercise of remedies, including foreclosing on the assets in a
judicial proceeding, would provide sufficient funds to repay all amounts due on
the bonds.
IF THE PARTIES THAT WE DEPEND ON BREACH THEIR OBLIGATIONS TO US, OUR CASH FLOW
AND ABILITY TO MAKE PAYMENTS OF INTEREST ON AND PRINCIPAL OF THE BONDS MAY BE
IMPAIRED.
During the term of the power purchase agreement, we will be
dependent on Williams Energy for revenues from sales of capacity, ancillary
services and energy from our facility and on Williams Energy and its
affiliates for fuel supply and transportation. We depend on Siemens
Westinghouse for certain maintenance and spare parts services. We are
dependent on Jersey Central Power for connection of our facility to the
electric transmission grid, as well as on other third-party sources of goods
and services which constitute the principal inputs to our facility's
operations. Any material breach by any of these parties of their obligations
under the project contracts could adversely affect our cash flows and could
impair our ability to make payments of principal of and interest on the bonds.
The other parties to the project contracts have the right to terminate
and/or withhold payments or performance under the contracts if specific events
occur. If a project contract were to be terminated due to nonperformance by us
or by the other party to the contract, our ability to enter into a substitute
agreement having substantially equivalent terms and conditions is uncertain.
IF WILLIAMS ENERGY'S FINANCIAL CONDITION DETERIORATES OR IT BREACHES ITS
OBLIGATIONS TO US AND CANNOT BE ADEQUATELY REPLACED, OUR ABILITY TO MAKE
PAYMENTS OF INTEREST ON AND PRINCIPAL OF THE BONDS MAY BE IMPAIRED.
Williams Energy currently is our sole customer for purchases of
capacity, ancillary services and energy. Williams Energy's payments under the
power purchase agreement are expected to provide all of our revenues during the
term of the power purchase agreement. It is uncertain whether we would be able
to find another purchaser on similar terms for our facility's output if Williams
Energy were not performing under the power purchase agreement. If another
purchaser or purchasers could be found, we cannot assure that the price paid by
that purchaser or purchasers would be sufficient to enable us to make payments
in respect of the bonds. Any material failure by Williams Energy to make
capacity and fuel conversion payments under the power purchase agreement could
therefore have a material adverse effect on revenues and our ability to make
payments in respect of the bonds.
The ability of Williams Energy to meet its obligations under the power
purchase agreement will be dependent on Williams Energy's financial condition
generally, and Williams Energy's financial condition will in part be dependent
upon its ability to sell our facility's capacity and electric energy at adequate
prices.
As we have described in this prospectus, The Williams Companies, Inc.
has provided us a guaranty of Williams Energy's obligations under the power
purchase agreement to make fixed payments and to pay damages if Williams Energy
fails to make the payments. The Williams Companies, Inc.'s obligations under
that guaranty are capped at an amount equal to 125% of the sum of (i) the
principal amount of the bonds, (ii) the maximum debt service reserve account
required balance and (iii) the working capital facility maximum amount. If the
power purchase agreement is terminated due to an event of default by Williams
Energy, we might not recover sufficient amounts from The Williams Companies,
Inc. under the guaranty to repay all outstanding principal of and accrued
interest on the bonds and our other senior debt.
IF WE ENCOUNTER SIGNIFICANT CONSTRUCTION DELAYS, ANY LIQUIDATED DAMAGES,
CONTINGENCY FUNDS, OR INSURANCE PROCEEDS MAY NOT BE SUFFICIENT TO COVER PAYMENTS
OF INTEREST ON AND PRINCIPAL OF THE BONDS.
As with any major construction undertaking, completion of our facility
could be delayed or prevented, or cost overruns could be incurred, as a result
of numerous factors, including shortages of material, labor disputes, weather
interferences, difficulties in obtaining necessary permits or in meeting permit
conditions or unforeseen engineering, environmental or geological problems. We
cannot assure that any available liquidated damages or contingency funds,
22
<PAGE>
including any contingent equity commitment, or the proceeds of any insurance and
warranties would be sufficient to pay for any significant cost overruns, to pay
debt service or to redeem a sufficient principal amount of the bonds so that
projected debt service coverage ratios can be achieved or maintained. In
particular, we are required to pay principal of and interest on the bonds
without regard to any unexpected or uncontrollable events under the construction
agreement.
If as a result of unexpected or uncontrollable events specified in the
construction agreement or specified acts or omissions by us, completion of our
facility is delayed or prevented, or our facility cannot achieve operation in
accordance with design specifications and performance guarantees, Raytheon
Engineers would not be obligated to pay liquidated damages. Under these
circumstances, no proceeds of insurance may be available to us or any proceeds
that are available may not be sufficient to pay our debt service or increased
costs. Generally, Raytheon Engineers would not be obligated to pay liquidated
damages for events or circumstances that adversely affect its ability to perform
its obligations under the construction agreement to the extent that the events
or circumstances are beyond its reasonable control and are not caused by its or
its subcontractors' negligence or lack of due diligence and could not have been
avoided by the use of its reasonable efforts. In addition, the date for
achievement of provisional acceptance and the guaranteed provisional acceptance
under the construction agreement could be subject to adjustment as a result of
unexpected or uncontrollable events.
The power purchase agreement requires that the commercial operation
date occur by no later than December 31, 2001, as the date may be extended
pursuant to the terms of the power purchase agreement to no later than June 30,
2003, including, for any extensions beyond June 30, 2002, the payment of
specified amounts to Williams Energy. Payment of the amounts would reduce funds
available for other construction-related contingencies. If the commercial
operation date, as extended pursuant to the terms of the power purchase
agreement, fails to occur by June 30, 2003, Williams Energy will be permitted to
terminate the power purchase agreement, causing us to lose our anticipated
source of revenue.
Under the construction agreement, we are responsible for a number of
matters in connection with the construction, completion and start-up of our
facility. We are relying on other parties to enable us to perform our
responsibilities under the construction agreement, and we cannot be certain that
the other parties will meet their obligations under their contracts. See
"SUMMARY OF PRINCIPAL PROJECT CONTRACTS--Construction Agreement."
BECAUSE THE FACILITY HAS NOT YET BEEN CONSTRUCTED AND WE HAVE NO OPERATING
HISTORY, VARIOUS UNEXPECTED EVENTS MAY INCREASE OUR EXPENSES OR REDUCE OUR
REVENUES AND IMPAIR OUR ABILITY TO SERVICE THE BONDS.
Because our facility has not yet been constructed, it has no operating
history. As with any new business venture of this size and nature, operation of
our facility could be affected by many factors, including start-up problems, the
breakdown or failure of equipment or processes, the performance of our facility
below expected levels of output or efficiency, failure to operate at design
specifications, labor disputes, changes in law, failure to obtain necessary
permits or to meet permit conditions, government exercise of eminent domain
power or similar events and catastrophic events including fires, explosions,
earthquakes and droughts. The occurrence of these events could significantly
reduce or eliminate revenues or significantly increase the expenses of our
facility, thereby jeopardizing our ability to make payments on the bonds. In
addition, the liability of AES Sayreville for failure to perform under the
operations agreement is subject to specific limitations and AES Sayreville is
not required to post a performance bond. The proceeds of any available insurance
and limited warranties may not be adequate to cover our lost revenues or
increased costs. See "SUMMARY OF PRINCIPAL PROJECT CONTRACTS--Power Purchase
Agreement" and "--Operations Agreement."
Access to the site is over land owned by Consolidated Rail Corporation,
and they have issued their standard form crossing license to us permitting
access to the site. The annual license fee currently is approximately $3,600 per
year and the license can be terminated by Consolidated Rail Corporation upon 30
days' notice or immediately if we breach the license. Any termination of the
license could result in our being denied access to the site, and there is no
assurance that alternative access could be found or that payments, if any,
available under our title insurance would be sufficient to cover payments of
principal and interest on the bonds.
FOLLOWING THE EXPIRATION OF THE POWER PURCHASE AGREEMENT, OUR FACILITY IS
EXPECTED TO BECOME A MERCHANT FACILITY AND WE CANNOT ASSURE THAT WE WILL BE ABLE
TO FIND ADEQUATE PURCHASERS OR OTHERWISE COMPETE EFFECTIVELY IN THE MERCHANT
MARKET.
At the end of the term of the power purchase agreement, at which
time 55% of the principal amount of the 9.20% Senior Secured Bonds Series B
will not yet have been repaid, our facility is expected to become a merchant
facility, or, an electric
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<PAGE>
generation facility with no dedicated long-term power purchase agreement, and
Williams Energy's obligation to provide fuel will cease. Upon the scheduled
termination of the power purchase agreement and if the power purchase agreement
is terminated prior to its stated term as a result of an event of default or
otherwise, our facility would enter a merchant phase. Given the uncertainty
regarding the performance of our facility, future environmental regulation,
competition from other generating facilities, including possibly some owned by
The AES Corporation and its affiliates, fuel prices and other market conditions
that may prevail in the future in the Pennsylvania/New Jersey/Maryland power
pool market, we cannot assure that we will be able to find purchasers or
otherwise compete effectively in the merchant market.
Also, there are current legal and regulatory limitations on our ability
to operate our facility on a merchant basis. Our rate schedule when filed with
the Federal Energy Regulatory Commission, or FERC, will be limited to sales to
Williams Energy. Under current law, before we could engage in sales to any other
entities, we would be required to seek additional market-based rate authority
from FERC. Although we do not currently anticipate that we would encounter
material difficulty in obtaining this additional market-based rate authority, we
cannot assure that FERC will grant this authority. In addition, our status as an
exempt wholesale generator under federal law prohibits us from making retail
sales of electricity in the United States. We currently anticipate that electric
energy generated by our facility will be sold primarily in the wholesale market
both during the term of the power purchase agreement and after our facility
becomes a merchant plant. Nevertheless, if we were to desire to participate
directly in the retail electric market when that market develops, we would be
precluded from doing so absent a change in federal law. Under current federal
law, however, we would not be precluded from making sales to a power marketer,
including an affiliate, which could in turn make retail sales.
COMPLIANCE WITH ENVIRONMENTAL AND OTHER REGULATORY MATTERS COULD CAUSE
SIGNIFICANT DELAYS AND EXPENSES THAT MAY IMPAIR OUR ABILITY TO SERVICE THE
BONDS.
GENERAL
We are subject to a number of statutory and regulatory standards and
required approvals relating to energy, labor and environmental laws. Although
the necessary environmental permits for the commencement of construction of our
facility have been obtained, we are required to comply with the terms of our
environmental permits and to obtain in the future other construction related
permits as well as permits for the operation of our facility. Under specific
circumstances, delay in receipt of or failure to obtain the permits could delay
completion of the construction of our facility or prevent the operation of our
facility.
Some permits that have been obtained by us in connection with our
facility will require amendment prior to commercial operation of our facility
and others will require renewal or reissuance during the life of our facility.
While we have no reason to believe that the permits cannot be amended or will
not be renewed or reissued, our inability to amend, renew or obtain reissuance
of these permits in the future could cause the suspension of construction or
operation of our facility.
The permits that have been obtained and that will be obtained contain
ongoing requirements. Failure to satisfy and maintain any permit conditions or
other applicable requirements could delay or prevent completion of the
construction of our facility, prevent the operation of our facility and/or
result in additional costs. If our facility attains commercial operation, we
cannot assure that our facility will operate within the limits established by
the permits or approvals. See "OUR BUSINESS--Permits and Regulatory Approvals"
and "ANNEX B: INDEPENDENT TECHNICAL REVIEW--Environmental and Permitting."
ENERGY REGULATORY MATTERS
We believe that we have obtained all material energy-related federal,
state and local approvals required as of the date of this prospectus to
construct and operate our facility. Although not currently required, additional
regulatory approvals, including, without limitation, renewals, extensions,
transfers, assignments, reissuances or similar actions may be required in the
future due to a change in laws and regulations, a change in our power purchasers
or for other reasons. We cannot assure that we will be able to:
o obtain all required regulatory approvals that we do not yet
have or that we may require in the future,
o obtain any necessary modifications to existing regulatory
approvals or
o maintain required regulatory approvals.
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Delay in obtaining or failure to obtain and maintain in full force and effect
any regulatory approvals, or amendments, or delay or failure to satisfy any the
conditions or applicable requirements, could prevent operation of our facility
or sales to third parties, or could result in additional costs to us. Our
business also could be materially and adversely affected as a result of
statutory or regulatory changes or judicial or administrative interpretations of
existing laws and regulations that impose more comprehensive or stringent
requirements on us.
THE INSURANCE WE HAVE OBTAINED MAY BE INADEQUATE IN THE EVENT OF A TOTAL LOSS OR
TAKING OF OUR FACILITY, AND WE CANNOT ASSURE THAT THE INSURANCE PROCEEDS WE
RECEIVE WILL BE SUFFICIENT TO SATISFY ALL OF OUR INDEBTEDNESS.
We are obligated under the financing documents and other project
contracts to obtain and keep in force comprehensive insurance with respect to
our facility, including general liability insurance and machinery coverage,
business interruption insurance, delay in start-up insurance and all-risk
property damage insurance, including, among other things, damage caused by fire,
floods or hurricanes. We cannot assure that the insurance coverage will be
available in the future at commercially reasonable costs or that the amounts for
which we are insured or amounts which we receive under insurance coverage will
cover all losses. If there is a total loss or taking of our facility, we cannot
assure that the insurance proceeds we receive will be sufficient to satisfy all
our indebtedness, including for the redemption of the bonds as required under
the indenture. See "SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Indenture."
OUR ABILITY TO INCUR ADDITIONAL INDEBTEDNESS MAY IMPAIR OUR ABILITY TO SERVICE
THE BONDS.
We may issue additional bonds and we may incur additional indebtedness
at any time or from time to time, in accordance with the terms of the indenture.
Any additional bonds will be, and any additional senior debt may be, secured by
the collateral ratably with all our senior secured indebtedness. The issuance of
additional bonds, other than for refinancing purposes, or additional senior debt
would create additional claims against the collateral under the security
documents and could result in a reduction in debt service coverage ratios and
cash available to make payments of principal of and interest on the bonds. See
"SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Indenture."
Subject to limitations set forth in the indenture, we are permitted to
incur subordinated debt, which may be secured by a junior lien on the
collateral, for purposes allowed under the indenture. Although subordinated debt
would be subject to limitations contained in the collateral agency agreement
concerning the ability of the holders of subordinated debt to declare defaults,
exercise remedies or institute specified legal proceedings, the incurrence of
subordinated debt would increase our leverage and the total debt service payable
by us. In addition, the holders of subordinated debt may be our secured
creditors and therefore have the rights available to secured creditors under
federal and state law.
DRAWINGS UNDER LETTERS OF CREDIT MAY INCREASE PAYMENTS OF DEBT SERVICE ON SENIOR
DEBT.
Drawings under the debt service reserve letter of credit will be
converted into debt service reserve letter of credit loans which will mature
five years after the date of the loans. Interest on debt service reserve letter
of credit loans is payable at the same level in the flow of funds as payments of
interest on other senior debt, including the bonds. Principal on debt service
reserve letter of credit loans is generally payable out of available cash flow
after the payment of principal on the bonds. In specific circumstances, however,
principal payments on any drawings under the debt service reserve letter of
credit will be made at the same level in the flow of funds as payments of
principal on the bonds.
As discussed above, we have provided to Williams Energy a letter of
credit to support our obligations under the power purchase agreement. If our
facility is not completed within the time period specified in the power
purchase agreement, as the period may be extended, Williams Energy may draw
on the power purchase agreement letter of credit. Drawings under the power
purchase agreement letter of credit will be converted into power purchase
agreement letter of credit loans under the power purchase agreement letter of
credit reimbursement agreement that will mature in 10 years from the
conversion. Principal of and interest on any power purchase agreement letter
of credit loans under the power purchase agreement letter of credit
reimbursement agreement will be made at the same respective levels in the
flow of funds as payments of principal and of interest on the bonds.
Thus, drawings on the power purchase agreement letter of credit and,
in specific circumstances, drawings under the debt service reserve letter of
credit, will increase payments of debt service on senior debt. We cannot
assure that our revenues from sales of capacity and fuel conversion services
under the power purchase agreement or otherwise would be sufficient to cover
these increases in debt service payments. The lenders under the debt service
reserve letter of credit reimbursement agreement and the power purchase
agreement letter of credit reimbursement agreement will be secured equally
with the bonds by a lien on and security interest in the collateral.
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THE COLLATERAL AGENCY AGREEMENT CONTAINS PROVISIONS THAT MAY LIMIT THE REMEDIES
THAT COULD BE EXERCISED IN RESPECT OF AN EVENT OF DEFAULT, OTHER THAN A
BANKRUPTCY EVENT OF DEFAULT, UNLESS AND UNTIL THE REQUIRED SENIOR PARTIES HAVE
DIRECTED THE COLLATERAL AGENT TO DO SO.
We have entered into a collateral agency agreement with our senior
creditors designating the collateral agent as the agent for each of the
senior parties. The collateral agency agreement requires the affirmative vote
of senior parties holding at least a majority of the outstanding debt to
direct specific actions of the collateral agent, including the exercise of
remedies following a Trigger Event. Because the affirmative vote of these
required senior parties is required before the collateral agent can exercise
remedies, if an event of default under the indenture were to occur, no
remedies could be exercised in respect of the event of default, other than a
bankruptcy event of default, unless and until the required senior parties
have directed the collateral agent to do so. If the holders of the bonds do
not constitute holders of at least a majority of the outstanding debt, the
trustee and the holders of the bonds may not be able to direct the collateral
agent to exercise remedies in respect of an event of default under the
indenture without the affirmative vote of other senior parties. In addition,
under the terms of the other financing documents, we may not terminate, amend
or otherwise modify any provision of the indenture, any other security
document or any subordinated loan agreement, if the termination, amendment or
modification could, in the reasonable opinion of the creditors who are
parties to the other financing documents, reasonably be expected to have a
material adverse effect on the rights and benefits of the other senior
parties. See "SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency
Agreement."
PROJECTIONS AND THE ASSUMPTIONS UNDERLYING THOSE PROJECTIONS ARE INHERENTLY
SUBJECT TO SIGNIFICANT UNCERTAINTIES AND ACTUAL RESULTS MAY DIFFER, PERHAPS
MATERIALLY, FROM THOSE PROJECTED AND SHOULD NOT BE UNDULY RELIED UPON.
The financing of our facility has been structured on the basis of
assumptions and projections with respect to our facility's potential revenue
generating capacity and associated costs over the term of the bonds. Stone &
Webster has evaluated the technical, environmental and economic aspects of our
project. Stone & Webster's report contains a discussion of the many assumptions
utilized in preparing these projections. Investors should review the Stone &
Webster's report in its entirety.
Projections of future operations and the economic results of those
operations included in the Stone & Webster's report have been prepared by us
and reviewed by Stone & Webster on the basis of present knowledge and
assumptions which we and Stone & Webster believe to be reasonable. Our
independent auditors have not examined, reviewed or compiled the projections
and, accordingly, do not express an opinion or any other form of assurance
with respect to them. After the issuance of the exchange bonds, neither we
nor Stone & Webster will provide the holders of the exchange bonds with
revised projections or any report of the differences between the projections
and actual operating results later achieved by our project.
For purposes of preparing the projections, assumptions were made, of
necessity, with respect to completion of construction, availability and
performance of our facility, dispatch levels, capital expenditures, operation
and maintenance expenditures, the revenues that we will receive for capacity and
electric energy, the availability of fuel, our tax treatment, general business
and economic conditions and several other material contingencies and other
matters that are not within our control and the outcome of which cannot be
predicted by us, Stone & Webster, or any other person with any certainty of
accuracy. These assumptions and the other assumptions used in the projections
are inherently subject to significant uncertainties and actual results will
differ, perhaps materially, from those projected. Accordingly, the projections
are not necessarily indicative of current values or future performance and
neither we, Stone & Webster, 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 materially less favorable than
those shown or if the assumptions used in formulating the projections prove to
be incorrect, our ability to make payments of principal of, premium, if any, and
interest on the bonds may be adversely affected.
A CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS.
Specific statements contained in this prospectus are forward-looking
statements. The forward-looking statements can be identified by the use of
forward-looking terminology such as "believes," "expects," "may," "intends,"
"will," "should" or "anticipates," or the negative thereof or other variations
thereon or comparable terminology, or by discussions of strategy. Although we
believe these statements are based upon reasonable assumptions, no assurance can
be given that the future results covered by the forward-looking statements will
be achieved. Forward-looking statements are subject to risks, uncertainties and
other factors that may be outside of our control and that could cause actual
results
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to differ materially from future results expressed or implied by the
forward-looking statements. The most significant of the risks, uncertainties and
other factors are discussed under the heading "RISK FACTORS" in this prospectus,
and prospective investors are urged to consider these factors carefully. Each
investor in the exchange bonds offered in this prospectus will be deemed to have
represented and agreed that it has read and understood the description of the
assumptions and uncertainties underlying the projections that are set forth in
this prospectus and the Annexes hereto and to have acknowledged that we are
under no obligation to update the information and do not intend to do so.
FAILURE OF A MARKET IN THE EXCHANGE BONDS TO DEVELOP COULD AFFECT THE LIQUIDITY
AND PRICE OF YOUR EXCHANGE BONDS.
The bonds are securities for which there currently is no market. If the
bonds are traded, they may trade at a discount from their face value, depending
upon the number of willing purchasers, prevailing interest rates, the market for
similar securities and other factors. We do not intend to apply for listing of
the bonds on any securities exchange or the Nasdaq National Market. Accordingly,
we cannot assure you that a liquid trading market for the bonds will develop.
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USE OF PROCEEDS
We will not receive any cash proceeds from the issuance of the exchange
bonds. In consideration for issuing the exchange bonds, we will receive in
exchange a like principal amount of outstanding bonds. The outstanding bonds
surrendered in the exchange offer will be retired and canceled and cannot be
reissued. We intend to use the net proceeds from the sale of the outstanding
bonds, together with up to an approximately $55.75 million equity contribution
from AES Red Oak, Inc., approximately as follows (in thousands):
<TABLE>
<S> <C>
Prepaid Construction Costs $295,700
Infrastructure/Other Hard Construction-Related Costs $ 10,816
Lenders' and Letter of Credit Fees $ 6,292
Development and Start-up Costs $ 25,425
Net Interest During Construction $ 69,452
Treasury Hedge Settlement Costs $ 13,349
Other Soft Costs $ 4,401
Contingency $ 14,315
---------
TOTAL USES OF FUNDS $439,750
</TABLE>
As of May 31, 2000:
o the following line items have been paid in their entirety:
- Prepaid Construction Costs;
- Lenders' and Letter of Credit Fees;
- Treasury Hedge Settlement Costs;
o the following line items have been partially paid as follows
(in thousands):
- Infrastructure/Other Hard Construction-Related Costs
- $5,227;
- Net Interest During Construction - $ 6,492;
- Development and Start-up Costs - $16,276; and
- Other Soft Costs - $1,444;
o the following line items have not been used:
- Our Contingency.
28
<PAGE>
CAPITALIZATION
The following table sets forth our capitalization as of March 31, 2000.
The following information should be read in conjunction with the consolidated
financial statements and related notes thereto and the other financial
information contained elsewhere in this prospectus. See "SELECTED FINANCIAL
DATA" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS."
LONG-TERM DEBT:
<TABLE>
<CAPTION>
(thousands)
<S> <C>
Bonds Payable...................................... $384,000
=======
</TABLE>
Funds available from the issuance of the outstanding bonds will be
drawn from time to time to fund construction of our facility. Once the available
outstanding bond proceeds have been used, AES Red Oak, Inc. agrees to fund up to
approximately $55.75 million of project costs to be contributed to us pursuant
to the equity subscription agreement.
CALCULATION OF EARNINGS TO FIXED CHARGES DEFICIENCY
FOR THE PERIOD FROM MARCH 15, 2000 THROUGH MARCH 31, 2000
<TABLE>
<CAPTION>
EARNINGS (in thousands)
<S> <C>
Pretax Income................................. $ (245)
Fixed Charges................................. 1,608
Capitalized Interest.......................... (1,396)
-------
Net Total..................................... $33
FIXED CHARGES
Interest Expense.............................. $203
Capitalized Interest.......................... 1,396
Other......................................... 10
------
Total......................................... $1,609
</TABLE>
THE DOLLAR AMOUNT OF THE DEFICIENCY OF EARNINGS TO FIXED CHARGES IS: ($1,642)
(in thousands).
29
<PAGE>
THE EXCHANGE OFFER
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
In connection with the issuance of the outstanding bonds, we entered
into a registration rights agreement. Under the registration rights agreement,
we agreed to:
o prepare and file a registration statement with the SEC for the
purpose of exchanging the outstanding bonds for bonds which
have been registered under the Securities Act;
o use our reasonable efforts to cause the registration statement
to become effective within 220 days following the original
issuance of the outstanding bonds;
o keep the exchange offer open for at least 30 days after the
date the registration statement is declared effective by the
SEC; and
o accept for exchange all outstanding bonds validly tendered by
and not withdrawn in accordance with the terms of the exchange
offer set forth in the registration statement.
As soon as practicable after the registration statement is declared
effective, we will offer the holders of outstanding bonds who are not prohibited
by any law or policy of the SEC from participating in this exchange offer the
opportunity to exchange their outstanding bonds for exchange bonds registered
under the Securities Act that are substantially identical to the outstanding
bonds, except that the exchange bonds will not contain terms with respect to
transfer restrictions, registration rights and additional interest.
Additional interest above the stated rate will accrue on the bonds at a
rate of 0.5% per annum if the exchange offer is not consummated on or prior to
275 days after March 15, 2000. Any additional interest will accrue on the
outstanding bonds from and including the date on which the circumstances giving
rise to the additional interest will occur to but excluding the date on which
all the circumstances have been cured. Any additional interest will be payable
on the bond payment dates.
To exchange your outstanding bonds for freely transferable exchange
bonds, you will be required to make the following representations:
o any exchange bonds that you receive will be acquired in the
ordinary course of your business;
o you have no arrangement or understanding with any person or
entity to participate in the distribution of the exchange
bonds;
o you are not our "affiliate," as defined in Rule 405 of the
Securities Act;
o you are not a broker-dealer, and you are not engaged in and do
not intend to engage in the distribution of the exchange
bonds; and
o if you are a broker-dealer that will receive exchange bonds
for your own account and you acquired those bonds as a result
of market-making activities or other trading activities, you
will deliver a prospectus, as required by law, in connection
with any resale of the exchange bonds.
RESALE OF EXCHANGE BONDS
Based on the interpretations of the SEC staff in no-action letters
issued to third parties, we believe that exchange bonds issued in the exchange
offer may be offered for resale, resold and otherwise transferred by you without
compliance with the registration and prospectus delivery provisions of the
Securities Act, if:
o you are not our "affiliate" within the meaning of Rule 405
under the Securities Act;
o the exchange bonds are acquired in the ordinary course of your
business; and
o you do not intend to participate in any distribution of the
exchange bonds.
Broker-dealers that acquired outstanding bonds directly from us may not
rely on the interpretations of the SEC described above. Accordingly, in order to
sell their bonds, broker-dealers that acquired outstanding bonds directly from
us must comply with the registration and prospectus delivery requirements of the
Securities Act, including being named as a selling security holder in any resale
prospectus. If you are a broker-dealer that will receive exchange bonds for your
own account in exchange for outstanding bonds and you acquired those bonds as a
result of market-making activities or other trading activities, you must deliver
a prospectus, as required by law, in connection with any resale of the exchange
30
<PAGE>
bonds. Only broker-dealers that acquired outstanding bonds as a result of
market-making or other trading activities may participate in the exchange offer.
If you do not satisfy the above conditions, you
o cannot rely on the interpretations by the SEC staff; and
o must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a
secondary resale transaction.
We do not intend to seek our own no-action letter, and we cannot assure
you that the SEC staff would make a similar determination with respect to the
exchange bonds as it has in prior no-action letters issued to other parties. In
November 1998, the SEC proposed certain changes to the regulatory structure for
offerings registered under the Securities Act. The SEC has stated that, if these
proposals are adopted, the SEC staff will repeal the interpretations set forth
in prior no-action letters. We cannot predict whether these proposals will be
adopted or, if they are adopted, when and in what form they will be adopted or
what impact any new interpretations would have on this exchange offer.
If an exemption from registration is not available, any bondholder
intending to resell exchange bonds must be covered by an effective registration
statement under the Securities Act containing the selling bondholder's
information required by Item 507 of Regulation S-K under the Securities Act.
This prospectus may be used for an offer to resell, resale or other retransfer
of exchange bonds only as specifically described in this prospectus. Please read
the section captioned "PLAN OF DISTRIBUTION" for more details regarding the
transfer of exchange bonds.
TERMS OF THE EXCHANGE OFFER
Upon the terms and subject to the conditions described in this
prospectus and in the letter of transmittal, we will accept for exchange any
outstanding bonds properly tendered and not withdrawn prior to the expiration
date. We will issue exchange bonds in principal amount equal to the principal
amount of outstanding bonds surrendered. Outstanding bonds may be tendered for
exchange bonds only in integral multiples of $1,000.
The exchange offer is not conditioned upon any minimum aggregate
principal amount of outstanding bonds being tendered for exchange.
As of the date of this prospectus, $384 million aggregate principal
amount of the outstanding bonds are outstanding. This prospectus and the letter
of transmittal are being sent to all registered holders of outstanding bonds.
There will be no fixed record date for determining registered holders of
outstanding bonds entitled to participate in the exchange offer.
We intend to conduct the exchange offer in accordance with the
provisions of the registration rights agreement, the applicable requirements of
the Securities Act and the Exchange Act of 1934, or the Exchange Act, and the
rules, regulations and interpretations of the SEC. Outstanding bonds that are
not tendered for exchange will remain outstanding and continue to accrue
interest and will be entitled to the rights and benefits the holders have under
the indenture relating to the bonds and the registration rights agreement, if
any.
We will be deemed to have accepted for exchange properly tendered
outstanding bonds when we have given oral or written notice of the acceptance to
the exchange agent and complied with the applicable provisions of the
registration rights agreement. The exchange agent will act as agent for the
tendering holders for the purposes of receiving the exchange bonds from us.
If you tender outstanding bonds in the exchange offer, you will not be
required to pay brokerage commissions or fees or, subject to the instructions in
the letter of transmittal, transfer taxes with respect to the exchange of
outstanding bonds. We will pay all charges and expenses, other than applicable
taxes described below, in connection with the exchange offer. It is important
that you read the "--Fees and Expenses" section for more details regarding fees
and expenses incurred in the exchange offer.
We will return any outstanding bonds that we do not accept for exchange
for any reason without expense to their tendering holder as promptly as
practicable after the expiration or termination of the exchange offer.
NEITHER WE NOR OUR BOARD OF DIRECTORS NOR THE EXCHANGE AGENT MAKES ANY
RECOMMENDATION TO HOLDERS OF THE OUTSTANDING BONDS AS TO WHETHER TO TENDER OR
REFRAIN FROM TENDERING ALL OR ANY PORTION OF THEIR OUTSTANDING BONDS IN THE
EXCHANGE OFFER. IN ADDITION, NO ONE HAS BEEN AUTHORIZED TO MAKE ANY
RECOMMENDATION TO HOLDERS OF THE OUTSTANDING BONDS. AFTER READING THIS
PROSPECTUS AND THE LETTER OF TRANSMITTAL AND CONSULTING WITH THEIR ADVISERS, IF
31
<PAGE>
ANY, BASED ON YOUR FINANCIAL POSITION AND REQUIREMENTS, YOU MUST MAKE YOUR OWN
DECISION WHETHER TO PARTICIPATE IN THE EXCHANGE OFFER, AND, IF SO, THE AGGREGATE
AMOUNT OF OUTSTANDING BONDS TO TENDER.
EXPIRATION DATE
The exchange offer will expire at 5:00 p.m., New York City time on
________, 2000, unless, in our sole discretion, we extend it. Notwithstanding
the preceding, we will not extend the expiration date beyond __________________,
2000.
EXTENSIONS, DELAYS IN ACCEPTANCE, TERMINATION OR AMENDMENT
We expressly reserve the right, at any time or various times, to extend
the period of time during which the exchange offer is open. We may delay
acceptance of any outstanding bonds by giving oral or written notice of the
extension to their holders. During any extensions, all outstanding bonds
previously tendered will remain subject to the exchange offer, and we may accept
them for exchange.
In order to extend the exchange offer, we will notify the exchange
agent orally or in writing of any extension. We will notify the registered
holders of outstanding bonds of the extension no later than 9:00 a.m., New York
City time, on the business day after the previously scheduled expiration date.
If any of the conditions described below under "--Conditions to the
Exchange Offer" have not been satisfied, we reserve the right, in our sole
discretion:
o to delay accepting for exchange any outstanding bonds;
o to extend the exchange offer; or
o to terminate the exchange offer
by giving oral or written notice of the delay, extension or termination to the
exchange agent. We also reserve the right to amend the terms of the exchange
offer.
Any delay in acceptance, extension, termination or amendment will be
followed as promptly as practicable by oral or written notice to the registered
holders of outstanding bonds. If we amend the exchange offer in a manner that we
determine to constitute a material change, we will promptly file a
post-effective amendment to the registration statement and disclose the
amendment by means of a prospectus supplement when the post-effective amendment
has been declared effective by the SEC. The prospectus supplement will be
distributed to the registered holders of the outstanding bonds. Depending upon
the significance of the amendment and the manner of disclosure to the registered
holders, we will extend the exchange offer if the exchange offer would otherwise
expire during any period of delay.
CONDITIONS TO THE EXCHANGE OFFER
Despite any other term of the exchange offer, we will not be required
to accept for exchange, or exchange any exchange bonds for any outstanding
bonds, and we may terminate the exchange offer as provided in this prospectus
before accepting any outstanding bonds for exchange, if in our reasonable
judgment:
o the exchange offer, or the making of any exchange by a holder
of outstanding bonds, would violate applicable law or any
applicable interpretation of the staff of the SEC; or
o any action or proceeding has been instituted or threatened in
any court or by or before any governmental agency with respect
to the exchange offer that, in our judgment, would reasonably
be expected to impair our ability to proceed with the exchange
offer.
In addition, we will not be obligated to accept for exchange the
outstanding bonds of any holder that has not made to us the representations
described under "--Purpose and Effect of the Exchange Offer," "--Procedures for
Tendering" and "PLAN OF DISTRIBUTION."
We expressly reserve the right to amend or terminate the exchange offer
and to reject for exchange any outstanding bonds not previously accepted for
exchange, upon the occurrence of any of the conditions to the exchange offer
specified above. We will give oral or written notice of any extension,
amendment, non-acceptance or termination to the registered holders of the
outstanding bonds as promptly as practicable.
These conditions are for our sole benefit and we may assert them in
whole or in part at any time or at various times in our sole discretion. If we
fail at any time to exercise any of these rights, this failure will not mean
that we have
32
<PAGE>
waived our rights. Each right will be deemed an ongoing right that we may assert
at any time or at various times. If any waiver or amendment constitutes a
material change to the exchange offer, we will promptly disclose the waiver or
amendment by means of a prospectus supplement that will be distributed to the
registered holders of the outstanding bonds. In this case, we will extend the
exchange offer to the extent required by the Exchange Act to provide holders of
outstanding bonds the opportunity to effectively consider the additional
information and to factor this information into their investment decision.
In addition, we will not accept for exchange any outstanding bonds
tendered, and will not issue exchange bonds in exchange for any outstanding
bonds, if at the time any stop order has been threatened or is in effect with
respect to (i) the registration statement of which this prospectus constitutes a
part or (ii) the qualification of the indenture relating to the bonds under the
Trust Indenture Act of 1939.
PROCEDURES FOR TENDERING
HOW TO TENDER GENERALLY
Only a holder of outstanding bonds may tender the outstanding bonds in
the exchange offer. To tender in the exchange offer, a holder must:
o complete, sign and date the letter of transmittal, or a
facsimile of the letter of transmittal;
o have the signature on the letter of transmittal guaranteed, if
the letter of transmittal so requires; and
o mail, send by facsimile or otherwise deliver the letter of
transmittal to the exchange agent prior to the expiration
date; or
o comply with the automated tender offer program procedures of
DTC, as described below.
In addition, either:
o the exchange agent must receive, prior to the expiration date,
a timely confirmation of book-entry transfer of the
outstanding bonds into the exchange agent's account at DTC
according to the procedure for book-entry transfer described
below or a properly transmitted agent's message; or
o the holder must comply with the guaranteed delivery
procedures, as described below.
To be tendered effectively, the exchange agent must receive any
physical delivery of the letter of transmittal and other required documents at
its address provided below under "--Exchange Agent" prior to the expiration
date.
The tender by a holder that is not withdrawn prior to the expiration
date will constitute an agreement between the holder and us in accordance with
the terms and subject to the conditions described in this prospectus and in the
letter of transmittal.
THE METHOD OF DELIVERY OF THE LETTER OF TRANSMITTAL AND ALL OTHER
REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT YOUR ELECTION AND RISK. RATHER
THAN MAIL THESE ITEMS, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND DELIVERY
SERVICE. IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT TIME TO ASSURE DELIVERY TO
THE EXCHANGE AGENT BEFORE THE EXPIRATION DATE. DO NOT SEND THE LETTER OF
TRANSMITTAL TO US. YOU MAY REQUEST YOUR BROKERS, DEALERS, COMMERCIAL BANKS,
TRUST COMPANIES OR OTHER NOMINEES TO EFFECT THE ABOVE TRANSACTIONS FOR YOU.
HOW TO TENDER IF YOU ARE A BENEFICIAL OWNER
If you beneficially own outstanding bonds that are registered in the
name of a broker, dealer, commercial bank, trust company or other nominee and
you wish to tender those bonds, you should contact the registered holder
promptly and instruct it to tender on your behalf.
YOUR REPRESENTATION TO US
By signing or agreeing to be bound by the letter of transmittal, you
represent to us that, among other things:
o any exchange bonds that you receive are being acquired in the
ordinary course of your business;
o you have no arrangement or understanding with any person or
entity to participate in any distribution of the exchange
bonds;
33
<PAGE>
o you are not engaged in and do not intend to engage in any
distribution of the exchange bonds;
o if you are a broker-dealer that will receive exchange bonds
for your own account in exchange for outstanding bonds and you
acquired those bonds as a result of market-making activities
or other trading activities, you will deliver a prospectus, as
required by law, in connection with any resale of the exchange
bonds; and
o you are not our "affiliate," as defined in Rule 405 of the
Securities Act.
SIGNATURES AND SIGNATURE GUARANTEES
You must have signatures on a letter of transmittal or any notice of
withdrawal, as described below, guaranteed by a member firm of a registered
national securities exchange or of the National Association of Securities
Dealers, Inc., a commercial bank or trust company having an office or
correspondent in the United States, or an "eligible guarantor institution"
within the meaning of Rule 17Ad-15 under the Exchange Act, that is a member of
one of the recognized signature guarantee programs identified in the letter of
transmittal, unless the outstanding bonds are tendered:
o by a registered holder who has not completed the box entitled
"SPECIAL ISSUANCE INSTRUCTIONS" or "SPECIAL DELIVERY
INSTRUCTIONS" on the letter of transmittal; or
o for the account of a member firm of a registered national
securities exchange or of the National Association of
Securities Dealers, Inc., a commercial bank or trust company
having an office or correspondence in the United States, or an
eligible guarantor institution.
If the letter of transmittal or any bonds or bond powers are signed by
trustees, executors, administrators, guardians, attorneys-in-fact, officers of
corporations or others acting in a fiduciary or representative capacity, those
persons should so indicate when signing. Unless waived by us, the parties listed
above should also submit evidence satisfactory to us of their authority to
deliver the letter of transmittal.
TENDERING THROUGH DTC'S AUTOMATED TENDER OFFER PROGRAM
The exchange agent and DTC have confirmed that any financial
institution that is a participant in DTC's system may use DTC's automated tender
offer program to tender. Participants in the program may transmit their
acceptance of the exchange offer electronically. They may do so by causing DTC
to transfer the outstanding bonds to the exchange agent in accordance with its
procedures for transfer. DTC will then send an agent's message to the exchange
agent.
The term "agent's message" means a message transmitted by DTC, received
by the exchange agent and forming part of the book-entry confirmation, to the
effect that:
o DTC has received an express acknowledgment from a participant
in its automated tender offer program that it is tendering
outstanding bonds that are the subject of the book-entry
confirmation;
o the participant has received and agrees to be bound by the
terms of the letter of transmittal or, in the case of an
agent's message relating to guaranteed delivery, that the
participant has received and agrees to be bound by the
applicable notice of guaranteed delivery; and
o the agreement may be enforced against the participant.
DETERMINATIONS UNDER THE EXCHANGE OFFER
We will determine in our sole discretion all questions as to the
validity, form, eligibility, time of receipt, acceptance of tendered outstanding
bonds and withdrawal of tendered outstanding bonds. Our determination will be
final and binding on all parties. We reserve the absolute right to reject any
outstanding bonds not properly tendered or any outstanding bonds our acceptance
of which would, in the opinion of our counsel, be unlawful. We also reserve the
right to waive any defect, irregularities or conditions of tender as to
particular outstanding bonds. Our interpretation of the terms and conditions of
the exchange offer, including the instructions in the letter of transmittal,
will be final and binding on all parties. Unless waived, all defects or
irregularities in connection with tenders of outstanding bonds must be cured
within the time as we will determine. Although we intend to notify holders of
defects or irregularities with respect to tenders of outstanding bonds, neither
we, the exchange agent nor any other person is obligated to do so, and no such
parties will incur any liability for failure to give the notification. Tenders
of outstanding bonds will not be deemed made until the defects or irregularities
have been cured or waived. Any outstanding bonds received by the exchange agent
that are not properly tendered and as to which the defects or irregularities
have not been cured or waived
34
<PAGE>
will be returned to the tendering holder, unless otherwise provided in the
letter of transmittal, as soon as practicable following the expiration date.
WHEN WE WILL ISSUE EXCHANGE BONDS
In all cases, we will issue exchange bonds for outstanding bonds that
we have accepted for exchange only after the exchange agent timely receives:
o outstanding bonds or a timely book-entry confirmation of the
outstanding bonds into the exchange agent's account at DTC;
o a properly completed and duly executed letter of transmittal
and all other required documents or a properly transmitted
agent's message; and
o the exchange offer has expired.
RETURN OF OUTSTANDING BONDS NOT ACCEPTED OR EXCEPTED
If we do not accept any tendered outstanding bonds for exchange for any
reason described in the terms and conditions of the exchange offer or if
outstanding bonds are submitted for a greater principal amount than the holder
desires to exchange, the unaccepted or non-exchanged outstanding bonds will be
returned without expense to their tendering holder. In the case of outstanding
bonds tendered by book-entry transfer into the exchange agent's account at DTC
according to the procedures described below, the non-exchanged outstanding bonds
will be credited to an account maintained with DTC. These actions will occur as
promptly as practicable after the expiration or termination of the exchange
offer.
BOOK-ENTRY TRANSFER
The exchange agent will establish an account with respect to the
outstanding bonds at DTC for purposes of the exchange offer promptly after the
date of this prospectus. Any financial institution participating in DTC's system
may make book-entry delivery of outstanding bonds by causing DTC to transfer the
outstanding bonds into the exchange agent's account at DTC in accordance with
DTC's procedures for transfer.
GUARANTEED DELIVERY PROCEDURES
If you wish to tender your outstanding bonds but you cannot deliver the
letter of transmittal or any other required documents to the exchange agent or
comply with the applicable procedures under DTC's automated tender offer program
prior to the expiration date, you may still tender if:
o the tender is made through a member firm of a registered
national securities exchange or of the National Association of
Securities Dealers, Inc., a commercial bank or trust company
having an office or correspondent in the United States, or an
eligible guarantor institution;
o prior to the expiration date, the exchange agent receives from
a member firm as described above, either a properly completed
and duly executed notice of guaranteed delivery by facsimile
transmission, mail or hand delivery or a properly transmitted
agent's message and notice of guaranteed delivery:
o setting forth your name and address, the registered
number(s) of your outstanding bonds and the principal
amount of outstanding bonds tendered;
o stating that the tender is being made thereby;
o guaranteeing that, within three New York Stock
Exchange trading days after the expiration date, the
letter of transmittal or facsimile thereof, together
with the outstanding bonds or a book-entry
confirmation, and any other documents required by the
letter of transmittal will be deposited by the
eligible guarantor institution with the exchange
agent; and
o the exchange agent receives the properly completed and
executed letter of transmittal or facsimile thereof, as well
as a book-entry confirmation, and all other documents
required by the letter of transmittal, within three New
York Stock Exchange trading days after the expiration date.
Upon request to the exchange agent, a notice of guaranteed delivery
will be sent you if you wish to tender your outstanding bonds according to the
guaranteed delivery procedures described above.
35
<PAGE>
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, you may withdraw your
tender at any time prior to the expiration date.
For a withdrawal to be effective:
o the exchange agent must receive a written notice of withdrawal
at one of the addressees listed below under "--Exchange
Agent," or
o you must comply with the appropriate procedures of DTC's
automated tender offer program system.
Any notice of withdrawal must:
o specify the name of the person who tendered the outstanding
bonds to be withdrawn; and
o identify the outstanding bonds to be withdrawn, including the
principal amount of the outstanding bonds.
If outstanding bonds have been tendered under the procedure for
book-entry transfer described above, any notice of withdrawal must specify the
name and number of the account at DTC to be credited with the withdrawn
outstanding bonds and must otherwise comply with the procedures of DTC.
We will determine all questions as to the validity, form, eligibility
and time of receipt of notice of withdrawal, and our determination will be final
and binding on all parties. We will deem any outstanding bonds so withdrawn not
to have been validly tendered for exchange for purposes of the exchange offer.
Any outstanding bonds that have been tendered for exchange but that are
not exchanged for any reason will be credited to an account maintained with DTC
for the outstanding bonds. This crediting will take place as soon as practicable
after withdrawal, rejection of tender or termination of the exchange offer. You
may retender properly withdrawn outstanding bonds by following one of the
procedures described under "--Procedures for Tendering" above at any time on or
prior to the expiration date.
EXCHANGE AGENT
The Bank of New York has been appointed as the exchange agent for the
exchange offer. Questions and requests for assistance or additional copies of
this prospectus or the letter of transmittal should be directed to the exchange
agent addressed as follows:
BY REGISTERED MAIL OR CERTIFIED MAIL BY OVERNIGHT COURIER
The Bank of New York The Bank of New York
101 Barclay Street, Floor 7W 101 Barclay Street, Floor 7W
New York, NY 10286 New York, NY 10286
Attention: Reorganization Department Attention: Reorganization Department
BY TELEPHONE BY FACSIMILE
(212) 815-2742 (212) 815-6339
FEES AND EXPENSES
We will bear the expenses of the exchange offer. The principal
solicitation is being made by mail; however, we may make additional solicitation
by telegraph, telephone or in person by our officers and regular employees and
those of our affiliates.
We have not retained any dealer-manager in connection with the exchange
offer and will not make any payments to broker-dealers or other soliciting
acceptances of the exchange offer. We will, however, pay the exchange agent
reasonable and customary fees for its services and reimburse it for its related
reasonable out-of-pocket expenses.
We will pay the expenses to be incurred in connection with the exchange
offer. They include:
o SEC registration fees;
o fees and expenses of the exchange agent and trustee;
o accounting and legal fees and printing costs; and
o any related fees and expenses.
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<PAGE>
TRANSFER TAXES
We will pay all transfer taxes, if any, applicable to the exchange of
outstanding bonds under the exchange offer. The tendering holder, however, will
be required to pay any transfer taxes, whether imposed on the registered holder
or any other person, if:
o certificates representing outstanding bonds for principal
amounts not tendered or accepted for exchange are to be
delivered to, or are to be issued in the name of, any person
other than the registered holder of outstanding bonds
tendered;
o tendered outstanding bonds are registered in the name of any
person other than the person signing the letter of
transmittal;
o a transfer tax is imposed for any reason other than the
exchange of outstanding bonds under the exchange offer; or
o satisfactory evidence of payment of any transfer taxes payable
by a bondholder is not submitted with the letter of
transmittal.
In such circumstances, the amount of the transfer taxes will be billed
directly to that tendering holder.
CONSEQUENCES OF FAILURE TO EXCHANGE
If you do not exchange your outstanding bonds for exchange bonds in the
exchange offer, you will remain subject to the existing restrictions on transfer
of the outstanding bonds, and the market for secondary resales is likely to be
minimal. In general, you may not offer or sell the outstanding bonds unless they
are registered under the Securities Act, or if the offer or sale is exempt from
registration under the Securities Act and applicable state securities laws.
Except as required by the registration rights agreement, we do not intend to
register the outstanding bonds under the Securities Act. Unless they are
broker-dealers selling under certain circumstances, holders of outstanding bonds
will no longer have any rights under the registration rights agreement.
Broker-dealers that are not eligible to participate in the exchange offer may
have additional rights under the registration rights agreement to facilitate the
sale of their outstanding bonds.
ACCOUNTING TREATMENT
We will record the exchange bonds in our accounting records at the same
carrying value as the outstanding bonds, which is the aggregate principal amount
of the outstanding bonds, as reflected in our accounting records on the date of
exchange. Accordingly, we will not recognize any gain or loss for accounting
purposes in connection with the exchange offer. Participation in the exchange
offer is voluntary, and you should carefully consider whether to accept. You are
urged to consult your financial and tax advisors in making your own decision on
what action to take.
FURTHER BOND ACQUISITION
We may in the future seek to acquire untendered outstanding bonds in
open market or privately negotiated transactions, through subsequent exchange
offers or otherwise. We are not required and have no present plans to acquire
any outstanding bonds that are not tendered in the exchange offer or to file a
registration statement to permit resales of any untendered outstanding bonds.
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<PAGE>
SELECTED FINANCIAL DATA
Our selected financial data is presented below and consists of our
summary balance sheet and operating information as of March 31, 2000, which
should be read in conjunction with "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION" and with our financial statements appearing elsewhere in
this prospectus. We began construction of our facility in March, 2000 and,
since we are in the development stage, we currently have no operating
revenues. All construction costs and all project development costs have been
capitalized and will continue to be capitalized until the commencement of
commercial operation of our facility. The balance sheet information as of
March 31, 2000 and the statement of operations for the period ended March 31,
2000 have been derived from our financial statements which have been audited
by Deloitte & Touche LLP, independent public accountants, whose report
appears elsewhere in this prospectus.
AES RED OAK, L.L.C.
(DEVELOPMENT STAGE ENTERPRISE)
AS OF AND FOR THE PERIOD ENDED MARCH 31, 2000
<TABLE>
<CAPTION>
(thousands)
<S> <C>
ASSETS
Current Assets $ 2,966
Prepaid Construction Costs 288,573
Land 4,240
Construction in Progress 26,398
Deferred Financing Costs 18,709
Long-term Investment Held by Trustee 45,809
----------
Total Assets $ 386,695
==========
LIABILITIES & MEMBER'S DEFICIT
Current Liabilities $ 2,940
Bond Financing 384,000
Member's Deficit (245)
==========
Total Liabilities & Member's Deficit 386,695
OPERATING EXPENSES:
General and Administrative Expenses $ 162
==========
Net Operating loss 162
==========
Interest Income 120
Interest Expense (203)
==========
NET LOSS $ (245)
===========
Cash Paid for Construction in
Progress Since Inception $26,618
</TABLE>
38
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
GENERAL
We were formed on September 13, 1998, to develop, construct, own,
operate and maintain our facility. We were dormant until March 15, 2000, the
date we sold the outstanding bonds. We are in the development stage and have no
operating revenues. We obtained $384 million of project funding from the sale of
the outstanding bonds. The total cost of the construction of our facility is
estimated to be approximately $439.8 million, which will be financed by the
proceeds from the sale of the bonds and the equity contributions described
below.
Our facility is still under construction and we expect it to be
completed and operational by approximately December 31, 2001. We cannot assure
you that our expectations will be met.
EQUITY CONTRIBUTIONS
Under the equity subscription agreement, AES Red Oak, Inc. will be
obligated to contribute to us approximately $41.6 million in base equity to
fund project costs and up to approximately $14.2 million in contingent equity
to fund construction-related contingencies. AES Red Oak, Inc.'s obligation to
make base equity contributions is supported by an insurance bond issued by an
insurance company that complies with credit ratings criteria that are
specified in our financing documents. AES Red Oak, Inc.'s obligation to make
contingent equity contributions is supported by a guaranty issued by The AES
Corporation.
RESULTS OF OPERATIONS
For the period from March 15, 2000 (inception) through March 31,
2000, costs in the amount of $26.4 million pertaining to the cost of the
construction of our facility have been capitalized as construction in
progress and are included as assets on the consolidated balance sheet.
Interest capitalized during this period was approximately $1.4 million. The
cost of purchasing land for construction of our facility has been separately
identified on the consolidated balance sheet.
From March 15, 2000 through March 31, 2000, general and administrative
costs of $162,000 were incurred. These costs did not directly relate to
construction and are included as expenses in the consolidated statement of
operations.
A portion of the proceeds from the sale of the outstanding bonds have
not yet been expended on construction and were invested by the trustee. The
interest income earned on these invested funds is included in our consolidated
statement of operations.
The interest expense incurred on the portion of the outstanding bond
proceeds expended during the construction period is capitalized to construction
in progress and is included on the consolidated balance sheet. Interest expense
incurred on the outstanding bond proceeds not spent on construction of our
facility are included as interest expense in the consolidated statement of
operations.
For the period from March 15, 2000 through March 31, 2000,
non-capitalizable costs plus interest expense and less interest income resulted
in a net loss on the March 31, 2000 statement of operations of approximately
$245,000. The results of operations may not be comparable with the results of
operations during future periods, especially when our facility begins commercial
operations in late 2001.
LIQUIDITY AND CAPITAL RESOURCES
We believe that the net proceeds from the sale of the outstanding
bonds, together with the equity contributions, will be sufficient to:
o fund the engineering, procurement, construction, testing and
commissioning of our facility until it is placed in commercial
operation;
o pay certain fees and expenses in connection with the financing
and development of our project; and
o pay project costs, including interest on the bonds during
construction of the facility.
After our facility is placed in commercial operation, we will depend on our
revenues under the power purchase agreement, and after the power purchase
agreement expires, we expect to depend on market sales of electricity.
39
<PAGE>
In order to provide liquidity in the event of cash flow shortfalls
following the commencement of commercial operations, the debt service reserve
account will contain an amount equal to the debt service reserve account
required balance through cash funding, issuance of the debt service reserve
letter of credit or a combination of the two.
As of March 31, 2000, apart from commitments totaling $511,000 arising
from the construction of our facility, we have committed to two additional
capital expenditures totaling $1.6 million. One is for a water pipeline for $1.1
million and the other is for a water pumping station for $0.5 million. We expect
to pay these amounts in fiscal year 2000. These amounts are expected to be paid
out of the proceeds from the sale of the outstanding bonds and the equity
contribution.
BUSINESS STRATEGY AND OUTLOOK
Our overall business strategy is to market and sell all of our net
capacity, fuel conversion and ancillary services to Williams Energy during the
term of the power purchase agreement. After expiration of the power purchase
agreement, we anticipate selling facility capacity, ancillary services and
energy under a power purchase agreement or into the Pennsylvania/New
Jersey/Maryland power pool market. We intend to cause our facility to be
managed, operated and maintained in compliance with the project contracts and
all applicable legal requirements.
40
<PAGE>
OUR BUSINESS
GENERAL
We are a Delaware limited liability company formed to develop,
construct, own, lease, operate and maintain our project and manage the
production of electric generating capacity, ancillary services and energy at our
facility. After the commercial operation date, our sole business will be the
ownership, leasing and operation of the project. Our facility will be designed,
engineered, procured and constructed for us by Raytheon Engineers, Inc. on a
fixed-price, turnkey basis under the construction agreement. Siemens
Westinghouse Power Corporation will provide combustion turbine maintenance
services and spare parts with respect to the turbines for our facility under the
maintenance services agreement for an initial term of sixteen years from the
date of execution of the agreement or after the twelfth scheduled outage for a
turbine, whichever occurs first, unless we exercise our right to cancel the
agreement after the first major outage of the turbines at approximately the
sixth year of operation of the facility. AES Sayreville, a wholly owned
subsidiary of AES, will provide development, construction management and
operations and maintenance services for the project under the operations
agreement. We will act as construction agent for our affiliate, AES URC, for the
development and construction of part of the facility under the construction
agency agreement. We own the land on which our facility will be located, and we
will lease part of the facility from AES URC with an option to purchase.
We have entered into a power purchase agreement for a term of 20 years
under which Williams Energy has committed to purchase all of the net capacity,
fuel conversion and ancillary services of our facility. Net capacity is the
maximum amount of electricity generated by our facility net of electricity used
at our facility. Fuel conversion services consist of the combustion of natural
gas in order to generate electric energy. Ancillary services consist of services
necessary to support the transmission of capacity and energy. Williams Energy is
obligated to supply us with all natural gas necessary to provide net capacity,
fuel conversion services and ancillary services under the power purchase
agreement. We anticipate that during the term of the power purchase agreement
substantially all of our revenues will be derived from payments made under the
power purchase agreement.
OUR PROPERTY
Since we are a development stage company, our principal property is the
project site, which we own. We will lease our site for a 25 year term to AES
URC, who will construct and own part of the facility on the site. AES URC will
lease to us the site and that part of the facility owned by AES URC and at the
end of the lease term we will have an option to purchase that part of the
facility so that we will own all of the site and facility. The site is located
in the Borough of Sayreville, Middlesex County, New Jersey on an approximately
62-acre parcel of land. We have access, utility and construction easements and
licenses across neighboring property. We have title insurance in connection with
our property rights.
Under the indenture and the other related financing documents, our
rights and interests in our property, are encumbered by mortgages, security
agreements, collateral assignments and pledges for the benefit of the
bondholders and other senior creditors.
COMPETITION
Under the power purchase agreement, Williams Energy will be required to
purchase all of our facility's capacity and energy. Therefore, during the term
of the power purchase agreement, competition from other capacity and energy
providers will become an issue only if the power purchase agreement is
terminated or not performed in accordance with its terms. Following the term of
the power purchase agreement, we anticipate selling facility capacity, ancillary
services and energy under a power purchase agreement or into the PJM power pool
market. At that time, we will face competition from other generating facilities
selling into the PJM power pool market including, possibly, other facilities
owned by The AES Corporation or its affiliates.
EMPLOYEES
Other than the officers listed under "OUR MANAGEMENT-Management," we
have no employees and do not anticipate having any employees in the future.
Under the operations agreement, AES Sayreville will manage the development and
construction of and the operation and maintenance of our facility. The direct
labor personnel and the plant operations management will be employees of The AES
Corporation provided to AES Sayreville under a services agreement.
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<PAGE>
INSURANCE
As owner of our site and lessee and owner of the facility, we will
maintain a comprehensive insurance program as required under the indenture and
underwritten by recognized insurance companies. Among other insurance policies,
we will maintain commercial general liability insurance, permanent property
insurance for full replacement value of the facility and business interruption
insurance covering at least 18 months of gross revenues less variable operating
expenses. We have obtained title insurance in an amount equal to the principal
amount of the bonds.
AES Sayreville, as operator of our facility, will maintain, among other
insurance policies, workers' compensation insurance (or evidence of
self-insurance), if required, and comprehensive automobile bodily injury and
property damage liability insurance.
LEGAL PROCEEDINGS
Neither we nor AES URC is party to any legal proceedings.
PERMITS AND REGULATORY APPROVALS
AES Sayreville, as operator of our facility, and us, as owner and
lessee of our facility, must comply with numerous federal, state and local
regulatory requirements including environmental requirements in the operation of
our facility. The material regulatory permits and authorizations that we must
obtain for construction and operation are described in the independent
engineer's report, which is attached as Annex B to this prospectus.
On November 4, 1999 we received a certification from FERC that we
are an exempt wholesale generator. Certification as an exempt wholesale
generator exempts us from regulation under the Public Utility Holding Company
Act of 1935. We will maintain this status so long as we continue to make only
wholesale sales of electricity, which we intend to do. Prior to commercial
operation, we will be required to file the power purchase agreement with FERC
and obtain approval for the rates contained therein. We anticipate filing
with FERC and obtaining the approval prior to the end of 2000. We may also
need to obtain FERC approval for sales of electricity at market-based rates
after the power purchase agreement is no longer in effect.
On January 28, 2000, we received our Prevention of Significant
Deterioration Permit, or "air permit," from the New Jersey Department of
Environmental Protection. The appeal period in respect of the air permit expired
on February 28, 2000 and no appeal was filed. The air permit requires that our
facility be constructed in a manner that will allow it to meet specified
limitations on emissions of air pollutants. Under the construction agreement,
Raytheon Engineers is required to construct our facility to meet these
requirements.
We are subject to a number of statutory and regulatory standards and
required approvals relating to energy, labor and environmental laws. Although
the necessary environmental permits for the commencement of construction of our
facility have been obtained, we are required to comply with the terms of our
environmental permits and to obtain other permits for the construction and
operation of our facility. Several of the permits have not yet been obtained,
and some cannot be obtained until operation of our facility has commenced. Under
specific circumstances, delay in receipt of or failure to obtain the permits
could delay completion of the construction of our facility or prevent the
operation of our facility.
Some permits that we have obtained in connection with our facility will
require amendment prior to commercial operation of our facility and others will
require renewal or reissuance during the life of our facility. While we have no
reason to believe that the permits cannot be amended or will not be renewed or
reissued, our inability to amend, renew or obtain reissuance of these permits in
the future could cause the suspension of construction or operation of our
facility.
The permits that have been obtained and that will be obtained contain
and will contain ongoing requirements. Failure to satisfy and maintain any
permit conditions or other applicable requirements could delay or prevent
completion of the construction of our facility, prevent the operation of our
facility and result in additional costs. See "ANNEX B: INDEPENDENT TECHNICAL
REVIEW--Environmental and Permitting."
42
<PAGE>
OUR MANAGEMENT
We are a Delaware limited liability company and have no employees other
than our officers. Our officers receive no compensation for the services they
provide to us or for any transaction between us and any of our affiliates. We
are managed by our board of directors under the terms of our the Amended and
Restated Limited Liability Company Agreement, dated as of November 23, 1999. The
following table sets forth the names, ages and positions of our directors and
executive officers. Our directors are elected annually and each elected director
holds office until the director's successor is elected and qualified or the
director resigns or is removed. Our officers are elected from time to time by
vote of the board of directors.
<TABLE>
<CAPTION>
NAME AGE POSITION(S)
---- --- -----------
<S> <C> <C>
John R. Ruggirello..........................49 President and Director
Barry J. Sharp..............................40 Director and Chief Financial Officer
Charles B. Falter...........................35 Vice President
Patricia L. Rollin..........................39 Vice President
Bart R. Rossi...............................51 Vice President
Joel Abramsom...............................29 Vice President
Edward C. Hall, III.........................40 Vice President
Kevin Polchow...............................38 Vice President
Michael Romaniw.............................31 Vice President and Treasurer
Maureen B. Shearer .........................36 Secretary
Roger Naill.................................52 Director
</TABLE>
JOHN RUGGIRELLO has served as our Director and President since 1998.
Mr. Ruggirello is Senior Vice President of The AES Corporation. Mr. Ruggirello
also serves as the President of AES Enterprise, a business development and plant
operations division serving the Mid-Atlantic United States since 1994. Prior to
his current position, Mr. Ruggirello was plant manager of AES Beaver Valley. Mr.
Ruggirello spends approximately 20% of his time in his capacity as Senior Vice
President of The AES Corporation.
BARRY SHARP has served as our Director and Chief Financial Officer
since 1998. Mr. Sharp is currently Senior Vice President and Chief Financial
Officer of The AES Corporation. He joined The AES Corporation as Director of
Finance and Administration in 1986. Prior to The AES Corporation, he held
various positions with Arthur Anderson & Company and Marriott. Mr. Sharp spends
approximately 95% of his time in his capacity as Senior Vice President and Chief
Financial Officer of The AES Corporation.
CHARLES FALTER has served as our Vice President since 1998. Mr. Falter
was the Project Director for our project through March 15, 2000 and now works as
a Project Director on other AES projects. He joined The AES Corporation as a
Project Engineer in 1988.
PATRICIA ROLLIN has served as our Vice President since 1998. Ms. Rollin
is also a Vice President of AES Enterprise. She served as Director of Investor
Relations of The AES Corporation from 1994 through 1995. She joined The AES
Corporation Corporate Strategic Planning Group in 1984.
BART ROSSI has served as our Vice President since 1998. Mr. Rossi is
currently a project Engineering Director at The AES Corporation. He assumed that
position in 1996. Prior to joining The AES Corporation, Mr. Rossi served as a
Chief Engineer for Ebasco Services, Inc.
JOEL ABRAMSON has served as our Vice President since 1998. Mr. Abramson
is currently a Project Manager of The AES Corporation and has held that position
since 1995.
EDWARD HALL, III has served as our Vice President since 1998. Mr. Hall
is currently Executive Vice President of AES Endeavor, focused on business
development in New York, New England and Canada. He joined The AES Corporation
in 1988.
KEVIN POLCHOW has served as our Vice President since 1998. Mr. Polchow
is currently the Tax Director of The AES Corporation. He assumed that position
in 1994. Prior to joining The AES Corporation, Mr. Polchow served as a Senior
Manager at Deloitte & Touche LLP.
43
<PAGE>
MICHAEL ROMANIW has served as our Vice President and Treasurer since
2000. Mr. Romaniw is currently Tax Manager of The AES Corporation and has held
that position since 1999. Prior to joining The AES Corporation, Mr. Romaniw was
with Ernst & Young LLP.
MAUREEN B. SHEARER has served as our Secretary since 1999. She is
currently Corporate Paralegal of The AES Corporation and has held that
position since 1995. She joined The AES Corporation as an Executive Assistant
in 1989. Prior to joining The AES Corporation, Ms. Shearer was on active duty
with the U.S. Coast Guard.
ROGER F. NAILL has served as our Director since 1999. Mr. Naill is
Senior Vice President of The AES Corporation and heads The AES Corporation
Corporate Strategic Planning Group. He assumed that position in 1981. Mr. Naill
spends approximately 95% of his time in his capacity as Senior Vice President of
The AES Corporation.
Each of our officers and directors listed above is currently an
officer, director or employee of The AES Corporation or an affiliate of The AES
Corporation and receives compensation from The AES Corporation or the affiliate.
We are not a party to any agreement with The AES Corporation or its affiliates
governing the compensation paid to our officers, directors or employees. These
persons are paid by The AES Corporation or its affiliates, as applicable, in the
normal course of their employment with the relevant party. No cash or non-cash
compensation is currently proposed to be paid in the current calendar year by us
to any of the officers and directors listed above. AES Sayreville will perform
development and construction management and operations and maintenance services
for us on a reimbursable cost, plus fixed-fee basis under the operations
agreement.
44
<PAGE>
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN AFFILIATIONS
We, AES Red Oak, Inc., AES Sayreville and AES URC are each wholly owned
direct and indirect subsidiaries of The AES Corporation. We, AES Red Oak, Inc.
and the Bank of New York, as collateral agent, have entered into an equity
subscription agreement under which AES Red Oak, Inc. has agreed to contribute up
to $55,750,031 to us to fund project costs. Other than the equity subscription
agreement, the only other business we intend to transact with any of our
affiliates is an operations agreement with AES Sayreville and several project
related agreements with AES URC.
OTHER RELATIONSHIPS AND RELATED TRANSACTIONS
THE AES CORPORATION. The AES Corporation is a leading global power
company committed to supplying electricity in a socially responsible way. The
AES Corporation currently has assets in excess of $20 billion and employs
approximately 40,000 people around the world. Under a services agreement, The
AES Corporation will supply to AES Sayreville all of the personnel and services
necessary for AES Sayreville to comply with its obligations under the operations
agreement.
AES RED OAK, INC. AES Red Oak, Inc. is a Delaware corporation and a
wholly owned subsidiary of The AES Corporation. AES Red Oak, Inc. currently has
no operations outside of its activities in connection with our project and does
not anticipate undertaking any operations not associated with our project. AES
Red Oak, Inc. owns all of the ownership interests in our company and AES
Sayreville and, under the pledge agreement, AES Red Oak, Inc. has pledged to the
collateral agent all of its ownership interests in us.
AES SAYREVILLE. AES Sayreville is a Delaware limited liability company
and wholly owned subsidiary of AES Red Oak, Inc. We have entered into the
operations agreement with AES Sayreville under which AES Sayreville will manage
the operation and maintenance of our facility. The direct labor personnel and
the plant operations management will be provided to AES Sayreville by The AES
Corporation under a services agreement entered into by AES Sayreville and The
AES Corporation.
AES URC. AES Red Oak Urban Renewal Corporation is a New Jersey
corporation and is our wholly owned subsidiary. AES URC was created as an
urban renewal corporation for the development of the project and to enable
the project to receive classification under the New Jersey Long Term
Exemption Law as a redevelopment area or project. By having the project
classified as a redevelopment area or project, and under an agreement with
the Borough of Sayreville, we can benefit by having the project be
responsible for fixed annual payments to the Borough of Sayreville in lieu of
real estate taxes as long as the project complies with the requirements of
the law and the agreement. To allow the project to receive this
classification, AES URC will own a portion of the facility and lease the site
from us for a 25 year term. We will sublease the site back from AES URC and
also lease the portion of the facility from AES URC. AES URC will cause the
development and construction of the portion of the facility under a
construction agency agreement with us, under which we will act as agent and
oversee the development of the portion of the facility for AES URC. Proceeds
from the bond offering in the amount of $40 million will be loaned by us to
AES URC to provide the funds for construction of the AES URC portion of the
facility.
45
<PAGE>
SUMMARY OF PRINCIPAL PROJECT CONTRACTS
The following chart sets forth the parties to our project contracts and
each contract is described in more detail below:
[GRAPHIC]
The following summaries contain the material terms of the principal
project contracts and are qualified in their entirety by reference to the full
text of the actual agreements. All capitalized terms used in the following
summaries and not otherwise defined in this prospectus have the meanings given
the terms in the respective project contract.
POWER PURCHASE AGREEMENT
We have entered into a Fuel Conversion Services, Capacity and Ancillary
Services Purchase Agreement, dated as of September 17, 1999 with Williams
Energy, for the sale to Williams Energy of all of the electric energy and
unforced capacity produced by our facility as well as ancillary services and
fuel conversion services.
TERM
The term of the power purchase agreement extends for 20 years after the
first contract anniversary date, which is the last day of the month in which the
commercial operation date occurs. The commercial operation date occurs when:
46
<PAGE>
o the initial start-up testing of our facility has been
successfully completed;
o we have received all approvals necessary to make the
contemplated sales; and
o we have obtained all required permits and authorizations for
the operation of our facility.
The term may be extended by Williams Energy for up to a total of 24
months for each hour during the initial term for which we are unable to deliver
energy or ancillary services because of an event of force majeure.
If the commercial operation date has not occurred by December 31, 2001
for any reason, including the continued existence of or delay caused by a force
majeure event affecting us, other than any delay caused by any act or failure to
act by Williams Energy or any of its affiliates where the action is required
under the power purchase agreement, Williams Energy will have the right to
terminate the power purchase agreement. We, however, can extend the commercial
operation date to June 30, 2002 (i) if we provide an opinion from a third-party
engineer that the commercial operation date will occur no later than June 30,
2002 (the "Free Extension Option"), or (ii) by giving Williams Energy written
notice of the extension no later than November 30, 2001, and paying to Williams
Energy $2.5 million, for which we believe we have made adequate provision in our
project budget, by no later than January 31, 2002 (the "First Paid Extension
Option").
If we qualify for the Free Extension Option or elect the First Paid
Extension Option, if the commercial operation date has not occurred by June 30,
2002 for any reason, including, without limitation, the continued existence of
or delay caused by a force majeure event affecting us, other than any delay
caused by any act or failure to act by Williams Energy or any of its affiliates
where the action is required under the power purchase agreement, we may elect to
extend our obligation to achieve the commercial operation date up to and
including June 30, 2003 by giving Williams Energy written notice of the
estimated extension required no later than April 30, 2002 and paying to Williams
Energy specified amounts varying from $11,000 per day to $50,000 per day of the
extension (the "Second Paid Extension Option"). If we elect the Second Paid
Extension Option but did not elect the First Paid Extension Option, we also will
pay Williams Energy up to $3.0 million.
If the commercial operation date does not occur by June 30, 2003 for
any reason including the continued existence of or delay caused by a force
majeure event affecting us, other than as a result of any act or failure to act
by Williams Energy or any of its affiliates, where the action is required under
the power purchase agreement, Williams Energy will have the absolute right to
terminate the power purchase agreement unless it fails to terminate the power
purchase agreement prior to the commercial operation date.
PURCHASE AND SALE OF CAPACITY AND FUEL CONVERSION SERVICES
During the term, commencing with the commercial operation date, we will
perform for Williams Energy on an exclusive basis, and Williams Energy will
purchase and pay for, fuel conversion services. Fuel conversion services include
the operation of our facility by us to combust natural gas delivered by Williams
Energy in order to generate and deliver energy or to provide ancillary services.
We will sell and make available to Williams Energy on an exclusive basis, and
Williams Energy will purchase and pay for, our facility's net capacity and
ability to generate electric energy. We may not sell, without the consent of
Williams Energy in its sole discretion, capacity generated on the site but not
from our facility.
As instructed by us, Williams Energy will deliver or cause to be
delivered to us at the natural gas delivery point on an exclusive basis all
quantities of natural gas required by us to:
o generate net electric energy and/or ancillary services;
o perform start-ups;
o perform shutdowns; and
o operate our facility during any period other than a start-up,
shutdown or dispatch period for any reason.
Williams Energy will at all times retain title to the natural gas
delivered to us except that when our facility is operated during any period
other than a start-Up, shutdown or dispatch period title is transferred to us at
the natural gas delivery point.
Williams Energy will be solely responsible for all costs and expenses
related to the supply and transportation of natural gas to the natural gas
delivery point. We will be responsible for all costs and expenses related to the
transportation, gathering or taxation of natural gas or its use or possession at
and after the natural gas delivery point.
47
<PAGE>
Williams Energy will be responsible for the construction of all gas
interconnection facilities. If the gas interconnection facilities have not been
constructed and/or Williams Energy is unable for any reason to deliver natural
gas to our facility by the date that our facility would otherwise be prepared to
begin initial start-up testing, and but for the failure to provide the natural
gas our facility is otherwise ready, or would otherwise have been ready, to
begin testing, then Williams Energy will commence making payments to us for each
day of the delay beginning on the start-up testing date and continuing until the
date that natural gas is delivered to our facility for initial start-up testing,
in an amount for each day of delay which is equal to one-thirtieth of the
applicable total fixed payment. Upon the expiration of the power purchase
agreement or any termination of the power purchase agreement as the result of
Williams Energy's default thereunder, we will have the right to purchase the Gas
Interconnection Facilities from Williams Energy, or if Williams Energy does not
own the gas interconnection facilities, Williams Energy will assign to us all of
its rights to transportation services using the gas interconnection facilities.
PRICING AND PAYMENTS
For each month of the term after the commercial operation date,
Williams Energy will pay us for our facility's net capacity, successful
start-ups and associated shutdowns, ancillary services and fuel conversion
services at the applicable rates set forth in the power purchase agreement. Each
monthly payment by Williams Energy will consist of a total fixed payment, a
variable operations and maintenance payment and an energy exercise fee. The
total fixed payment, which is payable regardless of facility dispatch by
Williams Energy but is subject to adjustment based on facility availability, is
calculated by multiplying an unforced capacity rate for each contract year by
the temperature adjusted unforced capacity in the billing month and adding to
that the product of the fuel conversion option demand charge and the average
facility capacity for that month. The total fixed payment is anticipated to be
sufficient to cover our debt service and fixed operating and maintenance costs
and to provide us a return on equity. The variable operations and maintenance
payment is intended to cover our variable operating and maintenance costs and
escalates annually based on an escalation index set forth in the power purchase
agreement. The energy exercise fee is intended to compensate us for each
successful start-up. We may receive heat rate bonuses or be required to pay heat
rate penalties.
Prior to the commercial operation date, and during some facility tests
thereafter, we will purchase natural gas from Williams Energy. Williams Energy
will sell to us the natural gas at prices specified in the power purchase
agreement, and we will sell to Williams Energy at the electric delivery point
any net electric energy produced during the periods at the hourly integrated
market clearing marginal price for electric energy at the location where it is
delivered or received, calculated pursuant to the terms of the operating
agreement of PJM Interconnection, LLC, which is the independent system operator
that operates the transmission system to which our facility will interconnect.
We will be solely responsible for any fines or penalties resulting from the
delivery of the net electric energy at the electric delivery point when the
delivery is made without the authorization of PJM, Jersey Central Power, which
is the host utility, or FERC.
Williams Energy will be entitled to an annual fuel conversion volume
rebate if its dispatch of our facility exceeds specified levels and monthly
non-dispatch payments if, under some circumstances, our facility does not
deliver, in whole or in part, the requested net electric energy requested by
Williams Energy. All fuel conversion volume rebate payments and non-dispatch
payments will be made to Williams Energy after debt service and certain other
payments but prior to any distribution to holders of equity interests in our
company. Fuel conversion volume rebate payments and any non-dispatch payments
owed to Williams Energy and not paid when due will be paid, together with
interest thereon, when funds become available to us at the priority level
described above. A separate reserve account must be maintained by us and our
lenders and we must deposit to that account on a monthly basis, from our cash
flow, any applicable and unpaid non-dispatch payment plus a ratable amount of
the maximum fuel conversion volume rebate amount that Williams Energy may have
earned. Amounts held in that reserve account will be used to pay, to the extent
owed, the fuel conversion volume rebate and non-dispatch payments.
PROJECT DEVELOPMENT
We will provide to Williams Energy not later than 10 days after the
completion of initial start-up testing, pertinent written data substantiating
our facility's capability to provide net facility capacity and, no later than 30
days prior to the commercial operation date, pertinent written data depicting
our facility's temperature-adjusted net capacity and temperature-adjusted unit
capacity.
We will, at our own cost and expense, obtain as and when required all
approvals, permits, licenses and other authorizations from governmental
authorities as may be required for us to construct, operate and maintain our
facility, the interconnection facilities and protective gas apparatus and to
perform its obligations under the power purchase
48
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agreement, and during the term, we will obtain all additional governmental
approvals, permits, licenses and authorizations as may be required with respect
to our facility as soon as practicable.
INITIAL START-UP TESTING; COMMERCIAL OPERATION
We will provide to Williams Energy (i) written notice, at least 30 days
in advance, of the expected commercial operation date and (ii) a copy of the
notice of commercial operation within 5 days after the commercial operation
date. Williams Energy will have the right to be present at initial start-up
testing of our facility. Costs and expenses incurred in connection with Initial
start-up testing and any testing thereafter to demonstrate our net capacity will
be borne by us. The costs and expenses include the cost of natural gas and
transmission costs associated with the transmission of the electrical energy
produced. We will be solely responsible for any fines and penalties resulting
from the unauthorized delivery of net electric energy at the electric delivery
Point.
INTERCONNECTION AND METERING EQUIPMENT
At our sole cost and expense, we will own and design, construct,
install and maintain, or be responsible for the design, construction,
installation and maintenance of our facility, the interconnection facilities and
protective gas apparatus needed to generate and deliver net electric energy
and/or ancillary services to the electric delivery point in order to fulfill our
obligations under the power purchase agreement, including all interconnection
facilities and protective gas apparatus that may be located at any switchyard
and/or substation to be built at our facility. Our facility, interconnection
facilities and protective gas apparatus will be designed, constructed and
completed in a good and workmanlike manner and in accordance with accepted
electrical practices (with respect to our facility and interconnection
facilities) or in accordance with standard gas industry practices (with respect
to protective gas apparatus), so that the expected useful life of our facility,
the interconnection facilities and protective gas apparatus will be not less
than the term of the power purchase agreement.
Williams Energy will be responsible for the installation, maintenance
and testing of the natural gas interconnection facilities and natural gas
metering equipment, to the extent not otherwise installed, maintained and tested
by the supplier of gas transportation services, as reasonably approved by us.
Except under limited circumstances, we will not enter into any modification or
amendment of the interconnection agreement with Jersey Central Power without the
prior written consent of Williams Energy.
All electric metering equipment and gas metering equipment, whether
owned by us or by a third party, will be operated, maintained and tested in
accordance with accepted electrical practices, in the case of the electric
metering equipment, and in accordance with applicable industry standards, in the
case of the gas metering equipment.
OPERATION AND DISPATCH
Our facility and the interconnection facilities will be operated in
accordance with accepted electrical practices and applicable requirements and
guidelines of Jersey Central Power pursuant to the interconnection agreement.
The protective gas apparatus will be operated in accordance with standard gas
industry practices. If there is a conflict between the terms and conditions of
the power purchase agreement and Jersey Central Power requirements, the Jersey
Central Power requirements will control.
We will operate our facility in parallel with Jersey Central Power's
electrical system in accordance with the interconnection agreement. When
dispatched by Williams Energy, we will operate our facility and each unit
thereof with automatic regulation equipment in service.
The power purchase agreement acknowledges that Jersey Central Power has
the right to require us to disconnect our facility from its electrical system,
or otherwise curtail, interrupt or reduce deliveries of net electric energy, in
accordance with the terms of the interconnection agreement. If our facility has
been disconnected for these reasons, Williams Energy will continue to be
obligated to make total fixed payments for at least 24 hours after the
occurrence of disconnection of our facility by Jersey Central Power.
We will use commercially reasonable efforts to correct promptly any
condition at our facility which necessitates the disconnection of our facility
from Jersey Central Power's electrical system or the reduction, curtailment or
interruption of electrical output of our facility.
Williams Energy will have the exclusive right to use the net electric
energy and ancillary services and to schedule the operation of our facility or a
unit thereof in accordance with the provisions of the power purchase agreement;
however, the scheduling must be consistent with the design limitations of our
facility, applicable law, regulations and permits, and the agreements and the
manuals of PJM.
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Williams Energy and our company will perform each of our respective
obligations in a manner that avoids the creation of cashout obligations or
imbalance penalties imposed by the natural gas transporter. Williams Energy will
try to minimize any imbalance charges under a transporter's tariff and
thereafter we will be responsible for imbalance charges levied by the natural
gas transporter to the extent that the charges result from: (i) an imbalance
caused by us greater than the allocable tolerance in the transporter's tariff or
(ii) our failure to promptly notify Williams Energy of a change in the operation
of our facility that would cause any imbalance.
If we or one of our affiliates does not directly operate our facility,
we will enter into an agreement with a reputable firm prior to the commercial
operation date for the operation and maintenance of our facility. The choice of
the firm will be subject to the prior review and approval of Williams Energy.
MAINTENANCE
At all times during the term of the power purchase agreement, we will,
at our sole cost and expense, maintain our facility and the Protective Gas
Apparatus and also maintain the interconnection facilities in a manner
consistent with the terms of the interconnection agreement. The maintenance will
be performed in accordance with accepted electrical practices (with respect to
our facility and interconnection facilities) or in accordance with standard gas
industry practices (with respect to protective gas apparatus) and the
engineering, procurement and construction contractors' recommended maintenance
procedures and in accordance with the maintenance and planned outage provisions
of the power purchase agreement.
METERING, BILLING, PAYMENT AND TAXES
Net electric energy delivered by us to Williams Energy will be metered
at the electric delivery point using Jersey Central Power's electric metering
equipment on an hour-by-hour basis, or shorter intervals as may be necessary to
implement the power purchase agreement when technically feasible using the
metering equipment and agreed to by Jersey Central Power.
We will provide to Williams Energy a monthly statement using Jersey
Central Power's meters, or back-up electric metering equipment installed by us
if Jersey Central Power's electric meters are not functional. The statement will
set forth the amount of net electric energy and ancillary services delivered by
us to Williams Energy in each hour and our computation of the amount due from
Williams Energy to us and the other amounts as may then be due and payable by
Williams Energy to us. Williams Energy will pay us the net amount shown to be
due to us on the monthly statement or, if the monthly statement will reflect a
net amount due to Williams Energy from us, we will pay the net amount shown to
be due to Williams Energy. Overdue payments will accrue interest from, and
including, the due date to, but excluding, the date of payment at the late
payment interest rate. If either party, in good faith, disputes a monthly
statement, the party will provide to the other party a written explanation of
the basis for the dispute and will make payment of the portion of the monthly
statement not disputed no later than the due date. To the extent any disputed
amount is later determined to be properly due and payable, it will be paid
within 10 days of the determination, together with interest accrued at the late
payment interest rate from the due date to the date payment is made, if made
within 10 days of the determination, and if not paid within 10 days of the
determination, together with interest accrued after the 10-day period to the
date payment is made at the late payment interest rate plus 1% per annum.
The payments by Williams Energy to us do not include reimbursement for,
and Williams Energy is liable for and will pay, cause to be paid, or reimburse
us if we have paid, all taxes imposed on or with respect to natural gas or the
use or consumption or transportation thereof (other than any of the taxes for
which we are liable as described in the following paragraph) or on net electric
energy and ancillary services or the use and consumption thereof after the
electric delivery point. Williams Energy will indemnify, defend and hold
harmless us from any liability for the taxes.
Except as provided in the previous paragraph and for specified taxes
that may be imposed in the future, the payments by Williams Energy to us include
full reimbursement for all taxes. If Williams Energy is required to remit any
tax for which we are responsible, the amount will be deducted from sums due to
us. We will indemnify, defend and hold harmless Williams Energy from any
liability for the taxes.
LIABILITY; DEDICATION
Nothing in the power purchase agreement will be construed to create any
duty, standard of care or liability to any person not a party to the power
purchase agreement.
Notwithstanding anything contained in the power purchase agreement,
except with respect to third-party claims, neither party will be liable to the
other party, its affiliates, directors, officers, partners, agents, employees,
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successors or assigns, for claims for incidental, special, punitive, indirect or
consequential damages arising out of the power purchase agreement, including
claims in the nature of lost revenues, income or profits (other than payments
specifically provided for and properly due under the power purchase agreement)
or losses, damages or liabilities under any financing, lending or construction
contracts, agreements or arrangements to which we may be a party. The provisions
discussed in this paragraph survive the termination or expiration of the power
purchase agreement.
No undertaking by either party under any provision of the power
purchase agreement will constitute the dedication of that party's electrical or
gas reserves, system, equipment, or facilities, or any portion thereof, to the
other party or to the public.
INDEMNITY
Subject to the provisions of the power purchase agreement, each party
will indemnify, hold harmless and defend the other party, its affiliates,
directors, officers, partners, agents and employees from and against any loss,
to the extent arising out of, in connection with or resulting from the
indemnifying party's breach of any of the representations or warranties made in,
or the indemnifying party's failure to perform any of its obligations under, the
power purchase agreement, or the indemnifying party's design, installation,
construction, ownership, operation, repair, relocation, replacement, removal or
maintenance of, or the failure of, any of the party's equipment and/or
facilities, including, but not limited to, the interconnection facilities, our
facility, natural gas interconnection facilities and protective gas apparatus
and any natural gas facilities, and/or any appurtenances thereto, and any
electric transmission facilities used in connection with the power purchase
agreement. Neither party, however, will have any indemnification obligations in
respect of any loss to the extent caused by the other party's gross negligence,
bad faith or willful misconduct.
Each party will further protect, defend, indemnify and save harmless
the other party, its officers, directors, shareholders, agents, employees,
successors and assigns from, against and in respect of, any and all losses,
costs and liabilities that arise out of or in connection with (i) as to us, any
claims by other parties or any governmental authority concerning environmental
conditions at our facility, and (ii) as to Williams Energy, any claims by other
parties concerning environmental conditions at our facility resulting from its
actions or those of its contractors or natural gas transporters.
As between the parties, Williams Energy will be deemed to be in
exclusive possession and control (and responsible for any damages or injury
resulting therefrom or caused thereby) of natural gas to the natural gas
delivery point and the net electric energy and ancillary services at and from
the electric delivery point, and we will be deemed to be in exclusive possession
and control, and responsible for any damages or injury resulting therefrom or
caused thereby, of natural gas at and from the natural gas delivery point and
the net electric energy and ancillary services up to the electric delivery
point. Risk of loss related to natural gas will transfer from Williams Energy to
us at the natural gas delivery point and risk of loss related to the net
electric energy and ancillary services will transfer from us to Williams Energy
at the electric delivery point. Williams Energy will indemnify, defend and hold
harmless us from and against any loss arising out of or in any way relating to
Williams Energy's possession or control of natural gas up to the natural gas
delivery point or its possession and control of the net electric energy and
ancillary services at and after the electric delivery point, and we will
indemnify, defend and hold harmless Williams Energy from and against any Loss
arising out of or in any way relating to our possession or control of natural
gas at and from the natural gas delivery point or our possession and control of
the net electric energy and ancillary services prior to the electric delivery
point.
The foregoing indemnification provisions of the power purchase
agreement will survive the termination or expiration of the power purchase
agreement.
INSURANCE
We will keep our facility continuously insured against loss or damage
in the amounts and for the risks set forth in the power purchase agreement.
We and the operator of our facility will each procure or cause to be
procured and will maintain for so long as the insurance is available on
commercially reasonable terms with companies rated "A", "IX" or better by A.M.
Best the following minimum insurance coverage for our facility: workers'
compensation; employer's liability; commercial or comprehensive general
liability including coverage for bodily injury, broad form property damage,
blanket contractual liability, personal injury liability, independent
contractors, products/completed operations, sudden and accidental pollution
liability, and underground, explosion and collapse hazard; automobile liability
(owned, hired, non-owned); and commercial excess or umbrella liability.
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We will procure and maintain in effect continuously during the term of
the power purchase agreement, "all risk" property insurance in sufficient
amounts to cover and otherwise insure for the full replacement cost of our
facility and business interruption insurance. This insurance will include the
interests of our subsidiaries, the operator and Williams Energy.
All insurance policies, except workers' compensation insurance, will
name Williams Energy as an additional insured.
Our insurance will include provisions or endorsements providing that
the policies will not be canceled except upon 30 days prior written notice to
Williams Energy or, in respect to cancellation for nonpayment of premiums, 10
days prior written notice.
FORCE MAJEURE
A party will be excused from performing its obligations under the power
purchase agreement and will not be liable in damages or otherwise to the other
party if and to the extent the party declares that it is unable to perform or is
prevented from performing an obligation under the power purchase agreement by a
force majeure condition, except for any obligations and/or liabilities under the
power purchase agreement to pay money, which will not be excused, and except to
the extent an obligation accrues prior to the occurrence or existence of a force
majeure condition as long as:
o the party declaring its inability to perform by virtue of
force majeure, as promptly as practicable after the occurrence
of the force majeure condition, but in no event later than 5
days thereafter, gives the other party written notice
describing, in detail, the nature, extent and expected
duration of the force majeure condition;
o the suspension of performance is of no greater scope and of no
longer duration than is reasonably required by the force
majeure condition;
o the party declaring force majeure uses all commercially
reasonable efforts to remedy its inability to perform; and
o as soon as the party declaring force majeure is able to resume
performance of its obligations excused as a result of the
force majeure condition, it will give prompt written
notification thereof to the other party.
Irrespective of whether the force majeure condition is declared by
Williams Energy or us, the time period of a force majeure will be excluded from
the calculation of all payments under the power purchase agreement and Williams
Energy will be under no obligation to pay us any of the payments described in
the power purchase agreement. If Williams Energy declares a force majeure,
however, it will continue to pay us only the applicable monthly total fixed
payment as described in the power purchase agreement until the earlier of (i)
the termination of the force majeure condition or (ii) the termination of the
power purchase agreement. Furthermore, if a force majuure declared by us due to
an action or inaction of Jersey Central Power that prevents us from delivering
net electric energy to the electric delivery point, Williams Energy will
continue to pay the applicable portion of the total fixed payment for the first
24 hours of the period.
Notwithstanding anything to the contrary contained in the power
purchase agreement, except as may expressly be provided in the power purchase
agreement, the term force majeure will not include or excuse a party's
performance in the following circumstances:
o Except as otherwise set forth in the power purchase agreement,
the failure to complete our facility by or to achieve the
commercial operation date as extended under the power purchase
agreement, which failure is caused by, arises out of or
results from our acts or omissions, and/or from the acts or
omissions of any third party, unless, and then only to the
extent that, any acts or omissions of the third party (i)
would itself be excused under the power purchase agreement by
virtue of a force majeure condition, or (ii) is the result of
a failure of Williams Energy to provide fuel to our facility
under the power purchase agreement;
o Any reduction, curtailment or interruption of generation or
operation of our facility, or of the ability of Williams
Energy to accept or transmit net electric energy, whether in
whole or in part, which reduction,
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curtailment or interruption is caused by or arises from the
acts or omissions of any third party providing services or
supplies to the party claiming force majeure, including any
vendor or supplier to either party of materials, equipment,
supplies or services, or any inability of Jersey Central Power
to deliver Net Electric Energy to Williams Energy, unless, and
then only to the extent that, any acts or omissions would
itself be excused under the power purchase agreement as a
force majeure;
o Any outage, whether or not due to our fault or negligence
attributable to a defect or inadequacy in the manufacture,
design or installation of our facility that prevents,
curtails, interrupts or reduces the ability of our facility to
generate Net Electric Energy or our ability to perform our
obligations under the power purchase agreement;
o To the extent that the party claiming force majeure failed to
prevent or remedy the force majeure condition by taking all
commercially reasonable acts (short of litigation, if the
remedy requires litigation) and, except as otherwise provided
in the power purchase agreement, failed to resume performance
under the power purchase agreement with reasonable dispatch
after the termination of the force majeure condition;
o To the extent that the claiming party's failure to perform was
caused by lack of funds;
o To the extent Williams Energy is unable to perform due to a
shortage of natural gas supply not caused by an event of force
majeure; or
o Because of an increase or decrease in the market price of
electric energy/capacity or natural gas or because it is
uneconomic for the party to perform its obligations under the
power purchase agreement.
Neither party will be required to settle any strike, walkout, lockout
or other labor dispute on terms which, in the sole judgment of the party
involved in the dispute, are contrary to its interest.
Williams Energy will have the right to terminate the power purchase
agreement if we have declared a force majeure and the effect of said force
majeure has not been fully corrected or alleviated within 18 months after the
date said force majeure was declared. Williams Energy, however, will not have
the right to terminate the power purchase agreement if (i) the force majeure was
caused by Williams Energy or (ii) the force majeure event does not prevent or
materially limit Williams Energy's ability to sell our facility net capacity
into or through the Pennsylvania/New Jersey/Maryland power pool market or to a
third party.
EVENTS OF DEFAULT; TERMINATION; REMEDIES
The following will constitute events of default under the power
purchase agreement:
o breach of any term or condition of the power purchase
agreement, including, but not limited to, (i) any failure to
maintain or to renew any security, (ii) any breach of a
representation, warranty or covenant or (iii) failure of
either party to make a required payment to the other party;
o our facility is not available to provide fuel conversion
services or ancillary services to Williams Energy during any
period of 180 consecutive days after the occurrence of the
commercial operation date, except as may be excused by force
majeure or the absence of available natural gas, or if
non-availability is caused by act or failure by Williams
Energy where the action is required by the power purchase
agreement;
o we sell or supply net electric energy, ancillary services or
capacity from our facility, or agrees to do the same, to any
person or entity other than Williams Energy, without the prior
approval of Williams Energy;
o our failure for 30 consecutive days to perform regular and
required maintenance, testing or inspection of the
interconnection facilities, our facility and/or other electric
equipment and facilities where the failure is material;
o our failure for 30 consecutive days to correct or resolve a
material violation of any code, regulation and/or statute
applicable to the construction, installation, operation or
maintenance of our facility, the
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interconnection facilities, protective gas apparatus or any
other electric equipment and facilities required to be
constructed and operated under the power purchase agreement
when the violation impairs our continued ability to perform
its obligations under the power purchase agreement;
o involuntary bankruptcy or insolvency of either party that
continues for more than 60 days;
o voluntary bankruptcy or insolvency by either party;
o any modifications, alterations or other changes to our
facility by or on our behalf which prevent us from fulfilling,
or materially diminish our ability to fulfill, its
obligations, duties, rights and responsibilities under the
power purchase agreement and which after reasonable notice and
opportunity to cure, are not corrected;
o there will be outstanding for more than 60 days any
unsatisfied final, non-appealable judgment against us in an
amount exceeding $500,000, unless the existence of the
unsatisfied judgment will not materially affect our ability to
perform its obligations under the power purchase agreement;
and
o The AES Corporation will cease to own, directly or indirectly,
beneficially and of record, at least 50 percent of the equity
interests in our company, or will cease to possess the power
to direct or cause the direction of our company's management
or policies, or any person, other than The AES Corporation or
an affiliate, authorized to act as a power marketer by FERC or
any affiliate of the person will own, directly or indirectly,
beneficially or of record, any of the equity interests in our
company.
Upon the occurrence of any event of default, other than a
bankruptcy-related event of default, for which no notice will be required or
opportunity to cure permitted, the party not in default, to the extent the party
has actual knowledge of the occurrence of the event of default, will give prompt
written notice of the default to the defaulting party. The notice will set
forth, in reasonable detail, the nature of the default and, where known and
applicable, the steps necessary to cure the default. The defaulting party will
have 30 days, two business days in the case of a default related to the breach
of a representation, warranty or covenant, following receipt of the notice
either to cure the default or commence in good faith all the steps as are
necessary and appropriate to cure the default if the default cannot be
completely cured within the 30-day period.
If the defaulting party fails to cure the default or take the steps as
provided under the preceding paragraph, and immediately upon the occurrence
insolvency or the filing of a voluntary petition for bankruptcy, the power
purchase agreement may be terminated by the non-defaulting party, without any
liability or responsibility whatsoever, by written notice to the party in
default hereof. The power purchase agreement will then terminate and the
non-defaulting party may exercise all rights and remedies as are available to it
to recover damages caused by the default, seek specific performance or exercise
other rights and remedies that it may have in equity or at law.
SECURITY
We have agreed to compensate Williams Energy for any actual damages
it suffers or incurs as the result of Williams Energy's reliance upon the
delivery of our facility net capacity, ancillary services and fuel conversion
services, by December 31, 2001 as such date is extended in accordance with
the terms of the power purchase agreement to the extent said damages cannot
be mitigated fully. We further agree that the damages Williams Energy may
suffer under these circumstances will be any and all reasonable costs
incurred by Williams Energy in excess of costs that would have been incurred
had the commercial operation date occurred on or before December 31, 2001, as
the date may be extended under the power purchase agreement.
Under the power purchase agreement, we must provide financial
security to Williams Energy for our performance and payment obligations under
the power purchase agreement in the initial amount of $30 million, which will
be reduced to $10 million on the commercial operation date and will remain in
effect during the term. We may, at any time at our option, elect to either
provide the financial security in the form of a guaranty of The AES
Corporation or in the form of a single letter of credit, satisfactory to
Williams Energy in form and substance, upon which Williams Energy may draw if
our facility does not achieve the commercial operation date by the date
specified in the power purchase agreement, as the date may be extended, and
after the commercial operation date as specified in the power purchase
agreement. If the financial security contains an expiration date, either
express or implied, we will renew the financial security not later than 10
days prior to the expiration date and will provide written
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notice of the renewal to Williams Energy at the same time. If we fail to
renew the financial security as set forth above, Williams Energy is entitled
to demand and receive payment thereunder on or after three days after written
notice of the failure is provided to us, and the amount drawn will be
deposited in an interest bearing escrow account and will be returned to us at
the commercial operation date unless otherwise drawn on by Williams Energy in
satisfaction of our obligations under the foregoing security provisions.
The letter of credit referred to above must be issued by a financial
institution that at all times during the term of the letter of credit meets and
maintains the following criteria: (i) a U.S. or foreign bank rated "C" or better
by Thompson Bankwatch; or (ii) a U.S. or foreign bank, surety company or
financial institution whose senior debt has the rating listed below by two of
the three rating agencies: Standard & Poor's: "A-" or better; Moody's: "A3" or
better; Duff & Phelps: "A-" or better.
If the bank, surety company or financial institution fails to maintain
the ratings criteria, then upon 30 days, written notice from Williams Energy, we
are required to obtain equivalent security from another bank, surety company or
financial institution meeting the above stated criteria.
No later than the closing on financing for our facility, Williams
Energy is required to provide to us a guarantee of Williams Energy's
performance and payment obligations under the power purchase agreement issued
by The Williams Companies, Inc. or its affiliate. If at any time Moody's or
Standard & Poor's rates the long term senior unsecured debt of The Williams
Companies, Inc. lower than investment grade and the rating agency does not
reestablish within 60 days an investment grade rating for the debt, then
Williams Energy will provide alternative credit support reasonably acceptable
to us within 90 days of the day on which the debt was rated lower than
investment grade.
ASSIGNMENT
Neither the power purchase agreement nor any rights, duties, interests
or obligations thereunder may be assigned, transferred, pledged or otherwise
encumbered or disposed of, by operation of law or otherwise without the prior
written consent of the other party; except that
o Williams Energy, at any time after reasonable advance notice
to us and without our consent, may assign the power purchase
agreement and any of its rights, interests, duties or
obligations thereunder to any affiliate of Williams Energy or
any other entity; so long as (a) the affiliate or the other
entity's long-term unsecured debt at the time is rated
investment grade by Standard & Poor's and Moody's or that the
affiliate or the other entity's obligations under the power
purchase agreement are guaranteed by an affiliate whose
long-term unsecured debt at the time is rated investment grade
by Standard & Poor's and Moody's and (b) any assignee will
agree to be bound by all of the terms and conditions of the
power purchase agreement to the same extent as Williams
Energy;
o We, at any time, and from time to time, after reasonable
advance notice to Williams Energy and without the consent of
Williams Energy, may assign the power purchase agreement and
any of its rights, interests, duties or obligations thereunder
as collateral security to any lender so long as the assignee
will agree to be bound by all of the terms and conditions of
the power purchase agreement to the same extent as us if the
lender exercises its rights under the assignment; and
o We will have the right at any time without the consent of
Williams Energy to assign the power purchase agreement and its
rights, interests, duties and obligations thereunder to any
affiliate; so long as the affiliate assumes in writing all of
our obligations and duties thereunder and the
guaranty/security required under to the power purchase
agreement remains in effect. The power purchase agreement will
inure to the benefit of and bind the parties thereto,
including any permitted assignee or successor.
Except as otherwise specified in the foregoing assignment provisions,
no assignment or disposition of rights under the power purchase agreement will
(i) relieve or in any way discharge us or Williams Energy from the performance
of their respective obligations and liabilities under the power purchase
Agreement or (ii) alter, amend, diminish or otherwise impair Williams Energy's
or our rights under the power purchase agreement.
We agree that we will not sell, transfer, assign, lease or otherwise
dispose of our facility or any substantial portion thereof or interest therein
necessary to perform our obligations under the power purchase agreement to any
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person that is a FERC-authorized power marketer or an affiliate thereof without
the prior written consent of Williams Energy, which consent will not be
unreasonably withheld.
Except as specifically provided for in the foregoing assignment
provisions, any assignment or transfer of the power purchase agreement or any
rights, duties or interests thereunder or any disposition of our facility or any
portion thereof or interest therein by any party without the written consent of
the other party as provided therein will be void and of no force or effect.
Each party will reimburse the other for the reasonable costs and
expenses, including reasonable legal fees and expenses, incurred in connection
with a party's agreement to review, execute and deliver any instruments,
agreements or documents that may be used in connection with any assignment
requested by a party or otherwise permitted under the power purchase agreement.
CONSTRUCTION AGREEMENT
We have entered into an Agreement for Engineering, Procurement and
Construction Services, dated as of October 15, 1999, with Raytheon Engineers
under which Raytheon Engineers will perform services in connection with the
design, engineering, procurement, site preparation and clearing, civil works,
construction, start-up, training and testing and to provide all materials and
equipment (excluding operational spare parts), machinery, tools, construction
fuels, chemicals and utilities, labor, transportation, administration and other
services and items (collectively and separately, the services) for our
facility.
RAYTHEON ENGINEERS SERVICES AND OTHER OBLIGATIONS
Raytheon Engineers will complete our project by performing or causing
to be performed all of the services. The services will include: engineering and
design; construction and construction management; providing us design documents,
instruction manuals, a project procedures manual and quality assurance plan;
procurement of all materials, equipment and supplies and all contractor and
subcontractor labor and manufacturing and related services; providing a spare
parts list; providing all labor and personnel; obtaining all applicable permits;
performing inspection, expediting, quality surveillance and traffic services;
transporting, shipping, receiving and marshaling all materials, equipment and
supplies and other items; providing storage for all materials, supplies and
equipment and procurement or disposal of all soil and gravel (including
remediation and disposal of specific hazardous materials); providing for design,
construction and installation of electrical interconnection facilities
(including electric metering equipment, automatic regulation equipment,
protective apparatus and control system equipment) and reviewing other utility
interconnections to our facility (including gas and water pipelines); performing
performance tests; providing for start-up and initial operation functions;
providing specified spare parts, waste disposal services, chemicals, consumables
and utilities.
The services will also include: training our personnel prior to
provisional acceptance; providing us and our designee with access to the site;
obtaining additional necessary real estate rights; cleaning-up and waste
disposal (including hazardous materials brought to the site by Raytheon
Engineers or the subcontractors); submitting a project schedule and progress
reports; paying of contractor taxes; making employee identification and security
arrangements; protecting adjoining utilities and public and private lands from
damage; paying appropriate royalties and license fees; providing final releases
and waivers to us; posting collateral or providing other assurances if major
subcontractors fail to furnish final waivers; maintaining labor relations and
project labor agreements; providing further assurances; coordinating with other
contractors; and causing Raytheon Corporation to execute and deliver the related
guaranty.
CONSTRUCTION AND START-UP
Except for specific services the performance of which has already
commenced, Raytheon Engineers will commence performance of the services on the
date specified in our notice to proceed. Raytheon Engineers will perform the
services in accordance with prudent utility practices, generally accepted
standards of professional care, skill, diligence and competence applicable to
engineering, construction and project management practices, all applicable laws,
all applicable permits, the real estate rights, the quality assurance plan, the
electrical interconnection requirements, the environmental requirements and
safety precautions set forth in the construction agreement, and all of the
requirements necessary to maintain the warranties granted by the subcontractors
under the construction agreement. Raytheon Engineers will perform the services
in accordance with our project schedule and will cause:
o each construction progress milestone to be achieved on or
prior to the applicable construction progress milestone date;
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o provisional acceptance of our facility to occur on or prior to
the guaranteed provisional acceptance date; and
o final acceptance of our facility to occur on or before the
guaranteed final acceptance date.
Raytheon Engineers will perform the services so that our facility, when
operated in accordance with the instruction manual and the power purchase
agreement operating requirements as of provisional acceptance and final
acceptance, will comply with all applicable laws and applicable permits, the
electrical interconnection requirements and the guaranteed emissions limits in
accordance with the completed performance test requirements.
CONTRACT PRICE AND PAYMENT
The adjusted contract price may either be paid in installments in
accordance with the payment and milestone schedule or be prepaid as described in
the collateral agency agreement. See "SUMMARY OF PRINCIPAL FINANCING
DOCUMENTS--Collateral Agency Agreement--Prepayment of Construction Agreement."
The adjusted contract price was prepaid on the closing date, in the amount of
$295.7 million, which included base scope changes through March 15, 2000.
The contract price may be adjusted as a result of scope changes. We will make
scheduled reductions in the amount available under the letter of credit posted
by Raytheon Engineers upon receipt of Raytheon Engineers request unless
the independent engineer fails to confirm the matters certified to by Raytheon
Engineers in the request, in which case we may defer the scheduled reductions in
the amount available under the letter of credit posted by Raytheon Engineers
until the condition is satisfied. We will withhold from each scheduled reduction
in the amount available under the letter of credit posted by Raytheon Engineers,
other than our project completion reduction, 10% of the requested reduction
until after final acceptance. At final acceptance, we will pay all
retainage except for 150% of the cost of completing all punch list items and the
lesser of (i) 150% of the cost of repairing or replacing any items that have
already been repaired or replaced by Raytheon Engineers and (ii) $1 million. We
will pay our project completion payment, including all remaining retainage,
within 30 days after project completion. Within 30 days of the first anniversary
of the earlier of provisional acceptance or final acceptance, we will, so long
as project completion has occurred, pay all remaining retainage. Upon the
termination of the construction agreement, Raytheon Engineers will be entitled
to retain funds that were prepaid by us in the amount of a termination payment
equal to the scheduled payments due and owing, retainage and termination costs
incurred by Raytheon Engineers and subcontractors. We are not obligated to make
any payment to Raytheon Engineers at any time Raytheon Engineers is in material
breach of the construction agreement, unless Raytheon Engineers is diligently
pursuing a cure and instead, because the construction contract was prepaid by
us, will be able to receive funds under the letter of credit posted by Raytheon
Engineers.
OUR SERVICES
Our responsibilities include: designating a representative for our
project; furnishing Raytheon Engineers access to the site; securing specified
real estate rights; providing specified start-up personnel; furnishing specified
spare parts, water disposal services and consumables; providing permanent
utilities for the start-up, testing and operation of our facility; providing raw
and potable water arrangements; providing fuel supply arrangements; providing
electrical interconnection facilities arrangements; furnishing approvals;
administering third-party contracts; causing The AES Corporation to provide a
pre-financial closing guaranty.
If we fail to meet any of our obligations under the construction
agreement, then, to the extent that Raytheon Engineers was reasonably delayed in
the performance of the services as a direct result thereof, an equitable
adjustment to one or more of the contract price, the guaranteed completion
dates, the construction progress milestone dates, the payment and milestone
schedule and our project schedule, and, as appropriate, the other provisions of
the construction agreement that may be affected thereby, will be made by
agreement between us and Raytheon Engineers.
COMPLETION AND ACCEPTANCE OF OUR PROJECT
MECHANICAL COMPLETION
Mechanical completion will be achieved when:
o All equipment and facilities necessary for the full, safe and
reliable operation of our facility have been properly
constructed, installed, insulated and protected where
required, and correctly adjusted, and can be
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safely used for their intended purposes in accordance with the
instruction manual and all applicable laws and applicable
permits;
o The tests required for mechanical completion that are
identified in the construction agreement have been
successfully completed;
o Our facility is fully and properly interconnected and
synchronized with the electrical system of Jersey Central
Power in accordance with the electrical interconnection
requirements, and all features and equipment of our facility
are capable of operating simultaneously; and
o The complete performance by Raytheon Engineers of all the
services relating to our facility under the construction
agreement, except for any remaining punch list items,
performance tests, power purchase agreement output tests and
reliability run applicable thereto, in compliance with the
standards of performance set forth in the construction
agreement, so that our facility meets all of the requirements
set forth in the construction agreement applicable thereto but
excluding the achievement of the guaranteed emission limits
and the performance guarantees.
When Raytheon Engineers believes that it has achieved mechanical
completion, it will deliver to us the notice of mechanical completion. Within 5
days of receipt of the notice of mechanical completion, if we are satisfied that
the mechanical completion requirements have been met, we will deliver to
Raytheon Engineers a mechanical completion certificate. If reasonable cause
exists for doing so, we will notify Raytheon Engineers in writing that
mechanical completion has not been achieved, stating the reasons therefor. If
mechanical completion has not been achieved as so determined by us, Raytheon
Engineers will promptly take the action or perform the additional services as
will achieve mechanical completion of our facility and will issue to us another
notice of mechanical completion. The procedure will be repeated as necessary
until mechanical completion of our facility has been achieved.
PERFORMANCE TESTS AND POWER PURCHASE AGREEMENT OUTPUT TESTS
Once mechanical completion has been achieved, Raytheon Engineers will
perform the performance tests in accordance with criteria set forth in the
construction agreement. Raytheon Engineers will give us notice of the
performance tests. We will arrange for the disposition of output during start-up
and testing. Raytheon Engineers may declare the performance test to be a
completed performance test if during the tests the operation of our facility
complies with applicable laws, applicable permits, Guaranteed Emissions Limits
and other required standards.
PROVISIONAL ACCEPTANCE
Provisional acceptance will be achieved upon the earlier of Final
Acceptance or when:
o Raytheon Engineers has caused a completed performance test in
which our facility demonstrates an average net electrical
output of 95% (or higher) of the electrical output guarantee
and 105% (or lower) of the gas-based heat rate guarantee.
o Our facility has achieved, and continues to satisfy, the
requirements of mechanical completion.
When Raytheon Engineers believes that it has achieved provisional
acceptance of our facility, it will deliver to us a notice of provisional
acceptance. If it is satisfied that the provisional acceptance requirements have
been met, we will deliver to Raytheon Engineers a provisional acceptance
certificate. If reasonable cause exists for doing so, we will notify Raytheon
Engineers in writing that provisional acceptance of our facility has not been
achieved, stating the reasons therefor. If we determine that provisional
acceptance of our facility has not been achieved, Raytheon Engineers will
promptly take the action or perform the additional services as will achieve
provisional acceptance and, if Raytheon Engineers believes that provisional
acceptance of our facility has been achieved, will issue to us another notice of
provisional acceptance. Unless final acceptance of our facility will have
previously occurred, the procedure will be repeated as necessary until
provisional acceptance of our facility has been achieved. Upon the earliest to
occur of provisional acceptance and final acceptance of our facility, we will
take possession and control our facility and will thereafter be solely
responsible for the operation and maintenance thereof. After we take possession
and control of our facility, Raytheon Engineers will have reasonable access to
our facility to complete the services.
FINAL ACCEPTANCE
Final acceptance will be achieved when:
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o Raytheon Engineers has caused a completed performance test in
accordance with the construction agreement to be concluded in
which our facility demonstrates during the performance test an
average net electrical output of 100% (or higher) of the
electrical output guarantee and 100% (or lower) of the heat
rate guarantee;
o our facility has achieved, and continues to satisfy the
requirements for the achievement of, mechanical completion;
o the reliability guarantee has been achieved under the
construction agreement; and
o Raytheon Engineers has completed performance of the services
except for (i) punch list items and (ii) services that are
required by the terms of the construction agreement to be
completed after the achievement of final acceptance, such as
Raytheon Engineers' warranty obligations.
The reliability guarantee will have been achieved if and only if our
facility demonstrates an average equivalent availability of not less than 95%
while operating over a period of at least 30 consecutive days in accordance with
applicable laws, applicable permits, the electrical interconnection
requirements, the power purchase agreement operating requirements, the
guaranteed emissions limits, the instruction manual and the power purchase
agreement.
When Raytheon Engineers believes that it has achieved final acceptance
of our facility, it will deliver to us a notice of final acceptance. If it is
satisfied that the final acceptance requirements have been met, we will deliver
to Raytheon Engineers a final acceptance certificate. If reasonable cause exists
for doing so, we will notify Raytheon Engineers in writing that final acceptance
has not been achieved, stating the reasons therefor. If we determine that final
acceptance has not been achieved, Raytheon Engineers will promptly take the
action or perform the additional services as will achieve final acceptance and
will issue to us another notice of final acceptance. The procedure will be
repeated as necessary until final acceptance has been achieved or deemed to have
occurred.
At any time, by giving notice to Raytheon Engineers, we in our sole
discretion may elect to effect final acceptance, in which case final acceptance
will be deemed effective as of the date of the notice, and Raytheon Engineers
will have no liability to us for any amounts thereafter arising as performance
guarantee payments, other than any interim period rebates that arose prior to
the election by us, for failure of our facility to achieve any or all of the
performance guarantees applicable thereto.
At any time after provisional acceptance of our facility has been
achieved, Raytheon Engineers may, after exhausting all reasonable repair and
replacement alternatives in order to achieve the applicable performance
guarantees for final acceptance, and so long as that the reliability guarantee
will have been achieved, give to us notice of its intention to elect to declare
final acceptance. In that event, Raytheon Engineers may elect to use the results
of the most recent eligible completed performance test for the purpose of
determining our facility's level of achievement of the performance guarantees.
final acceptance will be deemed effective as of the last to occur of (i) the
date of our receipt of the declaration and report of the final completed
performance test, or, as applicable, the most recent completed performance test
and (ii) the effective date of the achievement of the reliability guarantee.
If on or before the guaranteed final acceptance date (i) our facility
has achieved provisional acceptance and (ii) the reliability guarantee has been
achieved, then final acceptance of our facility will be deemed to occur on the
guaranteed final acceptance date.
PROJECT COMPLETION
Project completion will be achieved under the construction agreement
when:
o Final acceptance of our facility will have occurred and the
performance guarantees with respect to our facility will have
been achieved (or in lieu of achievement of the performance
guarantees, applicable rebates under the construction
agreement will have been paid, or we will have elected final
acceptance);
o The reliability guarantee will have been achieved;
o Raytheon Engineers will have demonstrated during the completed
performance test that the operation of our facility does not
exceed the guaranteed emissions limits;
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o The requirements for achieving mechanical completion of our
facility will continue to be met;
o The punch list items will have been completed in accordance
with the construction agreement; and
o Raytheon Engineers will have performed all of the services,
other than those services, such as Raytheon Engineers'
warranty obligations, which by their nature are intended to be
performed after project completion.
When Raytheon Engineers believes that it has achieved project
completion, it will deliver to us a notice of project completion. If it is
satisfied that the final acceptance requirements have been met, we will deliver
to Raytheon Engineers a project completion certificate. If reasonable cause
exists for doing so, we will notify Raytheon Engineers in writing that project
completion has not been achieved, stating the reasons therefor. If our project
completion has not been achieved as so determined by us, Raytheon Engineers will
promptly take the action or perform the additional services as will achieve
project completion and will issue to us another notice of project completion.
The procedure will be repeated as necessary until project completion is
achieved.
Raytheon Engineers will be obligated to achieve project completion
within 90 days after final acceptance of our facility. If Raytheon Engineers
does not achieve our project completion on or before our project completion
deadline or if we determine that Raytheon Engineers is not proceeding with all
due diligence to complete the services in order to achieve project completion by
the deadline, we may retain another contractor to complete the work at
contractor's expense.
PRICE REBATE FOR FAILURE TO MEET GUARANTEES
COMPLETION DATES
Raytheon Engineers guarantees that (i) provisional acceptance or final
acceptance of our facility will be achieved on or before the guaranteed
provisional acceptance date and (ii) final acceptance of our facility will be
achieved on or before the guaranteed final acceptance date.
If neither provisional acceptance nor final acceptance of our facility
occurs by the date that is 50 days after the guaranteed provisional acceptance
date, Raytheon Engineers will pay us $108,000 per day as provisional acceptance
late completion payments, for each day provisional acceptance or final
acceptance is later than the guaranteed provisional acceptance date, but in no
event will the aggregate amount of the payments be greater than 13% of the
adjusted contract price.
If neither provisional acceptance nor final acceptance of our facility
occurs on or before the date that is 90 days after the guaranteed provisional
acceptance date, Raytheon Engineers will, on that date, submit for approval by
us and the independent engineer a plan to accelerate the performance of the
services as necessary in order to achieve final acceptance of our facility by
the guaranteed final acceptance date. If the plan is not approved by us and the
independent engineer, Raytheon Engineers will revise the plan and resubmit a
revised plan for approval by us and the independent engineer.
If provisional acceptance or final acceptance, whichever is the earlier
to occur, of our facility occurs prior to the guaranteed provisional acceptance
date, we will pay Raytheon Engineers $56,000 per day for each day by which
provisional acceptance or final acceptance precedes the guaranteed provisional
acceptance date, but in no event will the aggregate amount of the bonus exceed
$2,520,000.
PERFORMANCE GUARANTEES
ELECTRICAL OUTPUT
If the average net electrical output of our facility at provisional
acceptance is less than the electrical output guarantee, then Raytheon Engineers
will pay us, as a rebate, for each day during the interim period, an amount
equal to $0.22 per day for each kilowatt by which the average net electrical
output is less than the electrical output guarantee.
Upon final acceptance, if the average net electrical output of our
facility during the completed performance test is less than the electrical
output guarantee, then Raytheon Engineers will pay us, as a rebate, an amount
equal to $520 for each kilowatt by which the average net electrical output is
less than the electrical output guarantee minus any interim period electrical
output rebates.
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HEAT RATE GUARANTEES
If the average net heat rate of our facility at provisional acceptance,
if having occurred before final acceptance, exceeds the heat rate guarantee,
then Raytheon Engineers will pay us, as a rebate, for each day during the
interim period, an amount equal to $46 per day for each BTU/KwH by which the
measured net heat rate is greater than the heat rate guarantee.
Upon final acceptance, if the net heat rate of our facility during the
completed performance test exceeds the heat rate guarantee, then Raytheon
Engineers will pay us, as a rebate, an amount equal to $110,000 for each BTU/KwH
by which the measured heat rate is greater than the heat rate guarantee.
LIABILITY AND DAMAGES
LIMITATION OF LIABILITY
In no event will Raytheon Engineers' liability (i) for provisional
acceptance late completion payments exceed an amount equal to 13% of the
contract price, (ii) for performance guarantee payments arising from the
electrical output guarantee exceed in the aggregate an amount equal to 10% of
the contract price, (iii) for performance guarantee payments arising from the
heat rate guarantee exceed in the aggregate 15% of the contract price and
(iv) for all provisional acceptance late completion payments and performance
guarantee payments exceed an amount equal to 34% of the contract price.
CONSEQUENTIAL DAMAGES
Neither party nor any of its contractors, subcontractors or other
agents providing equipment, material or services for our project will be liable
for any indirect, incidental, special or consequential loss or damage of any
type.
AGGREGATE LIABILITY OF CONTRACTOR
The total aggregate liability of Raytheon Engineers and any of its
subcontractors, including, without limitation, liabilities described above, to
us will not in any event exceed an amount equal to the contract price for
liability due to events occurring before the provisional acceptance date or 40%
of the contract price for liability due to events occurring after the
provisional acceptance date; however, the limitation of liability will not apply
to obligations to remove liens or to make indemnification payments.
WARRANTIES AND GUARANTEES
Raytheon Engineers warrants and guarantees that during the applicable
warranty period
o all machinery, equipment, materials, systems, supplies and
other items comprising our project will be new and of
first-rate quality which satisfies utility-grade standards and
in accordance with prudent utility practices and the
specifications set forth in the construction agreement,
suitable for the use in generating electric energy and
capacity under the climatic and normal operating conditions
and free from defective workmanship or materials;
o it will perform all of its design, construction, engineering
and other Services in accordance with the construction
agreement;
o our project and its components will be free from all defects
caused by errors or omissions in engineering and design, as
determined by reference to prudent utility practices, and will
comply with all applicable laws, all applicable permits, the
electrical interconnection requirements, the power purchase
agreement operating requirements and the guaranteed emissions
limits; and
o the completed project will perform its intended functions of
generating electric energy and capacity as a complete,
integrated operating system as contemplated in the
construction agreement.
If we notify Raytheon Engineers within 30 days after the expiration of
the applicable warranty period of any defects or deficiencies discovered during
the applicable warranty period, Raytheon Engineers will promptly reperform any
of the services at its own expense to correct any errors, omissions, defects or
deficiencies and, in the case of defective or otherwise deficient machinery,
equipment, materials, systems supplies or other items, replace or repair the
same at its own expense. Raytheon Engineers warrants and guarantees that, to the
extent we have made all payments
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then due to Raytheon Engineers, title to our facility and all work, materials,
supplies and equipment will pass to us free and clear of all liens, other than
any permitted liens. Other than the warranties and guarantees provided in the
construction agreement there are no other warranties of any kind, whether
statutory, express or implied relating to the services.
Upon notification from us no later than 30 days after the expiration of
the applicable warranty period of any defects or deficiencies in our project or
any component thereof, we will, subject to the provisions of the construction
agreement, make our facility or the subject equipment available to Raytheon
Engineers for Raytheon Engineers to re-perform, replace or, at Raytheon
Engineers' option, repair the same at Raytheon Engineers' expense so that it is
in compliance with the standards warranted and guaranteed, all in accordance
with the construction agreement.
FORCE MAJEURE
FORCE MAJEURE EVENT
A force majeure event will mean any act or event that prevents the
affected party from performing its obligations, other than the payment of money,
under the construction agreement or complying with any conditions required to be
complied with under the construction agreement if the act or event is beyond the
reasonable control of and not the fault of the affected party and the party has
been unable by the exercise of due diligence to overcome or mitigate the effects
of the act or event. Force majeure events include, but are not limited to, acts
of declared or undeclared war, sabotage, landslides, revolution, terrorism,
flood, tidal wave, hurricane, lightning, earthquake, fire, explosion, civil
disturbance, insurrection or riot, act of God or the public enemy, action,
including unreasonable delay or failure to act, of a court or public authority,
or strikes or other labor disputes of a regional or national character that are
not limited to only the employees of Raytheon Engineers or its subcontractors
and that are not due to the breach of a labor contract or applicable law by the
party claiming force majeure or any of its subcontractors. Force majeure events
do not include (i) acts or omissions of Raytheon Engineers or any
subcontractors, except as expressly provided in the foregoing sentence, (ii)
late delivery of materials or equipment, except to the extent caused by a force
majeure event, and (iii) economic hardship.
EXCUSED PERFORMANCE
If either party is rendered wholly or partly unable to perform its
obligations because of a force majeure event, that party will be excused from
whatever performance is affected by the force majeure event to the extent so
affected so long as:
o the non-performing party gives the other party prompt notice
describing the particulars of the occurrence;
o the suspension of performance is of no greater scope and of no
longer duration than is reasonably required by the force
majeure event;
o the non-performing party exercises all reasonable efforts to
mitigate or limit damages to the other party;
o the non-performing party uses its best efforts to continue to
perform its obligations under the construction agreement and
to correct or cure the event or condition excusing
performance; and
o when the non-performing party is able to resume performance of
its obligations, that party will give the other party written
notice to that effect and will promptly resume performance
under the construction agreement.
SCOPE CHANGES
We may order scope changes to the services, in which event one or more
of the contract price, the construction progress milestone dates, the guaranteed
completion dates, the payment and milestone schedule, our project schedule and
the performance guarantees will be adjusted accordingly, if necessary. All scope
changes will be authorized by a scope change order and only we or our
representative may issue scope change orders.
As soon as Raytheon Engineers becomes aware of any circumstances which
Raytheon Engineers has reason to believe may necessitate a scope change,
Raytheon Engineers will issue to us a scope change order notice at Raytheon
Engineers' expense. If we desire to make a scope change, in response to a scope
change order notice or otherwise,
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we will submit a scope change order request to Raytheon Engineers. Raytheon
Engineers will promptly review the scope change order request and notify us in
writing of the options for implementing the proposed scope change and the
effect, if any, each option would have on the contract price, the guaranteed
completion dates, the construction progress milestone dates, the payment and
milestone schedule, our project schedule and the performance guarantees.
No scope change order will be issued and no adjustment of the contract
price, the guaranteed completion dates, the construction progress milestone
dates, the payment and milestone schedule, our project schedule or the
performance guarantees will be made in connection with any correction of errors,
omission, deficiencies, or improper or defective work on the part of Raytheon
Engineers or any subcontractors in the performance of the services. Changes due
to changes in applicable laws or applicable permits occurring after the date of
the construction agreement will be treated as scope changes.
EFFECT OF FORCE MAJEURE EVENT
If and to the extent that any force majeure events affect Raytheon
Engineers' ability to meet the guaranteed completion dates, or the construction
progress milestone dates, an equitable adjustment in one or more of the dates,
the payment and milestone schedule and our project schedule will be made by
agreement of us and Raytheon Engineers. No adjustment to the performance
guarantees and, except as otherwise expressly set forth below, the contract
price will be made as a result of a force majeure event. If Raytheon Engineers
is delayed in the performance of the services by a force majeure event, then:
o to the extent that the delay(s) are, in the aggregate, 60 days
or less, Raytheon Engineers will absorb all of its costs and
expenses resulting from said delay(s); and
o to the extent that the delay(s) are, in the aggregate, more
than 60 days, Raytheon Engineers will be reimbursed by us for
those incremental costs and expenses resulting from said
delay(s) which are incurred by Raytheon Engineers after said
60 day period.
PRICE CHANGE
An increase or decrease in the contract price, if any, resulting from a
scope change requested by us or made under the construction contract will be
determined by mutual agreement of the parties.
CONTINUED PERFORMANCE PENDING RESOLUTION OF DISPUTES
Notwithstanding any dispute regarding the amount of any increase or
decrease in Raytheon Engineers' costs with respect to a scope change, Raytheon
Engineers will proceed with the performance of the scope change promptly
following our execution of the corresponding scope change order.
HAZARDOUS MATERIALS
If hazardous materials were not identified in an environmental site
assessment report delivered by us to Raytheon Engineers prior to the
commencement date and were not brought onto the site by Raytheon Engineers or
any of its subcontractors, then Raytheon Engineers will be entitled to a scope
change under the construction agreement.
INDEMNIFICATION
CONTRACTOR INDEMNITY
Raytheon Engineers will fully indemnify, save harmless and defend us,
our parents, subsidiaries and other affiliates, the financing parties, and the
directors, officers, agents, employees, successors and assigns of each of them,
from and against any and all losses, costs, damages, injuries, liabilities,
claims, demands, penalties, interest and causes of action, including without
limitation reasonable attorneys' fees (collectively for the purpose of this
indemnification section, the damages):
o directly or indirectly arising out of, resulting from or
related to any third-party claims associated with the
construction agreement including without limitation any claims
for damage to or destruction of property of, or death of or
bodily injury to, persons to the extent caused or contributed
to by Raytheon Engineers' or any subcontractor's negligence or
intentionally wrongful act in the performance of the services
or
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otherwise relating to the construction agreement or our
project, whether or not we or our indemnified parties are
contributorily negligent);
o in favor of any governmental authority or other third party to
the extent caused by (a) failure of Raytheon Engineers or any
subcontractor to comply with applicable laws and applicable
permits as required by the construction agreement, (b) failure
of Raytheon Engineers or any subcontractor to properly
administer and pay taxes or (c) nonpayment of amounts due as a
result of furnishing materials or services to Raytheon
Engineers or any subcontractor in connection with the
services;
o by reason of any claims or suits arising out of claims of
infringement of any domestic or foreign patent rights,
copyrights or other intellectual property, proprietary or
confidentiality rights with respect to materials and
information used by Raytheon Engineers or any subcontractor in
performing the services or in any way incorporated in or
related to our project; or
o resulting from (a) any hazardous material which has been
brought onto the site by any Raytheon Engineers responsible
party and (b) the negligence or willful misconduct of any
Raytheon Engineers responsible party in connection with the
presence of hazardous material on the facility site or the
release of any hazardous material on or from the facility site
but only to the extent not caused or contributed to by us or
our indemnified parties.
COMPANY INDEMNITY
We will fully indemnify, save harmless and defend Raytheon Engineers,
its parent, subsidiaries and other affiliates, and the directors, officers,
agents, employees, successors and assigns of each of them from and against all
Damages resulting from the presence of any hazardous material on, or the release
of any hazardous material on or from, the site, other than any hazardous
material brought onto the site by any Raytheon Engineers responsible party.
INSURANCE
GENERAL
Raytheon Engineers will provide and maintain the following types of
insurance at all times while Raytheon Engineers or any subcontractor is
performing the services: workers' compensation insurance and employers'
liability insurance; commercial general liability insurance; business
automobile liability insurance; commercial umbrella and/or excess insurance;
"all-risk" builder's risk insurance; and ocean marine cargo insurance. Before
permitting any of its subcontractors to perform any services at the site,
Raytheon Engineers will obtain a certificate of insurance from each
subcontractor evidencing that the subcontractor has obtained insurance in the
amounts and against the risks as is consistent with Raytheon Engineers'
customary practices for the types of subcontracts for projects of similar
type and capacity to our project. All insurance policies supplied by Raytheon
Engineers will include a waiver of any right of subrogation of the insurers
and of any right of the insurers to any set-off, counterclaim or other
deduction.
COST OF PREMIUMS
Raytheon Engineers will bear responsibility for payment of all premiums
for insurance coverage required to be provided by Raytheon Engineers.
RISK OF LOSS
With respect to our facility, until the risk transfer date, Raytheon
Engineers will bear the risk of loss and full responsibility for the costs of
replacement, repair or reconstruction resulting from any damage to or
destruction of our facility or any materials, equipment, tools and supplies that
are purchased for permanent installation in or for use during construction of
our facility.
After the risk transfer date with respect to our facility, we will bear
all risk of loss and full responsibility for repair, replacement or
reconstruction with respect to any loss, damage or destruction to our facility
which occurs after the risk transfer date.
DEDUCTIBLES
Raytheon Engineers will be responsible for deductibles for any losses
covered by insurance required to be provided by Raytheon Engineers. We, however,
will be responsible for the following:
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o deductibles in connection with any project losses that are
covered by builder's risk insurance and ocean marine cargo
insurance, in each case only up to the permitted deductibles
and only to the extent that the deductibles are in respect of
losses caused by our negligence or intentional misconduct; and
o deductibles in connection with any project losses that are (i)
covered by the "Delay In Start-Up" insurance or (ii) caused by
an event of force majeure.
ADDITIONAL INSUREDS
All insurance coverages furnished by Raytheon Engineers and us, with
the exception of workers compensation insurance, will include us, Raytheon
Engineers, the financing parties, Jersey Central Power and all their assignees,
subsidiaries and affiliates as additional insureds, as their respective
interests may appear and, with respect to the "all risk" builder's risk
insurance, will designate the financing parties, as identified by us, as loss
payees for losses in excess of $1 million.
NO LIMITATION OF LIABILITY
The required coverages will in no way affect, nor are they intended as
a limitation of, Raytheon Engineers' liability with respect to its performance
of the services except as expressly provided elsewhere.
INSURANCE PRIMARY
All policies of insurance provided by Raytheon Engineers will be
written as primary and noncontributing with respect to any other similar
coverage that we, the financing parties, Jersey Central Power and their
assignees, subsidiaries and affiliates may carry.
TERMINATION
TERMINATION FOR OUR CONVENIENCE
We may for our convenience terminate any part of the services or all
remaining services at any time upon 30 days' prior written notice to Raytheon
Engineers specifying the part of the services to be terminated and the effective
date of termination. We may elect to suspend completion of all or any part of
the services upon 10 days' prior written notice to Raytheon Engineers, or, in
emergency situations, upon prior notice as circumstances permit.
TERMINATION BY CONTRACTOR
If we fail to pay to Raytheon Engineers any payment and the failure
continues for 30 days, then (i) Raytheon Engineers may suspend its performance
of the services upon 10 days' prior written notice to us, which suspension may
continue until the time as the payment, plus accrued interest thereon, is paid
to Raytheon Engineers, and/or (ii) if the payment has not been made prior to the
commencement of a suspension by Raytheon Engineers under clause (i) above,
Raytheon Engineers may terminate the construction agreement upon 60 days' prior
written notice to us, however, the termination will not become effective if the
payment, plus accrued interest thereon, is made to Raytheon Engineers prior to
the end of the notice period. If the suspension occurs, an equitable adjustment
to one or more of the contract price, the guaranteed completion dates, the
construction progress milestone dates, the payment and milestone schedule and
our project schedule, and, as appropriate, the other provisions of the
construction agreement that may be affected thereby, will be made by agreement
between us and Raytheon Engineers. If we have suspended completion of all or any
part of the services in accordance with the construction agreement for a period
in excess of 365 days in the aggregate, Raytheon Engineers may, at its option,
at any time thereafter so long as the suspension continues, give written notice
to us that Raytheon Engineers desires to terminate the construction agreement.
Unless we order Raytheon Engineers to resume performance of the suspended
services within 15 days of the receipt of the notice from Raytheon Engineers,
the suspended services will be deemed to have been terminated by us for our
convenience. If the occurrence of one or more force majeure events prevents
Raytheon Engineers from performing the services for a period in the aggregate of
720 days, either party may, at its option, give written notice to the other
party of its desire to terminate the construction agreement.
CONSEQUENCES OF TERMINATION
o Upon any termination, we may, so long as the termination is
pursuant to any default Raytheon Engineers will have been paid
all amounts due and owing to it under the construction
agreement, which will not be deemed to constitute a waiver by
Raytheon Engineers of any rights to payment it may have as a
result of a non-default
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related termination in the event of a termination pursuant to
a default, at our option elect to have itself, or our
designee, which may include any other affiliate or any
third-party purchaser, (i) assume responsibility for and take
title to and possession of our project and any or all work,
materials or equipment remaining at the site and (ii) succeed
automatically, without the necessity of any further action by
Raytheon Engineers, to the interests of Raytheon Engineers in
any or all items procured by Raytheon Engineers for our
project and in any and all contracts and subcontracts entered
into between Raytheon Engineers and any subcontractor with
respect to the equipment specified in the construction
agreement, and with respect to any or all other subcontractors
selected by us which are materially necessary to the timely
completion of our project, Raytheon Engineers will use all
reasonable efforts to enable us, or our designee, to succeed
to Raytheon Engineers' interests thereunder.
o If any termination occurs, we may, without prejudice to any
other right or remedy it may have, at its option, finish the
services by whatever method we may deem expedient.
SURVIVING OBLIGATIONS
Termination of the construction agreement (i) will not relieve either
party of any obligation with respect to the confidentiality of the other party's
information, (ii) will not relieve either party of any obligation which
expressly or by implication survives termination of the construction agreement
and (iii) except as otherwise provided in any provision of the construction
agreement expressly limiting the liability of either party, will not relieve
either party of any obligations or liabilities for loss or damage to the other
party arising out of or caused by acts or omissions of the party prior to the
effectiveness of the termination or arising out of the termination, and will not
relieve Raytheon Engineers of its obligations as to portions of the services
already performed or as to obligations assumed by Raytheon Engineers or us prior
to the date of termination.
DEFAULT AND REMEDIES
CONTRACTOR'S DEFAULT
Raytheon Engineers' events of default include: voluntary bankruptcy or
insolvency; involuntary bankruptcy or insolvency; materially adverse misleading
or false representation or warranty; improper assignment; failure to maintain
required insurance; failure to comply with applicable laws or applicable
permits; cessation or abandonment of the performance of services; termination or
repudiation of, or default under the related construction contract guaranty;
failure to supply sufficient skilled workers or suitable material or equipment;
failure to make payment when due for labor, equipment or materials;
non-occurrence of either provisional acceptance or final acceptance within 90
days after the guaranteed provisional acceptance date, non-occurrence of
construction progress milestones and failure to be proceeding under a
remediation plan within 90 days after the non-occurrence; and failure to remedy
non-performance or non-observance of any provision in the construction
agreement.
COMPANY'S RIGHTS AND REMEDIES
If Raytheon Engineers is in default of its obligations, we will have
any or all of the following rights and remedies, in addition to any other rights
and remedies that may be available to us under the construction agreement or at
law or in equity, and Raytheon Engineers will have the following obligations:
o We may, without prejudice to any other right or remedy we may
have under the construction agreement or at law or in equity,
terminate the construction agreement in whole or in part
immediately upon delivery of notice to Raytheon Engineers. In
case of the partial termination, the parties will mutually
agree upon a scope change order to make equitable adjustments,
including the reduction and/or deletion of obligations of the
parties commensurate with the reduced scope Raytheon Engineers
will have after taking into account the partial termination,
to one or more of the guaranteed completion dates, the
construction progress milestone dates, the contract price, the
payment and milestone schedule, our project schedule, the
performance guarantees and the other provisions of the
construction agreement which may be affected thereby, as
appropriate. If the parties are unable to reach mutual
agreement as to said scope change order and the dispute
resolution procedures set forth in the construction agreement
are invoked, the procedures will give due consideration to
customary terms and conditions under which Raytheon Engineers
has entered subcontracts with third party prime contractors
covering services substantially similar to those services
which are not being terminated.
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o If requested by us, Raytheon Engineers will withdraw from the
site, will assign to us such of contractor's subcontracts, to
the extent permitted therein, as we may request, and will
remove the materials, equipment, tools and instruments used
by, and any debris and waste materials generated by, Raytheon
Engineers in the performance of the Services as we may direct,
and we, without incurring any liability to Raytheon Engineers,
other than the obligation to return to Raytheon Engineers at
the completion of our project the materials that are not
consumed or incorporated into our project, solely on an "as
is, where is" basis without any representation or warranty of
any kind whatsoever, may take possession of any and all
designs, drawings, materials, equipment, tools, instruments,
purchase orders, schedules and facilities of Raytheon
Engineers at the site that we deem necessary to complete the
services.
ASSIGNMENT
The parties shall have no right to assign or delegate any of their
respective rights or obligations under the construction agreement either
voluntarily or involuntarily or by operation of law, except that we may, without
Raytheon Engineers' approval, assign any or all of its rights under the
construction agreement (a) as collateral security to the financing parties and
(b) to any transferee of our project or a substantial portion so long as such
assignee has financial and operational capabilities that are either
substantially similar to those of ours at the time or otherwise are such that
the assignment could not reasonably be expected to have a material adverse
effect on Raytheon Engineers' rights and obligations under the construction
agreement.
MAINTENANCE SERVICES AGREEMENT
We have entered into the Maintenance Program Parts, Shop Repairs and
Scheduled Outage TFA Services Contract, dated as of December 8, 1999, with
Siemens Westinghouse by which Siemens Westinghouse will provide us with, among
other things, combustion turbine parts, shop repairs and scheduled outage
technical field assistance services.
The maintenance services agreement became effective on the date of
execution and unless terminated early, will terminate upon completion of shop
repairs performed by Siemens Westinghouse following the twelfth scheduled outage
of the applicable combustion turbine or sixteen years from the date of
execution, whichever occurs first, unless we exercise our right to terminate the
agreement after the first major outage of the turbines, which will be
approximately the sixth year of operation of the facility.
SCOPE OF WORK
During the term of the maintenance services agreement, and in
accordance with the scheduled outage plan, Siemens Westinghouse is required to
do the following:
o deliver the type and quantity of new program parts for
installation of the combustion turbine;
o repair/refurbish program parts and equipment for the
combustion turbine;
o provide miscellaneous hardware;
o provide us with material safety data sheets for all hazardous
materials Siemens Westinghouse intends to bring/use on the
site;
o provide the services of a maintenance program engineer to
manage the combustion turbine maintenance program; and
o provide technical field assistance, or TFA Services, which
involves advice and consultation for the disassembly,
inspection and assembly of various equipment.
We are responsible for, among other things:
o storing and maintaining parts, materials and tools to be used
in or on the combustion turbine;
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o maintaining and operating the combustion turbine consistently
with the warranty conditions;
o ensuring that our operator and maintenance personnel are
properly trained;
o transporting program parts in need of repair/refurbish; and
o providing Siemens Westinghouse, on a monthly basis, with the
number of equivalent starts and the number of EBHs incurred by
each combustion turbine.
We and Siemens Westinghouse will jointly develop the scheduled outage
plan. The scheduled outage plan will be consistent with the terms and conditions
of the power purchase agreement.
EARLY REPLACEMENT
If it is determined that due to normal wear and tear a program part(s)
for the combustion turbine has failed or will not last until the next scheduled
outage, and the part has to be repaired before the scheduled replacement period,
Siemens Westinghouse will replace the program part by moving up a new program
Part which is otherwise scheduled to be delivered at a later date. The contract
price for the replacement will not be affected if the replacement date is less
than or equal to one year earlier than the scheduled outage during which the
program part was scheduled to be replaced. If the actual replacement date for a
program part is more than one year earlier than the scheduled outage at which
point the program part was scheduled to be replaced, the early replacement will
result in an adjustment to the payment schedule. Siemens Westinghouse has the
final decision with regard to the replacement or refurbishment associated with
any program part. If we dispute Siemens Westinghouse's decision, we may seek to
resolve the dispute in accordance with the dispute resolution procedures
discussed below.
PARTS LIFE CREDIT
After applicable warranty periods set forth in the maintenance services
agreement and the construction agreement, Siemens Westinghouse will provide a
parts life credit if a program part requires replacement due to normal wear and
tear prior to meeting its expected useful life. Siemens Westinghouse has the
final decision with regard to actual parts life and the degree of repair or
refurbishment associated with any program parts. The parts life credit will be
calculated in terms of EBHs and equivalent starts. The price of the replacement
part will be adjusted for inflation. If we dispute Siemens Westinghouse's
decision, we may seek to resolve the dispute in accordance with the dispute
resolution procedures discussed below.
CONTRACT PRICE AND PAYMENT TERMS
Siemens Westinghouse will invoice us monthly and payments are then due
within 25 days. The fees assessed by Siemens Westinghouse will be based on the
number of EBHs accumulated by the applicable combustion turbine as adjusted for
changes in the consumer price index. The contract price will be the aggregate
number of fees as adjusted plus any additional payment amount mutually agreed to
by the parties under a change order.
UNSCHEDULED OUTAGES AND UNSCHEDULED OUTAGE WORK
If during the term of the maintenance services agreement an Unscheduled
outage occurs resulting from (i) the non-conformity of new program parts; (ii)
the failing of a shop repair; (iii) a program part requiring replacement due to
normal wear and tear prior to achieving its expected life in terms of EBHs or
equivalent starts; or (iv) the failure of a service, performed by Siemens
Westinghouse, we will hire Siemens Westinghouse, to the extent not supplied by
Siemens Westinghouse as a warranty remedy under Siemens Westinghouse's
warranties under the maintenance services agreement, to supply any additional
parts, miscellaneous hardware, shop repairs and TFA Services under a change
order. We will be entitled to any applicable parts life credit with respect to
program parts as well as a discount for TFA Services. If the unscheduled outage
occurs within a specified number of EBHs of a scheduled outage and it was
anticipated that the additional parts, miscellaneous hardware, shop repairs and
TFA Services to be used in the unscheduled outage were to be used during the
upcoming scheduled outage, the upcoming scheduled outage will be moved up in
time to become the unscheduled outage/moved-up scheduled outage. We will not be
required to pay any additional money for the program parts, miscellaneous
hardware, shop repairs and TFA Services.
If any Program Parts are delivered by Siemens Westinghouse within 15
days of receipt of the change order, we will pay to Siemens Westinghouse the
price for the program part set forth in the maintenance services agreement plus
a
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specified percentage. Any program part delivered after 30 days of the change
order will cost us the price set forth in the maintenance services agreement
minus a specified percentage.
The remedies set forth in the maintenance services agreement, and
discounts on any TFA Services purchased by us from Siemens Westinghouse will
constitute Siemens Westinghouse's sole liability and our exclusive remedies for
unscheduled outages whether our claims are based in contract, in tort, or
otherwise. If Siemens Westinghouse fails to send a TFA Services representative
by the end of the second day following written receipt of the unscheduled
outage, we may hire another qualified person, at its cost, to perform the work.
If the hired party proceeds to disassemble the combustion turbine to determine
the case of the unscheduled outage and Siemens Westinghouse still has not
provided personnel to assist with the inspection, we can elect to terminate the
maintenance services agreement on the basis that Siemens Westinghouse has failed
to perform a material obligation.
CHANGES IN OPERATING RESTRICTIONS
The maintenance services agreement requires that each combustion
turbine will be operated in accordance with the requirements of the power
purchase agreement and prudent utility practices, with 8,000 EBH/year and 250
equivalent starts per year by using natural gas fuel or liquid fuel and water.
Should the actual operations differ from these operating parameters which causes
a scheduled outage to be planned/performed earlier or later than as expected,
then, under a change order, an adjustment in the scope, schedule, and price will
be made.
WARRANTIES
Siemens Westinghouse warrants that the new program parts, miscellaneous
hardware and any shop repairs will conform to standards of design, materials and
workmanship consistent with generally accepted practices of the electric utility
industry. The warranty period with respect to program parts, hardware and shop
repair is until the earlier of one year from the date of installation of the
original program part or hardware, a specific number of starts or fired hours
after installation of the program parts and hardware, or three years from the
date of delivery of the original program part, hardware, and in the case of shop
repair, three years from completion of the work. Warranties on the program parts
and hardware will not expire more than one year after the conclusion of the
maintenance services agreement. Siemens Westinghouse will repair or replace any
program part or hardware, at its cost, if notified of any failure or
non-conformity of the program part or hardware during the warranty period.
Siemens Westinghouse also warrants that the services of its personnel
and technical information transmitted will be competent and consistent with
prudent utility practices and the services will comply in all material respects
with laws and will be free from defects in workmanship for a period of one year
from the date of completion of that item of services. The warranties on the
services will expire no later than one year after the termination or end of the
term of the maintenance services agreement.
In addition, Siemens Westinghouse warrants any program part removed
during a scheduled outage and delivered by us to the designated facility for
repair will be repaired and delivered by Siemens Westinghouse within 26 weeks.
If Siemens Westinghouse does not deliver the program part within this time frame
or does not provide a new program part in lieu of the program part being shop
repaired and an outage occurs which requires such a program part, Siemens
Westinghouse will pay us liquidated damages for each day the program part is not
repaired and delivered the aggregate of which liquidated damage payments will
not exceed a maximum annual cap. If upon reaching the maximum cap on aggregate
liquidated damages, Siemens Westinghouse still has not repaired and delivered
the program part, we may elect to terminate the maintenance services agreement
because Siemens Westinghouse will be considered to have failed to perform its
material obligations.
Except for the express warranties set forth in the maintenance services
agreement, Siemens Westinghouse makes no other warranties or representations of
any kind. No implied statutory warranty of merchantability or fitness for a
particular purpose applies.
The warranties provided by Siemens Westinghouse are conditioned upon
(i) our receipt, handling, storage, operation and maintenance of our project,
including any program parts and miscellaneous hardware, being done in accordance
with the terms of the combustion turbine instruction manuals; (ii) operation of
the combustion turbine in accordance with the terms of the maintenance services
agreement; (iii) repair of accidental damage done consistently with the
equipment manufacturer's recommendations; (iv) us providing Siemens Westinghouse
with access to the site to perform its services under the maintenance services
agreement; and (v) hiring Siemens Westinghouse to provide TFA Services, program
parts, shop repairs and miscellaneous hardware required to dissemble, repair and
reassemble the combustion turbine.
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INSURANCE
Siemens Westinghouse will maintain in full force and effect during the
term of the maintenance services agreement the following required insurance
coverage: commercial general liability, workers' compensation, umbrella excess
liability and business automobile liability. All the policies of workers'
compensation must provide a waiver of subrogation rights against us.
We will maintain in full force and effect during the term of the
maintenance services agreement the following required insurance coverage:
property insurance, commercial general liability, workers' compensation,
umbrella excess liability and business automobile liability insurance. The
policies of property insurance and workers' compensation must include waivers of
subrogation rights against Siemens Westinghouse.
TERMINATION
We may terminate the maintenance services agreement if (i) specific
bankruptcy events affecting Siemens Westinghouse occur; (ii) Siemens
Westinghouse fails to perform or observe in any material respect any provision
in the maintenance services agreement and fails to (a) promptly commence to cure
and diligently pursue the cure of the failure or (b) remedy the failure within
45 days after Siemens Westinghouse receives written notice of the failure; (iii)
we terminate the construction agreement due to Raytheon Engineers' default
thereunder or due to our inability to obtain construction financing or
environmental operating permits; or (iv) Raytheon Engineers terminate the
construction agreement for any reason other than our default thereunder.
Notwithstanding the foregoing, we may terminate the maintenance services
agreement at any time for convenience following the completion of the first
major outage of both combustion turbine generators. In addition, the maintenance
services agreement will automatically terminate if (i) we terminate the
construction agreement for reasons other than (a) the default of Raytheon
Engineers and (b) our inability to obtain permits for our project or (ii) the
Raytheon Engineers terminates the construction agreement for our default
thereunder. If such termination, Siemens Westinghouse will discontinue any work
or services being performed and continue to protect our property. Siemens
Westinghouse will transfer title to and deliver any new program parts and
miscellaneous hardware already purchased by us. We will pay Siemens Westinghouse
those amounts owed at the time of termination.
Siemens Westinghouse may also terminate the maintenance services
agreement if: (i) we fail to make payments or (ii) specific bankruptcy events
affecting us occur. Siemens Westinghouse cannot terminate the maintenance
services agreement if we pay outstanding amounts due within 90 days. Upon
termination, Siemens Westinghouse will stop all work, place no additional
orders, protect our property and deliver the property to us upon our
instructions. Siemens Westinghouse will be entitled to payment for work
performed up until its termination of the maintenance services agreement, all
outstanding fees and reasonable costs associated with the termination.
INDEMNIFICATION
To the fullest extent permitted by law, each party will defend,
indemnify and hold harmless the other party from and against liability resulting
from injury to or death of persons and from damage to or loss of third-party
property, caused by or arising in whole or in part out of, but only to the
extent of the negligent acts or omissions of the party while performing its
obligations under the maintenance services agreement. Each party's indemnity
obligation under the maintenance services agreement will not apply to any
liabilities arising out of or relating to events or circumstances occurring more
than one year after end of the term of the maintenance services agreement.
LIMITATION OF LIABILITY
Each party agrees that, except to the extent liquidated damages
provided in the maintenance services agreement are so considered, neither
Siemens Westinghouse, nor its suppliers, nor will we under any circumstances be
liable for: any indirect, special, incidental or consequential loss or damage
whatsoever; damage to or loss of property or equipment; loss of profits or
revenues; loss of use of material, equipment or power system; increased costs of
any kind, including but not limited to capital cost, fuel cost and cost of
purchased or replacement power, or claims of our customers.
We agree that the remedies provided in the maintenance services
agreement are exclusive and that under no circumstances will the total aggregate
liability of Siemens Westinghouse during a given year exceed 100% of the
contract price payable to Siemens Westinghouse for that given year under the
maintenance services agreement. We further agree that under no circumstances
will the total aggregate liability of Siemens Westinghouse for liquidated
damages during a given year exceed a specified percentage of the contract price
payable to Siemens Westinghouse for that given year under the maintenance
services agreement. We further agree that under no circumstances will the total
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aggregate liability of Siemens Westinghouse exceed a specified percentage of the
contract price payable to Siemens Westinghouse under the maintenance services
agreement.
FORCE MAJEURE
Neither party will be liable for failure to perform any obligation or
delay in performance, excluding payment, to the extent the failure or delay is
caused by any act or event beyond the reasonable control of the affected party
or Siemens Westinghouse's suppliers; so long as the act or event is deemed to be
a force majeure and is not the fault or the result of negligence of the affected
party and the party has been unable by exercise of reasonable diligence to
overcome or mitigate the effects of the act or event. Force majeure includes:
any act of God; act of civil or military authority; act of war whether declared
or undeclared; act, including delay, failure to act, or priority, of any
governmental authority; civil disturbance; insurrection or riot; sabotage; fire;
inclement weather conditions; earthquake; flood; strikes, work stoppages, or
other labor difficulties of a regional or national character which are not
limited to only the employees of Siemens Westinghouse or its subcontractors or
suppliers and which are not due to the breach of an applicable labor contract by
the party claiming force majeure; embargo; fuel or energy shortage; delay or
accident in shipping or transportation to the extent attributable to another
force majeure; changes in laws which substantially prevents a party from
complying with its obligations in conformity with its requirements under the
maintenance services agreement or failure or delay beyond its reasonable control
in obtaining necessary manufacturing facilities, labor, or materials from usual
sources to the extent attributable to another force majeure; or failure of any
principal contractor to provide equipment to the extent attributable to another
force majeure. Force majeure will not include: (i) economic hardship, (ii)
changes in market conditions or (iii) except due to an event of force majeure,
late delivery of program parts or other equipment.
If a delay in performance is excusable due to a force majeure, the date
of delivery or time for performance of the work will be extended by a period of
time reasonably necessary to overcome the effect of the force majeure and if the
force majeure lasts for a period longer than 30 days and the delay directly
increases Siemens Westinghouse's costs or expenses, we, after reviewing Siemens
Westinghouse's additional direct costs and expenses, will reimburse Siemens
Westinghouse for its reasonable additional direct costs and expenses incurred
after 30 days from the beginning of the force majeure resulting from said delay.
ENVIRONMENTAL COMPLIANCE
Siemens Westinghouse will indemnify us from any fines, penalties,
expense, loss or liability, including the costs of clean-up, incurred by us as a
result of (i) Siemens Westinghouse's failure to meet its obligations under the
maintenance services agreement or (ii) any spills of hazardous waste or oil,
petroleum or petroleum products to the environment which are attributable to and
occur during Siemens Westinghouse's performance, or the performance of its
contractors or subcontractors, of the workscope obligations at the site under
the maintenance services agreement.
We will indemnify Siemens Westinghouse from any fines, penalties,
expense, loss or liability incurred by Siemens Westinghouse as a result of our
failure to meet our obligations under the maintenance services agreement. We
will have no responsibility or liability with regard to any hazardous waste or
oil, petroleum or petroleum products which were spilled by Siemens Westinghouse,
or any other of its contractors or subcontractors performing workscope
obligations at the site.
FLEETWIDE ISSUE NOTIFICATION
During the term of this agreement, if Siemens Westinghouse becomes
aware of a fleetwide issue involving the Siemens Westinghouse 501F Combustion
Turbine which may have a deleterious effect on our combustion turbines, Siemens
Westinghouse will, within a reasonable time of becoming aware of the fleetwide
issues, notify us thereof, and if the fleetwide issue requires an additional
repair or replacement of a program part or miscellaneous hardware to be
performed, the additional repair or replacement will be performed in accordance
with the provisions of the maintenance services agreement.
INTERCONNECTION AGREEMENT
We have entered into a Generation Facility Transmission
Interconnection Agreement, dated as of April 27, 1999 with Jersey Central
Power, for the installation, operation and maintenance of the facilities
necessary to interconnect our facility to Jersey Central Power's transmission
system. Under the interconnection agreement, we and Jersey Central Power will
construct, own, operate and maintain the interconnection facilities. We are
responsible for all of the costs of construction, operation and maintenance
of the interconnection facilities, including those owned by Jersey Central
Power.
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SCOPE
The interconnection agreement will become effective on the effective
date established by FERC and will continue in full force and effect until a
mutually agreeable termination date not to exceed the retirement date for our
facility.
JERSEY CENTRAL POWER'S OBLIGATIONS
Upon issuance of a notice to proceed by us to Jersey Central Power, the
parties will enter into an interconnection installation agreement, by which
Jersey Central Power will install, at our cost and expense the Jersey Central
Power Interconnection Facilities. The Jersey Central Power Interconnection
Facilities, together with the facilities to be installed by us, are necessary to
allow the interconnection of our facility with the transmission system of Jersey
Central Power. After the installation is complete, Jersey Central Power will
own, maintain and operate, at the cost and expense of us, the Jersey Central
Power Interconnection Facilities which include, but are not limited to, certain
substation protective relaying equipment and two 230 kV 2-cycle circuit
breakers. The remainder of the interconnection facilities will be installed,
owned, maintained and operated by us.
Jersey Central Power will complete the installation of the Jersey
Central Power Interconnection Facilities necessary to permit us to energize the
switch yard and commence commissioning of our facility by the scheduled
completion date, which is 540 days from the day on which we issued the notice to
proceed. If the Jersey Central Power Interconnection Facilities are completed
prior to the scheduled completion date, Jersey Central Power will be paid an
early completion bonus of $5,000 for each day of early completion up to and
including 30 days. If the Jersey Central Power Interconnection Facilities are
completed after the scheduled completion date, Jersey Central Power will pay
delay damages of $5,000 for each day of delay up to and including 45 days. We
will have the ability to take over the completion of these facilities if it
becomes apparent that Jersey Central Power will not be able to complete them
within the 45 day-period, Jersey Central Power has not proposed a reasonable
recovery plan, and we can demonstrate that it is able to complete the facilities
more quickly than Jersey Central Power.
COMPANY'S OBLIGATIONS
We will install, own, operate and maintain a portion of the
interconnection facilities, including, but not limited to, a 230 kV switchyard,
including generator step up transformers, instrument transformers, revenue
metering, power circuit breakers, control and protective relay panels,
supervisory control and data acquisition equipment, and protective relaying
equipment.
We will reimburse Jersey Central Power for its actual costs of
installing Jersey Central Power Interconnection Facilities. Our payments to
Jersey Central Power consist of advance payments of $100,000 on the execution
date of the interconnection installation agreement, $200,000 upon the issuance
of the notice to proceed, $1,700,000 at the closing for financing for our
facility and payments of monthly invoices for the work performed. The advance
payments by us to Jersey Central Power will be credited to offset invoices
during the later stages of completing the Jersey Central Power Interconnection
Facilities. We may assign to the purchaser of the output of our facility the
payment obligations to Jersey Central Power for installing the Interconnection
Facilities.
We are obligated to give prior notice to Jersey Central Power before
undertaking any additions, modifications or replacements to our facility or our
interconnection facilities that will increase the generating capacity of our
facility or could reasonably be expected to affect the transmission system, the
Jersey Central Power Interconnection Facilities or the operation of our
facility. We must reimburse Jersey Central Power for all costs incurred by
Jersey Central Power associated with any modifications, additions or
replacements that it must make to the transmission system or the Jersey Central
Power Interconnection Facilities, as reasonably required by Jersey Central
Power, in connection with our proposed addition, modification or replacement at
our facility. We are obligated to modify its portion of the interconnection
facilities as may be required to conform to changes in good utility practice or
as required by PJM Interconnection, L.L.C., which is the independent system
operator that operates the transmission system to which our facility will be
interconnected.
We are obligated to keep our facility insured against loss or damage in
accordance with the minimum coverages specified in the Interconnection
Agreement.
OPERATION AND MAINTENANCE OF INTERCONNECTION FACILITIES
The parties are obligated to operate and maintain their respective
portions of the interconnection facilities in accordance with good utility
practices and the requirements and guidelines of PJM and Jersey Central Power.
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Jersey Central Power will have the right to disconnect our facility
from its transmission system and/or curtail, interrupt or reduce the output of
our facility when operation of our facility or the interconnection facilities
adversely affects the quality of service rendered by Jersey Central Power or
interferes with the safe and reliable operation of its transmission system or
the regional transmission system. Jersey Central Power, however, is obligated to
use reasonable efforts to minimize any disconnection, curtailment, interruption
or reduction in output.
In accordance with good utility practice, Jersey Central Power may
remove the interconnection facilities from service as necessary to perform
maintenance or testing or to install or replace equipment on the interconnection
facilities or the transmission system. Jersey Central Power is obligated to use
due diligence to restore the interconnection facilities to service as promptly
as practicable.
In addition, if we fail to operate, maintain, administer, or insure our
facility or its portion of the interconnection facilities, Jersey Central Power
may, following 30 days notice and opportunity to cure the failure, disconnect
our facility from the transmission system.
REVENUE METERING
Revenue meters, which are part of the interconnection facilities, will
be installed to measure the transfer of electrical energy between the parties at
the point of interconnection. The revenue meters will be installed, owned,
maintained and repaired by Jersey Central Power, at our expense. Jersey Central
Power will install, also at our expense, telemetering equipment or other
communications equipment, other than an operating telephone link, which will be
installed by us, to retrieve certain information. The revenue meters are to be
tested at least once every two years, or more frequently at our request. Any
revenue meter found to be inaccurate by greater than 1% is to be adjusted,
repaired or replaced.
LAND RIGHTS AND ACCESS
We have granted to Jersey Central Power the right of reasonable access
and all necessary rights of way, easements, and licenses as Jersey Central Power
may require to install, operate, maintain, replace and remove the revenue meters
and other portions of the Jersey Central Power Interconnection Facilities.
FORCE MAJEURE
If either party is delayed in or prevented from performing or carrying
out its obligations under the interconnection agreement by reason of force
majeure, the party will not be liable to the other party for or on account of
any loss, damage, injury or expense resulting from or arising out of the delay
or prevention, however, the party encountering the delay or prevention will use
due diligence to remove the cause or causes thereof.
LIABILITY AND INDEMNIFICATION
Neither party will be liable to the other for incidental, special,
indirect or consequential damages. We are obligated to indemnify Jersey Central
Power for claims, liabilities, costs, damages, losses and expenses for damage to
property, injury to or death of any persons to the extent caused by any act or
omission, negligent or otherwise, relating to the design, construction,
ownership, operation, or maintenance of our facility or our portion of the
interconnection facilities. We also are obligated to indemnify Jersey Central
Power for any taxes that may be imposed if our payment, or failure to pay, to
Jersey Central Power of the costs associated with the purchase or installation
of any portion of the Jersey Central Power Interconnection Facilities are
treated as a contribution in aid of construction by the taxing authorities under
the U.S. Internal Revenue Service Notice 88-129 and 90-60. We also must provide
a certification of the independent engineer, attesting as to the anticipated
power flows through the interconnection facilities and will make Jersey Central
Power whole for any increase in its tax liabilities that arise because of
exceeding the limitations set forth in IRS Notice 88-129.
DEFAULT
The events of default under the interconnection agreement are:
o breach of a material term or condition and uncured failure to
provide a required schedule, report or notice;
o failure or refusal of a party to permit the representatives of
the other party access to maintenance records, or its
interconnection facilities or protective apparatus;
o appointment by a court of a receiver or liquidator or trustee
that is not discharged within 60 days, issuance by a court of
a decree adjudicating a party as bankrupt or insolvent or
sequestering a substantial part of its
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property that has not been discharged within 60 days after its
entry, or filing of a petition to declare a party bankrupt or
to reorganize a party under the Federal Bankruptcy Code or
similar state statute that has not been dismissed within 60
days;
o voluntary filing by a party of a petition in bankruptcy or
consent to the filing of a bankruptcy or reorganization
petition, an assignment for the benefit of creditors, an
admission by a party in writing of its inability to pay its
debts as they come due, or consent to the appointment of a
receiver, trustee, or liquidator of a party or any
part of its property; and
o failure to provide the other party with reasonable written
assurance of the party's ability to perform any of the
material duties and responsibilities under the interconnection
agreement within 60 days of a reasonable request for the
assurance.
Upon an event of default, the non-defaulting party may give notice of
the event of default to the defaulting party. The defaulting party will have 60
days following the receipt of the notice to cure the default or to commence in
good faith the steps necessary to cure a default that cannot be cured within
that 60-day period. If the defaulting party fails to cure its default within 60
days or fails to take the steps necessary to cure a default that cannot be cured
within a 60-day period, the non-defaulting party will have the right to
terminate the interconnection agreement.
Jersey Central Power will have the right to operate and/or to purchase
specific equipment, facilities and appurtenances from us that are necessary for
Jersey Central Power to operate and maintain its transmission system if (i) we
commence bankruptcy proceedings or petitions for the appointment of a trustee or
other custodian, liquidator, or receiver; (ii) a court issues a decree for
relief of our company or appoints a trustee or other custodian, liquidator, or
receiver for our company or a substantial part of our assets and the decree is
not dismissed within 60 days or (iii) we cease operation for 30 consecutive days
without having an assignee, successor, or transferee in place.
OPERATIONS AGREEMENT AND SERVICES AGREEMENT
We have entered into a Development and Operations Services
Agreement, dated as of March 10, 2000, with AES Sayreville under which AES
Sayreville will provide development and construction management services and,
after the commercial operation date, operating and maintenance services for
our facility for a period of 32 years. Under the operations agreement, AES
Sayreville will be responsible for, among other things, preparing plans and
budgets related to start-up and commercial operation of our facility,
providing qualified operating personnel, making repairs, purchasing
consumables and spare parts (not otherwise provided under the maintenance
services agreement) and providing other services as needed according to
industry standards.
AES Sayreville will be compensated for the services on a cost plus fixed-fee
basis.
Under a services agreement between AES Sayreville and The AES
Corporation, The AES Corporation will provide to AES Sayreville all of the
personnel and services necessary for AES Sayreville to comply with its
obligations under the operations agreement.
WATER SUPPLY AGREEMENT
We have entered into a Water Supply Agreement dated as of December
22, 1999 with the Borough of Sayreville under which the Borough will provide
untreated water to our facility.
SUPPLY OF UNTREATED WATER
UNTREATED WATER SUPPLY
Subsequent to the completion of the Lagoon Pumping Station and the
Lagoon Water Pipeline, the Borough will make available to our facility a supply
of untreated water from the South River that is not less than 4.6 million
gallons per day and 1.53 billion gallons per year. The Borough will use
reasonable efforts to maintain the Lagoon's water level at an elevation of 29
feet, but during periods when water cannot be drawn from the South River, the
Lagoon's water level will be drawn to elevations below 29 feet. The Borough will
supply us with water drawn from the South River when the Lagoon's water level is
20 feet or higher. During periods when either the Lagoon's water level is below
20 feet and water cannot be drawn from the South River or when water from the
Lagoon is needed to ensure a supply of treated water to Borough treated water
customers, the Borough will supply our facility with water drawn from the
Duhernal acquifer and transported through the Duhernal water pipeline.
The Borough will use reasonable efforts to comply with our requests for
untreated water in excess of 4.6 million gallons per day and 1.533 billion
gallons per year.
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COMPENSATION
We will pay the Borough an initial payment of $150,000 from the bond
proceeds, which will be credited to our account and will be used to offset the
cost of untreated water purchased during our project's start-up and testing
phase and during the first year of operation. If the Borough incurs additional
costs from Middlesex Water Company as a result of the Borough providing us with
Duhernal Water, we also will pay the Borough for those additional costs. We will
pay the Borough monthly for all untreated water delivered to the point of
delivery during the prior month. The base rate for untreated water supplied from
the South River is $216 per million gallons, which includes $53 per million
gallons to cover operations, maintenance and administrative costs and $163 per
million gallons to cover past infrastructure costs. The operations and
maintenance rate will be escalated in accordance with the percentage changes in
water rates that are applicable to other Borough water customers. The base rate
for untreated water delivered from the Duhernal acquifer is $932 per million
gallons which includes $785 to cover the operations, maintenance and
administrative costs and $147 to cover acquisition costs. The operations and
maintenance portion of the base rate for water delivered from the Duhernal
acquifer is also subject to escalation in accordance with the percentage changes
in water rates that are applicable to other Borough water customers.
With respect to each contract year there will be a minimum bill amount,
which will initially be $300,000 per year. One-twelfth of the minimum bill
amount will be paid each month. The minimum bill amount will be adjusted as
follows:
o For the first contract year it will be reduced by the amount
of the initial payment;
o It will be reduced by an amount equal to the product of (x)
the quantity of untreated water that would have been delivered
but for service interruptions by the Borough and (y) the rate
for untreated water delivered from the South River; and
o Starting with 8th contract year and with six months' prior
written notice, we have the right to reduce the minimum bill
amount for any contract year by reducing the annual quantity
of water to be provided by up to 15%. Starting with the 21st
contract year we may reduce the annual quantity to be
delivered without limit.
SERVICE INTERRUPTIONS
In the event that there is an interruption in the delivery of untreated
water attributable to a break in the infrastructure, the Borough will provide a
shortfall notice and the Borough and we will agree on the best way to repair the
infrastructure and restore service. If the Borough fails to restore service
within a reasonable period of time, we may, at our expense, contract with
contractors reasonably approved by the Borough to remedy the interruption.
INFRASTRUCTURE AND REAL ESTATE RIGHTS
THE LAGOON WATER PIPELINE, LAGOON PUMPING STATION AND SAYREVILLE INTERCONNECTION
NUMBER 2
The Borough will design, at our expense, the Lagoon Water Pipeline,
Lagoon Pumping Station and Sayreville Interconnection Number 2 in conformance
with standard water system practice. The Borough is responsible for obtaining,
at our expense, all necessary government approvals. The Borough and we will
cooperate to obtain, at our expense, the real estate rights necessary for the
construction, operation and maintenance of the Lagoon Water Pipeline, Lagoon
Pumping Station and Sayreville Interconnection Number 2. If necessary, the
Borough will exercise its power of eminent domain to obtain the necessary real
estate rights. Upon completion of the Lagoon Water Pipeline, Lagoon Pumping
Station and Sayreville Interconnection Number 2, we will execute, without being
compensated by the Borough, the documents as are necessary to evidence the
Borough's ownership of those facilities. We are responsible for selecting a
contractor to construct the Lagoon Water Pipeline, Lagoon Pumping Station and
Sayreville Interconnection Number 2 and must pay for all costs associated with
the construction and construction inspection of those facilities.
OPERATION AND MAINTENANCE OF INFRASTRUCTURE
The Borough will operate and maintain all infrastructure necessary to
supply the untreated water to the project boundary. We will reimburse the
Borough for its associated maintenance and replacement costs.
We will own and maintain metering equipment to measure the delivery of
untreated water from each source to the point of delivery and will transmit a
signal of the measurements to the Borough, which will use the information to
compile billing invoices. At least once every five years, or more often if
requested by either party, we shall test the
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metering equipment. If the tests reveal that the metering equipment is
inaccurate, the equipment must be recalibrated or replaced and a billing
adjustment may be made.
The Borough will own and maintain metering equipment, which it may
elect to read monthly, to confirm the quantities of untreated water supplied
from each source. The equipment will be tested and recalibrated or replaced if
necessary in the same manner that our metering equipment is tested.
INFRASTRUCTURE STUDIES AND ADDITIONS
We will pay for the actual cost, subject to a mutually agreed upon cap,
of infrastructure studies to determine the costs and benefits of (i) installing
a new pipeline and (ii) improving the existing South River intake structure. We
will have the right to pay for the upgrades, improvements and/or new
infrastructure that may be identified as necessary or desirable by the studies
in exchange for the benefits allowed with their implementation. Other water
users that benefit from the improvements will pay a pro-rata portion of the
costs of the improvements.
CAPITAL IMPROVEMENTS
If the Borough or we reasonably determines that capital improvements to
the infrastructure are required, the party will notify the other party and the
parties will meet in good faith to determine the scope of the capital
improvements. We will pay for our costs and expenses arising from the capital
improvements as well as those of the Borough. If we damage either infrastructure
or capital improvements, we will restore the damaged portions thereof or pay the
Borough to restore the damaged portions.
ADDITIONAL OBLIGATIONS OF THE PARTIES
ADDITIONAL OBLIGATIONS OF THE BOROUGH
The Borough will use its best efforts to either (i) amend its existing
permit, which limits pumping from the Lagoons to 1,000,000 gallons of water per
day or (ii) obtain or change any other permits necessary to allow it to meet its
obligations under the water supply agreement. The Borough will provide us with
written invoices by not later than the 15th of each month. The amounts due under
the invoices will be due within 30 days of receipt. The Borough will provide us
and the financing parties with escorted access to any infrastructure or other
property owned by the Borough to which we or the financing parties reasonably
request access.
OUR ADDITIONAL OBLIGATIONS
We will provide the Borough with notice of any violation by the Borough
of applicable government approvals related to the delivery of untreated water.
Not later than the 15th day of each month, we will provide the Borough with a
detailed invoice listing any amounts due to us under the water supply agreement.
FORCE MAJEURE
If either party is unable to carry out any obligation under the water
supply agreement due to an event of force majeure, the water supply agreement
will remain in effect but the obligation will be suspended for the period
necessitated by the force majeure, as long as:
o the affected party gives the other party written notice within
48 hours of the occurrence of the force majeure;
o the suspension of performance is of no greater scope and no
longer than required by the force majeure; and
o the non-performing party uses its best efforts to remedy its
inability to perform.
TERM
The water supply agreement has a term of 30 years with an option to
extend for up to four additional five year terms. The agreement may be
terminated by us and by the Borough under some circumstances including; (i) our
failure to deliver a commencement notice on or prior to December 31, 2003; (ii)
the occurrence of a bankruptcy event affecting the other party; and (iii)
failure of a party to perform a material obligation within the time contemplated
and the continuation of the failure for a period of 30 days or more.
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ROLE OF THE INDEPENDENT ENGINEER
Stone & Webster Management Consultants, Inc. will initially serve as
the independent engineer in accordance with the indenture.
Under a consulting services agreement with us, and in accordance with
the indenture, the independent engineer is responsible for confirming the
reasonableness of statements and projections made in specified certificates
required to be provided, including with respect to
o satisfaction of certain requirements under the construction
agreement;
o the cost of and occurrence of the completion of rebuilding,
repairing or restoring of our facility following an event of
loss;
o under specified circumstances, the calculation of debt service
coverage ratios and the consistency of assumptions made in
connection with the calculations;
o whether any termination, amendment or modification of any
project contract would reasonably be expected to have a
material adverse effect; and
o specified tests required for the issuance of additional debt.
The trustee may remove the independent engineer if at any time the
independent engineer becomes incapable of acting or is, or is reasonably likely
to be, adjudged bankrupt or insolvent or a receiver is appointed for, or any
public officer will take charge or control of, the independent engineer or its
property or its affairs for the purpose of rehabilitation, conservation or
liquidation, and will appoint a successor independent engineer. Within 30 days
of receipt by the trustee of a written notification from us to the effect that
the independent engineer has failed to carry out its obligations in a timely
manner, and in other circumstances, the trustee must remove the independent
engineer and appoint a successor independent engineer from those engineers then
listed on a schedule to the indenture. We will pay for all services performed by
the independent engineer and its reasonable costs and expenses related to the
services.
If we and the independent engineer are in dispute in respect of a
notice, plan, report or certificate and we are unable to resolve the dispute
within seven days of the independent engineer expressing its disagreement with
the notice, plan, report or certificate, a single independent engineer will be
designated to consider and decide the issues raised by the dispute. The
selection of the third-party engineer will be made from the list of engineers
described below. We must designate the third-party engineer from the list not
later than the third day following the expiration of the seven-day period
described above and the designation will become effective in three days. Within
three days of the designation of a third-party engineer, we and the independent
engineer will submit to the third-party engineer a notice setting forth in
detail the person's position in respect of the issues in dispute. The notice
will include supporting documentation, if appropriate.
The third-party engineer must complete all proceedings and issue his
decision with regard to the issues in dispute as promptly as reasonably
possible, but in any event within 10 days of the date on which he is designated
as third-party engineer, unless the third-party engineer reasonably determines
that additional time is required in order to give adequate consideration to the
issues raised. In the case the third-party engineer must state in writing his
reasons for believing that additional time is needed and will specify the
additional period required, which period will not exceed 10 days without our
agreement.
If the third-party engineer determines that the position set forth in
the independent engineer's notice is correct, it must so state and must state
the corrective actions to be taken by us. In that case, we will promptly take
the corrective actions. We will thereafter bear all costs which may arise from
actions taken under the third-party engineer's decision. If the third-party
engineer determines that the position described in the independent engineer's
notice is not correct, it must so state and must state the appropriate actions
to be taken by us. In this case, we will take such actions and for purposes of
the indenture, the independent engineer and the trustee will be deemed to have
approved, confirmed, concurred in or consented to the notice, plan, report,
certificate or budget in dispute. The decision of the third-party engineer will
be final and non-appealable. We will bear all reasonable costs incurred by the
third-party engineer in connection with this dispute resolution mechanism.
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The third-party engineer will be chosen from the list of qualified
engineers set forth in a schedule to the indenture. The list will also be used
by the trustee to choose a successor independent engineer. At any time either we
or the trustee may remove a particular engineer from the list by obtaining the
other person's reasonable consent to the removal. However, neither we nor the
trustee may remove a name or names from the list if the removal would leave the
list without at least two names, unless, at the same time, we and the trustee
reasonably agree to the addition of one or more names to the list. During
January of each year, we and the independent engineer will review the current
list of third-party engineers and give notice to the trustee of any proposed
additions to the list and any intended deletions. Intended deletions will
automatically become effective 30 days after the trustee received notice unless
the trustee makes a written objection within 30 days and so long as deletions do
not leave the list fewer than two names. Proposed additions to the list will
automatically become effective 30 days after the trustee received notice unless
the trustee makes a written objection within 30 days. We may add a new name or
names to the list of third-party engineers at any time so long as that no person
will be added to the list or authorized to act as third-party engineer unless
the person is a competent firm of professional engineers or consultants with a
national reputation.
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DESCRIPTION OF THE EXCHANGE BONDS
GENERAL
The following is a summary description of certain specific provisions
of the exchange bonds. These provisions discussed below are equally applicable
to both the outstanding bonds and the exchange bonds. You may obtain a complete
description of each provision of the bonds and the indenture by requesting
copies from the trustee. Unless otherwise specified, the description below
applies to each series of the bonds.
We will issue the bonds under the indenture and will offer the bonds as
set forth below. Copies of the indenture and the other financing documents are
available for inspection during normal business hours at the offices of the
trustee. We will issue the bonds in fully registered form without coupons and in
denominations of $100,000 and any integral multiple of $1,000 in excess thereof.
The indenture provides for the issuance of the bonds and any future
senior secured indebtedness pursuant to a supplemental indenture as may be
authorized from time to time in accordance with the indenture. Any other series
of debt issued by us under the indenture may be issued pursuant to a
supplemental indenture on terms established by us subject to the indenture. See
"SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Indenture--AMENDMENTS,
MODIFICATIONS."
The exchange bonds will be direct obligations of ours and will be
secured by the collateral in the same manner as the outstanding bonds.
PRINCIPAL AMOUNT, INTEREST RATE AND STATED MATURITY
We will issue Series A exchange bonds in the aggregate principal amount
of $224,000,000. The Series A bonds will bear interest at a rate of 8.54% per
annum and will mature on November 30, 2019. We will issue Series B exchange
bonds in the aggregate principal amount of $160,000,000. The Series B bonds will
bear interest at a rate of 9.20% per annum and mature on November 30, 2029.
PAYMENT OF INTEREST AND PRINCIPAL
We will pay interest on the bonds quarterly in arrears on each February
28, May 31, August 31 and November 30, to the registered owners on the
immediately preceding record date, as the information appears on our register.
The respective record dates are February 1, May 1, August 1 and November 1.
We will pay principal on the bonds in installments quarterly on each
February 28, May 31, August 31 and November 30, commencing August 31, 2002, for
the Series A bonds and February 28, 2019 for the Series B bonds, to the
registered owners on the immediately preceding record date as follows:
SERIES A BONDS
<TABLE>
<CAPTION>
YEAR FEBRUARY 28 MAY 31 AUGUST 31 NOVEMBER 30 ANNUAL TOTAL
---- ----------- ------ --------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
2002 0.0000% 0.0000% 0.5400% 0.5400% 1.0799%
2003 0.2082% 0.2082% 1.1799% 1.1799% 2.7761%
2004 0.1751% 0.1751% 0.9922% 0.9922% 2.3346%
2005 0.1698% 0.1698% 0.9621% 0.9621% 2.2638%
2006 0.2378% 0.2378% 1.3474% 1.3474% 3.1704%
2007 0.3066% 0.3066% 1.0562% 1.0562% 2.7257%
2008 0.4079% 0.4079% 1.4051% 1.4051% 3.6260%
2009 0.8383% 0.8383% 1.9561% 1.9561% 5.5887%
2010 0.9396% 0.9396% 1.8444% 1.8444% 5.5679%
2011 0.9937% 0.9937% 1.9506% 1.9506% 5.8887%
2012 1.3031% 1.3031% 2.1718% 2.1718% 6.9498%
2013 1.2872% 1.2872% 2.1453% 2.1453% 6.8648%
2014 1.3728% 1.3728% 2.2879% 2.2879% 7.3214%
</TABLE>
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<TABLE>
<S> <C> <C> <C> <C> <C> <C>
2015 1.8153% 1.8153% 2.5854% 2.5854% 8.8013%
2016 1.8536% 1.8536% 2.6399% 2.6399% 8.9870%
2017 1.9740% 1.9740% 2.8115% 2.8115% 9.5711%
2018 2.3269% 2.3269% 3.3141% 3.3141% 11.2819%
2019 0.9751% 0.9751% 1.6252% 1.6252% 5.2007%
100.00%
</TABLE>
SERIES B BONDS
<TABLE>
<CAPTION>
YEAR FEBRUARY 28 MAY 31 AUGUST 31 NOVEMBER 30 Annual Total
---- ----------- ------ --------- -----------
<S> <C> <C> <C> <C> <C> <C>
2019 1.9180% 1.9180% 2.3442% 2.3442% 8.5244%
2020 3.4608% 3.4608% 4.9290% 4.9290% 16.7796%
2021 3.6665% 3.6665% 6.1109% 6.1109% 19.5548%
2022 1.1946% 1.1946% 1.1946% 1.1946% 4.7784%
2023 1.4740% 1.4740% 1.4740% 1.4740% 5.8959%
2024 1.6322% 1.6322% 1.6322% 1.6322% 6.5290%
2025 1.6048% 1.6048% 1.6048% 1.6048% 6.4192%
2026 1.6957% 1.6957% 1.6957% 1.6957% 6.7829%
2027 1.8993% 1.8993% 1.8993% 1.8993% 7.5972%
2028 2.0449% 2.0449% 2.0449% 2.0449% 8.1797%
2029 2.2398% 2.2398% 2.2398% 2.2398% 8.9590%
100.00%
</TABLE>
At our direction, the trustee will round principal amounts to be
redeemed to the nearest $1,000.
Interest will be computed on the basis of a 360-day year comprised of
twelve 30-day months and, for any period shorter than a full month, on the basis
of the actual number of days elapsed. Interest on the bonds will accrue from the
most recent date to which interest has been paid or, if no interest has been
paid, from the date of original issuance.
PAYMENT AND PAYING AGENTS
Principal, make-whole premium, if any, and interest in respect of the
bonds will be paid at the paying agent's office in the County of New York, The
City of New York. The trustee is also the principal paying agent and transfer
agent. The bonds may be presented for payment of principal at the office of any
paying agent. Payments in respect of principal of the bonds will be made only
against surrender of the bonds. Payment in respect of interest on any interest
payment date with respect to any bond will be made to the person in whose name
the bond is registered on February 1, May 1, August 1 and November 1, each date
a "regular record date", as the case may be, immediately preceding the interest
payment date, except that interest payable at maturity will be payable to the
person to whom the principal of the bond is paid. All payments of principal and
interest with respect to certificated bonds, if any, will be made by dollar
check drawn on a bank in The City of New York or, for bondholders of at least
U.S.$1,000,000 in aggregate principal amount of bonds, by wire transfer to a
dollar account maintained by the payee with a bank in The City of New York so
long as written request from the bondholder to that effect designating the
account is received by the trustee or the paying agent no later than the regular
record date immediately preceding the interest payment date. Unless the
designation is revoked, any designation made by that person with respect to
certificated bonds will remain in effect with respect to any future payments
with respect to the certificated bonds payable to that person. Payments with
respect to global bonds will be made to DTC or its nominee, as bondholder, under
DTC's rules, regulations and procedures.
If any payment in respect of a bond is due on a day that is, at any
place of payment, not a business day, the bondholder will not be entitled to
payment of the amount due until the next succeeding business day at the place
and will not be entitled to any further interest or other payment in respect of
any delay.
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The indenture provides that any money paid by us to the trustee for any
payment with respect to the bonds that remains unclaimed for two years will be
repaid to us, and thereafter the bondholder will look only to us for payments
thereof as an unsecured creditor, and we will not be liable to pay any taxes or
other duties in connection with the payment. Unless otherwise provided by
applicable law, the right to receive payment of principal and interest on any
bond, whether at maturity, redemption or otherwise, will become void at the end
of 5 years from the relevant date thereof, or the shorter period as may be
prescribed by applicable law.
Subject to specific limitations described in the indenture, we reserve
the right at any time to vary or terminate the appointment of the securities
registrar or any paying agent or transfer agent with or without cause (upon
giving 30 days' written notice to the securities registrar, the paying agent or
transfer agent, as the case may be, and the trustee) and to appoint another
securities registrar or additional or other paying agents or transfer agents and
to approve any change in the specified offices through which any paying agent or
transfer agent acts so long as we will at all times maintain a securities
registrar, paying agent and transfer agent in the County of New York, The City
of New York.
OPTIONAL REDEMPTION
We may redeem all of the bonds of each series, in whole or in part, at
our option at any time, at a redemption price equal to the outstanding principal
amount plus accrued and unpaid interest to the redemption date, together with
the applicable make-whole premium.
MANDATORY REDEMPTION
EVENT OF LOSS AND EVENT OF EMINENT DOMAIN
If either an event of loss or an event of eminent domain occurs, as
soon as reasonably practicable but no later than the date of receipt by us or
the collateral agent of the resulting casualty proceeds or eminent domain
proceeds, as the case may be, we will make a reasonable good faith determination
as to whether (i) our facility or any portion of it can be rebuilt, repaired or
restored to permit operation of our facility or a portion of it on a
commercially feasible basis and (ii) the casualty proceeds or the eminent domain
proceeds, as the case may be, together with any other amounts that are available
to us for the rebuilding, repair or restoration are sufficient to permit the
rebuilding, repair or restoration of our facility or a portion of it. Our
determination will be evidenced by a certificate as to redemption filed with the
collateral agent which, if we determine that our facility or a portion of it can
be rebuilt, repaired or restored to permit operation thereof on a commercially
feasible basis and that the casualty proceeds or the eminent domain proceeds, as
the case may be, together with any other amounts that are available to us for
the rebuilding, repair or restoration, are sufficient, will also set forth a
reasonable good faith estimate by us of the total cost of the rebuilding, repair
or restoration. In addition, we will deliver to the collateral agent at the time
we deliver the certificate as to redemption a certificate of the independent
engineer, dated the date of the certificate as to redemption, confirming that,
based upon reasonable investigation and review of the determination made by us,
the independent engineer believes the determination and the estimate of the
total cost, if any, described in the certificate as to redemption to be
reasonable.
We must redeem bonds upon an event of loss or an event of eminent
domain:
o In whole, at a redemption price equal to 100% of the principal
amount together with any accrued and unpaid interest through
the redemption date, within 90 days after receipt by the
trustee of casualty proceeds or eminent domain proceeds if our
facility is substantially destroyed and cannot be rebuilt,
repaired or restored to permit operation on a commercially
feasible basis or an event of eminent domain has occurred and
our facility cannot be operated on a commercially feasible
basis, as the case may be. Our obligation to redeem the bonds
upon an event of loss or an event of eminent domain under the
preceding circumstances is not limited to the casualty
proceeds or eminent domain proceeds actually received; and
o In part, at a redemption price equal to 100% of the principal
amount together with any accrued and unpaid interest through
the redemption date, within 90 days after receipt by the
trustee of casualty proceeds or eminent domain proceeds if a
portion of our facility is destroyed or taken but our facility
can be rebuilt, repaired or restored to permit operation on a
commercially feasible basis. The aggregate amount of the bonds
to be redeemed under this paragraph will equal the amount
received by the trustee for the purpose in accordance with the
provision of the collateral agency agreement. The bonds will
not be subject to mandatory redemption when the proceeds not
used for rebuilding, repair or restoration do not exceed $5
million and we certify to the trustee, which certification is
confirmed by the independent engineer, that (i) the proceeds
are not needed for rebuilding, repair or restoration of our
facility or (ii) not using the proceeds for the rebuilding,
repair or restoration of our facility would not reasonably be
expected to result in a material adverse effect.
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Any eminent domain proceeds and casualty proceeds received by the
trustee under the two preceding paragraphs will be deposited in the redemption
subaccount.
UPON RECEIPT OF PERFORMANCE LIQUIDATED DAMAGES UNDER THE CONSTRICTION AGREEMENT
If we receive performance liquidated damages under the construction
agreement, we will, as soon as reasonably practicable, make a reasonable good
faith determination as to whether:
o it is technically feasible to modify, repair or replace any
portion of our facility in order to remedy the circumstances
giving rise to the obligation of Raytheon Engineers to pay the
performance liquidated damages;
o the performance liquidated damages, together with any other
amounts that are available to us for the modification, repair
or replacement, are sufficient to permit the modification,
repair or replacement, including the making of all required
payments of interest and principal on our indebtedness during
the modification, repair or replacement;
o the projected average senior debt service coverage ratio,
after giving effect to the modification, repair or replacement
and the application of the performance liquidated damages to
accomplish the same, during the power purchase agreement term
(taken as one period) and the post-power purchase agreement
period (taken as one period) would be equal to or greater than
the projected average senior debt service coverage ratio set
forth in the base case projections for each period included in
this prospectus; and
o the projected minimum senior debt service coverage ratio,
after giving effect to the modification, repair or replacement
and the application of the performance liquidated damages to
accomplish the same, during the power purchase agreement term
and the post-power purchase agreement period would be equal to
or greater than the projected minimum senior debt service
coverage ratio set forth in the base case projections for each
period included in this prospectus.
Our determination will be evidenced by an officer's certificate,
together with the supporting detail as the collateral agent or the independent
engineer may reasonably request, filed with the collateral agent which, if we
determine that the portion of our facility can be modified, repaired or replaced
and that the other statements described above are true, will also set forth our
reasonable good faith estimate of the total cost of the modification, repair or
replacement. We will deliver to the collateral agent at the time we deliver the
officer's certificate referred to above a certificate of the independent
engineer, dated the date of the officer's certificate, stating that, based upon
reasonable investigation and review of the determinations, assumptions,
conclusions and estimates of costs made by us, the independent engineer believes
the determinations, assumptions, conclusions and estimates of costs described in
the officer's certificate to be reasonable.
If the requirements of the preceding paragraph are satisfied, the
collateral agent will apply the amounts received from Raytheon Engineers to the
payment, or reimbursement to the extent the same have been paid or satisfied by
us of the costs of modification, repair and replacement of that portion of our
facility that requires modification, repair or replacement in order to remedy
the circumstances giving rise to the obligation of Raytheon Engineers to pay the
performance liquidated damages. Upon receipt of an officer's certificate of from
us confirmed by the independent engineer, certifying that
o all modifications, repairs or replacements of that portion of
our facility that requires modification, repair or replacement
in order to remedy the circumstances giving rise to the
obligation of Raytheon Engineers to pay performance liquidated
damages have been completed; and
o the projected debt service coverage ratio tests referred to in
the immediately preceding paragraph continue to be met, the
collateral agent will transfer all remaining proceeds of the
performance liquidated damages to us or to whomever we direct
in writing.
If the requirements of the preceding paragraph are not satisfied, then
we must redeem the bonds:
o in part, at a redemption price equal to 100% of the principal
amount together with any accrued and unpaid interest through
the redemption date, within 90 days after receipt by the
trustee of performance liquidated damages to be used to redeem
a portion of the bonds. The aggregate amount of the bonds to
be redeemed under this paragraph, including accrued and unpaid
interest, is limited to the amount of performance liquidated
damages actually received by the trustee; and
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o any performance liquidated damages under the construction
agreement received by the trustee under the preceding
paragraph will be deposited in the redemption subaccount.
UPON RECEIPT OF PROCEEDS UNDER THE WILLIAMS GUARANTY
If the power purchase agreement is terminated as a result of an event
of default by Williams Energy thereunder and we receive proceeds under the
Williams Guaranty in respect thereof, we must redeem the bonds, in whole or in
part, at a redemption price equal to 100% of the principal amount together with
any accrued and unpaid interest to the redemption date, as soon as reasonably
practicable, but in any event within 90 days of the receipt of the proceeds.
After the payment of specific administrative fees, the aggregate amount of the
bonds to be redeemed under this paragraph, including accrued and unpaid
interest, will equal an amount which is equal to the amount paid under the
guaranty provided by The Williams Companies, Inc. multiplied by a fraction the
numerator of which is the then outstanding principal amount of the bonds and
accrued and unpaid interest and the denominator of which is the principal of and
accrued and unpaid interest on all senior debt including the bonds.
RATINGS
The Series A bonds and the Series B bonds have been rated "BBB-" by
Standard & Poor's and "Baa3" by Moody's. The ratings reflect only the views of
the rating agencies at the time the rating is issued, and any explanation of the
significance of the ratings may only be obtained from the rating agency. We
cannot assure you that the credit ratings will remain in effect for any given
period of time or that the ratings will not be lowered, suspended or withdrawn
entirely by the rating agency, if, in the rating agency's judgment,
circumstances so warrant. Any lowering, suspension or withdrawal of any rating
may have an adverse effect on the market price or marketability of the bonds.
BOOK-ENTRY, DELIVERY AND FORM
The exchange bonds will initially be represented by one or more
permanent global bonds in definitive, fully registered book-entry form that will
be registered in the name of Cede & Co., the global bond holder, as nominee of
DTC. The global bonds will be deposited on behalf of the acquirors of the
exchange bonds represented thereby with a custodian for DTC for credit to the
respective accounts of the acquirors or to the other accounts as they may direct
at DTC. See "THE EXCHANGE OFFER--Procedures for Tendering--BOOK-ENTRY TRANSFER."
THE GLOBAL BONDS
We expect that under procedures established by DTC:
o upon deposit of the global bonds with DTC or its custodian,
DTC will credit on its internal system portions of the global
bonds that must be comprised of the corresponding respective
amounts of the global bonds to the respective accounts of
persons who have accounts with the depositary; and
o ownership of the bonds will be shown on, and the transfer of
ownership thereof will be effected only through, records
maintained by DTC or its nominee, with respect to interests of
persons, or "participants," who have accounts with DTC, and
the records of participants, with respect to interests of
persons other than participants.
So long as DTC or its nominee is the registered owner or holder of any
of the bonds, DTC or the nominee will be considered the sole owner or holder of
the bonds represented by the global bonds for all purposes under the indenture
and under the bonds represented thereby. No beneficial owner of an interest in
the global bonds will be able to transfer the interest except in accordance with
the applicable procedures of DTC in addition to those provided for under the
indenture.
Payments on the bonds represented by the global bonds will be made to
DTC or its nominee, as the case may be, as the registered owner of the global
bonds. Neither we, the trustee nor any paying agent under the indenture 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
bonds or for maintaining, supervising or reviewing any records relating to the
beneficial ownership interest.
We expect that DTC or its nominee, upon receipt of any payment on the
bonds represented by the global bonds, will credit participants' accounts with
payments in amounts proportionate to their respective beneficial interests in
the global bonds as shown in the records of DTC or its nominee. We also expect
that payments by participants to owners of beneficial interests in the global
bonds held through the participants will be governed by standing instructions
and customary practice as is now the case with securities held for the accounts
of customers registered in the names of nominees for the customers. The payment
will be the responsibility of the participants.
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Transfers between participants in DTC will be effected in accordance
with DTC rules and will be settled in immediately available funds.
DTC has advised us that it will take any action permitted to be taken
by a holder of bonds, including the presentation of bonds for exchange as
described below, only at the direction of one or more participants to whose
account the DTC interests in the global bonds are credited and only in respect
of the aggregate principal amount as to which the participant or participants
has or have given the direction. However, if there is an event of default under
the indenture, DTC will exchange the global bonds for certificated securities
that it will distribute to its participants.
DTC has advised us as follows:
o DTC is a limited-purpose trust company organized under the New
York Banking Law, 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 New
York Uniform Commercial Code and a "clearing agency"
registered under the provisions of Section 17A of the Exchange
Act;
o DTC holds securities that its participants deposit with DTC
and facilitates the settlement among participants of
securities transactions, as transfers and pledges in deposited
securities through electronic computerized book-entry changes
in participants' accounts, thereby eliminating the need for
physical movement of securities certificates;
o Direct participants include securities brokers and dealers,
banks, trust companies, clearing corporations and other
organizations;
o DTC is owned by a number of its participants and by the New
York Stock Exchange, Inc., the American Stock Exchange, Inc.
and the National Association of Securities Dealers, Inc.;
o Access to the DTC system is also available to others the as
securities brokers and dealers, banks and trust companies that
clear through or maintain a custodial relationship with a
direct participant, either directly or indirectly; and
o The rules applicable to DTC and its participants are on file
with the SEC.
Although DTC is expected to follow these procedures in order to
facilitate transfers of interests in the global bonds among participants of DTC,
it is under no obligation to perform the procedures, and the procedures may be
discontinued at any time. Neither we nor the trustee will have any
responsibility for the performance by DTC or its direct or indirect participants
of their respective obligations under the rules and procedures governing their
operations.
CERTIFICATED SECURITIES
As of the date of this prospectus, all of the interests in outstanding
bonds are in book-entry form. It is not expected that any outstanding bonds will
be in registered certificated form at the time of the exchange. It is expected
that all outstanding bonds before the exchange, and all bonds outstanding after
the exchange, will be represented by global certificates for bonds in bearer
form held by The Bank of New York as depositary and that DTC will have a
book-entry interest in those bonds. Beneficial interests in those bonds will be
held through participants in DTC acting as securities intermediaries. Therefore,
references in this section to bonds are references to beneficial interests in
the bonds in book-entry form except where the discussion is explicitly about
certificated bonds, and references to owners are to owners of those beneficial
interests.
Interests in the global bonds will be exchanged for certificated
securities if:
o DTC or any successor depositary notifies us that it is
unwilling or unable to continue as depositary for the global
bonds, or DTC ceases to become a "clearing agency" registered
under the Exchange Act, and a successor depositary is not
appointed by us within 90 days;
o an event of default has occurred and is continuing with
respect to the bonds and the registrar has received a request
from DTC or any successor depository to issue certificated
securities within 30 days of the request; and
o we determine not to have the bonds represented by global
bonds.
Upon the occurrence of any of the events described in the preceding
sentence, we will cause the appropriate certificated securities to be delivered.
Neither we nor the trustee will be liable for any delay by DTC or any successor
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depositary or its nominee in identifying the beneficial owners of the related
bonds. Each person may conclusively rely on instructions from DTC or any
successor depositary or the nominee for all purposes, including the registration
and delivery and the respective principal amounts, of the exchange bonds to be
issued.
Owners of outstanding bonds should instruct the brokers, dealers,
commercial banks or trust companies with whom they have securities accounts or
their nominees to tender for them. Exchanges by owners will be represented by an
exchange of global certificates for outstanding bonds held by the depositary for
global certificates for exchange bonds. If fewer than all outstanding bonds are
tendered for exchange, the depositary will hold separate global certificates for
bonds representing the appropriate aggregate amounts of remaining outstanding
bonds and of exchange bonds.
REPLACEMENT
If any bond at any time is mutilated, defaced, destroyed, stolen or
lost, the bond may be replaced at the cost of the applicant, including the
reasonable and duly documented fees and our expenses and the trustee, when it
provides evidence satisfactory to us and the trustee that the bond was
destroyed, stolen or lost, together with an indemnity as the trustee and we may
require. Mutilated or defaced bonds must be surrendered before replacements will
be issued.
SAME-DAY SETTLEMENT AND PAYMENT
The indenture requires that payments in respect of the bonds
represented by the global bonds, including principal, premium, if any, and
interest, be made by wire transfer of immediately available funds to the
accounts specified by the global bond holder. With respect to certificated
bonds, if any, we will make all payments of principal, premium, if any, and
interest by wire transfer of immediately available funds to the accounts
specified by the holders thereof or, if no account is specified, by mailing a
check to each holder's registered address. Secondary trading in long-term bonds
and debentures of corporate issues is generally settled in clearinghouse or
next-day funds. In contrast, bonds represented by the global bonds are expected
to be eligible to trade in the PORTAL market and to trade in DTC's Same-Day
Funds Settlement System, and any permitted secondary market trading activity in
the bonds will, therefore, be required by DTC to be settled in immediately
available funds. We expect that secondary trading in the certificated bonds will
also be settled in immediately available funds.
Because of time zone differences, the securities account of a Euroclear
or Clearstream Banking participant purchasing an interest in global bonds from a
participant in DTC will be credited, and any crediting will be reported to the
relevant Euroclear or Clearstream Banking participant, during the securities
settlement processing day, which must be a business day for Euroclear or
Clearstream Banking, immediately following the settlement date of DTC. DTC has
advised us that cash received in Euroclear or Clearstream Banking as a result of
sales of interests in a global bond by or through a Euroclear or Clearstream
Banking participant to a participant in DTC will be received with value on the
settlement date of DTC but will be available in the relevant Euroclear or
Clearstream Banking cash account only as of the business day for Euroclear or
Clearstream Banking following DTC's settlement date.
LIMITED RECOURSE NATURE OF THE BONDS
All obligations in connection with the bonds are solely ours. The
bondholders will have recourse only to us and the collateral for repayment of
the bonds. No holder of ownership interests in our company or any other
affiliate of ours or any of their respective incorporators, stockholders,
directors, officers or employees will guarantee the payment of the bonds. The
bondholders will have no claim against or recourse to the holders of the
ownership interests in our company or any other affiliate of ours or their
respective incorporators, stockholders, directors, officers or employees by
operation of law or otherwise for the repayment of the bonds.
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SUMMARY OF PRINCIPAL FINANCING DOCUMENTS
The following disclosure is a summary of the material provisions of
the indenture and other financing documents. This summary highlights selected
information from the indenture and other financing documents; however, to
understand all of the terms of the exchange offer you should read the
indenture and other financing documents in their entirety. Capitalized terms
used herein and not otherwise defined in this prospectus have the meanings
given to them in the indenture or the other financing documents.
INDENTURE
ACCOUNTS
INDENTURE ACCOUNTS
The following accounts will be established by the trustee:
o the bond proceeds account,
o the bond payment account, including the interest payment
subaccount, the principal payment subaccount and the
redemption subaccount, and
o the construction interest account.
All amounts from time to time held in each indenture account will be held in the
name of the trustee subject to the lien and security interest granted under the
indenture and in the custody of the depositary bank on behalf of the trustee.
BOND PROCEEDS ACCOUNT
The trustee deposited the net proceeds from the issuance of the
outstanding bonds into the bond proceeds account prior to transferring the
proceeds to the construction account in amounts specified by us on the date of
original issuance of the bonds.
BOND PAYMENT ACCOUNT
The trustee will deposit (i) all funds received by it for the payment
of interest on the bonds into the interest payment subaccount of the bond
payment account for disbursement in accordance with the indenture and (ii) all
funds received by it for the payment of principal on the bonds (including any
funds transferred from the redemption subaccount) into the principal payment
subaccount of the bond payment account for disbursement in accordance with the
indenture.
CONSTRUCTION INTEREST ACCOUNT
The trustee will deposit all funds received by it for the payment of
interest on the bonds then outstanding from and including the date of original
issuance of the bonds to and through the commercial operation date into the
construction interest account. The trustee will disburse from the construction
interest account the amount required to pay interest on the bonds when due,
whether on an interest payment date or upon call for redemption or by
acceleration or otherwise. On the commercial operation date and upon our
delivery to the collateral agent and the trustee of a commercial operation
certificate, the trustee will transfer all funds remaining in the construction
interest account to the bond payment account for deposit in the interest payment
subaccount.
INTEREST PAYMENT SUBACCOUNT, PRINCIPAL PAYMENT SUBACCOUNT AND REDEMPTION
SUBACCOUNT
(a) The trustee is authorized and directed to disburse from the
interest payment subaccount, the amount required to pay interest on the bonds
when due, whether on an interest payment date or upon call for redemption or by
acceleration or otherwise.
(b) The trustee is authorized and directed to disburse from the
principal payment subaccount, the amount required to pay principal on the bonds
when due, whether on a principal payment date or upon call for redemption or by
acceleration or otherwise.
(c) The trustee is authorized and directed to disburse funds from the
redemption subaccount, when amounts on deposit therein equal or exceed
$5,000,000, for the redemption of bonds in accordance with the indenture. The
preceding notwithstanding, the trustee will transfer funds remaining in the
redemption subaccount
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for more than one year and not applied to the redemption of bonds under the
indenture to the principal payment subaccount for application by the trustee in
accordance with the indenture.
AFFIRMATIVE COVENANTS
We will make the following affirmative covenants:
PAYMENT OF PRINCIPAL, PREMIUM, IF ANY, AND INTEREST
We will duly and punctually pay, or cause to be paid, the principal of,
premium, if any, and interest on, and all other amounts payable in respect of,
the bonds in accordance with their terms and the terms of the indenture and of
the related series supplemental indenture.
REPORTING REQUIREMENTS
We will furnish to the senior parties:
(a) unless we are then filing comparable reports pursuant to the
reporting requirements of the Exchange Act, as soon as practicable and in any
event within 60 days after the end of the first, second and third quarterly
accounting periods of each fiscal year of our company, commencing with the
quarter ending June 30, 2000, an unaudited balance sheet of our company as of
the last day of the quarterly period and the related statements of income and
cash flows, and reports of all dividends and other distributions paid to owners
during the quarterly period prepared in accordance with generally accepted
accounting principles and, in the case of second and third quarterly periods,
for the portion of the fiscal year ending with the last day of the quarterly
period, in each case describing in comparative form corresponding unaudited
figures from the preceding fiscal year and accompanied by a written statement of
an authorized representative of our company to the effect that the financial
statements fairly represent our financial condition and results of operations at
and as of their respective dates;
(b) unless we are then filing comparable reports pursuant to the
reporting requirements of the Exchange Act, as soon as practicable and in any
event within 120 days after the end of each fiscal year commencing with the
fiscal year ended December 31, 2000, a balance sheet as of the end of the year
and the related statements of income and cash flow during the year described in
each case in comparative form corresponding figures from the preceding fiscal
year, accompanied by an audit report thereon of a firm of independent public
accountants of recognized national standing;
(c) at the time of the delivery of the financial statements provided
for in clause (a) and (b) above, or at the time of the filing of the comparable
report pursuant to the Exchange Act, an officer's certificate to the effect
that, to the best of the officer's knowledge, (i) we are in compliance with all
of our material obligations under the terms of the project contracts and the
financing documents the non-performance of which has resulted or could
reasonably be expected to result in a material adverse effect and (ii) to the
best of the officer's knowledge, no default or event of default has occurred and
is continuing or, if any default or event of default has occurred and is
continuing, specifying the nature and extent of the default and what action we
are taking or propose to take in response to the default;
(d) each of the following items, which will continue to be delivered
after registration under the Exchange Act:
o promptly after we obtain actual knowledge of the occurrence
of an event of default, written notice of the occurrence of
any event or condition which constitutes an event of default
and our officer's certificate specifically stating that the
event of default has occurred and setting forth the details
of the default and the action which we are taking or
proposes to take with respect thereto;
o promptly after we obtain actual knowledge of the occurrence
of an event of eminent domain, written notice of the
occurrence of any event of eminent domain or any event of
loss and our officer's certificate describing the details of
the event of eminent domain and the action which we are
taking or propose to take with respect to the event of
eminent domain; and
o until the occurrence of the commercial operation date,
within 45 days after the end of each fiscal quarter,
commencing with our quarter ending June 30, 2000, a
quarterly construction report describing the progress of our
facility's construction and expenditure of funds.
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(e) we will furnish or cause to be furnished to the senior parties no
later than six months prior to the expiration of the term of the power purchase
agreement an independent forecast prepared by an independent consultant which
describes projections of (i) electricity prices for the PJM market, or if the
market no longer exists at that time, any successor market or substitute market
as determined in good faith by us which approximates, to the extent practicable,
the region, and (ii) gas prices on a delivered basis to our facility, in each
case on at least an annual basis through the final maturity date for the bonds;
however, if:
o we enter into a replacement power purchase agreement,
effective as of the date that is six months prior to the
expiration of the term of the power purchase agreement and
extending to at least the final maturity date for the bonds;
o the projected senior debt service coverage ratio through the
final maturity date for the bonds, based on the provisions
of the replacement power purchase agreement are greater than
2.0 to 1; and
o the senior unsecured long term debt of the power
purchaser(s) under the agreement(s) is rated at least
investment grade, we will not be required to provide the
forecast referenced herein.
(f) upon the request of any bondholder, or the trustee on behalf of a
holder of a beneficial interest in the bonds, we will furnish the information
specified in paragraph (d)(4) of Rule 144A of the Securities Act to the
bondholder, and holders of beneficial interests in the bonds, to a prospective
purchaser of the bonds, and prospective purchasers of beneficial interests in
the bonds, who is a Qualified Institutional Buyer or Institutional Accredited
Investor or to the trustee for delivery to the bondholder or prospective
purchaser of the bonds, as the case may be, unless, at the time of the request,
we are subject to the reporting requirements of Section 13 or 15(d) of the
Exchange Act.
(g) All information provided to the senior parties under clauses (a),
(b), (c) and (d) above will also be provided by the trustee (i) to the
bondholders and (ii) to holders of beneficial interests in the bonds or
prospective purchasers of the bonds or beneficial interests in the bonds upon
written request to the trustee, which may be a single continuing request. We
will furnish the trustee, upon its request, with sufficient copies of all the
information to accommodate the requests of the holders of beneficial interests
in the bonds.
(h) The information specified in paragraphs (a), (b), (c), (d) and (e)
above will be provided to each rating agency concurrently with its delivery to
the senior parties.
(i) Once we have registered the bonds under the Exchange Act, we will
continue to file with the SEC all the reports as required by the Exchange Act
for the term of the bonds.
INSURANCE
We will maintain or cause to be maintained in accordance with the terms
of the indenture the following insurance coverages: (i) during construction of
our facility, builder's risk, with full replacement cost coverage, delayed
start-up providing coverage for at least 18 months of projected continuing
expenses and debt service, with not greater than a 60-day deductible,
comprehensive general liability, workers' compensation and employer's liability,
automobile liability and umbrella liability; and (ii) subsequent to transfer of
care, custody and control of our facility to us, all risk property and boiler
and machinery insurance, covering full replacement cost, subject to reasonable
and customary deductibles and sublimits, business interruption, providing
coverage of 18 months of gross earnings less non-continuing expenses,
comprehensive general liability, workers' compensation and employer's liability,
automobile liability and umbrella liability, with a minimum limit of $9 million
per occurrence and aggregate. All policies of insurance except workers'
compensation and automobile liability policies will name the collateral agent
and Williams Energy as additional insureds. If at any time any of the required
insurance will no longer be available on commercially reasonable terms as
confirmed by the independent insurance adviser, we will procure substitute
insurance coverage reasonably satisfactory to the independent insurance advisor
that is the most equivalent to the required coverage and that is available on
commercially reasonable terms.
MAINTENANCE OF EXISTENCE, LIENS AND GOVERNMENTAL APPROVALS
We will at all times:
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o preserve and maintain in full force and effect (i) its existence
as a limited liability company and its good standing under the
laws of the State of Delaware and (ii) its qualification to do
business in each other jurisdiction in which the character of the
properties owned or leased by it or in which the transaction of
its business as conducted or proposed to be conducted makes the
qualification necessary;
o obtain and maintain in full force and effect all governmental
approvals, including maintaining compliance with environmental
laws, and other consents and approvals required at any time in
connection with the construction, maintenance, ownership or
operation of our facility;
o preserve and maintain good and marketable title to its properties
and assets, subject to no liens other than permitted liens; and
o preserve and maintain liens of the senior parties on the
collateral.
OPERATING AND MAINTENANCE
We will, or will cause the operator to, use, maintain and operate our
facility and the site in compliance with generally accepted prudent operating
and maintenance practices and the material provisions of all relevant project
contracts.
COMPLIANCE WITH APPLICABLE LAWS
We will comply with, and will ensure that our facility is constructed
and operated in compliance with, and will make alterations to our facility and
the site as may be required for compliance with, all applicable laws,
environmental laws and governmental approvals, except where noncompliance would
not reasonably be expected to result in a material adverse effect.
PROJECT CONTRACTS; WILLIAMS GUARANTY; OPERATION OF OUR FACILITY
We will (i) perform and observe in all material respects our covenants
and agreements contained in any of our project contracts, (ii) enforce, defend
and protect all of its rights contained in any of our project contracts and
(iii) take all reasonable and necessary actions to prevent the termination or
cancellation of any of our project contracts, except in case of (i) and (ii)
above, where non-performance could not reasonably be expected to have a material
adverse effect.
We will (i) fully enforce our rights under the guaranty provided by the
Williams Companies, Inc. and the power purchase agreement with respect to
substitute security under the circumstances provided for therein and (ii) will
not, without the consent of bondholders holding a majority in outstanding
principal amount of the bonds, make a written demand for or take any legal
action under the guaranty provided by the Williams Companies, Inc. if, as a
result of payments made pursuant to the demand or legal action by us, the
aggregate amount available under the guaranty provided by the Williams
Companies, Inc. would be less than or equal to the principal amount of the then
outstanding senior debt, including the undrawn portions of the maximum amounts
of the working capital agreement and any debt service reserve letter of credit.
We will (i) in the event of any termination of the power purchase agreement,
fully enforce our rights under the guaranty provided by the Williams Companies,
Inc., (ii) use any amounts obtained under the guaranty provided by the Williams
Companies, Inc. to redeem the bonds in accordance with the indenture and to pay
principal and interest on our other senior debt in accordance with the financing
documents and in each case in accordance with the collateral agency agreement
and (iii) upon any payment event of default or other event of default under the
power purchase agreement, exercise our rights to terminate the power purchase
agreement in accordance with its terms.
We will (i) exercise all of our rights under the operations agreement
to terminate the agreement if (a) a bankruptcy event in respect of the operator
has occurred and is continuing and (b) the operator has failed to perform any
material obligation under the operations agreement and (ii) exercise our rights
under the operations agreement to cause the operator to terminate the services
agreement under the terms of that agreement if (a) a bankruptcy event in respect
of The AES Corporation has occurred and is continuing and (b) The AES
Corporation has failed to perform any material obligation under the services
agreement.
ANNUAL BUDGET
Not less than 30 days prior to (i) the anticipated commercial operation
date, and thereafter (ii) the
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commencement of each fiscal year, we will provide to the senior parties and the
rating agencies an annual budget. The first annual budget will cover the period
from the commercial operation date through the end of the fiscal year in which
the commercial operation date occurs, and if the period consists of less than
six months, for the immediately succeeding fiscal year. Each annual budget will
specify the estimated sales of capacity and energy under the power purchase
agreement and any replacement power purchase agreement and all other sales of
capacity and energy, the estimated rates and revenues for each category of the
sales, all operating and maintenance costs, a manpower forecast, a periodic
inspection, maintenance and repair schedule, a description of all required
capital expenditures and the underlying operating assumption and implementation
plans for the fiscal year covered by the annual budget. We will operate and
maintain our facility, or cause our facility to be operated and maintained, in
accordance with the annual budget other than deviations resulting from operating
requirements under our project contracts or prudent operating and maintenance
practices.
INSURANCE REPORT
Within 30 days after the end of each fiscal year, we will submit to the
senior parties and each rating agency that currently is rating any of the bonds
then outstanding a certificate (i) listing all insurance being carried by, or on
behalf of us under the indenture and (ii) certifying that all insurance policies
required to be maintained under our project contracts and the indenture are in
full force and effect and all premiums therefor have been fully paid.
INSPECTION
The senior parties will have the right, upon reasonable advance written
notice to us to inspect our facility and the site from time to time so long as
we will have the right to specify reasonable dates and times for any the
inspection in order to avoid any material interference with operation of our
facility.
CONSTRUCTION OF THE FACILITY
We will cause the construction of the facility to be prosecuted and
completed with diligence and continuity, except for interruptions provided for
in the construction agreement or due to events of force majeure, which events of
force majeure we will use our commercially reasonable efforts to mitigate, in a
good and workmanlike manner and in accordance with sound, generally accepted
building and engineering practices, all material applicable governmental
requirements and the construction agreement. We will at all times cause a
complete set of the current and, when available, as-built plans, and all
supplements, relating to the facility to be maintained on the site or Raytheon
Engineers' offices and available for inspection by the independent engineer.
CONTRACTOR PERFORMANCE TESTS; FINAL ACCEPTANCE
The independent engineer will have the right to witness and verify the
performance tests required by the construction agreement. We will not, without
the prior written confirmation by the independent engineer, either (i) grant the
final acceptance certificate to Raytheon Engineers under the construction
agreement or (ii) elect to effect final acceptance under the construction
agreement.
CASUALTY PROCEEDS; EMINENT DOMAIN PROCEEDS
We will cause all casualty proceeds and eminent domain proceeds to be
deposited in the restoration account under the collateral agency agreement.
PAYMENT OF TAXES AND IMPOSITIONS
We will pay or cause to be paid, before any fine, interest or penalty
is imposed, all Impositions. If, under any applicable law, any Impositions may
at our option be paid in installments, whether or not interest accrues on the
unpaid balance thereof, we will have the right so long as no event of default
then exists, to exercise the option and to pay or cause to be paid the
Impositions and any accrued interest in installments as they fall due and before
any fine, penalty, further interest or cost may be added.
We will pay all taxes and other governmental charges, including stamp
taxes, assessed by any governmental authorities and imposed on the collateral
agent, its successors or assignees, by reason of the collateral agent's
ownership of the mortgage or the other security documents or payable by either
us or the collateral agent upon any modification, amendment, extension and/or
consolidation. We will also pay any tax imposed directly or indirectly on the
mortgage in lieu of a tax on the mortgaged property or any part thereof, whether
by reason of:
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(i) the passage after the date of the mortgage of any law of the State
of New Jersey deducting from the value of real property for the purposes of
taxation any lien,
(ii) any change in the laws for the taxation of mortgages or debts
secured by mortgages for state or local purposes,
(iii) a change in the means of collection of any tax, or
(iv) any tax, now or hereafter assessed against the mortgage or
assessed against, or withheld from, any payments made by us under the indenture.
We will not claim or demand or be entitled to any credit or credits for
the payment of any Impositions, and no deduction will otherwise be made or
claimed from the taxable value of the mortgaged property, or any part thereof,
by reason of the mortgage.
PRESERVATION OF LIEN OF MORTGAGE
We will (i) preserve our right, title and interest in and to the
mortgaged property and will warrant and defend the same against any and all
claims and demands whatsoever, (ii) continue to have full power and lawful
authority to encumber and convey the mortgaged property as provided in the
mortgage, and (iii) maintain and preserve the priority of the lien of the
mortgage until all of the obligations under the financing documents are paid and
performed in full.
PRESERVATION OF OWNERSHIP OF AES URC
We will maintain our ownership of 100% of the ownership interests in
AES URC while any bonds are outstanding.
NEGATIVE COVENANTS
We will make the following negative covenants:
LIMITATIONS ON ADDITIONAL INDEBTEDNESS
We will not create or incur or suffer to exist any indebtedness or
lease obligations except for:
o the bonds;
o indebtedness incurred under the debt service reserve letter of
credit reimbursement agreement or the power purchase agreement
letter of credit reimbursement agreement;
o letters of credit and other financial obligations arising under
our project contracts;
o subordinated debt of our affiliates;
o purchase money obligations incurred to finance discrete items of
equipment not comprising an integral part of our project that
extend only to the equipment being financed and that do not in
the aggregate have annual debt service or lease obligations
exceeding $5 million escalated at the gross domestic product
implicit price deflator;
o trade accounts payable, other than for borrowed money, arising,
and accrued expenses incurred, in the ordinary course of business
so long as the trade accounts payable are payable within 90 days
of the date the respective goods are delivered or the respective
services are rendered;
o obligations in respect of surety bonds or similar instruments in
an aggregate amount not exceeding $5 million at any one time
outstanding;
o any lines of credit for working capital purposes including the
working capital agreement in the maximum amount of $5 million;
o senior debt or subordinated debt, from persons who are not our
affiliates, for required modifications and optional
modifications; however, we may issue (a) senior debt on a parity
basis with the bonds only for required modifications and only if
(1) the projected average and minimum senior debt service
coverage
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ratios, after giving effect to the senior debt, are at least 1.30 to
1.0 and 1.20 to 1.0, respectively, through the end of the power
purchase agreement term, taken as one period, and at least 2.0 to 1.0
and 1.70 to 1.0, respectively, during the post-power purchase
agreement period, taken as one period, or (2) we provide a ratings
reaffirmation from each of the ratings agencies; (b) subordinated debt
for required modifications only if (1)(A) the projected average total
debt service coverage ratio, after taking into account the
subordinated debt, is at least 1.20 to 1.0 through the end of the
power purchase agreement term, taken as one period, and at least 1.65
to 1.0 during the post-power purchase agreement period, taken as one
period, and (B) the projected minimum total debt service coverage
ratio, after giving effect to the subordinated debt, is at least 1.1
to 1.0 through the power purchase agreement term and at least 1.35 to
1.0 during the post-power purchase agreement period, or (2) we provide
a ratings reaffirmation from each of the ratings agencies; or (c)
subordinated debt for optional modifications only if we provide a
ratings reaffirmation from each of the ratings agencies. In the case
of clauses (b) and (c) of the preceding proviso, the final maturity
date of the subordinated debt will not be earlier than the final
maturity date for the bonds and the average life of the subordinated
debt must be no shorter than the average remaining life of the bonds.
RESTRICTED PAYMENTS
We will not make any payments restricted under the indenture unless the
distribution conditions described in the collateral agency agreement have been
satisfied. See "SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency
Agreement--DISTRIBUTION ACCOUNT."
PROHIBITION OF CHANGE IN CONTROL
We will not engage in, or suffer to occur, any change in control, where
change in control means any failure by The AES Corporation, at all times while
bonds are outstanding, to maintain directly or indirectly at least a 51% voting
and economic interest in our company unless prior to giving effect to the
reduction in the voting or economic interest of The AES Corporation in our
company either (i) each of the rating agencies provides a ratings reaffirmation
to the trustee or (ii) the reduction in The AES Corporation's voting or economic
interest has been approved by bondholders holding at least 66-2/3% in aggregate
principal amount of the bonds.
NATURE OF BUSINESS
Neither we nor AES URC will engage in any business other than the
development, financing, construction and operation and maintenance of our
facility as contemplated by our project contracts.
AMENDMENTS TO PROJECT CONTRACTS
We will not, except as otherwise expressly described in the financing
documents, terminate, amend, modify or consent to the termination, amendment or
modification, other than immaterial amendments or modifications as certified by
us, of any of our project contracts to which we are a party, or consent to any
assignment by another party, unless (i) we certify to the senior parties that
the termination, amendment, modification or assignment is not reasonably
expected to result in a material adverse effect and the termination, amendment,
modification or assignment is not reasonably expected to materially increase the
likelihood of the occurrence of a future material adverse effect and (ii) the
independent engineer does not within 10 business days of receipt of the
certificate disagree in writing to the certification provided under clause (i).
We, however, will not (a) amend or modify the power purchase agreement unless in
addition to the requirements of clauses (i) and (ii) above, we certify that the
amendment or modification would not cause our net operating revenues to decrease
by more than 5% and the certification is confirmed by the independent engineer,
(b) except as otherwise expressly set forth in the financing documents,
terminate the power purchase agreement or consent to any release of, assignment
by or change in the identity of Williams Energy unless (1) within 90 days of the
termination or consent resulting from an event of default by Williams Energy
under the power purchase agreement, or prior to any the termination or consent
for any other reason we (A) enter into a replacement power purchase agreement or
(B) provide the senior parties and each of the ratings agencies with a power
marketing plan and (2) we provide to the trustee and the collateral agent a
ratings reaffirmation from each rating agency within the 90-day period or prior
to the termination or consent, as the case may be, or (c) release or modify in
any way the guaranty provided by The Williams Companies, Inc. unless we obtain
substitute security therefor under the power purchase agreement.
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PROHIBITION ON FUNDAMENTAL CHANGES AND DISPOSITION OF ASSETS
We will not enter into any transaction of merger or consolidation,
change our form of organization or our business, liquidate or dissolve
ourselves, or suffer any liquidation or dissolution, except as permitted in the
indenture. We will not amend our governing instruments except where the
amendment could not reasonably be expected to result in a material adverse
effect. We will not purchase or otherwise acquire all or substantially all of
the assets of any other person unless we may maintain ownership interests in
subsidiaries if the subsidiaries are involved solely in owning, leasing,
operating, maintaining or supplying fuel for our facility. In addition, except
as contemplated by our project contracts or permitted under the indenture, or as
authorized by the first and second provisos below, we will not sell, lease (as
lessor) or transfer (as transferor) any property or assets material to the
operation of our facility except in the ordinary course of business to the
extent that the property is worn out or is no longer useful or necessary in
connection with the operation of our facility. Furthermore, we:
o will not sell, lease or transfer any of such property or assets
without the written approval of the collateral agent, if the
aggregate fair market value of all sales, leases and transfers in
the current fiscal year exceeds $5 million escalated at the gross
domestic product implicit price deflator;
o may loan useful spare parts to other electric power generating
facilities owned by an affiliate of ours without prior approval
of the trustee or the collateral agent on the conditions that,
with respect to any spare part whose value is in excess of
$50,000: (i) at the time of the loan the recipient of the spare
part enters into an enforceable obligation to replace the spare
part in kind, or to pay to us an amount equal to the replacement
value of the spare part within 30 days of our demand for the same
and (ii) immediately preceding the loan, we certify to the
collateral agent that the spare part will not be necessary for a
planned outage or for scheduled maintenance of our facility prior
to being replaced, and the certificate is confirmed by the
independent engineer.
LIENS AND PERMITTED LIENS
We will not create or suffer to exist or permit any lien upon or with
respect to any of our properties, other than permitted liens.
Permitted liens means, collectively,
o liens specifically created, required or permitted by the
financing documents;
o liens for taxes which are either not yet due, are due but payable
without penalty or are the subject of a good faith contest by us;
o any exceptions to title which are contained in the title
insurance policy for the site;
o the minor defects, easements, rights of way, restrictions,
irregularities, encumbrances and clouds on title and statutory
liens that do not materially impair the property affected thereby
and that do not individually or in the aggregate materially
impair the value of the security interests granted under the
security documents;
o deposits or pledges to secure statutory obligations or appeals;
release of attachments, stay of execution or injunction;
performance of bids, tenders, contracts (other than for the
repayment of borrowed money) or leases, or for purposes of like
general nature in the ordinary course of business;
o liens in connection with workmen's compensation, unemployment
insurance or other social security or pension obligations;
o legal or equitable encumbrances deemed to exist by reason of the
existence of any litigation or other legal proceeding if the same
is the subject of a good faith contest (excluding any attachment
prior to judgment, judgment lien or attachment in aid of
execution on a judgment); and
o mechanic's, workmen's, materialmen's, construction or other like
liens arising in the ordinary course of business or incident to
the construction or improvement of any property in respect of
obligations which are not yet due or which are the subject of a
good faith contest.
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TRANSACTIONS WITH AFFILIATES
We will not enter into any transactions with our affilliates other than
(i) the operations agreement and the equity subscription agreement, (ii) the URC
documents and (iii) transactions in the ordinary course of business on fair and
reasonable terms no less favorable to us than we would obtain in an arm's length
transaction with a person that is not an affiliate of ours.
CHANGE ORDERS
We will not initiate or approve any change order under the construction
agreement that individually exceeds $5,000,000 or when aggregated with all other
change orders exceeds $10,000,000, unless we certify in writing to the
collateral agent that
(i) the change order is technically feasible,
(ii) the change order is not reasonably expected to materially and
adversely affect the operation or reliability of our facility,
(iii) the implementation of the change order is not reasonably expected
to cause the commercial operation date to occur after June 30, 2003,
(iv) adequate funds are available to us to fund the change orders and
other project costs through the commercial operation date, and
(v) the certification is confirmed by the independent engineer.
EVENTS OF DEFAULT
Events of default, as described in the indenture, will continue to
be an event of default and remain an event of default for whatever reason for
the event of default, whether voluntary or involuntary, affected by question
of law or under open compliance with any applicable law, if and for so long
as it has not been remedied. Events of default include the following:
o We fail to pay any principal, interest or premium, if any,
including any make-whole premium, on a bond when the same becomes
due and payable, whether at scheduled maturity or required
prepayment or by acceleration or otherwise and the failure
continues for 10 or more days; or
o Any representation or warranty made by us in the indenture proves
to have been false or misleading in any respect as of the time
made, confirmed or furnished and the inaccuracy has resulted or
is reasonably expected to result in a material adverse effect and
the circumstances surrounding the misrepresentation continues
uncured for 30 or more days from its discovery; however, if we
commence efforts to cure the factual situation resulting in the
misrepresentation within the 30-day period, we may continue to
effect the cure of the misrepresentation, and the
misrepresentation will not be deemed an event of default, for an
additional 60 days so long as we certify that no other event of
default has occurred and is continuing and we are diligently
pursuing the remedy; or
o We fail to maintain insurance in accordance with the indenture;
or
o We fail to perform or observe covenants or agreements in the
indenture with respect to the following: maintenance of existence
and governmental approvals; nature of business; compliance with
applicable laws; amendments to project contracts; prohibition on
fundamental changes and disposition of assets; liens;
indebtedness; or restricted payments; and the failure will
continue unremedied for more than 30 days after we have actual
knowledge of the failure; or
o A change in control occurs; or
o We fail to perform or observe any of our covenants or agreements
contained in any other provision of the indenture not referred to
above and the failure will continue unremedied for more than 30
days after we have actual knowledge of the failure; however, if
we commence efforts to remedy the default within the 30-day
period and are diligently attempting to remedy the default, and
certify to the trustee the steps we are taking, we may continue
to effect the remedy of the default, and the default will not be
deemed an
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event of default, for an additional 60 days so long as we certify
that no other event of default has occurred and is continuing and
we are diligently pursuing the remedy; or
o We or, so long as The AES Corporation has any outstanding
obligations under any acceptable credit support, The AES
Corporation or, so long as AES Red Oak, Inc. has any outstanding
obligations under the equity subscription agreement, AES Red Oak,
Inc. or, so long as AES URC has any interest in the site or the
facility, AES URC shall
(i) apply for or consent to the appointment of, or the
taking of possession by, a receiver, custodian,
trustee or liquidator of ourselves or of all or
substantially all of our property,
(ii) admit in writing our inability, or be generally
unable, to pay our debts as the debts become due,
(iii) make a general assignment of the benefit of our
creditors,
(iv) commence a voluntary case under the Bankruptcy Reform
Act of 1978, Title II of the United Stated Code, or
the Bankruptcy Code,
(v) file a petition seeking to take advantage of any law
relating to bankruptcy, insolvency, reorganization,
winding-up or the composition or readjustment of
debts,
(vi) fail to controvert in a timely and appropriate manner,
or acquiesce in writing to, any petition filed against
the person in an involuntary case under the Bankruptcy
Code, or
(vii) take any corporate or other action for the purpose of
effecting any of the preceding.
o A proceeding or case shall be commenced without our application
or consent or, so long as The AES Corporation has any outstanding
obligations under any acceptable credit support, The AES
Corporation or, so long as AES URC has any interest in the site
or the facility, AES URC or, so long as AES Red Oak, Inc. has any
outstanding obligations under the equity subscription agreement,
AES Red Oak, Inc. in any court of competent jurisdiction, seeking
(i) its liquidation, reorganization, dissolution, winding-up or
the composition or readjustment of debts, (ii) the appointment of
a trustee, receiver, custodian, liquidator or the like of the
person under any law relating to bankruptcy, insolvency,
reorganization, winding-up or the composition or adjustment of
debts, and the proceeding or case shall continue undismissed, or
any order, judgment or decree approving or ordering any of the
foregoing shall be entered and continue unstayed and in effect,
for a period of 90 or more consecutive days, or any order for
relief against the person will be entered in an involuntary case
under the Bankruptcy Code (each event described herein and in the
immediately preceding bullet point shall be referred to as a
"Bankruptcy Event"); or
o A final and non-appealable judgment or judgments for the payment
of money in excess of $15,000,000 shall be rendered against us
and the same remain unpaid or unstayed for a period of more than
60 or more consecutive days from the date it is entered; or
o An event of default has occurred and is continuing under the debt
service reserve letter of credit and reimbursement agreement, the
power purchase agreement letter of credit and reimbursement
agreement or any other indebtedness of ours the holder of which,
or an agent or trustee therefor, is a party to the collateral
agency agreement, other than indebtedness incurred under the
indenture, or an event of default has occurred and is continuing
in respect of any other indebtedness of ours having a principal
amount exceeding $15,000,000; or
o With respect to any project contract:
(i) the project contract is declared unenforceable by a
governmental authority,
(ii) any other party thereto denies it has a material
obligation under the project contract or
(iii) any other party thereto defaults in respect of its
obligations under the project contract, and in the
case of each event described in clause (i), (ii) or
(iii), the event would be likely to result in a
material adverse effect; however, none of the events
will be an event of
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default under the indenture if within 180 days (90 days
in respect of the power purchase agreement or the
construction agreement) from the occurrence of the
event (A) the other party resumes performance or enters
into an alternative agreement with us or (B) we enter
into a replacement contract or contracts with another
party or parties which (1) contains, as certified by
us, substantially equivalent terms and conditions or,
if the terms and conditions are no longer available on
a commercially reasonable basis, the terms and
conditions then available on a commercially reasonable
basis and (2) either (I) we provide to the trustee and
the collateral agent a ratings reaffirmation from each
rating agency or (II) we certify that it would, after
giving effect to the alternative agreement, maintain a
projected minimum senior debt service coverage ratio in
any year during the remaining term of the bonds equal
to or greater than the lesser of (x) the projected
minimum annual senior debt service coverage ratio which
would have been in effect had performance under the
original project contract continued and (y) 1.25 to 1.0
or (C) in the case of the power purchase agreement, we
deliver to the trustee and collateral agent a power
marketing plan and either (1) certify that based on
projections prepared on a reasonable basis and based on
an independent forecast prepared at the time, the
average and minimum annual senior debt service coverage
ratio through the final maturity date of any
outstanding bonds will at least equal the projections
as described in the prospectus at the time of the
issuance of the bonds, or (2) obtain a ratings
reaffirmation from each ratings agency; or
o Any grant of a lien contained in the security documents shall
cease to be effective to grant a perfected lien to the trustee or
the collateral agent on a material portion of the collateral
described in the security document with the priority purported to
be created thereby; however, we will have 10 days from actual
knowledge to remedy any cessation; or
o The construction of the facility is permanently abandoned; or
o AES Red Oak, Inc. fails to perform or breaches any of its payment
obligations under the equity subscription agreement and such
failure or breach continues for 10 business days or more; or
o Any acceptable credit provider fails to perform or breaches any
of its payment obligations under any acceptable credit support
and such failure or breach continues for 10 business days or
more.
REMEDIES UPON DEFAULT
(a) If one or more events of default has occurred and is continuing,
then:
o in the case of a bankruptcy event, the entire principal amount of
the bonds then outstanding, all interest accrued and unpaid
thereon, and all premium payable under the bonds and the
indenture, if any, will automatically become due and payable
without presentment, demand, protest or notice of any kind, all
of which are waived; or
o in the case of any other event of default, the trustee may, and
upon written direction of the bondholders of not less than
33-1/3% of the aggregate principal amount of the bonds then
outstanding, the trustee will, by notice to us, declare the
entire principal amount of the bonds, all interest accrued and
unpaid thereon, and all premium payable under the bonds and the
indenture, if any, to be due and payable, whereupon the same will
become due and payable without presentment, demand, protest or
further notice of any kind, all of which are waived; or
o the trustee will (if the required bondholders request in writing
to the trustee) direct the collateral agent (to the extent
permitted under the collateral agency agreement) to take
possession of all the collateral and, under the collateral agency
agreement, to sell the collateral, as and to the extent permitted
under the collateral agency agreement.
(b) If an event of default occurs and is continuing and is known to
the trustee (as described in the indenture), the trustee will mail to each
bondholder a notice of the event of default within 30 days after the occurrence
thereof. Except in the case of an event of default in payment of principal of or
interest on any bond, the
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trustee may withhold the notice to the bondholders if a committee of its trust
officers in good faith determines that withholding the notice is in the interest
of the bondholders.
(c) At any time after the principal of the bonds becomes due and
payable upon a declared (but not an automatic) acceleration as provided in the
indenture, and before any judgment or decree for the payment of the money so
due, or any portion thereof, is entered, the bondholders of not less than a
majority in aggregate principal amount of the bonds then outstanding, by written
notice to us and the trustee, may rescind and annul the declaration and its
consequences if:
o there will have been paid to or deposited with the trustee a sum
sufficient to pay
(A) all overdue installments of interest on the bonds,
(B) the principal of and premium, if any, on any bonds that
have become due otherwise than by the declaration of
acceleration and interest thereon at the respective
rates provided in the bonds for late payments of
principal or premium,
(C) to the extent that payment of the interest is lawful,
interest upon overdue installments of interest at the
respective rates provided in the bonds for late
payments of interest, and
(D) all sums paid or advanced by the trustee under the
indenture and the reasonable compensation, expenses,
disbursements, and advances of the trustee, its agents
and counsel, and
o all events of default, other than the non-payment of the
principal of the bonds that has become due solely by such
acceleration, have been remedied or waived as provided in the
indenture.
No such rescission will affect any subsequent default or impair any
right consequent thereon.
Except as otherwise specifically provided in the indenture, the
holders of a majority in principal amount of the bonds will have the right to
direct the time, place and method of conducting any proceeding for any remedy
available to the trustee or exercising any power conferred on the Trustee; so
long as (i) the direction does not conflict with any law or the indenture or the
collateral agency agreement and (ii) the trustee may take any other action
deemed proper by the trustee which is not inconsistent with the direction.
All rights and remedies available to the bondholders, or to the
trustee with respect to the collateral, or otherwise under the security
documents, are subject to the collateral agency agreement, including the ability
to enforce any remedy and the limitations on the trustee's ability to vote the
interests represented by the bonds.
AFFILIATE CURE RIGHTS
Any affiliate of ours will, at its option, have the right, but not the
obligation, to remedy any events of default for which remedies are applicable.
TRUSTEE
The Bank of New York will act as the trustee under the indenture. The
indenture provides that the trustee will not be liable in connection with the
performance of its duties thereunder, except for its own gross negligence, bad
faith or willful misconduct. The trustee may become the owner of any bonds, with
the same rights it would have if it were not the trustee, and may carry any
monies held by the trustee on deposit with itself and will not have any
liability for interest upon the monies.
The trustee may resign at any time and be discharged from its duties
and obligations under the indenture by giving written notice to us and upon
appointment and acceptance of a successor. The trustee may be removed at any
time by the holders of not less than a majority in principal amount of the bonds
then outstanding. We or any holder who has been a bona fide holder of a bond for
at least six months, may remove the trustee if
(i) the trustee fails to comply with the provisions of the indenture
regarding conflicting interests,
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(ii) the trustee ceases to be eligible as required under the indenture
and fails to resign after written request,
(iii) the trustee becomes bankrupt or insolvent, or
(iv) the trustee fails to carry out its obligations in a timely
manner.
Notwithstanding the foregoing, no resignation or removal of the
trustee and no appointment of a successor trustee will become effective until
the acceptance of appointment by the successor trustee.
Except during the continuance of an event of default under the
indenture, the trustee will perform only the duties as are specifically
described in the indenture. During the existence of an event of default, the
trustee will exercise the rights and powers vested in it by the indenture, and
use the same degree of care and skill in their exercise as a prudent person
would exercise or use under the circumstances in the conduct of such person's
own affairs.
The indenture contains limitations on our rights to obtain payments of
claims in specific cases or to realize on specific property received by us in
respect of any such claim as security or otherwise. The trustee is permitted to
engage in other transactions with us; however, if it acquires any "conflicting
interest," as defined in the indenture, it must eliminate such conflict or
resign as trustee under the indenture.
SUPPLEMENTAL INDENTURES
SUPPLEMENTAL INDENTURES AND AMENDMENTS WITHOUT THE CONSENT OF BONDHOLDERS
Without the consent of the bondholders, we and the trustee, at any
time and from time to time, may enter into one or more supplemental indentures
in form reasonably satisfactory to the trustee and may amend any of the other
financing documents, for any of the following purposes:
o to establish the form and terms of bonds of any series permitted
by the indenture;
o to evidence the succession of another entity to us and the
assumption by any successor of our covenants under the bonds and
the indenture;
o to evidence the succession of a new trustee or a co-trustee or
separate trustee under the indenture;
o to add to our covenants, for the benefit of the bondholders, or
to surrender any right or power conferred upon us under the
indenture;
o to convey, transfer and assign to the trustee, and to subject to
the lien of the indenture, additional properties or assets and to
correct or amplify the description of any property at any time
subject to the lien of the indenture or to assure, convey and
confirm unto the trustee any property subject or required to be
subject to the lien of the indenture;
o to facilitate the issuance of bonds in uncertificated form;
o to change or eliminate any provision of the indenture; however,
if such change or elimination would adversely affect the
interests of the holders of any bonds of any series, the change
or elimination will become effective with respect to the series
only when no bond of the series remains outstanding;
o to comply with changes in applicable law; however, no such
amendment or supplement will result in a material adverse effect
or otherwise adversely affect the interests of the holders of any
bonds in any material respect;
o to make any changes required by Standard & Poor's or Moody's or
any other nationally recognized securities rating agency as a
condition to the issuance or maintenance of the then current
rating on the bonds or any series thereof so long as any such
change will not result in a material adverse effect or otherwise
adversely affect the interests of the holders of any bonds in any
material respect; or
o to remedy any ambiguity, to correct or supplement any provision
of the indenture that may be defective or inconsistent with any
other provision of the indenture, or to make any other provisions
with respect to matters or questions arising under the indenture
so long as the action will not adversely affect the interest of
the bondholders of any series in any material respect.
SUPPLEMENTAL INDENTURES WITH THE CONSENT OF BONDHOLDERS
With the consent of the bondholders of not less than a majority in
aggregate principal amount of the bonds
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of all series then outstanding, we and the trustee may, and the trustee will,
enter into one or more supplemental indentures for the purpose of adding any
provisions to or changing in any manner or eliminating any of the provisions of,
the indenture. No such supplemental indenture may, however, without the consent
of the bondholder of each outstanding bond directly affected thereby: (i) change
the stated maturity of any bond (or, if the principal thereof is payable in
installments, the stated maturity of the installment), or of any payment of
interest, or the dates or circumstances of payment of premium, if any, on, any
bond, or change the principal amount or the interest or any premium payable upon
the redemption, or change the place of payment where, or the coin or currency in
which, any bond or the premium, if any, or the interest is payable, or impair
the right to institute suit for the enforcement of the payment of principal or
interest on or after the stated maturity (or, in the case of redemption, on or
after the redemption date) or such payment of premium, if any, on or after the
date such premium becomes due and payable; or
(ii) except for permitted liens, permit the creation of any lien prior
to or, equally with the lien of any of the security documents with respect to
any of the collateral, or terminate the lien on any collateral or deprive any
bondholder of the security afforded by the lien of the indenture; or
(iii) reduce the percentage in principal amount of the bonds then
outstanding, the consent of whose bondholders is required for any such
supplemental indenture, or the consent of whose bondholders is required for any
waiver, of compliance with specified provisions of the indenture or specified
defaults under the indenture and their consequences, provided for in the
indenture, or reduce the requirements for quorum or voting; or
(iv) modify specified provisions of the indenture relating to remedies
following an event of default, except to increase the percentage of the
principal amount of the bonds required to waive past defaults.
SATISFACTION AND DISCHARGE
We may terminate the indenture by delivering all bonds then
outstanding to the trustee for cancellation and by paying all sums payable under
the indenture and by effecting delivery of officer's certificates and an opinion
of counsel stating that all conditions precedent have been satisfied.
In addition to the preceding, bonds then outstanding will, prior to
the stated maturity, be deemed to be paid, and our indebtedness will be deemed
to be satisfied and discharged, at any time all the conditions set forth below
have been satisfied:
(i) we have irrevocably deposited with the trustee, in trust, monies
or permitted investments in an amount which will be sufficient to pay when due,
without reinvestment, the principal of and premium, if any, and interest due and
to become due on the bonds then outstanding on or prior to the stated maturity
of the final installments of principal thereof or upon redemption or prepayment;
(ii) we have delivered to the trustee, a company order stating that
monies deposited with the trustee or in permitted investments will be held by
the trustee, in trust, as provided in the indenture;
(iii) in the case of redemption or prepayment of the bonds then
outstanding, the notice requisite to the validity of such redemption or
prepayment has been given, or irrevocable authority will have been given by us
to the trustee to give the notice; and
(iv) there has been delivered to the trustee an opinion of counsel to
the effect that as a result of a change in applicable law after the date of the
indenture the satisfaction and discharge of our indebtedness with respect to the
bonds then outstanding will not be deemed to be, or result in, a taxable event
with respect to holders of bonds then outstanding for purposes of United States
Federal income taxation unless the trustee will have received documentary
evidence that the bondholders either are not subject to, or are exempt from,
United States Federal income taxation.
COLLATERAL AGENCY AGREEMENT
PROJECT ACCOUNTS
The following trust accounts will be established and created with and
in the name of the collateral agent: construction account; revenue account;
operating and maintenance account; debt service reserve account; debt service
reserve letter of credit reimbursement fund; power purchase agreement letter of
credit reimbursement fund;
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restoration account; major maintenance reserve account; fuel conversion payment
volume rebate account; subordinated debt account; and distribution account.
COLLECTION OF PROJECT REVENUES
We will arrange for the direct payment to the collateral agent of all
project revenues, and to the extent any such project revenues are at any time
received by us prior to the commercial operation date, we will hold all such
revenues and other amounts in trust for the collateral agent and will transfer
to the collateral agent for deposit of the project revenues in the construction
account in each case as soon as reasonably practical but no later than three
business days after receipt, duly endorsed, if necessary, to the collateral
agent.
ADVANCES
Notwithstanding any other provision of the collateral agency
agreement to the contrary, we may, by delivering an officer's certificate to
the collateral agent, withdraw cash on deposit in or credited to any of the
project accounts listed above, other than the construction account and the
distribution account; however, if at the time of the making of such advance:
(i) no default or event of default has occurred and is continuing and our
officer's certificate will so certify and (ii) our obligations to repay the
advances will be supported by acceptable credit support. The collateral agent
may conclusively rely on the officer's certificate certifying that all
conditions for withdrawals from the applicable accounts have been met. We
will repay immediately or cause to be repaid any advances to the extent that
the funds on deposit in the applicable accounts are insufficient to make the
necessary withdrawals and transfers. In addition, we will cause to be repaid
immediately the aggregate amount of all advances upon the occurrence of
o a default in the payment of principal of, premium, if any, or
interest on the bonds or under the debt service reserve letter of
credit and reimbursement agreement, the power purchase agreement
letter of credit and reimbursement agreement or the working
capital agreement,
o any event of default,
o any default by an acceptable credit provider in respect of its
obligations under its acceptable credit support, or
o our failure to provide, within five business days, acceptable
credit support in respect of our obligations to repay advances
upon the failure of the acceptable credit provider to meet the
requirements of the definition thereof. Any amounts so repaid
will be allocated to and deposited in the project accounts, other
than the construction account and the distribution accounts, to
which the repayment is required to be made as directed by us in
an officer's certificate.
CONSTRUCTION ACCOUNT
On the date of original issuance of the bonds, the net proceeds of the
sale of the bonds received by us were transferred to the collateral agent for
deposit in the construction account.
On the date of original issuance of the bonds, upon receipt by the
collateral agent of a complete and properly executed requisition signed by us,
the contents of which will be confirmed by the independent engineer, the
collateral agent will apply the amounts in the construction account to the
payment, or reimbursement, to the extent the same have been paid or satisfied by
us, of project costs. Each requisition, except for any requisition with respect
to the initial drawing on the date of original issuance of the bonds, will be
submitted to the collateral agent no less than three business days in advance of
the drawing date and will include the following:
(i) a certification that the proceeds thereof will be used solely to
pay project costs in accordance with the indenture;
(ii) a certification that work performed to date has been
satisfactorily performed in a good and workmanlike manner and according to the
construction agreement;
(iii) a statement that undisbursed funds in the construction account,
together with funds available under the equity subscription agreement and other
available sources of funds, are reasonably expected to be sufficient to complete
our facility according to the construction agreement by June 30, 2003;
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(iv) a statement that no default or event of default under the
indenture, the debt service reserve letter of credit and reimbursement
agreement, the power purchase agreement letter of credit and reimbursement
agreement or the working capital agreement has occurred and is continuing;
(v) a statement that all proceeds of prior requisitions have been
expended or applied under the provisions of the financing documents and that the
items for which amounts are requested in the subject requisition have not been
the basis for a previous requisition;
(vi) a certification that required insurance, material governmental
approvals and necessary project contracts are in full force and effect; and
(vii) a certification that specified representations set forth in the
indenture are true and correct in all material respects.
If we cannot satisfy the requirements of clauses (i) or (v) of the
preceding paragraph, the collateral agent will not release funds from the
construction account in respect of the requisition until the clauses are
satisfied. If we cannot satisfy clauses (ii), (iii), (iv), (vi) or (vii) of the
preceding paragraph, but the collateral agent receives a requisition signed by
us, the contents of which will be confirmed by the independent engineer, (a)
specifying and identifying the failure, and the causes for the failure, to
satisfy the requirements of clauses (ii), (iii), (iv), (vi) or (vii) of the
preceding paragraph and (b) certifying that (1) the requirements of clauses (i)
and (v) of the preceding paragraph are satisfied, (2) there exists no bankruptcy
event in respect of us, AES URC or AES Red Oak, Inc. and (3) each of the
construction agreement, the operations agreement, the power purchase agreement,
required insurance policies and material governmental approvals needed for
construction of our facility is in full force and effect, then the collateral
agent will disburse funds in accordance with the requisition. Within fifteen
(15) days of receipt of such requisition, the collateral agent will give notice
to the senior parties describing the failure and specifying that, unless the
required senior parties give notice to the collateral agent of their objection
to payment of further requisitions containing any such specified failures, the
collateral agent will continue to make payment of such requisitions from
available funds in the construction account, unless the collateral agent has
received, by the second business day prior to the time of payment of such
requisition, notice of objection from the required senior parties.
Notwithstanding the foregoing, the collateral agent will not release
funds from the construction account in respect of a requisition if a Trigger
Event will have occurred and be continuing until the collateral agent determines
that such Trigger Event is no longer continuing or the required senior parties
give instructions to the collateral agent as to application of funds.
PREPAYMENT OF CONSTRUCTION AGREEMENT
We have the right to prepay the fixed-price of the construction
agreement by requisitioning a portion of the proceeds of the sale of the bonds
to pay a discounted fixed-price amount reduced by payments previously made
according to the schedule of payments described in the construction agreement.
As a condition to the construction agreement prepayment, Raytheon Engineers will
be required to provide us with one or more letters of credit meeting certain
criteria set forth in the financing documents. The amount available to be drawn
under such letters of credit will be reduced from time to time upon submission
of a requisition by us specifying, among other things, that the applicable
portions of work required to be completed under the construction agreement have
been completed in accordance with such contract. The collateral agent will be
entitled to draw on such letters of credit upon the occurrence of certain
events, including, but not limited to, a default by Raytheon Engineers or a
Trigger Event under the financing documents.
PAYMENTS ON COMMERCIAL OPERATION DATE
Not later than 10 days after receipt by the collateral agent of our
commercial operation certificate, the contents of which will be confirmed in
writing by the independent engineer, certifying, among other things, that (i)
all conditions to the commencement of commercial operation under the power
purchase agreement have been satisfied, (ii) the power purchase agreement letter
of credit has been reduced in accordance with the power purchase agreement,
(iii) all permits then required have been obtained and (iv) no default or event
of default is continuing, the collateral agent will, after retaining in the
construction account the amount, if any, specified by us as necessary to pay
project costs which are not then due and payable, transfer all remaining funds
in the construction account, plus the base equity contribution, to the extent
not already made, and to the extent necessary any other amounts available
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under the equity subscription agreement to fund items first through fifth below,
by wire transfer to the following accounts and recipients in the following order
of priority:
FIRST, to the operating and maintenance account, an amount, to the
extent available, as specified by us but in any event, no less than one-month's
non-fuel operating and maintenance costs to the working capital provider an
amount equal to principal and interest on any working capital loans made prior
to commercial operation date;
SECOND, to the bond payment account, an amount, to the extent
available, as specified by us for funding of the interest payment subaccount and
principal payment subaccount;
THIRD, to the debt service reserve account, an amount, to the extent
available, equal to the debt service reserve account required balance to the
extent not already funded or provided through a debt service reserve letter of
credit;
FOURTH, if applicable, to the power purchase agreement letter of
credit provider, an amount, to the extent available, equal to the principal of
and interest on any power purchase agreement letter of credit loans outstanding
on the commercial operation date;
FIFTH, to the major maintenance reserve account, an amount, to the
extent available, as specified by us equal to any initial deposit required
therein; and
SIXTH, to the revenue account, any remaining amounts.
PAYMENTS DURING OPERATING PERIOD
After the transfer specified in the above paragraphs regarding
payments on the commercial operation date and upon receipt by the collateral
agent of, not less than three business days prior to the date of the proposed
transfer, our officer's certificate detailing the amounts to be paid, the
collateral agent will transfer all remaining funds in the revenue account by
wire transfer in the following order of priority:
FIRST, (i) as and when required, to the working capital agent, an
amount certified by us as the amount, if any, then payable in respect of
principal of or interest on loans, and in respect of commitment fees, under the
working capital agreement; and (ii) as and when requested, to the operating and
maintenance account, the amount certified by us as necessary for payment of
operating and maintenance costs;
SECOND, on a monthly basis, (i) to the trustee and the collateral
agent, any amounts certified by us as the amounts then due and payable in
respect of trustee claims and collateral agent claims, respectively; (ii) to any
debt service reserve letter of credit provider, any amounts certified by us as
the amounts then due and payable in respect of debt service reserve letter of
credit provider claims; (iii) to any power purchase agreement letter of credit
provider, any amounts certified by us as the amounts then due and payable in
respect of power purchase agreement provider claims; and (iv) to the working
capital agent, any amounts certified by us as the amounts then due and payable
in respect of working capital agent claims; however, if funds in the revenue
account are insufficient on any date to make the payments specified in this
paragraph SECOND, distribution of funds will be made ratably based on the amount
owing to the specified recipients;
THIRD, on a monthly basis, (i) to the trustee, for deposit in the
interest payment subaccount, an amount equal to one-third of the interest
becoming due on the bonds on the next succeeding bond payment date; (ii) to
the debt service reserve letter of credit reimbursement fund, (a) an amount
equal to one-third of the interest becoming due on any debt service reserve
letter of credit loan on the next succeeding bond payment date, plus
one-third of any fees becoming due under the debt service reserve letter of
credit and reimbursement agreement on the next succeeding bond payment date,
(b) an amount equal to one-third of the interest becoming due on any debt
service reserve bond on the next succeeding bond payment date and (c) an
amount equal to one-third of the interest becoming due on any debt service
reserve letter of credit term loan on the next succeeding bond payment date;
and (iii) to the power purchase agreement letter of credit reimbursement
fund, an amount equal to one-third of the interest becoming due on any power
purchase agreement letter of credit loan on the next succeeding bond payment
date, plus one-third of any fees becoming due under the power purchase
agreement letter of credit and reimbursement agreement on the next succeeding
bond payment date; however, if funds in the revenue account are insufficient
on any date to make the payments specified in this paragraph THIRD,
distribution of funds will be made ratably to the specified recipients;
FOURTH, on a monthly basis, (i) to the trustee, for deposit in the
principal payment subaccount, an amount
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equal to one-third of the principal becoming due on the bonds on the next
succeeding bond payment date; (ii) to the debt service reserve letter of credit
reimbursement fund, (a) an amount equal to one-third of the principal becoming
due on any debt service reserve bond on the next succeeding bond payment date,
and (b) an amount equal to one-third of the principal becoming due on any debt
service reserve letter of credit term loan on the next bond payment date; and
(iii) to the power purchase agreement letter of credit reimbursement fund, an
amount equal to one-third of the principal becoming due on any power purchase
agreement letter of credit loan on the next succeeding bond payment date;
however, if funds in the revenue account are insufficient on any date to make
the payments specified in this paragraph FOURTH, distribution of funds will be
made ratably based on the amount owing to the specified recipients;
FIFTH, on a monthly basis, first, to the debt service reserve
provider, an amount equal to the outstanding principal amount of any debt
service reserve letter of credit loans that have not been converted to debt
service reserve term loans or debt service reserve bonds, and second, to the
collateral agent for deposit in the debt service reserve account, an amount
necessary to fund the debt service reserve account up to the debt service
reserve account required balance, taking into account any amounts remaining
available to be drawn under the debt service reserve letter of credit; however,
if amounts available for drawing under the debt service reserve letter of credit
are not being reinstated to the full extent of payments made to the debt service
reserve provider and funds in the revenue account are insufficient on any date
to make the payments specified in this paragraph FIFTH, distribution of funds
will be made ratably to the specified recipients;
SIXTH, on a monthly basis, to the major maintenance reserve account,
amounts necessary to cause the balance thereof to be equal to the minimum
balance required at such time under the annual budget;
SEVENTH, on a monthly basis, to us for payment by us to Williams
Energy, the amount, if any, certified by us as required to make any non-dispatch
payments, as defined in the power purchase agreement, to Williams Energy under
the power purchase agreement;
EIGHTH, on a monthly basis, to the fuel conversion payment volume
rebate account, an amount equal to one-twelfth of the amount specified by us
that would be owed to Williams Energy at the end of the then current fiscal year
under the power purchase agreement;
NINTH, on a monthly basis, if any third-party subordinated debt is
outstanding, to the subordinated debt account, (x) an amount equal to one-third
or one-sixth (depending on the interest payment schedule of the debt) of the
interest becoming due on the third-party subordinated debt on the next
succeeding interest payment date for the debt, PLUS (y) one-third or one-sixth,
depending on the amortization schedule of the debt, of the principal becoming
due on the third-party subordinated debt on the next applicable principal
payment date;
TENTH, on a monthly basis, to Raytheon Engineers, an amount equal to
any subordinated bonuses payable to Raytheon Engineers under the construction
agreement; and
ELEVENTH, on a monthly basis, to the distribution account, any
remaining amounts for payment of distributions to holders of ownership
interests, including any payment in respect of principal or interest then due on
affiliate subordinated debt so long as the distribution conditions described in
the collateral agency agreement are satisfied.
When making the transfers specified above, each transfer will be
adjusted as necessary, taking into account investment gains or losses in such
project account or indenture account and further adjusting the transfers by the
amount of any prior over-fundings or any prior shortfalls in such project
account or indenture account, to ensure that the aggregate amounts so
transferred to the project accounts or indenture accounts are sufficient to pay
the amount due and payable from the project accounts and indenture accounts on
the applicable payment date.
DEBT SERVICE RESERVE ACCOUNT
After its issuance in accordance with the provisions of the debt
service reserve letter of credit and reimbursement agreement, the collateral
agent will hold the debt service reserve letter of credit as security agent
for the trustee and the debt service reserve letter of credit provider to the
extent of its interest therein. Upon the occurrence of the earlier of the
commercial operation date or the guaranteed provisional acceptance date, the
debt service reserve account will be funded, if necessary, from monies
available in the construction account for that purpose in an amount up to the
debt service reserve account required balance. Subsequent to the commercial
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operation date, the debt service reserve account will be funded, if necessary,
from monies transferred from the revenue account. When determining (i) the
amount, if any, required to be deposited into the debt service reserve account
from time to time or (ii) whether the debt service reserve account has deposited
therein the debt service reserve account required balance, amounts on deposit in
the debt service reserve account will be aggregated with the amount available to
be drawn under the debt service reserve letter of credit.
When there are insufficient monies in the bond payment account on any
bond payment date to pay the interest or principal then due on the bonds, the
collateral agent will, upon receipt prior to such bond payment date of our
officer's certificate in the following order of priority: FIRST, withdraw monies
on deposit in the debt service reserve account; and SECOND, draw on the debt
service reserve letter of credit in accordance with the terms and provisions
thereof up to the amount available for the purpose thereunder, in each case, to
the extent necessary to make the interest or principal payment on the bonds and
transfer the monies to the trustee for deposit in the bond payment account for
application against the payment.
If the collateral agent receives a written notice from us stating that
there has been a reduction in the long-term debt rating of the debt service
reserve letter of credit provider below the required rating, or if a responsible
officer of the collateral agent otherwise becomes aware of the reduction, and
the debt service reserve letter of credit has not been replaced within the time
period specified therefor, the collateral agent will draw on the debt service
reserve letter of credit in the amount necessary to fund the debt service
reserve account up to the debt service reserve account required balance, as
certified in our officer's certificate delivered to the collateral agent,
calculated without aggregating the amount available to be drawn under the debt
service reserve letter of credit but taking into account amounts then on deposit
in or credited to the debt service reserve account, whereupon the collateral
agent will deposit the proceeds of the drawing in the debt service reserve
account.
If the collateral agent receives a notice from the debt service
reserve letter of credit provider stating that the debt service reserve
letter of credit provider will terminate the debt service reserve letter of
credit on the date specified in the notice, the collateral agent will, within
three business days of receipt of the notice, draw on the debt service
reserve letter of credit in an amount equal to the amount necessary to fund
the debt service reserve account up to the debt service reserve account
required balance, calculated without aggregating therewith the amount
available to be drawn under the debt service reserve letter of credit but
taking into account amounts then on deposit in or credited to the debt
service reserve account, whereupon the collateral agent will deposit the
proceeds of the drawing in the debt service reserve account and the debt
service reserve letter of credit will automatically terminate.
If a Trigger Event has occurred and is continuing and the
collateral agent has received the written request of the required senior
parties contained in senior party certificates and such notice has not been
rescinded, then the collateral agent, upon receipt of our officer's
certificate setting forth the debt service reserve account required balance,
will draw on the debt service reserve letter of credit in an amount equal to
the amount necessary to fund the debt service reserve account up to the debt
service required balance, calculated without aggregating therewith the amount
available to be drawn under the debt service reserve letter of credit,
whereupon the collateral agent will distribute the proceeds of the drawing,
together with other amounts available in the debt service reserve account, to
the trustee, and the debt service reserve letter of credit will thereupon
automatically terminate.
If, subsequent to the commercial operation date, monies transferred to
the debt service reserve letter of credit provider under clause third under
"Payments During Operating Period" above are insufficient to repay the interest
on any debt service reserve letter of credit loans due or becoming due on the
first day of such month, the collateral agent, upon receipt of a certificate of
an authorized officer of the debt service reserve letter of credit provider
notifying the collateral agent of the existence, and describing the amount, of
the shortfall, within two business days of receipt of the certificate will draw
on the debt service reserve letter of credit in an amount equal to the amount of
the shortfall and transfer the amount to the debt service reserve letter of
credit provider in payment, in whole or part, of the interest on the debt
service reserve letter of credit loans. Notwithstanding the preceding, in no
event will any draw on the debt service reserve letter of credit described in
this paragraph individually or in the aggregate with all other draws, less any
draws previously reimbursed, exceed six months of interest on the maximum stated
amount of the debt service reserve letter of credit.
Unless the debt service reserve letter of credit is not extended or
replaced or unless there has been a debt service reserve letter of credit event
of default as described under "SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Debt
Service Reserve Letter of Credit Reimbursement Agreement," amounts available for
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drawing under the debt service reserve letter of credit will be reinstated
immediately to the extent of any reimbursement of principal of debt service
reserve letter of credit loans, but not debt service reserve bonds or debt
service reserve letter of credit term loans.
If we and the debt service reserve letter of credit provider will
agree to issue or reinstate the debt service reserve letter of credit in an
amount that, when aggregated with cash on deposit in the debt service reserve
account would exceed the debt service reserve account required balance, the
amount of such excess being referred to hereinafter as the "excess amount",
the collateral agent will, within two business days of receipt by the
collateral agent of (i) such reissued or reinstated debt service reserve
letter of credit, and (ii) our officer's certificate, transfer an amount
equal to the excess amount to the revenue account for application in
accordance with the applicable provisions of the collateral agency agreement
so long as the amount of the debt service reserve letter of credit may not
exceed the debt service reserve account required balance.
MAJOR MAINTENANCE RESERVE ACCOUNT
The major maintenance reserve account will be funded on a monthly
basis for amounts necessary to cause the balance of the account to be equal to
the minimum balance required at the time under the annual budget. We will
specify funding of the major maintenance reserve account in light of the annual
budget and will take into account expected costs of major maintenance, including
costs under the maintenance services agreement not included as an operating and
maintenance cost and major maintenance intervals.
When the collateral agent receives an officer's certificate from our
company detailing the amounts to be paid for major maintenance, the collateral
agent will transfer funds in the major maintenance reserve account to us or to
whomever we indicate should receive the payment for the payment of major
maintenance costs and expenses of our facility that are not otherwise paid as
operating and maintenance costs. If amounts in the revenue account and the debt
service reserve account, including amounts available under a debt service
reserve letter of credit, are insufficient to pay operating and maintenance
expenses and debt service on all financing liabilities in items FIRST through
FOURTH above under "Payments During Operating Period," we may, through the
delivery of an appropriate officer's certificate, direct the collateral agent to
apply funds in the major maintenance reserve account to the payment of operating
and maintenance expenses and debt service.
DISTRIBUTION ACCOUNT
The distribution account will be funded from funds transferred from
the revenue account in accordance with the collateral agency agreement. On any
date on which the conditions described below are satisfied, funds on deposit in
or credited to the distribution account may be distributed to, or as directed
by, us for the payment of affiliate subordinated debt, the making of
distributions to the holders of ownership interests in us or any other lawful
purpose, upon receipt by the collateral agent of our officer's certificate
requesting a distribution and certifying that:
(a) all of our project accounts and the bond payment account are
funded to their required levels;
(b) no (i) default or event of default under the indenture, (ii)
default or event of default under the debt service reserve letter of credit
and reimbursement agreement, (iii) default or event of default under the
power purchase agreement letter of credit and reimbursement agreement or (iv)
default under the working capital agreement has occurred and is continuing;
(c) the commercial operation date has occurred and at least one
complete fiscal quarter thereafter has elapsed;
(d) if the requested distribution is to be made during the power
purchase agreement term, (i) the senior debt service coverage ratio for the
preceding four fiscal quarters (or, with respect to any date prior to the first
anniversary of the commercial operation date, for the number of complete fiscal
quarters since the commercial operation date) measured as one period, is greater
than or equal to 1.2 to 1 and (ii) based on projections prepared by us on a
reasonable basis, the projected senior debt service coverage ratio for the
succeeding four fiscal quarters (including the quarter in which the distribution
is to be made) (or, with respect to any date within the 12-month period prior to
the end of the power purchase agreement term, the number of complete fiscal
quarters, if any, until the end of the power purchase agreement term) is
projected to be greater than or equal to 1.2 to 1; and
(e) if the requested distribution is to be made during the post-power
purchase agreement period,
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(i) the senior debt service coverage ratio for the preceding four fiscal
quarters (or, with respect to any date within the first 12 months of the
post-power purchase agreement period, the number of complete fiscal quarters, if
any, since the start of the post-power purchase agreement period) measured as
one period, is greater than or equal to 1.70 to 1.0 (or 1.2 to 1.0 with respect
to the period occurring prior to the end of the power purchase agreement term)
and (ii) based on projections prepared by us on a reasonable basis, the
projected senior debt service coverage ratio for the succeeding eight fiscal
quarters (including the fiscal quarter in which such distribution is to be made)
or, with respect to any date within the 24-month period prior to the final
maturity date for the bonds, the number of complete fiscal quarters, if any,
until the final maturity date for the bonds, in each case measured as one
period, is projected to be greater than or equal to 1.70 to 1 (or 1.2 to 1 with
respect to such period occurring prior to the end of the power purchase
agreement term), each as certified by an authorized officer; however,
o if distributions are blocked because we fail to satisfy the
conditions of clause (e)(ii) above, then in lieu of the coverage
ratio test set forth in such clause, the projected senior debt
service coverage ratio through the final maturity date for the
bonds, measured as one period, will be 1.70 to 1 in order to
satisfy clause (e)(ii) in respect of amounts then on deposit in
the distribution account;
o for purposes of calculating the projected senior debt service
coverage ratios in clause (e)(ii) above, we will use (1) for
electricity prices, either (x) the electricity prices forecasted
in the most recent independent forecast furnished to the trustee,
in each case, during the relevant period of calculation, or (y)
if and to the extent that electricity sales during the relevant
period of calculation are made under one or more power sales
agreements at prices other than prices which are by their terms
market prices, the electricity prices under such power sales
agreements and (2) for gas prices, either (x) the gas prices
forecasted in the most recent independent forecast furnished to
the trustee, in each case, during the relevant period of
calculation, or (y) if and to the extent that gas purchases
during the relevant period of calculation are made under one or
more gas purchase agreements at prices other than prices which
are by their terms market prices, the gas prices under the gas
purchase agreements;
o if, and to the extent that, (1) at least 75% of our facility
capacity is subject to one or more power sales agreements on
terms (other than pricing) substantially similar to the power
purchase agreement, but excluding the provision for gas to be
supplied for fuel conversion services by Williams Energy, or on
commercially reasonable terms (other than pricing) typical of
power sales agreements entered into at the time for the same
term, in each case with a term of not less than one year during
the relevant period of calculation, and (2) at least 75% of the
gas supply for our facility is subject to one or more gas supply
agreements on commercially reasonable terms (other than pricing)
typical of gas supply agreements entered into at the time for the
same term, in each case with a term of not less than one year
during the relevant period of calculation, compliance with such
requirements to be certified by us, then clause (e) above will be
deemed satisfied, if the senior debt service coverage ratio and
the projected senior debt service coverage ratio referred to in
clause (e) are each equal to or greater than 1.30 to 1 for
the portions of the time periods referred to in the clause (e) in
which the agreements were or are to be in effect, as certified by
us; and
o If amounts on deposit in or credited to the revenue account are
insufficient to make the transfers described in priorities FIRST
through EIGHTH above under "Payments During Operating Period,"
amounts on deposit in or credited to the distribution account
will, in the case of amounts necessary to make the transfers
specified in priorities FIRST through SIXTH, and may at our
option, in the case of amounts necessary to make the transfers
specified in priorities SEVENTH through EIGHTH, be transferred to
the revenue account to the extent necessary and applied in
accordance with the collateral agency agreement.
RESTORATION ACCOUNT
All casualty proceeds and eminent domain proceeds will be deposited
into the restoration account. Subject to the provisions described below, the
collateral agent will apply the amounts in the restoration account to the
payment, or reimbursement to the extent the same have been paid or satisfied by
us, of the costs of rebuilding, repair and restoration of our facility or any
part thereof that has been affected by an event of loss or an event of eminent
domain.
The collateral agent is authorized to disburse from the restoration
account the amount required to be paid
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for the repair or replacement of our facility or any part thereof as specified
in the preceding paragraph. The collateral agent is authorized and directed to
issue its checks or transfer funds electronically for each disbursement from the
restoration account, upon receipt of a restoration certificate signed by our
authorized representative, and approved by the independent engineer. No approval
of the independent engineer, however, will be required if less than $5,000,000
is requested under the requisition or requisitions in any one fiscal year. The
collateral agent will be entitled to rely on all certifications and statements
in the restoration certificate. The collateral agent will keep and maintain
adequate records pertaining to the restoration account and all disbursements
therefrom and will file an accounting thereof with us and the independent
engineer within three months following the last business day of each fiscal
year.
If an event of loss or an event of eminent domain will occur with
respect to any collateral, we will (i) diligently pursue all its rights to
compensation against any person with respect to such event of loss or event of
eminent domain, (ii) use our reasonable judgment to compromise or settle any
claim against any person with respect to such event of loss or event of eminent
domain and (iii) hold all amounts of casualty proceeds or eminent domain
proceeds (including instruments) received in respect of any event of loss or
event of eminent domain (after deducting all reasonable expenses incurred by it
in litigating, arbitrating, compromising or settling any claims) in trust for
the benefit of the collateral agent segregated from other funds of ours and will
promptly transfer to the collateral agent for deposit in the restoration account
such casualty proceeds or eminent domain proceeds.
If either an event of loss or an event of eminent domain occurs, as
soon as reasonably practicable but no later than the date of receipt by us or
the collateral agent of eminent domain proceeds or casualty proceeds, as the
case may be, we will make a reasonable good faith determination as to whether
(i) our facility or any portion can be rebuilt, repaired or restored to permit
operation of our facility or a portion on a commercially feasible basis and (ii)
the casualty proceeds or the eminent domain proceeds, as the case may be,
together with any other amounts that are available to us for the rebuilding,
repair or restoration, are sufficient to permit such rebuilding, repair or
restoration of our facility or a portion thereof, including the making of all
required payments of interest and principal on our indebtedness during such
rebuilding, repair or restoration. Our determination will be evidenced by a
certificate as to redemption filed with the collateral agent which, if we
determine that our facility or a portion thereof can be rebuilt, repaired or
restored to permit operation thereof on a commercially feasible basis and that
the casualty proceeds or the eminent domain proceeds, as the case may be,
together with any other amounts that are available to us for such rebuilding,
repair or restoration, are sufficient, will also describe a reasonable good
faith estimate by us of the total cost of such rebuilding, repair or
restoration. We will deliver to the collateral agent at the time it delivers the
certificate as to redemption a certificate of the independent engineer, dated
the date of the certificate as to redemption, stating that, based upon
reasonable investigation and review of the determination made by us, the
independent engineer believes the determination and the estimate of the total
cost described in the certificate as to redemption to be reasonable.
If, following an event of loss or event of eminent domain, the
determination is made that our facility cannot be rebuilt, repaired or restored
to permit operation on a commercially feasible basis or that the casualty
proceeds or the eminent domain proceeds, together with any other amounts that
are available to us for the rebuilding, repair or restoration, are not
sufficient to permit the rebuilding, repair or restoration, all of the casualty
proceeds or the eminent domain proceeds, as the case may be, will be distributed
as provided below.
If, following an event of loss or event of eminent domain, the
determination is made that the entire facility can be rebuilt, repaired or
restored to permit operation on a commercially feasible basis and that the
casualty proceeds or the eminent domain proceeds, together with any other
amounts that are available to us for the rebuilding, repair or restoration, are
sufficient to permit the rebuilding, repair or restoration, all of the casualty
proceeds or the eminent domain proceeds, as the case may be, together with the
other amounts as are available to us for the rebuilding, repair or restoration,
will be deposited in the restoration account and applied as provided below.
If, following an event of loss or event of eminent domain, the
determination is made that a portion of our facility can be rebuilt, repaired or
restored to permit operation on a commercially feasible basis and that the
casualty proceeds or the eminent domain proceeds, together with any other
amounts that are available to us for the rebuilding, repair or restoration, are
sufficient to permit the rebuilding, repair or restoration, (i) an amount equal
to the estimate of the total cost of the rebuilding, repair or restoration
described in the certificate as to redemption filed with the collateral agent
will be deposited in the restoration account and applied as provided below, and
(ii) the
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amount, if any, by which all of the casualty proceeds or the eminent domain
proceeds, as the case may be, exceed the estimate of the total cost will be
distributed as provided below.
If we receive casualty proceeds or eminent domain proceeds, as the
case may be, from an event of loss or an event of eminent domain that do not
exceed in the aggregate $5,000,000 during any fiscal year, we will not have to
make the good faith determination referred to above and the casualty proceeds or
the eminent domain proceeds, as the case may be, will be deposited in the
restoration account and applied for the rebuilding, repair or restoration of our
facility without any approval of the independent engineer.
APPLICATION OF CASUALTY AND EMINENT DOMAIN PROCEEDS AND CONTRACTOR PERFORMANCE
LIQUIDATED DAMAGE AMOUNTS
If the determination is made that all or a portion of our facility is
incapable of being rebuilt, repaired or restored to permit operation on a
commercially feasible basis, all casualty proceeds or eminent domain proceeds
received by the collateral agent and not deposited in the restoration account
will be distributed by the collateral agent within five business days of receipt
in the following order of priorities:
FIRST, to the collateral agent, the working capital agent, the debt
service reserve letter of credit provider, the power purchase agreement letter
of credit provider and the trustee, ratably, in an amount equal to the amounts
owed in respect of the collateral agent claims, the working capital agent
claims, the power purchase agreement provider claims, the debt service reserve
letter of credit provider claims and the trustee claims, respectively, due and
payable as of the date of the distribution;
SECOND, to the senior parties, ratably, an amount equal to the unpaid
amount of all financing liabilities owed to the senior parties, including the
amount required to be applied to a mandatory redemption of the bonds under the
indenture;
THIRD, to the subordinated debt providers, ratably, an amount equal to
the unpaid amount owed to the subordinated debt providers by us under any
subordinated loan agreement; and
FOURTH, to us or our successors or assigns or to whomever may be
lawfully entitled to receive the same or as a court of competent jurisdiction
may direct, any surplus then remaining from the proceeds.
At the time the collateral agent is to make a distribution under
clause SECOND in the immediately preceding paragraph, the collateral agent will
deposit, with the same priority as the distribution, ratably into the debt
service reserve letter of credit reimbursement fund and the power purchase
agreement letter of credit reimbursement fund, as applicable, maintained by the
collateral agent, an amount (in the case of the debt service reserve letter of
credit reimbursement fund) up to the amount equal to the maximum amount
available to be drawn under the debt service reserve letter of credit, taking
into account, without duplication, in the case of the debt service reserve
letter of credit, the maximum amount which may become available to be drawn in
the future by reason of an increase in the debt service reserve account required
balance, and not represented by a debt service reserve letter of credit loan,
debt service reserve letter of credit term loan or debt service reserve bond, an
amount (in the case of the power purchase agreement letter of credit
reimbursement fund) up to the amount available to be drawn under any power
purchase agreement letter of credit, and not represented by a power purchase
agreement letter of credit loan; however, if funds available are insufficient to
make all payments required under clause SECOND of the preceding paragraph and
the required deposits provided for in this sentence, distribution of funds will
be made ratably to the specified recipients. The collateral agent will hold the
funds in the separate funds until receipt of a written notice or notices from
the debt service reserve letter of credit provider and/or the power purchase
agreement letter of credit provider, as the case may be, which notice or notices
will be contemporaneously delivered by the debt service reserve letter of credit
provider and/or the power purchase agreement letter of credit provider to the
other senior parties, to the effect that either (i) a drawing has been made on
its letter of credit or (ii) its letter of credit has expired or terminated
without a drawing being made. Upon receipt of a notice or notices specified in
clause (i) of the preceding sentence, the collateral agent will distribute to
the debt service reserve letter of credit provider and/or the power purchase
agreement letter of credit provider, as the case may be, that proportionate
share of the amount in the relevant separate fund referred to above, equal to
the drawing's proportionate share of the letter of credit collateralized by the
fund. Upon receipt of a notice or notices specified in clause (ii) of the second
preceding sentence, the collateral agent will distribute from the relevant
separate account, in accordance with clauses SECOND, THIRD and FOURTH above and
without regard to this paragraph, to the appropriate persons an amount equal to
the
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amount in the separate fund.
All amounts received by us from Raytheon Engineers in respect of
performance liquidated damages under the construction agreement will be
deposited into a separate account maintained by the depositary bank on behalf of
the collateral agent.
As soon as reasonably practicable following our receipt or the
collateral agent's receipt of performance liquidated damage amounts received by
us from Raytheon Engineers, we will make a reasonable good faith determination
as to whether (i) it is technically feasible to modify, repair or replace that
portion of our facility that requires modification, repair or replacement in
order to remedy the circumstances giving rise to the obligation of Raytheon
Engineers under the construction agreement to pay performance liquidated damage
amounts, (ii) the performance liquidated damage amounts received by us from
Raytheon Engineers, together with any other amounts that are available to us for
the modification, repair or replacement, are sufficient to permit the
modification, repair or replacement, including the making of all required
payments of interest and principal on our indebtedness during the modification,
repair or replacement, (iii) the projected average senior debt service coverage
ratio, after giving effect to the modification, repair or replacement and the
application of the performance liquidated damage amounts received by us from
Raytheon Engineers to accomplish the same, during the power purchase agreement
term (taken as one period) and the post-power purchase agreement period (taken
as one period) is equal to or greater than the projected average senior debt
service coverage ratio described in the base case projections for each period
described in this prospectus and (iv) the projected minimum senior debt service
coverage ratio, after giving effect to such modification, repair or replacement
and the application of the performance liquidated damage amounts received by us
from Raytheon Engineers to accomplish the same, during the power purchase
agreement term and the post-power purchase agreement period, is equal to or
greater than the projected minimum senior debt service coverage ratio for each
period described in the base case projections described in this prospectus.
If the requisite officer's certificate is delivered, the collateral
agent is authorized to disburse from the separate account the amount required to
be paid for the modification, repair or replacement of that portion of our
facility that requires modification, repair or replacement in order to remedy
the circumstances giving rise to the obligation of Raytheon Engineers and
contractors under the construction agreement to pay performance liquidated
damage amounts.
Upon receipt of an officer's certificate, confirmed by the
independent engineer, certifying that all modifications, repairs or
replacements of that portion of our facility that requires modification,
repair or replacement in order to remedy the circumstances giving rise to the
obligation of Raytheon Engineers under the construction agreement to pay
performance liquidated damage amounts received have been completed, the
collateral agent will transfer all funds remaining in such separate account
FIRST, to the revenue account and to the accounts as are specified in the
collateral agency agreement and SECOND, to us or to whomsoever we in writing
direct.
If we cannot provide the officer's certificate to permit the
application of performance liquidated damage amounts received by us from
Raytheon Engineers toward the modification, repair or replacement of that
portion of our facility or the independent engineer fails to confirm the
officer's certificate, the collateral agent will distribute all performance
liquidated damage amounts received by us from Raytheon Engineers ratably, based
on the amount owing to the specified recipient to (i) the trustee in respect of
the amount of the bonds then outstanding for redemption of bonds in accordance
with the indenture, (ii) the debt service reserve letter of credit provider in
respect of the outstanding amount of debt service reserve loans and (iii) the
power purchase agreement letter of credit provider in respect of the outstanding
amount of any power purchase agreement letter of credit loans.
At the time the collateral agent is to make a distribution under the
immediately preceding paragraph, the collateral agent will deposit into two
separate trust accounts to be maintained by the collateral agent, the first to
contain an amount up to the amount available to be drawn under the debt service
reserve letter of credit, taking into account, without duplication, in the case
of the debt service reserve letter of credit, the maximum amount which may
become available to be drawn in the future by reason of an increase in the debt
service reserve account required balance, and not represented by a debt service
reserve letter of credit loan, a debt service reserve term loan or debt service
reserve bond, and the second to contain an amount up to the amount available to
be drawn under any power purchase agreement letter of credit, and not
represented by a power purchase agreement letter of credit loan; however, if
funds available are insufficient to make all payments required under clause
SECOND of the first paragraph
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of this section entitled "Application of Casualty and Eminent Domain Proceeds
and Contractor Performance Liquidated Damage Amounts" and the required
deposits provided for in this sentence, distribution of funds will be made
ratably to the specified recipients. The collateral agent will hold the funds
in such separate account until receipt of a written notice or notices from
the debt service reserve letter of credit provider and/or the power purchase
agreement letter of credit provider, as the case may be, which notice or
notices will be contemporaneously delivered by the debt service reserve
letter of credit provider and/or the power purchase agreement letter of
credit provider to the other senior parties, to the effect that either (i) a
drawing has been made on the letter of credit or (ii) the letter of credit
has expired or terminated without a drawing being made thereunder. Upon
receipt of a notice or notices specified in clause (i) in the preceding
sentence, the collateral agent will distribute to the debt service reserve
letter of credit provider and/or power purchase agreement letter of credit
provider, as the case may be, that proportionate share of the amount in the
relevant separate account referred to above, equal to such drawing's
proportionate share of the letter of credit collateralized by the account.
Upon receipt of a notice or notices specified in clause (ii) in the second
preceding sentence, the collateral agent will distribute from the relevant
separate account to the appropriate persons an amount equal to the amount in
the separate account.
EXERCISE OF RIGHTS UNDER SECURITY DOCUMENTS
The collateral agency agreement provides, among other things, that:
o if a Trigger Event has occurred and is continuing, and only in
such event, upon the written request of the required senior
parties contained in senior party certificates, the collateral
agent, on behalf of the trustee, the debt service reserve letter
of credit provider, the power purchase agreement letter of credit
provider, the working capital agent and any other senior party
that is a party to the collateral agency agreement, will be
permitted to take any and all actions and to exercise any and all
rights, remedies and options which it may have under the security
documents or the collateral agency agreement; however, if the
underlying event which caused the Trigger Event is a bankruptcy
event in respect of us of which the collateral agent has received
written notice, no written request of the required senior parties
will be required in order to permit the collateral agent
following the Trigger Event to take any and all actions and to
exercise any and all rights, remedies and options which it may
have under the security documents or the collateral agency
agreement. The foregoing will not restrict the right of any
senior party to cause the acceleration of the senior debt held by
the senior party or to terminate the debt service reserve letter
of credit or power purchase agreement letter of credit, as the
case may be, or to terminate the obligation of the banks to make
loans under the working capital agreement, or in the case of the
debt service reserve letter of credit provider, to terminate our
ability to cause reinstatement of the debt service reserve letter
of credit or to terminate the obligation of the banks to make
working capital loans.
o the senior parties will give each other and the collateral agent
written notice of the occurrence of an event of default and of a
Trigger Event as soon as practicable after the occurrence
thereof;
o the senior parties acknowledge and agree that all funds held by
the trustee in accordance with Article 5 of the indenture are
held for the benefit of the bondholders;
o the senior parties acknowledge and agree that all funds held in
the debt service reserve account by the collateral agent are held
for the benefit of the trustee, on behalf of the bondholders,
that all funds held in the debt service reserve letter of credit
reimbursement fund are held for the benefit of the debt service
reserve letter of credit provider and all funds held in the power
purchase agreement letter of credit reimbursement fund are held
for the benefit of the power purchase agreement letter of credit
provider;
o no senior party and no class or classes of senior parties will
have any right (a) to direct the collateral agent to take any
action in respect of the collateral other than in accordance with
the collateral agency agreement or (b) to take any action with
respect to the collateral (1) independently of the collateral
agent or (2) other than to direct the collateral agent in writing
to take action in accordance with the collateral agency
agreement; and
o the senior parties acknowledge and agree that if (a) there is an
event of default under the indenture and the event of default is
not caused directly or indirectly by a default or event of
default under the power purchase agreement and (b) they direct
the collateral agent to accelerate the bonds, the collateral
agent, at
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the direction of the required senior parties, will be obligated
to provide Williams Energy the opportunity for 90 days to
purchase our facility for an amount equal to the greater of (x)
the fair market value of our facility and (y) all financing
liabilities due and owing to the senior parties and any
subordinated debt provider, and if Williams Energy offers to
purchase our facility for the amount within the period, the
collateral agent will take actions as required to consummate the
sale as directed by the required senior parties in senior party
certificates.
In giving directions and otherwise exercising rights under the
security documents and the collateral agency agreement, the trustee will vote
(or otherwise represent) that portion of the combined exposure represented by
all bonds then outstanding according to the votes of a majority of the principal
amount of bonds held by responding bondholders. The trustee will not make
requests, give directions or vote on a proportional basis.
APPLICATION OF FORECLOSURE PROCEEDS
Following the receipt of proceeds under the guaranty provided by The
Williams Companies, Inc. as a result of a termination of the power purchase
agreement or a foreclosure or other exercise of remedies following a Trigger
Event, the proceeds of any sale, disposition or other realization by the
collateral agent or by a senior party upon the collateral under the security
documents will be distributed in the following order of priorities:
FIRST, to the collateral agent, the trustee, the working capital
agent, the debt service reserve letter of credit provider and the power purchase
agreement letter of credit provider, ratably, in an amount equal to the amounts
owed in respect of the collateral agent claims, the trustee claims, the working
capital agent claims, the debt service reserve letter of credit provider claims
and the power purchase agreement letter of credit provider claims, respectively,
due and payable as of the date of such distribution;
SECOND, to the senior parties, ratably, based on the amount owing to
the specified recipients, an amount equal to the unpaid amount of all financing
liabilities owed to or required to be deposited for the account of the senior
parties by us;
THIRD, to any subordinated debt providers, ratably, an amount equal to
the unpaid obligations owed to or required to be deposited for the account of
the subordinated debt providers by us under any subordinated loan agreement; and
FOURTH, to us, or our successors or assigns, or to whomever may be
lawfully entitled to receive the same or as a court of competent jurisdiction
may direct, any surplus remaining after giving effect to clauses FIRST, SECOND
and THIRD above.
SUBORDINATION PROVISIONS
Any subordinated debt will be subordinate and subject in right of
payment to the prior payment of all senior debt. Unless and until all senior
debt, whether of principal of and interest and premium or prepayment or
liquidation penalty on the senior debt and fees and expenses incurred with
enforcement of the same, has been paid in full in cash, (i) no payment on
account of any subordinated debt will be made to any subordinated debt provider
by us or by the collateral agent or the depositary bank on behalf of us and (ii)
no subordinated debt provider will ask, demand, sue for, take or receive from us
by set-off or any other manner, or seek any other remedy allowed at law or in
equity against us for breach of our obligations under any instrument
representing subordinated debt.
Upon any insolvency, bankruptcy or similar proceeding relating to us
or our creditors, or any liquidation, dissolution or other winding-up, or any
assignment for the benefit of creditors or any other marshaling of our assets
and liabilities, the senior parties will be entitled to receive payment in full
in cash of all amounts due or to become due on or in respect of all senior debt,
or provision will be made for such payment, before any subordinated debt
provider will be entitled to receive any payment with respect to subordinated
debt.
Subject to the payment in full in cash of all senior debt, the
subordinated debt providers will be subrogated to the rights of the senior
parties to receive payments and distributions of cash, property and securities
applicable to the senior debt until the subordinated debt will be paid in full
in cash.
THIRD-PARTY ENGINEER DISPUTE RESOLUTION
The collateral agency agreement provides that if we and the
independent engineer are in dispute in respect
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of a notice, plan, report or certificate and they are unable to resolve the
dispute within seven days of the independent engineer expressing its
disagreement with the notice, plan, report or certificate, a single independent
third party engineer will be designated to consider and decide the issues raised
by the dispute. For a more detailed description of the third-party engineer
dispute resolution provisions set forth in the indenture, see "ROLE OF THE
INDEPENDENT ENGINEER."
DEBT SERVICE RESERVE LETTER OF CREDIT AND REIMBURSEMENT AGREEMENT
Dresdner Bank AG, acting through its New York Branch, under a debt
service reserve letter of credit and reimbursement agreement has agreed to
provide the debt service reserve letter of credit for use by us in connection
with our project. The financing documents require that the debt service reserve
account be funded in an amount equal to the debt service reserve account
required balance on or before the anticipated commercial operation date.
Accordingly, on the date of original issuance of the bonds we entered into the
debt service reserve letter of credit and reimbursement agreement in order to
satisfy such obligation.
The debt service reserve letter of credit issuing bank issued the debt
service reserve letter of credit on the closing date, for our account in an
amount up to $21.7 million to be held by the collateral agent to serve as a debt
service reserve facility for our project.
The collateral agent will have the right to make drawings on the debt
service reserve letter of credit beginning on the earliest of:
(i) the commercial operation date, and
(ii) the guaranteed provisional acceptance date.
The collateral agent may make drawings under the debt service reserve
letter of credit upon the occurrence of the following events: (i) there being
insufficient monies in the bond payment account on any interest payment date or
principal payment date to pay interest or principal then due, after application
of funds from the debt service reserve account; (ii) upon receipt of a notice
from us that the long-term debt rating of Dresdner Bank, AG is less than the
required rating and the debt service reserve letter of credit has not been
replaced within the time period specified therein; (iii) if a Trigger Event
under the collateral agency agreement will have occurred and be continuing and
the collateral agent has received the written request of the required senior
parties; (iv) upon receipt of a notice from the debt service reserve letter of
credit provider that the debt service reserve letter of credit will not be
extended or replaced by the close of business on the day 45 days prior to its
stated expiration date; and (v) if, subsequent to the commercial operation date,
funds transferred to the debt service reserve letter of credit provider from the
revenue account are insufficient to repay the interest on any debt service
reserve letter of credit loans. The collateral agent will apply the proceeds of
each drawing: (a) in the case of clauses (i) and (v) of the preceding
sentence, to payment of the relevant obligation and (b) in the case of clauses
(ii), (iii), and (iv) of the preceding sentence, to the debt service reserve
account until there is deposited therein an aggregate amount equal to the debt
service reserve account required balance.
Subject to the conditions of drawing, the debt service reserve letter
of credit will, unless extended, mature, expire or terminate on the earlier to
occur of (i) seven years from the date of issuance of the debt service reserve
letter of credit and (ii) the occurrence of a debt service reserve letter of
credit event of default. The debt service reserve letter of credit, however, may
not be terminated upon the occurrence of a debt service reserve letter of credit
event of default without the debt service reserve letter of credit issuing bank
first giving the collateral agent and the trustee written notice thereof at
least 60 days prior to the termination during which period the collateral agent
will be entitled to draw on the debt service reserve letter of credit as
described above under "Collateral Agency Agreement--Debt Service Reserve
Account." The debt service reserve letter of credit provider will provide a copy
of such written notice to us at the time the notice is given to the collateral
agent and the trustee.
We will have the right to terminate or reduce the debt service reserve
letter of credit upon the receipt by the debt service reserve letter of credit
provider of notice from the trustee consenting to the termination or reduction.
The debt service reserve letter of credit is subject to renewal for
additional periods of one or more years at the sole discretion of the debt
service reserve letter of credit provider under the debt service reserve letter
of credit and reimbursement agreement.
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The amount available for drawing under the debt service reserve letter
of credit will be reduced upon (i) making draws thereunder, (ii) the reduction
of the debt service reserve account required balance and (iii) certain deposits
of cash in the debt service reserve account.
DEBT SERVICE RESERVE LETTER OF CREDIT LOANS
Each drawing on the debt service reserve letter of credit will
constitute the making by the debt service reserve letter of credit issuing bank
of a loan to us. We will pay interest on the unpaid principal amount of each
outstanding debt service reserve letter of credit loan from the date such debt
service reserve letter of credit loan is made until such principal amount has
been repaid in full at a rate PER ANNUM equal, at our option to either (i) the
adjusted base rate plus the applicable margin, or (ii) the Eurodollar rate plus
the applicable margin. The adjusted base rate will equal the higher of (i) the
federal funds rate plus .50% and (ii) the rate of interest officially announced
or published by the debt service reserve letter of credit provider as its
"prime" or "reference" rate. The Eurodollar rate will be determined by reference
to the offered rates that appear on Telerate page 3750 for deposits in dollars
two London banking days prior to the date on which the rate is to become
applicable to a debt service reserve letter of credit loan. The applicable
margin will be based upon the ratings of the bonds and the long-term senior
unsecured debt of the power purchase agreement guarantor. During an event of
default, all amounts outstanding under the debt service reserve letter of credit
reimbursement agreement will accrue interest at 2% above the rate of interest
otherwise applicable.
Each debt service reserve letter of credit loan will be evidenced by a
note in favor of the debt service reserve letter of credit provider. We will pay
the interest on any debt service reserve letter of credit loan out of cash
available in the revenue account at the same level in the flow of funds as
interest on other senior debt and will repay the principal amount of any debt
service reserve letter of credit loans out of cash available in the revenue
account after payment of debt service on all senior debt, including debt service
reserve bonds and debt service reserve term loans, other than principal of debt
service reserve letter of credit loans. Each debt service reserve letter of
credit loan will mature five years after the date such debt service reserve
letter of credit loan is made.
Unless the debt service reserve letter of credit is not extended or
replaced or unless there has been a debt service reserve letter of credit event
of default as described under "SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Debt
Service Reserve Letter of Credit Reimbursement Agreement," amounts available for
drawing under the debt service reserve letter of credit will be reinstated
immediately to the extent of any reimbursement of principal of debt service
reserve letter of credit loans, but not debt service reserve bonds or debt
service reserve letter of credit term loans.
NON-RENEWAL OF DEBT SERVICE RESERVE LETTER OF CREDIT
If the debt service reserve letter of credit is not extended or
replaced at least 45 days prior to its termination date, or the credit rating of
the debt service reserve letter of credit issuing bank is less than the required
rating and we do not within 45 days replace the debt service reserve letter of
credit with a letter of credit issued by a financial institution which meets the
required rating, the collateral agent will draw on the debt service reserve
letter of credit, creating a debt service letter of credit term loan, in an
amount equal to the lesser of (i) the amount available to be drawn under the
letter of credit and (ii) the positive difference between (x) the debt service
reserve account required balance and (y) amounts then on deposit in the debt
service reserve account, and will deposit the drawing into the debt service
reserve account. The debt service reserve letter of credit will then terminate.
A debt service reserve letter of credit term loan will amortize under a
"mortgage-style" amortization schedule and the maturity date of any debt service
reserve letter of credit term loan will be 10 years after the date such loan is
made. Interest on and principal of any debt service reserve letter of credit
term loan will be paid, respectively, at the same levels as interest on and
principal of the bonds.
CONVERSION INTO DEBT SERVICE RESERVE BONDS
If by the date 30 months after the making of a debt service reserve
letter of credit loan, we have failed to repay at least 50% of the original
amount of such debt service reserve letter of credit loan, or if by the maturity
date of such debt service reserve letter of credit loan we have failed to repay
such debt service reserve letter of credit loan in full, then from and after the
applicable date, such debt service reserve letter of credit loan may, at the
option of the debt service reserve letter of credit provider, subject to the
approval of the required debt service reserve letter of credit banks, be
converted into a new security, a debt service reserve bond, having a principal
amount equal to
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the remaining principal amount of the debt service reserve letter of credit loan
so converted. Each debt service reserve bond will be amortized on the same
amortization schedule as the Series B bonds and mature on the same maturity date
as the Series B bonds. Interest on and principal of any debt service reserve
bond will be paid, respectively, at the same levels as interest on and principal
of the bonds.
COVENANTS
Our covenants contained in the indenture will be incorporated by
reference (with appropriate substitution of parties) in the debt service
reserve letter of credit and reimbursement agreement as if described in full
in the debt service reserve letter of credit and reimbursement agreement.
DEBT SERVICE RESERVE LETTER OF CREDIT EVENTS OF DEFAULT
Each of the following will be an event of default under the debt
service reserve letter of credit and reimbursement agreement: (i) any amount
due under the debt service reserve letter of credit and reimbursement
agreement or any debt service reserve letter of credit note is not paid in
full within 15 days after the due date thereof; (ii) an event of default
under the indenture has occurred and is continuing or (iii) an event of
default under the power purchase agreement letter of credit and reimbursement
agreement will occur and be continuing.
REMEDIES
Upon the occurrence and during the continuation of a debt service
reserve letter of credit event of default, at the request of the banks holding
66 2/3 percent or more of the sum of the drawings and principal amount of all
debt service reserve letter of credit loans, debt service reserve letter of
credit term loans and debt service reserve bonds and/or the debt service reserve
letter of credit commitment, the debt service reserve letter of credit provider
may (i) after notice and the lapse of time as required in the financing
documents, terminate the debt service reserve letter of credit, (ii) declare all
amounts owing under the debt service reserve letter of credit and reimbursement
agreement and any debt service reserve note to be forthwith due and payable,
including amounts not yet advanced under the debt service reserve letter of
credit, which will upon being so advanced be and become immediately due and
payable, whereupon the obligations will become and be due and payable, without
presentment, demand or protest; (iii) terminate our ability to cause the
reinstatement of the debt service reserve letter of credit stated amount through
the reimbursement of drawings; and (iv) terminate our ability to continue any
debt service reserve loans as, or to convert debt service reserve loans to,
Eurodollar rate loans; so long as the debt service reserve letter of credit
provider and the banks will not have the right to exercise any other remedies
except in accordance with the provisions of the collateral agency agreement.
POWER PURCHASE AGREEMENT LETTER OF CREDIT REIMBURSEMENT AGREEMENT
Dresdner Bank AG, acting through its New York Branch, under a power
purchase agreement letter of credit and reimbursement agreement, has agreed to
provide and issue the power purchase agreement letter of credit for use by us in
connection with our project.
The power purchase agreement letter of credit issuing bank issued the
power purchase agreement letter of credit for our account in an amount up to
$30,000,000 and in favor of Williams Energy. Williams Energy may make drawings
under the power purchase agreement letter of credit under the circumstances
provided for in the power purchase agreement. The power purchase agreement
letter of credit stated amount will be decreased on the commercial operation
date to the lesser of (a) $10 million or (b) $30 million less all amounts drawn
under the power purchase agreement letter of credit and not repaid prior to the
commercial operation date.
Subject to the conditions of drawing, the power purchase agreement
letter of credit will mature, expire or terminate on the earliest to occur of
(i) seven years from the date of issuance of the power purchase agreement letter
of credit; (ii) the occurrence of a power purchase agreement letter of credit
event of default; however, the power purchase agreement letter of credit will
not be terminated upon the occurrence of a power purchase agreement letter of
credit event of default without the power purchase agreement letter of credit
issuing bank first giving the collateral agent and Williams Energy written
notice thereof at least 30 days prior to the termination; and (iii) receipt by
the power purchase agreement letter of credit issuing bank of a certificate from
us terminating the power purchase agreement letter of credit by reason of
delivery of substitute collateral under the power purchase agreement (the date
referred to in clause (i), (ii) or (iii), the "expiration date"). The power
purchase agreement letter of credit provider will provide a copy of the written
notice in clause (ii) to us at the time the notice is given to the
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collateral agent and Williams Energy.
We will have the right to replace the power purchase agreement letter
of credit with substitute collateral as permitted in the power purchase
agreement and may terminate or reduce the power purchase agreement letter of
credit upon the receipt by the power purchase agreement letter of credit issuing
bank of notice from us of the replacement. The amount available for drawing
under the power purchase agreement letter of credit will be reduced upon making
draws thereunder.
POWER PURCHASE AGREEMENT LETTER OF CREDIT LOANS
Each drawing on the power purchase agreement letter of credit will
constitute the making of a loan by the power purchase agreement letter of
credit issuing bank. We will pay interest on the unpaid principal amount of
each outstanding power purchase agreement letter of credit loan from the date
such power purchase agreement letter of credit loan is made until such
principal amount has been repaid in full at a rate PER ANNUM equal, at our
option to either (i) the adjusted base rate plus the applicable margin or
(ii) the Eurodollar rate plus the applicable margin. The adjusted base rate
will equal the higher of (i) the federal funds rate plus .50% and (ii) the
rate of interest officially announced or published by the power purchase
agreement letter of credit provider as its "prime" or "reference" rate. The
Eurodollar rate will be determined by reference to the offered rates that
appear on Telerate page 3750 for deposits in Dollars two London banking days
prior to the date on which the rate is to become applicable to a power
purchase agreement letter of credit loan. The applicable margin will be based
upon the ratings of the bonds and the long-term unsecured senior debt of the
power purchase agreement guarantor. During an event of default, all amounts
outstanding under the power purchase agreement letter of credit reimbursement
agreement will accrue interest at 2% above the rate of interest otherwise
applicable.
Each power purchase agreement letter of credit loan will be evidenced
by a note in favor of the power purchase agreement letter of credit provider. We
will pay the interest on and repay the principal amount (based on mortgage-style
amortizations) of any power purchase agreement letter of credit loan out of cash
available in the revenue account at the same level as interest on and the
principal of the bonds. Each power purchase agreement letter of credit loan will
mature 10 years after the date the power purchase agreement letter of credit
loan is made.
COVENANTS
Our covenants contained in the indenture will be incorporated by
reference, with appropriate substitution of parties, in the power purchase
agreement letter of credit reimbursement agreement as if described in full in
the power purchase agreement letter of credit reimbursement agreement.
POWER PURCHASE AGREEMENT LETTER OF CREDIT EVENTS OF DEFAULT
Each of the following will be an event of default under the power
purchase agreement letter of credit reimbursement agreement: (i) any amount due
under the power purchase agreement letter of credit reimbursement agreement or
any power purchase agreement letter of credit note is not paid in full within 15
days after the due date thereof; (ii) an event of default under the indenture
will occur and is continuing; (iii) an event of default under the debt service
reserve letter of credit reimbursement agreement has occurred and is continuing
and (iv) an event of default under the working capital agreement will occur and
is continuing.
REMEDIES
Upon the occurrence and during the continuation of a power purchase
agreement letter of credit event of default, at the request of the banks holding
66 2/3 percent or more of the drawings and principal amount of all power
purchase agreement letter of credit loans and/or the power purchase agreement
letter of credit commitment, the power purchase agreement letter of credit
provider may (i) terminate the power purchase agreement letter of credit in
accordance with its terms, (ii) declare all amounts owing under the power
purchase agreement letter of credit reimbursement agreement and any power
purchase agreement letter of credit note to be forthwith due and payable,
including amounts not yet advanced under the power purchase agreement letter of
credit, which will upon being so advanced be and become immediately due and
payable, whereupon the obligations will become and be due and payable, without
presentment, demand or protest and (iii) terminate the ability of us to continue
power purchase agreement letter of credit loans as or to convert power purchase
agreement letter of credit loans to Eurodollar rate loans so long as the power
purchase agreement letter of credit provider and the banks will not have the
right to
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exercise any other remedies except in accordance with the provisions of the
collateral agency agreement.
WORKING CAPITAL AGREEMENT
Pursuant to the working capital agreement, each bank named therein
will extend credit of up to $2.5 million in the aggregate to us by making loans
to us from time to time for use in connection with the project as described
therein.
Availability of loans under the working capital commitment will
commence, at the request of, on: (i) the commercial operation date or (ii) the
date on which we are obligated to make our first payment for fuel related to
testing and startup of the facility. The obligation of the banks to extend loans
under the working capital agreement is subject to the following conditions
precedent: (1) the bonds are rated "BB" or higher by Standard & Poor's and "Ba"
or higher by Moody's; (ii) no default or event of default under the working
capital agreement has occurred and is continuing; and (iii) no event has
occurred and is continuing which could reasonably be expected to have a material
adverse effect. The obligation of the banks to extend loans under the working
capital agreement will expire on the earlier to occur of: (i) the occurrence of
an event of default and the working capital agent's termination of the
obligation of each bank to make loans; (ii) the date that is five (5) years
after the closing date as the date may be extended by the banks and (iii) the
date on which the working capital commitment is fully terminated. On or prior to
the date that is four (4) years prior to the original or any extended final
disbursement date, the banks may, by unanimous consent, extend the original or
extended final disbursement date for an additional year. If the banks agree to
extend the then effective final disbursement date, the final disbursement date
will be the date one year after the then effective final disbursement date and
the outside maturity date, being the date two (2) years after the final
disbursement date, will simultaneously be extended for an additional year.
We will periodically have the right to reduce ratably in part or
terminate in whole the unused portion of each bank's respective commitment.
We will pay interest on the unpaid principal amount of each
outstanding loan from the date the loan is made until the principal amount has
been repaid in full at a rate PER ANNUM equal, at our option to either (a) the
adjusted base rate plus the applicable margin or (b) the Eurodollar rate plus
the applicable margin. The adjusted base rate will equal the higher of (i) the
federal funds rate plus .50% and (ii) the rate of interest officially announced
or published by the working capital agent as its "prime" or "reference" rate.
The Eurodollar rate will be determined by reference to the offered rates which
appear on Telerate page 3750 for deposits in dollars two London banking days
prior to the date on which the rate is to become applicable to a loan. During an
event of default, all amounts outstanding under the working capital agreement
will accrue interest at 2% above the rate of interest otherwise applicable.
The principal amount of each loan will be due and payable 180 days
after the loan is advanced subject to an annual 30-day cleanup period. We may,
upon one business day's written notice to the working capital agent, repay or
prepay any loan on any business day without premium or penalty, except for any
funding losses of the banks. We may re-borrow all amounts repaid or prepaid up
to the working capital commitment.
EVENTS OF DEFAULT
Each of the following will be an event of default under the working
capital agreement: (i) any amount due under the working capital agreement is not
paid in full within 15 days after the due date thereof; (ii) the occurrence of
an event of default under the indenture; (iii) the occurrence of an event of
default under the debt service reserve letter of credit reimbursement agreement;
and (iv) the occurrence of an event of default under the power purchase
agreement letter of credit reimbursement agreement.
REMEDIES
Upon the occurrence and during the continuation of an event of
default, the working capital agent, at the request of the banks holding at least
66-2/3% of the outstanding amount of the loans and/or the working capital
commitments, may: (a) declare the obligation of each bank to make loans to be
terminated; (b) declare all amounts owing, including principal, interest, fees,
expenses, indemnification or otherwise, under the working capital agreement to
be forthwith due and payable; and (c) exercise all rights and remedies available
to it under the financing documents or applicable law; so long as the working
capital agent will not have the right to exercise any other remedies except in
accordance with the provisions of the collateral agency agreement.
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EQUITY SUBSCRIPTION AGREEMENT
Under an equity subscription agreement entered into by and among
us, AES Red Oak, Inc., and the collateral agent, AES Red Oak, Inc. agreed to
contribute equity, or make or cause to be made affiliate subordinated loans,
to us from time to time during the construction period at the request of the
collateral agent. AES Red Oak, Inc. will agree to contribute a base equity
contribution of up to $41,556,431. AES Red Oak, Inc. will also agree to
contribute up to an additional $14,193,600 of contingent equity to fund
project costs in excess of the project budget. The obligation of AES Red Oak,
Inc. to make base equity contributions must be supported by either an
insurance bond or letter of credit, in each case issued by an issuer that
meets specified ratings criteria. That obligation is currently supported by
an insurance company bond issued by an insurance company that meets these
ratings criteria. The obligation to make contingent equity contributions is
supported by a guaranty of The AES Corporation. AES Red Oak, Inc.'s
obligation to make equity contributions will commence when all proceeds of
the offering of the bonds have been utilized but will not at any time exceed,
in the aggregate, $55,750,031. All equity contributions will be deposited in
the construction account and applied as describe under "DESCRIPTION OF THE
PRINCIPAL FINANCING DOCUMENTS--Collateral Agency Agreement--CONSTRUCTION
ACCOUNT."
The equity subscription agreement also provides that upon the
occurrence of an event of default under the indenture, AES Red Oak, Inc. will be
obligated to make a base equity contribution to us in an amount equal to
$41,556,431 less the aggregate of all base equity contributions previously
deposited into the construction account. Any such equity contribution following
an event of default will be deposited in the construction account and may be
used to prepay bonds and other outstanding senior permitted indebtedness in
accordance with the terms of the collateral agency agreement. AES Red Oak, Inc.
will be obligated to make contingent equity contributions as required in the
collateral agency agreement.
Subject to specified conditions under the equity subscription
agreement, any excess contingent equity which remains committed but unfunded at
the commercial operation date may be canceled. Conditions to the cancellation of
the excess contingent equity commitments include (i) the absence of any default
or event of default under the indenture or any other financing document, and
(ii) the occurrence of the commercial operation date.
CONSENTS TO ASSIGNMENTS
In connection with the collateral assignment of all contract rights
held by us including rights under our project contracts, the collateral agent
received an executed consent to assignment from third parties party to the
project contracts. In each consent, the applicable third party agreed to, in
respect of our project contracts to which it is a party, among other matters,
(i) consent to the collateral assignment thereof to the collateral agent on
behalf of the senior parties, (ii) pay all amounts, if any, receivable by us
thereunder directly into the revenue account created under the collateral agency
agreement, (iii) matters concerning the exercise of remedies by the collateral
agent upon an event of default under the collateral agency agreement and (iv)
the exercise by the senior parties of specific remedy rights with respect to our
project contracts.
MORTGAGE
We, as mortgagor, entered into the mortgage and will mortgage and
grant a security interest to the collateral agent for the benefit of the
senior parties in all of our right, title and interest in and to all real
property interests, including fee interests, easement interests and leasehold
interests, if any, of us to the site, portions of our facility and any
easements and all fixtures, equipment and improvements thereon, all accounts,
subject to the terms of the indenture, and personal property now owned or
hereafter acquired. Our rights in any leases affecting the real property,
including rights to receive income will be assigned by us to the collateral
agent under an assignment of leases and income.
The events of default under the mortgage incorporate by reference
those provided in the indenture. Under the terms of the mortgage, the collateral
agent may, upon the occurrence and during the continuance of an event of default
and satisfaction of conditions contained in the collateral agency agreement,
take possession of all collateral covered by the mortgage.
Proceeds from the exercise of remedies under the mortgage will be
applied in accordance with the security documents and the collateral agency
agreement.
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SECURITY AGREEMENT
We entered into the security agreement with the collateral agent for
the benefit of the senior parties providing for the granting of a security
interest in all of our personal property interests including, but not limited
to, all contract rights, equipment, receivables, accounts, insurance proceeds,
eminent domain proceeds, rights under any governmental approval (to the extent
permitted by applicable law) and patents and trademarks, including all proceeds
thereof and all documents evidencing all monies and investment therein. Upon the
occurrence of a Trigger Event under the collateral agency agreement, remedies
may be exercised under the security agreement.
Under the terms of the security agreement, the collateral agent may,
upon the occurrence and during the continuance of an event of default and
satisfaction of conditions contained in the collateral agency agreement, take
possession of all of the collateral covered by the security agreement.
Proceeds from the exercise of remedies under the security agreement
will be applied in accordance with the security documents.
PLEDGE AGREEMENT
Under the pledge agreement entered into by AES Red Oak, Inc. in favor
of the collateral agent, AES Red Oak, Inc. pledged to the collateral agent,
acting on behalf of the senior parties, all of its ownership interests in our
Company, and all rights under or derived therefrom, including its interests in
AES URC and the URC collateral, currently owned or later acquired and all
distributions, cash, instruments and other property and proceeds, and all rights
associated therewith, from time to time receivable or otherwise distributable
with respect to or in exchange for the ownership interests.
URC MORTGAGE AND URC SECURITY AGREEMENT
AES URC, as mortgagor, entered into a URC mortgage to mortgage and
grant a security interest to us in all of the URC collateral, including AES
URC's right, title and interest in and to all real property interests,
including fee interests, easement interests and leasehold interests, if any,
of AES URC to the site, portions of our facility and any easements and all
fixtures, equipment and improvements thereon and all personal property now
owned or hereafter acquired. AES URC's rights in any leases affecting the
real property (including rights to receive income) were assigned by AES URC
to us under an assignment of leases and income.
The events of default under the URC mortgage incorporate by reference
those provided in the indenture. Under the terms of the URC mortgage, we will
assign to the collateral agent the right, upon the occurrence and during the
continuance of an event of default and satisfaction of conditions contained in
the collateral agency agreement, to take possession of all collateral covered by
the URC mortgage.
Proceeds from the exercise of remedies under the URC mortgage will be
applied in accordance with the security documents and the collateral agency
agreement.
AES URC entered into the URC security agreement with us providing for
the granting of a security interest in all of AES URC's personal property
interests including, but not limited to, all URC collateral, contract rights,
equipment, receivables, accounts, insurance proceeds, eminent domain proceeds,
rights under any governmental approval, to the extent permitted by applicable
law, and patents and trademarks, including all proceeds thereof and all
documents evidencing all monies and investment therein. Upon the occurrence of a
Trigger Event under the collateral agency agreement, remedies may be exercised
under the URC security agreement.
Under the terms of the URC security agreement, we assigned to the
collateral agent the right, upon the occurrence and during the continuance of an
event of default and satisfaction of conditions contained in the collateral
agency agreement, to take possession of all of the URC collateral covered by the
URC security agreement.
Proceeds from the exercise of remedies under the URC security agreement
will be applied in accordance with the security documents.
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PLAN OF DISTRIBUTION
Except as described below, a broker-dealer may not participate in
the exchange offer in connection with a distribution of the exchange bonds.
Each broker-dealer that receives exchange bonds for its own account under the
exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of the exchange bonds. Based on SEC staff
interpretations issued to third parties, a broker-dealer could use this
prospectus, as it may be amended or supplemented from time to time, in
connection with resales of exchange bonds received in the exchange offer
where the beneficial interests in outstanding bonds for which they were
exchanged were acquired as a result of market-making activities or other
trading activities. We have agreed that for a period not to exceed 270 days
to make this prospectus, as amended or supplemented, available to any
broker-dealer for use in connection with any resale. In addition, until 120
days after the consummation of the exchange offer, all dealers effecting
transactions in the exchange bonds may be required to deliver a prospectus.
The information described above concerning SEC staff interpretations is
not intended to constitute legal advice, and broker-dealers should consult their
own legal advisors with respect to these matters.
We will not receive any proceeds from the exchange offer or any sale
of exchange bonds by broker-dealers. Exchange bonds received by
broker-dealers for their own account under the 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 exchange
bonds or a combination of those methods of resale, at market prices
prevailing at the time of resale, at prices related to those prevailing
market prices or negotiated prices. Any resale may be made directly to
purchasers or to or through brokers or dealers who may receive compensation
in the form of commissions or concessions from any broker-dealer and/or the
purchasers of any exchange bonds. Any broker-dealer that resells exchange
bonds that were received by it for its own account under the exchange offer
and any broker or dealer that participates in a distribution of the exchange
bonds may be deemed to be an "underwriter" within the meaning of the
Securities Act and any profit on any resale of exchange bonds and any
commissions or concessions received by any of those persons may be deemed to
be underwriting compensation under the Securities Act. Any broker or dealer
registered under the Exchange Act who holds outstanding bonds that were
acquired for its own account as a result of market-making activities or other
trading activities, other than outstanding bonds acquired directly from us,
may exchange those outstanding bonds under the exchange offer; however, that
broker or dealer may be deemed to be an "underwriter" within the meaning of
the Securities Act and must, therefore, deliver a prospectus meeting the
requirements of the Securities Act in connection with any resales of the
exchange bonds received by the broker or dealer in the exchange offer. This
prospectus delivery requirement may be satisfied by the delivery by that
broker or dealer of this prospectus. The letter of transmittal states that by
acknowledging that it will deliver and by delivering a prospectus, a
broker-dealer will not be deemed to admit that it is an "underwriter" within
the meaning of the Securities Act.
We have agreed to pay the expenses of registration of the exchange
bonds and will indemnify the holders of the exchange bonds, including any
broker-dealers, against certain liabilities, including liabilities under the
Securities Act.
Prior to the exchange offer, there has been no public market for the
outstanding bonds. We do not intend to apply for listing of the exchange bonds
on any securities exchange. There can be no assurance that an active market for
the exchange bonds will develop. To the extent that a market for the exchange
bonds develops, the market value of the exchange bonds will depend on market
conditions (including yields on alternative investments general economic
conditions), our financial condition and other conditions. Those conditions
might cause the exchange bonds, to the extent that they are actively traded, to
trade at a significant discount from face value. We have not entered into any
arrangement or understanding with any person to distribute the exchange bonds to
be received in the exchange offer.
We have not agreed to compensate broker-dealers who effect the exchange
of outstanding bonds on behalf of holders.
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
Because the exchange bonds will be identical to the outstanding bonds
in all material economic respects,
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the exchange of the outstanding bonds for the exchange bonds will not be treated
as an exchange for United States federal income tax purposes. Consequently,
there will be no United States federal income tax consequences to the exchange,
and holders of the exchange bonds will continue to account for the bonds for
federal income tax purposes as if the exchange had not taken place.
EXPERTS
The independent technical review included as Annex B to this prospectus
has been prepared by Stone & Webster Management Consultants, Inc. and is
included in this prospectus in reliance upon the authority of Stone & Webster
and its affiliates as experts in the review of the design, construction and
operation of electric generating facilities. The independent market assessment
included as Annex C to this prospectus has been prepared by ICF Resources, Inc.
and is included in this prospectus in reliance upon the authority of that firm
as experts in the analysis of power markets, including future market demand,
future market prices for electric energy and capacity and related matters, for
electric generating facilities.
This document has been prepared by the management of our company and
includes financial statements audited by Deloitte & Touche LLP as stated in
their independent auditors' report accompanying those financial statements.
These financial statements are included in this prospectus in reliance upon the
independent auditors' report of the firm given upon their authority as experts
in accounting and auditing.
LEGAL MATTERS
The validity of the exchange bonds will be passed upon for us by Hunton
& Williams, New York, New York and Washington, D.C.
WHERE YOU CAN FIND MORE INFORMATION
This prospectus is part of a registration statement on Form S-4 that we
have filed with the SEC. This prospectus does not contain all of the information
set forth in the registration statement. For further information about us and
the exchange bonds, you should refer to the registration statement. This
prospectus summarizes material provisions of contracts and other documents.
Since these summaries may not contain all of the information that you may find
important, you should review the full text of these documents. We have filed
certain of these documents as exhibits to our registration statement.
You should direct any request for information to our Project Manager,
at least 10 business days before you tender your exchange bonds in the exchange
offer. Our mailing address and telephone number are:
AES Red Oak, L.L.C.
c/o The AES Corporation
1001 North 19th Street
Arlington, Virginia 22209
(703) 522-1315
As a result of the exchange offer, we will be subject to the periodic
reporting and other informational requirements of the Securities Exchange Act of
1934. In addition, under the indenture governing the outstanding bonds and the
exchange bonds, we have agreed that unless we are filing comparable reports
under the reporting and informational requirements of the Exchange Act so long
as the outstanding bonds or the exchange bonds remain outstanding, we will
distribute to the holders of the bonds, copies of financial information
comparable to that which we would have been required to file with the SEC under
the Exchange Act. This financial information will include annual reports
containing consolidated financial statements and notes thereto, together with an
opinion thereon expressed by an independent public accounting firm, as well as
quarterly reports containing unaudited condensed consolidated financial
statements for the first three quarters of each fiscal year. We have also agreed
to furnish to holders of outstanding bonds and prospective purchasers of the
exchange bonds upon their request, the information
120
<PAGE>
required to be delivered pursuant to Rule 144(d)(4) under the Securities Act
during any period in which we are not subject to the reporting and informational
requirements of the Exchange Act. We are also obligated to provide the trustee
with copies of our annual audited financial statements prepared in accordance
with generally accepted accounting principles and certified by independent
public accountants, and with our unaudited interim financial statements prepared
in accordance with generally accepted accounting principles for the first three
quarters of each fiscal year. We will furnish the trustee, upon its request,
with sufficient copies of all information to accommodate the requests of
bondholders and holders on beneficial interests in the bonds.
The AES Corporation, The Williams Companies, Inc. and the Raytheon
Company are also subject to the periodic reporting requirements of the Exchange
Act. Our registration statement, as well as the reports, exhibits and other
information filed by us, the AES Corporation, The Williams Companies, Inc. and
Raytheon Company with the SEC can be inspected and copied, at prescribed rates,
at the public reference facilities maintained by the Public Reference of the SEC
at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C., 20549,
and at the Regional Offices of the SEC at 7 World Trade Center, 13th Floor, New
York, New York 10048 and Northwestern Atrium Center, 500 West Madison Street,
Suite 1400, Chicago Illinois 60661-2511. Please call the SEC at 1-800-SEC-0330
for additional information about its public reference. SEC filings are also
available without charge on the SEC's Internet site at http://www.sec.gov.
121
<PAGE>
AES RED OAK L.L.C.
(A DEVELOPMENT STAGE ENTERPRISE, AND AN INDIRECT WHOLLY OWNED
SUBSIDIARY OF THE AES CORPORATION)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE PERIOD
FROM MARCH 15 THROUGH MARCH 31, 2000
<TABLE>
<CAPTION>
PAGE
<S> <C>
Independent Auditors' Report........................................... F-2
Consolidated Balance Sheet............................................. F-3
Consolidated Statement of Operations................................... F-4
Consolidated Statement of Changes in Member's Deficit.................. F-5
Consolidated Statement of Cash Flows................................... F-6
Notes to Consolidated Financial Statements............................. F-7
</TABLE>
F-1
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Member of AES Red Oak, L.L.C.:
We have audited the accompanying consolidated balance sheet of AES Red Oak,
L.L.C. (an indirect wholly owned subsidiary of The AES Corporation and a
development stage enterprise) (the Company) as of March 31, 2000, and the
related consolidated statements of operations, changes in member's deficit and
cash flows for the period from March 15, 2000 (inception) through March 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 audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of AES Red Oak, L.L.C., as of March 31,
2000, and the results of its operations and its cash flows for the period
from March 15, 2000 (inception) through March 31, 2000, in conformity with
accounting principles generally accepted in the United States.
/s/ DELOITTE & TOUCHE LLP
June 12, 2000
McLean, Virginia
F-2
<PAGE>
AES RED OAK, LLC (A DEVELOPMENT STAGE ENTERPRISE)
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
MARCH 31, 2000
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
--------------------------------------------------------------------------------
ASSETS
<S> <C>
CURRENT ASSETS:
Cash $ 26
Investments held by trustee - at cost, which approximates market value 2,940
---------
Total current assets 2,966
PREPAID CONSTRUCTION COSTS 288,573
LAND 4,240
CONSTRUCTION IN PROGRESS 26,398
DEFERRED FINANCING COSTS - Net of accumulated amortization of $10 18,709
INVESTMENTS HELD BY TRUSTEE - at cost, which approximates market value 45,809
---------
TOTAL ASSETS $ 386,695
=========
LIABILITIES AND MEMBER'S DEFICIT
CURRENT LIABILITIES:
Accounts Payable $ 213
Accrued interest 1,598
Payable to affiliates 1,129
---------
Total current liabilities 2,940
BONDS PAYABLE 384,000
---------
Total liabilities 386,940
---------
COMMITMENTS (Notes 4,5,6, and 7)
MEMBER'S DEFICIT:
Common stock, $1 par value - 10 shares authorized, none issued or outstanding --
Deficit accumulated during the development stage (245)
---------
Total member's deficit (245)
---------
TOTAL LIABILITIES AND MEMBER'S DEFICIT $ 386,695
=========
</TABLE>
See notes to consolidated financial statements.
F-3
<PAGE>
AES RED OAK, LLC (A DEVELOPMENT STAGE ENTERPRISE)
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF OPERATIONS
PERIOD FROM MARCH 15, 2000 (INCEPTION) THROUGH MARCH 31, 2000
(IN THOUSANDS)
--------------------------------------------------------------------------------
<S> <C>
OPERATING EXPENSES:
General and administrative costs $(162)
-----
Operating loss (162)
OTHER INCOME/EXPENSE:
Interest income 120
Interest expense (203)
-----
NET LOSS $(245)
=====
</TABLE>
See notes to consolidated financial statements.
F-4
<PAGE>
AES RED OAK, LLC (A DEVELOPMENT STAGE ENTERPRISE)
CONSOLIDATED STATEMENT OF CHANGES IN MEMBER'S DEFICIT
PERIOD FROM MARCH 15, 2000 (INCEPTION) THROUGH MARCH 31, 2000
(IN THOUSANDS)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
COMMON STOCK ACCUMULATED
-------------------------- ------------------------
SHARES AMOUNT DEFICIT TOTAL
-------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
BALANCE, MARCH 15, 2000 - $ - $ - $ -
Net loss - - (245) (245)
-------- ---------- ------- ---------
BALANCE, MARCH 31, 2000 - $ - $ (245) $ (245)
======== ========== ======= ========
</TABLE>
See notes to consolidated financial statements.
F-5
<PAGE>
AES RED OAK, LLC (A DEVELOPMENT STAGE ENTERPRISE)
CONSOLIDATED STATEMENT OF CASH FLOWS
PERIOD FROM MARCH 15, 2000 (INCEPTION) THROUGH MARCH 31, 2000
<TABLE>
<CAPTION>
(IN THOUSANDS)
--------------------------------------------------------------------------------
<S> <C>
OPERATING ACTIVITIES:
Net loss $ (245)
Amortization of deferred financing costs 10
Change in:
Accounts Payable 213
Payable to affiliates 1,129
Accrued interest 1,598
---------
Net cash provided by operating activities 2,705
---------
INVESTING ACTIVITIES:
Prepaid construction costs (288,573)
Payments for construction in progress (26,398)
Payments for land (4,240)
Payments to restricted account (48,749)
---------
Net cash used in financing activities (367,960)
---------
FINANCING ACTIVITIES:
Proceeds from project debt issuance 384,000
Payments for deferred financing costs (18,719)
---------
Net cash provided by financing activities 365,281
---------
NET INCREASE IN CASH AND CASH EQUIVALENTS 26
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD --
---------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 26
=========
</TABLE>
See notes to consolidated financial statements.
F-6
<PAGE>
AES RED OAK L.L.C. (A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE PERIOD FROM MARCH 15, 2000 (INCEPTION) THROUGH MARCH 31, 2000
--------------------------------------------------------------------------------
1. ORGANIZATION
AES, Red Oak, L.L.C. (the Company) was incorporated on September 13,
1998, in the State of Delaware, to develop, construct, own and operate a
830-megawatt (MW) gas-fired, combined cycle electric generating facility in the
Borough of Sayreville, Middlesex County, New Jersey (the Plant). The Company was
considered dormant until March 15, 2000, at which time the Project Financing and
certain related agreements were consummated (hereinafter, inception). The Plant,
currently under construction, will consist of three Westinghouse 501 FD
combustion turbines, three unfired heat recovery steam generators, and one
multicylinder steam turbine. The Plant will produce and sell electricity, as
well as provide fuel conversion and ancillary services, solely to Williams
Energy Marketing and Trading Company (Williams) under a power purchase agreement
(the PPA) with a term of 20 years that will commence on the Plant's anticipated
commercial operation date, December 31, 2001 (see Note 5).
The Company is in the development stage and is not expected to generate
any operating revenues until the Plant achieves commercial operations. As with
any new business venture of this size and nature, operation of the Plant could
be affected by many factors. Management of the Company believes that the assets
of the Company are recoverable.
The Company is a wholly owned subsidiary of AES Red Oak, Inc. (Red
Oak), which is a wholly owned subsidiary of The AES Corporation (AES). Red Oak
has no assets other than its ownership interests in the Company and AES
Sayreville, L.L.C. (see Note 7). It has no operations and is not expected to
have any operations. Its only income will be from distributions it receives from
the Company and AES Sayreville, L.L.C., once the Company achieves commercial
operation. The equity that Red Oak is to provide to the Company will be provided
to Red Oak by AES, which owns all of the stock of Red Oak. AES files quarterly
and annual audited reports with the Securities and Exchange Commission under the
1934 Exchange Act, which are publicly available. Red Oak's equity contribution
obligations are required to be supported by either an insurance bond or letter
of credit. Currently those obligations are supported by an insurance bond issued
to the collateral agent and a guaranty by The AES Corporation (see Note 4).
The Company owns all of the equity interests in AES Red Oak Urban
Renewal Corporation (URC), which was organized as an urban renewal corporation
under New Jersey Law. Portions of the Plant can be designated as redevelopment
areas in order to provide real estate tax and development benefits to the Plant.
On March 15, 2000, the Company issued $384 million in senior secured
bonds (see Note 4) for the purpose of providing financing for the construction
of the Plant and to fund, through the construction period, interest payments to
the bondholders.
Pursuant to an Equity Subscription Agreement, Red Oak has agreed to
contribute up to approximately $55.7 million to the Company to fund construction
after the bond proceeds have been fully utilized (see Note 4).
2. SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLE OF CONSOLIDATION - The consolidated financial statements
include the accounts of the Company and AES URC, its wholly owned subsidiary.
All intercompany transactions and balances have been eliminated in
consolidation.
CASH AND CASH EQUIVALENTS - The Company considers unrestricted cash on
hand, deposits in banks, and investments with original maturities of three
months or less to be cash and cash equivalents for the purpose of the
F-7
<PAGE>
statement of cash flows.
INVESTMENTS HELD BY TRUSTEE - The Company is required to maintain a
construction funding account for the payment of certain qualifying construction
costs and a construction interest account from which quarterly interest payments
are to be made. As of March 31, 2000, these amounts were fully invested in money
market accounts. The balances in the construction funding account and the
construction interest account were approximately $21 million and $28 million,
respectively, as of March 31, 2000.
CONSTRUCTION IN PROGRESS - Costs incurred in developing the Plant,
including progress payments, engineering costs, management and development fees,
interest, and other costs related to construction are capitalized. Total
interest capitalized on the project financing debt was approximately $1.4
million, as of March 31, 2000. Certain costs related to construction activities
were paid by AES prior to the issuance of the bonds. These amounts were
approximately $12.4 million, are reflected within construction in progress, and
were reimbursed to AES out of the bond proceeds.
PREPAYMENT OF THE CONSTRUCTION AGREEMENT, OR EPC CONTRACT - The
Company has prepaid the EPC Contract in the amount of $288.6 million,
representing a discounted fixed price. Raytheon Engineers and Constructors,
Inc. (the Contractor) provided the Company with a letter of credit as
collateral for the prepayment which will be reduced as work under the EPC
contract is completed.
DEFERRED FINANCING COSTS - Financing costs are deferred and are being
amortized using the straight-line method over the expected period for which the
financing was obtained, which does not differ materially from the effective
interest method of amortization.
USE OF ESTIMATES - The preparation of financial statements in
conformity with generally accepted accounting principles requires the Company to
make estimates and assumptions that affect reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities as of the date
of the financial statements, as well as the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
INCOME TAXES - The Company is a limited liability corporation and is
treated as a partnership for tax purposes. Therefore, it does not pay income
taxes, and no provision for income taxes has been reflected in the accompanying
financial statements.
COMPREHENSIVE INCOME - The Company follows Statement of Financial
Accounting Standards No. 130, REPORTING COMPREHENSIVE INCOME (SFAS 130) which
establishes rules for the reporting of comprehensive income and its
components. SFAS 130 had no impact on the Company's financial statements as
the Company had no items of other comprehensive income.
START-UP COSTS - The Company follows AICPA Statement of Position (SOP)
98-5, REPORTING ON THE COSTS OF START-UP ACTIVITIES, which requires that
start-up and organizational costs be expensed as incurred. As such, no costs to
which the Statement applies have been capitalized in the accompanying balance
sheet.
FISCAL YEAR-END - The Company's fiscal year ends on December 31.
3. NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, Statement of Financial Accounting Standards No. 133,
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (SFAS 133), which
established standards for the accounting and reporting of derivative financial
instruments and hedging activities, was issued. As amended by SFAS 137, the
standard will be adopted by the Company during fiscal year 2001. The Company is
currently evaluating the impact of such adoption.
F-8
<PAGE>
4. BONDS PAYABLE
On March 15, 2000, the Company issued $224 million of 8.54% senior
secured bonds due 2019 and $160 million of 9.20% senior secured bonds due 2029
(collectively, the Bonds) to qualified institutional buyers and/or institutional
accredited investors, pursuant to a transaction exempt from registration under
the Securities and Exchange Act of 1933 (the Act) in accordance with Rule 144A
of the Act. The net proceeds of the bonds (after deferred financing costs),
approximately $379 million, were used to prepay the Contractor and other
construction costs of the Plant and will be used, during the construction
period, primarily for interest payments to bondholders.
HEDGING AGREEMENT - The Company entered into an agreement, which
required it to pay approximately $13.3 million to guarantee the interest rate
on the bonds over their respective lives. This amount has been included as
part of Deferred Financing Costs on the Consolidated Balance Sheet and will
be amortized over the life of the bonds.
Principal on the Bonds is payable quarterly in arrears, commencing on
August 31, 2002. The final maturity date for the Bonds is November 30, 2029.
PRINCIPAL & INTEREST REPAYMENT SCHEDULE (IN THOUSANDS):
<TABLE>
<CAPTION>
YEAR PRINCIPAL
AND INTEREST
<S> <C>
2000 $ 24,066
2001 33,850
2002 36,243
2003 39,755
2004 38,343
2005 and thereafter 814,905
---------
Total Payments 987,162
Less Interest Portion (603,162)
---------
Principal $ 384,000
=========
</TABLE>
FUTURE MATURITIES OF DEBT - Scheduled principal maturities of the
bonds at March 31, 2000, are (in thousands):
<TABLE>
<S> <C>
2000 0
2001 0
2002 2,419
2003 6,219
2004 5,230
2005 and thereafter 370,132
---------
TOTAL $ 384,000
=========
</TABLE>
OPTIONAL REDEMPTION - The Bonds are subject to optional redemption, in
whole or in part, at any time at a redemption price equal to 100% of the
principal amount plus accrued interest, together with a premium calculated using
a discount rate equal to the interest rate on comparable U.S. Treasury
securities plus 50 basis points.
F-9
<PAGE>
MANDATORY REDEMPTION - The Bonds are subject to mandatory redemption,
in whole or in part, at a redemption price equivalent to 100% of the principal
amount plus accrued interest under certain situations pursuant to receiving
insurance proceeds, eminent domain proceeds, or liquidated damages under the EPC
or in certain instances in which payments are received under the PPA when the
Company has terminated the PPA as a result of a default by Williams.
REGISTRATION RIGHTS - Under the Registration Rights Agreement, the
Company will prepare and file an Exchange Offer Registration Statement with the
SEC and will use its reasonable efforts to cause the Registration Statement to
be declared effective on or prior to 220 days after the original issue date of
the bonds.
INDENTURE - The Indenture contains limitations on the Company incurring
additional indebtedness, granting liens on the Company's property, distributing
equity and paying subordinated indebtedness issued by affiliates of the Company,
entering into transactions with affiliates, amending, terminating or assigning
any of the Company's contracts and fundamental changes or disposition of assets.
Collateral for the Bonds consists of the Plant and related facilities,
all agreements relating to the operation of the project, the bank and investment
accounts of the Company, and all ownership interests in the Company, as
prescribed under the trust indenture agency (the Indenture). The Company is also
bound by a collateral agency agreement (the Collateral Agency Agreement) and an
equity subscription agreement (the Equity Subscription Agreement).
COLLATERAL AGENCY AGREEMENT - The Collateral Agency Agreement requires
the Company to fund or provide the funding or a letter of credit for a debt
service reserve fund, which is expected to commence on February 14, 2002. The
amount required for funding the debt service reserve fund is equal to six months
scheduled payments of principal and interest on the bonds.
EQUITY SUBSCRIPTION AGREEMENT - The Company, along with Red Oak, has
entered into an Equity Subscription Agreement, pursuant to which Red Oak has
agreed to contribute up to approximately $55.7 million to the Company to fund
project costs. Approximately $42 million of this amount is supported by an
insurance bond obtained by Red Oak. Approximately $14 million will be
supported by a guarantee of The AES Corporation. Red Oak will fund these
amounts as they come due upon the earlier of (a) expenditure of all funds
that have been established for construction or (b) the occurrence and during
the continuation of an event of default, as defined under the Indenture. A
portion of this equity requirement may be made in the form of affiliate debt,
between Red Oak and the Company, which is subordinate to the Bonds.
COVENANTS - The Indenture, Collateral Agency Agreement and Equity
Subscription Agreement contain specific covenants and requirements to be met by
the Company.
5. POWER PURCHASE AGREEMENT
The Company and Williams have entered into a PPA for the sale of all
electric energy and capacity produced by the Plant, as well as ancillary
services and fuel conversion services. The term of the PPA is 20 years,
commencing on the Commercial Operation Date (COD) defined in the PPA as the day
the initial start up testing procedures have been successfully completed and
notified to Williams by the Company. The PPA provides for an anticipated COD on
or before December 31, 2001. However if the COD does not occur as of that date,
the Company has the right to extend the COD to June 30, 2002 by paying to
Williams an amount of $2.5 million. Beyond that first extension, the latest
possible extension of COD that may be requested by the Company is on June 30,
2003 through the payment of daily fees up to a maximum of $14.2 million.
Payment obligations to the Company are guaranteed by The Williams
Companies, Inc. Such payment obligations under the guarantee are capped at an
amount equal to 125% of the sum of the principal amounts of the bonds plus the
maximum debt service reserve account required balance. The Company has provided
Williams a guaranty issued by AES of specific payment obligations should the
Plant not achieve commercial operation by December 31, 2001. AES's liability
under the guaranty is capped at $30 million. The Company has the option, and
F-10
<PAGE>
may be required under specific conditions described in the PPA, to replace the
guaranty issued by AES with a letter of credit issued by a commercial bank. In
such case, the repayment obligations with respect to drawings under the letter
of credit are to be a senior debt obligation of the Company.
FUEL CONVERSION AND OTHER SERVICES - As instructed by the Company,
Williams has the obligation to deliver, on an exclusive basis, all quantities of
natural gas and fuel oil required by the Plant to generate electricity or
ancillary services, to start-up or shut-down the plant, and to operate the Plant
during any period other than a start-up, shut-down, or required dispatch by
Williams for any reason.
6. COMMITMENTS AND CONTINGENCIES
EPC - The Company has entered into a fixed-price turnkey agreement with
the Contractor for the design, engineering, procurement and construction of the
Plant. As explained in Note 2, the Company has prepaid the EPC contract in the
amount of $288.6 million, representing a discounted fixed price. In
consideration of the prepayment the Contractor issued in favor of the Company a
letter of credit with an initial amount of $237.7 million to be reduced over the
construction period.
MAINTENANCE SERVICES AGREEMENT - The Company has entered into an
agreement with Siemens Westinghouse Power Corporation (Siemens). Siemens will
provide the Company with specific combustion turbine maintenance services and
spare parts for an initial term of between six and sixteen years.
WATER SUPPLY - The Company has entered into a contract with the Borough
of Sayreville (the Borough) by which the Borough will provide untreated water to
the Company. The contract has a term of 30 years with an option to extend for up
to four additional five-year terms.
INTERCONNECTION AGREEMENT - The Company has entered into an
interconnection agreement with Jersey Central Power & Light Company d/b/a GPU
Energy (GPU) to transmit the electricity generated by the Plant to the
transmission grid so that it may be sold as prescribed under the Company's PPA.
The Agreement is in effect for the life of the Plant, yet may be terminated by
mutual consent of both GPU and the Company under certain circumstances as
detailed in the agreement. Costs associated with the agreement are based on
electricity transmitted via GPU at a variable price, the PJM (Pennsylvania/New
Jersey/Maryland) Tariff, as charged by GPU to the Company, which is comprised of
both service cost and asset recovery cost, as determined by GPU and approved by
the Federal Energy Regulatory Committee (FERC).
WATER SUPPLY PIPELINE - The Borough will design the Lagoon Water
Pipeline, Lagoon Pumping Station and Sayreville Interconnection Number 2 in
conformance with standard water system practice. The Company is responsible for
selection of a contractor and for payment of all costs.
7. RELATED PARTY TRANSACTIONS
Effective March 2000, the Company entered into a 32-year development
and construction management agreement with AES Sayreville, L.L.C. (Sayreville),
another wholly owned subsidiary of Red Oak, to provide certain support services
required by the Company for the development and construction of the Plant. Under
this agreement Sayreville will also provide operations management services for
the Plant once commercial operation is attained. Minimum amounts payable under
the contract during the construction period are $125,000 per month. Once
commercial operation is achieved, payments for operations management services
will be approximately $400,000 per quarter. The AES Corporation will supply
Sayreville with personnel and services necessary to carry out its obligations.
During the construction period, the construction management fees will
be paid to Sayreville from the investment balances or from equity funding.
Through March 31, 2000, $68,548 in construction management fees were incurred,
were charged to construction in progress, and are payable to Sayreville.
F-11
<PAGE>
8. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments have
been determined using available market information. The estimates are not
necessarily indicative of the amounts the Company could realize in a current
market exchange. The use of different market assumptions and/or estimation
methodologies may have a material effect on the estimated fair value amounts.
The fair value of the Company's restricted investments approximates
their carrying value. The estimated fair value of the Bonds as of March 31,
2000, based on quoted market prices of similarly rated bonds with similar
maturities, does not differ materially from their carrying value.
9. SEGMENT INFORMATION
Under the provisions of Statement of Financial Accounting Standards No.
131, DISCLOSURE ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION, the
Company's business is expected to be operated as one reportable segment, with
operating income or loss being the measure of performance evaluated by the chief
operating decision maker. As described in Notes 1 and 5, the Company's primary
customer will be Williams, which is expected to provide all of the revenues of
the Company during the term of the PPA.
* * * * * * * *
F-12
<PAGE>
-----------------------------------------
ANNEX A
GLOSSARY OF TERMS
-----------------------------------------
<PAGE>
GLOSSARY OF TERMS
The following terms will have the meanings set forth below and the
meanings are equally applicable to both the singular and plural forms of the
terms defined. Any term defined below by reference to any agreement or
instrument will have the meaning whether or not the agreement or instrument is
in effect. Unless otherwise specified, any agreement or instrument defined or
referred to below will include any amendments, modifications and supplements
thereto and waivers thereof made in accordance with the terms of the agreement
or instrument. Any reference to a person includes the successors and permitted
assigns of the person.
"Acceptable credit provider" means (i) in the case of an
unconditional guaranty, AES (if and for so long as its long-term unsecured
debt is rated at least Investment Grade and not lower than the then current
lowest rating of the bonds by each of Standard & Poor's and Moody's) and (ii)
in the case of an irrevocable letter of credit, a bank or trust company with
a combined capital and surplus of at least $1,000,000,000 whose long-term
unsecured debt is rated at least "A" by Standard & Poor's and "A2" by Moody's.
"Acceptable credit support" means (i) an unconditional guaranty in
the form prescribed in the Collateral Agency Agreement, or (ii) an
irrevocable letter of credit (which is not an obligation of AES Red Oak,
L.L.C. and is not secured by the Collateral), in either case from an
Acceptable Credit Provider.
"Assignment of leases and income" means the Assignment of Leases and
Income, by and between AES Red Oak, L.L.C. and the Collateral Agent.
"Available cash flow" means, with respect to each application of
funds required under the Collateral Agency Agreement as of any specified
date, all funds remaining in the Revenue Account as of the date and available
to be applied as set forth in the Collateral Agency Agreement after all prior
applications of funds in the Revenue Account required on the date.
"Bankruptcy event" means the occurrence or commission of either of
the following: (i) AES Red Oak, L.L.C., AES URC, or, so long as AES has any
outstanding obligations under any Acceptable Credit Support, AES or, so long
as AES Red Oak, Inc. has any outstanding obligations under the Equity
Subscription Agreement, AES Red Oak, Inc. will (a) apply for or consent to
the appointment of, or the taking of possession by, a receiver, custodian,
trustee or liquidator of itself or of all or substantially all of its
property, (b) admit in writing its inability, or be generally unable, to pay
its debts as the debts become due, (c) make a general assignment of the
benefit of its creditors, (d) commence a voluntary case under the Bankruptcy
Code, (e) file a petition seeking to take advantage of any law relating to
bankruptcy, insolvency, reorganization, winding-up, or the composition or
readjustment of debts, (f) fail to controvert in a timely and appropriate
manner, or acquiesce in writing to, any petition filed against the person in
an involuntary case under the Bankruptcy Code or (g) take any corporate or
other action for the purpose of effecting any of the foregoing; or (ii) a
proceeding or case will be commenced without the application or consent of
AES Red Oak, L.L.C., AES URC or, so long as AES has any obligations under any
Acceptable Credit Support, AES or, so long as AES Red Oak, Inc. has any
outstanding obligations under the Equity Subscription Agreement, AES Red Oak,
Inc., in any court of competent jurisdiction, seeking (a) its liquidation,
reorganization, dissolution, winding-up, or the composition or readjustment
of debts or (b) the appointment of a trustee, receiver, custodian, liquidator
or the like of the person under any law relating to bankruptcy, insolvency,
reorganization, winding-up, or the composition or adjustment of debts, and
the proceeding or case will continue undismissed, or any order, judgment or
decree approving or ordering any of the foregoing will be entered and
continue unstayed and in effect, for a period of 90 or more consecutive days,
or any order for relief against the person will be entered in an involuntary
case under the Bankruptcy Code.
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"Cash available for debt service" means, in respect of a specified
period, all funds (i) deposited in the Revenue Account (other than amounts
transferred to the account from the Major Maintenance Reserve Account, the
Distribution Account or the Construction Account), to the extent the
specified period occurred prior to the date of determination or (ii)
projected by AES Red Oak, L.L.C. on a reasonable basis to be deposited, to
the extent the specified period is to occur subsequent to the date of
determination, in the Revenue Account during the period minus all funds
transferred or projected to be transferred to (a) AES Red Oak, L.L.C. for
payment of Operating and Maintenance Costs, (b) the Trustee, Working Capital
Agent, Collateral Agent, Debt Service Reserve letter of credit Provider and
the power purchase agreement letter of credit Provider in respect of Trustee
Claims, Working Capital Agent Claims, Collateral Agent Claims, Debt Service
Reserve letter of credit Provider Claims and power purchase agreement letter
of credit Provider Claims, respectively, and (c) the Working Capital Agent in
respect of payments on working capital loans during the period.
"Certificate as to redemption" means the certificate filed by an
authorized representative of AES Red Oak, L.L.C., in the case of an event of
loss or event of eminent domain, in order to determine: (i) whether our
facility can be rebuilt, repaired or restored and (ii) the availability of
casualty proceeds or eminent domain proceeds for the rebuilding, repairing or
restoring.
"Collateral" means: (i) all revenues of AES Red Oak, L.L.C. and AES
URC; (ii) our project accounts (other than the debt service reserve account);
(iii) all real and personal property of AES Red Oak, L.L.C. (including its
interests in the URC Collateral) and its ownership interests in AES URC; (iv)
proceeds of insurance, condemnation and liquidated damages payments, if any;
(v) all project contracts; (vi) all ownership interests in AES Red Oak,
L.L.C.; (vii) the equity contribution and all rights under the equity
subscription agreement; and (viii) in respect of the bondholders only, the
indenture accounts, the debt service reserve account and the debt service
reserve letter of credit (other than the debt service reserve letter of
credit provider's right to specific proceeds under the debt service reserve
letter of credit).
"Date certain" means June 30, 2003, the final date by which the
facility must commence commercial operation pursuant to the power purchase
agreement.
"Debt service reserve letter of credit provider claims" means all
obligations of AES Red Oak, L.L.C., now or hereafter existing, to pay
administrative fees, costs, expenses, liabilities or indemnities under the
Debt Service Reserve letter of credit reimbursement agreement.
"Environmental law" means any governmental requirement in effect
from time to time governing or relating to (i) the environment, (ii) releases
or threatened releases of hazardous materials including, without limitation,
investigation, monitoring and abatement of the releases and (iii) the
manufacture, handling, transport, use, treatment, storage or disposal of
hazardous materials or materials containing hazardous materials.
"Financing liabilities" means all indebtedness, liabilities and
obligations of AES Red Oak, L.L.C. (of whatsoever nature and howsoever
evidenced including, but not limited to, principal, interest, fees,
reimbursement obligations, collateralization or deposit obligations,
penalties, indemnities and legal expenses, whether due after acceleration or
otherwise) under the Indenture, the bonds and any evidence of indebtedness
thereunder entered into, the
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working capital agreement and any evidence of indebtedness thereunder entered
into, the debt service reserve letter of credit reimbursement agreement and any
evidence of indebtedness thereunder entered into, the power purchase agreement
letter of credit reimbursement agreement and any evidence of indebtedness
thereunder entered into, the collateral agency agreement and any evidence of
indebtedness thereunder entered into, and the security documents, to the extent
arising on or prior to the final maturity date for the bonds, in each case,
direct or indirect, primary or secondary, fixed or contingent, now or hereafter
arising out of or relating to any the agreements.
"Fuel conversion payment volume rebate account" means the fuel
conversion payment volume rebate account established under the collateral agency
agreement.
"Good faith contest" means the contest of an item if: (i) the item is
diligently contested in good faith by appropriate proceedings timely instituted;
(ii) adequate reserves or bonding are established in accordance with GAAP with
respect to the contested item; and (iii) during the period of the contest, the
enforcement of any contested item is effectively stayed.
"Guaranteed final acceptance date" means, unless otherwise adjusted in
accordance with the construction agreement, April 1, 2003.
"Impositions" means all duties, Taxes, assessments, dues, charges,
fees, excises, levies, license and permit fees, impositions, water rates,
sewer rents and other charges, ordinary or extraordinary, whether foreseen or
unforeseen, of any kind whatsoever, (i) now or hereafter levied or assessed
or imposed against or upon or in respect of the mortgaged property (as
defined in the mortgage) or (ii) which now is or may be levied or assessed
against the income (as defined in the mortgage) by virtue of any present or
future law, as well as all income taxes, assessments and other governmental
charges levied and imposed by any governmental authority upon or against AES
Red Oak, L.L.C. in respect of the mortgaged property or any part thereof, to
the extent the same is in lieu of or in substitution of the items described
in clause (i). Impositions will not include any taxes imposed on the net
income, gross receipts or any franchise taxes of the trustee or collateral
agent, except as provided in this indenture.
"Independent forecast" means a report furnished by AES Red Oak,
L.L.C. to the senior parties no later than six months prior to the expiration
of the term of the power purchase agreement, prepared by an independent
consultant of national reputation which sets forth projections of (i)
electricity prices for the PJM Market (or if the market no longer exists at
the time, any successor market or substitute market as determined in good
faith by AES Red Oak, L.L.C. which approximates, to the extent practicable,
the region) and (ii) gas prices on a delivered basis to our facility, in each
case on at least an annual basis through the final maturity date for the
bonds.
"Independent insurance advisor" means, initially, AON Risk Services,
Inc., or another nationally recognized insurance advisory firm appointed as
insurance advisor by AES Red Oak, L.L.C.
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"Make-whole premium" means an amount calculated as of the date set
for the redemption or repurchase of any of the bonds as follows:
(a) the average life of the remaining scheduled payments of
principal in respect of bonds then outstanding (the "remaining average life")
will be calculated as of the determination date;
(b) the yield to maturity will be calculated for the United States
Treasury security having an average life equal to the remaining average life
and trading in the secondary market at the price closest to the principal
amount thereof (the "primary issue"); provided, however, that if no United
States Treasury security has an average life equal to the remaining average
life, the yields (the "other yields") for the two maturities of United States
Treasury securities having average lives most closely corresponding to the
remaining average life and trading in the secondary market at the price
closest to the principal amount thereof will be calculated, and the yield to
maturity for the primary issue will be the yield interpolated or extrapolated
from the other yields on a straightline basis, rounding in each of the
relevant periods to the nearest month;
(c) the discounted present value of the then remaining scheduled
payments of principal and interest (but excluding that portion of any
scheduled payment of interest that is actually due and paid on the
determination date) in respect of bonds then outstanding will be calculated
as of the determination date using a discount factor equal to the sum of (x)
the yield to maturity for the primary issue, plus (y) 50 basis points; and
(d) the amount of make-whole premium in respect of bonds to be
redeemed or repurchased will be an amount equal to (x) the discounted present
value of the bonds to be redeemed determined in accordance with clause (c)
above, minus (y) the unpaid principal amount of the bonds; provided, however,
that the make-whole premium will not be less than zero.
"Operating and maintenance costs" means all actual cash maintenance
and operation costs to be incurred and paid for with respect to the facility
in any particular period (other than any amounts paid under the URC
documents), including franchise, sales, property and other similar taxes (but
not taxes on or measured by net income), payments for the supply and
transportation of fuels, insurance, consumables, payments under any lease
(other than lease payments under the URC documents), payments pursuant to the
project contracts (including payments under the operations agreement, but
excluding payments made under the construction agreement, the URC documents
(other than additional rent payments thereunder) and any payments under the
project contracts that are expressly subordinated), repair and replacement
costs for equipment included in the facility, reasonable legal fees and
expenses paid by the company in connection with the management, maintenance
or operation of the facility, fees paid in connection with obtaining,
transferring, maintaining or amending any governmental approvals, employee
salaries, wages and other employment-related costs and reasonable general and
administrative expenses, all fees, expenses and other payments due to and all
indemnities and other arrangements providing for the payment of amounts to
the lenders, arrangers, underwriters, initial purchasers, independent
consultants, their agents, counsel and employees in connection with the
indebtedness of the company (but excluding transaction costs associated with
the offering and issuance of the bonds), but exclusive in all cases of (i)
non-cash charges, including depreciation or obsolescence charges or reserves
therefor, amortization of intangibles or other bookkeeping entries of a
similar nature, (ii) all interest charges, (iii) all commitment fees,
underwriting fees and other similar fees due and payable in connection with
indebtedness of the company, (iv) maintenance costs funded from amounts on
deposit in the major maintenance reserve account and (v) solely for purposes
of priority of payment, fees (but not costs) payable to the operator, except
to the extent that there are sufficient funds available in the revenue
account to make all required payments and deposits specified in priorities
FIRST through SIXTH for payments made during the operating period, as
described above under "SUMMARY OF PRINCIPAL FINANCING DOCUMENTS--Collateral
Agency Agreement--Payments During Operating Period".
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"Power marketing plan" means a marketing and procurement plan
prepared by or on behalf of AES Red Oak, L.L.C. which describes in reasonable
detail AES Red Oak, L.L.C.'s plan to (i) procure gas to be burned at our
facility and (ii) sell electric power from our facility without a replacement
power purchase agreement.
"Project costs" means all costs of developing, financing,
constructing, testing and initial operation of the facility, including but
not limited to: (i) all amounts payable under the construction agreement
including any contractor bonuses, site acquisition and preparation costs,
costs of acquisition and construction of fuel handling and processing
equipment, any electric interconnection and transmission upgrade costs
payable by the company pursuant to the power purchase agreement, all water
interconnection costs payable by the company and all gas interconnection
costs payable by the company; (ii) rent payments by the company to AES URC
and loans by the company to AES URC the proceeds of which will be used by the
company to construct the part of the facility that will be owned by AES URC;
(iii) all development costs and fees, which will be paid to, or as designated
by, the company on the closing date; (iv) all other facility-related costs,
including but not limited to fuel-related costs, fees and expenses payable
pursuant to the operations agreement and expenses to complete the
construction and financing of the facility; (v) start-up and testing costs
and initial working capital costs; (vi) initial reserve fund requirements;
(vii) fees and costs payable during construction with respect to loans under
the working capital agreement, the debt service reserve letter of credit, the
power purchase agreement Letter of Credit and any other letters of credit or
security provided under any project Contract; (viii) legal and other
transaction costs and financing-related fees; (ix) any other out-of-pocket
expenses related to the financing; (x) interest on the bonds during
construction; and (xi) any amounts owed to Williams Energy pursuant to
Section 2 of the power purchase agreement.
"Project revenues" means, for any period, the Company's revenues or
income received (but excluding all revenues received under the URC
Documents), including, without limitation: (i) except as otherwise specified
in the Collateral Agency Agreement, interest and other income earned and
credited on monies deposited in the project Accounts; (ii) amounts paid by
Williams Energy pursuant to the power purchase agreement; (iii) the proceeds
of the sale of any part of the facility which is not prohibited under the
Indenture; (iv) the proceeds of any insurance claims in respect of an event
or occurrence concerning the facility that is not an Event of Loss or an
Event of Eminent Domain; and (v) all amounts received by the Company under
the Williams Guaranty.
"Prudent operating and maintenance practices" means those practices,
methods and acts that at a particular time, in the exercise of reasonable
judgment in light of the facts known or that should have been known, would
have been expected to accomplish the goals established in the Annual
Operating plan, including the goals as efficiency, reliability, economy and
profitability, in a manner consistent with law, regulation, safety, and
environmental protection. With respect to our facility, Prudent Operating and
Maintenance Practices of the electrical generating industry include taking
reasonable actions to provide (i) adequate materials, resources and supplies,
to the extent within the control of Operator, available to meet our
facility's needs; (ii) a sufficient number of operators who are available and
adequately trained to operate our facility; and (iii) the timely performance
of preventive, routine, and non-routine maintenance and repairs, as
exemplified and generally described in the Operations Agreement.
"Redemption subaccount" means the Redemption Subaccount of the Bond
Payment Account established under the Indenture.
"Required bondholders" means, at any time, the persons that at the
time own a majority in aggregate principal amount of the bonds then
outstanding.
"Required modifications" means, collectively, those modifications
reasonably necessary for our facility to (i) remain in compliance with all
material applicable laws and Governmental Approvals and (ii) maintain, at a
minimum, the capacity production levels contemplated by the projected
operating results included in the final prospectus with respect to the bonds,
in either case, as confirmed by the Independent Engineer.
"Required senior parties" means, at any time, persons that at the
time hold at least a majority of the Combined Exposure.
"Restricted payments" means, collectively, (i) distributions
including payments of dividends to holders of ownership interests in AES Red
Oak, L.L.C.; (ii) payments of principal, interest or premium, if any, on and
any repurchase of any Affiliate Subordinated Debt; (iii) prepayments of any
Subordinated Debt; and (iv) the repurchase by AES Red Oak, L.L.C. of any
ownership interests in AES Red Oak, L.L.C.
"Step-up event" means, in respect of any Debt Service Reserve Letter
of Credit, (i) the Debt Service Reserve Letter of Credit has not been
extended or replaced within 45 days prior to the expiration date of the Debt
Service Reserve Letter of Credit or (ii) the credit rating of the Debt
Service Reserve letter of credit Issuing Bank is less than the Required
Rating and the Debt Service Reserve Letter of Credit has not been replaced
within 45 days of the failure to satisfy the requirements of the Required
Rating with a replacement letter of credit issued by an issuer that satisfies
the requirements of the Required Rating and, in each case, the Collateral
Agent has drawn on the Debt Service
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Reserve Letter of Credit in an amount sufficient to fund the Debt Service
Reserve Account up to the Debt Service Reserve Account Required Balance.
"Total debt service" means, for any period, an amount calculated by
AES Red Oak, L.L.C. as equal to the aggregate of (i) all amounts payable by
AES Red Oak, L.L.C. during the period in respect of Senior Debt Service; (ii)
all amounts payable by AES Red Oak, L.L.C. during the period in respect of
principal of, and interest, and premium, if any, on Subordinated Debt and any
other Indebtedness permitted under the Indenture and incurred by AES Red Oak,
L.L.C.; and (iii) all amounts payable by AES Red Oak, L.L.C. during the
period as fees and other expenses (including any interest thereon) to any
fiduciary acting in the capacity with respect to any Indebtedness referred to
in clause (ii) of this definition.
"Total debt service coverage ratio" means for any period, the ratio
of (i) Cash Available for Debt Service for the period to (ii) the amount of
Total Debt Service due and payable for the period.
"Trigger Event" means (i) an "Event of Default" under the Indenture
and an acceleration of the Indebtedness issued thereunder; (ii) an "Event of
Default" under the Debt Service Reserve letter of credit Reimbursement
Agreement and an acceleration of the Indebtedness incurred by AES Red Oak,
L.L.C. thereunder; (iii) an "Event of Default" under the power purchase
agreement letter of credit Reimbursement Agreement and an acceleration of the
Indebtedness incurred by AES Red Oak, L.L.C. thereunder; (iv) an "Event of
Default" or the equivalent under the Working Capital Agreement and an
acceleration of the Indebtedness incurred by AES Red Oak, L.L.C. thereunder;
or (v) a Bankruptcy Event in respect of AES Red Oak, L.L.C. or AES URC and
the expiration of the shortest applicable grace period.
"URC collateral" means (i) all revenues of AES URC, (ii) all real
and personal property and contract rights of AES URC and (iii) all Eminent
Domain Proceeds, Casualty Proceeds, insurance proceeds and liquidated damage
payments, if any, of AES URC.
"Working capital agent claims" means all obligations of AES Red Oak,
L.L.C., now or hereafter existing, to pay administrative fees, costs,
expenses, liabilities or indemnities under the Working Capital Agreement.
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ANNEX B
INDEPENDENT TECHNICAL REVIEW
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<PAGE>
STONE & WEBSTER
MANAGEMENT CONSULTANTS, INC.
----------------------------
INDEPENDENT TECHNICAL CONSULTANT'S REPORT
ON THE
AES RED OAK, L. L. C. POWER PROJECT
MARCH 10, 2000
PREPARED BY
STONE & WEBSTER MANAGEMENT CONSULTANTS, INC.
<PAGE>
STONE & WEBSTER MANAGEMENT CONSULTANTS, INC.
245 Summer Street
Tel. (617) 589-1930 Fax: (617) 589-1372
http://www.swmci.com
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LEGAL NOTICE
This report was prepared by Stone & Webster Management Consultants, Inc. with
the assistance of its affiliated company, Stone & Webster Engineering
Corporation; together hereafter referred to as Stone & Webster, expressly for
Lehman Brothers. Neither Stone & Webster, Lehman Brothers, nor any person acting
on their behalf: (a) makes any warranty, express or implied, with respect to the
use of any information or methods disclosed in this report; or (b) assumes any
liability with respect to the use of any information or methods disclosed in
this report.
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TABLE OF CONTENTS
<TABLE>
<S> <C> <C>
1. EXECUTIVE SUMMARY.............................................................................5
1.1 Project Description...........................................................................6
1.2 Conclusions...................................................................................7
2. SCOPE OF WORK................................................................................10
3. FACILITY DESIGN..............................................................................11
3.1 Facility Description.........................................................................11
3.2 Site Location and Description................................................................12
3.3 Combustion Turbine Generator.................................................................13
3.4 Heat Recovery Steam Generator................................................................17
3.5 Steam Turbine................................................................................17
3.6 Electric Generators..........................................................................18
3.7 Selective Catalytic Reduction................................................................19
3.8 Balance of Plant Systems.....................................................................19
3.9 Fuel System..................................................................................25
3.10 Electrical Systems...........................................................................25
3.11 Switchyard...................................................................................26
3.12 Miscellaneous Electrical Systems.............................................................27
3.13 Instrument and Control Systems...............................................................27
3.14 Civil and Structural Design..................................................................28
3.15 Interconnections.............................................................................30
4. ENVIRONMENTAL AND PERMITTING.................................................................33
4.1 Environmental Site Assessment................................................................33
4.2 Permitting...................................................................................33
5. PROJECT AGREEMENTS...........................................................................43
5.1 Power Purchase Agreement.....................................................................43
5.2 Interconnection Agreement....................................................................45
5.3 Engineering, Procurement, and Construction Services..........................................47
5.4 Development and Operations Services Agreement................................................51
5.5 Services Agreement...........................................................................52
5.6 Water Supply Agreement.......................................................................52
5.7 Agreements Relating to Real Estate...........................................................53
5.8 Maintenance Program Parts, Shop Repairs and Scheduled Outage TFA Services Contract...........54
6. PRINCIPAL PROJECT PARTICIPANTS...............................................................56
6.1 AES Red Oak, LLC.............................................................................56
6.2 AES Sayreville, LLC..........................................................................56
6.3 Williams Energy Marketing & Trading Company..................................................56
</TABLE>
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<TABLE>
<S> <C> <C>
6.4 Raytheon Engineers & Constructors............................................................56
6.5 Siemens Westinghouse Power Corporation.......................................................57
7. ASSESSMENT OF PROJECTED OPERATING RESULTS....................................................58
7.1 Overview.....................................................................................58
7.2 Principal Considerations and Assumptions.....................................................58
7.3 Project Cost.................................................................................59
7.4 Power Production.............................................................................61
7.5 Revenues.....................................................................................62
7.6 Operating Expenses...........................................................................62
7.7 Financing Assumptions........................................................................65
7.8 Projected Operating Results..................................................................65
7.9 Sensitivity Analyses.........................................................................66
7.10 Liquidated Damages Analyses..................................................................68
</TABLE>
EXHIBIT I
Base Case
Increased O&M Sensitivity (Case #1)
Increased Heat Rate Sensitivity (Case #2)
Decreased Availability Sensitivity (Case #3)
High Gas (Case #4)
Low Gas (Case #5)
Overbuild (Case #6)
EXHIBIT II
Document Log
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1. EXECUTIVE SUMMARY
Stone & Webster Management Consultants, Inc. is pleased to provide this report
(the "Report") which summarizes our independent technical review (the "Review")
of the proposed AES Red Oak Project (the "Project"). The Project will consist of
a nominal 832 MW (ISO) combined cycle electric generating facility (the
"Facility") to be located in Sayreville, New Jersey and the associated Project
documents and agreements.
The Review was conducted by Stone & Webster Management Consultants, Inc. with
the assistance of Stone & Webster Engineering Corporation (collectively, "Stone
& Webster"). The Review was conducted by Stone & Webster for the purpose of
producing this Report on behalf of Lehman Brothers as an Initial Purchaser of
certain bonds (the "Bonds") to be issued by AES Red Oak, LLC ("AES Red Oak"),
pursuant to Rule 144A under the Securities Act of 1933, as amended, to finance
the construction and initial start-up and testing of the Facility. The Bonds are
to be offered in the United States to qualified institutional buyers and
institutional accredited investors and in offshore transactions complying with
Regulation S under the Securities Act of 1933 as amended.
The scope of the Review included the conceptual design and interfaces of the
Project; the proposed Siemens Westinghouse Power Corporation ("SWPC") 501FD
combustion turbine ("CT") technology; the projected performance of the Project;
the Phase I site assessments for the Project; the issued permits for the
Project; the technical assumptions utilized in the Pennsylvania/New
Jersey/Maryland ("PJM") Market Study prepared by ICF Resources Incorporated
("ICF Resources") dated February 24, 2000, and the Project's projected operating
results through validation of the Project pro forma and verification of the
model results (the "Projected Operating Results").
Stone & Webster also reviewed the principal contracts and agreements associated
with the Project. These included the Fuel Conversion Services, Capacity and
Ancillary Services Purchase Agreement dated September 17, 1999 ("Tolling
Agreement"), the Generation Facility Transmission Interconnection Agreement
("Interconnection Agreement") with Jersey Central Power & Light Company
("JCP&L") d/b/a GPU Energy ("GPU Energy") dated April 27, 1999, the Engineering,
Procurement and Construction Services Agreement dated December 7, 1997 as
amended ("EPC Contract"), the Maintenance Program Parts, Shop Repairs and
Scheduled Outage TFA Services Contract dated December 7, 1997 ("Maintenance
Services Agreement"), the Water Supply Agreement ("WSA") dated December 22, 1999
the Development and Operations Services Agreement ("Operations Agreement"), the
Services Agreement ("Services Agreement"), and the Agreements Relating to Real
Estate (collectively the "Project Agreements"). Stone & Webster reviewed the
Project Agreements from a technical and economic standpoint to assess the
adequacy, compatibility, and reasonableness of their terms and conditions. Stone
& Webster made no determination as to the validity and enforceability of the
Project documents and permits. However, for the purposes of this Report, we have
assumed the Project Agreements and contracts will be fully enforceable in
accordance with their respective terms and that all parties will comply with the
provisions of their respective agreements. Stone & Webster also conducted a site
visit on October 22, 1999 and made general field observations, specifically the
existing above ground condition of the site.
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1.1 PROJECT DESCRIPTION
The Project is being developed and will be owned, operated, and maintained by
AES Red Oak. AES Red Oak is a limited liability company, organized and existing
under the laws of Delaware. AES Red Oak was formed to develop, construct, own,
and operate the Project. AES Red Oak is a special purpose project company and a
wholly owned subsidiary of AES Red Oak, Inc. AES Red Oak Inc. is a wholly owned
subsidiary of The AES Corporation ("AES"). AES, which was founded in 1981, is
one of the world's largest global power companies. AES Sayreville, L.L.C, ("AES
Sayreville"), a Delaware limited liability company and a wholly owned subsidiary
of AES Red Oak, Inc., will manage the development, construction, and operation
and maintenance of the Project pursuant to a management and operations and
services agreement between AES Sayreville and AES Red Oak.
The Facility will have a nominal 832 MW (ISO) designed electric generating
capacity and will be comprised of the following major equipment: three SWPC
model 501FD CTs and generators, three unfired, three pressure level reheat heat
recovery steam generators ("HRSGs"), one multicylinder reheat condensing steam
turbine ("ST") with hydrogen cooled generator, one water cooled condenser using
a forced draft cooling tower, one integrated plant distributed control system,
and balance of plant ("BOP") equipment including pumps, transformers, power
electrics, etc.. The CTs, the ST, and their associated generators will be
located indoors. The two HRSGs and associated auxiliary equipment will be
located outdoors.
The Facility will be dispatchable but will be capable of operating on a
continuous basis. The CTs will only burn natural gas supplied by way of a
pipeline. Each CT will be coupled with a three pressure level reheat HRSG that
will generate steam to operate the ST. Electrical generators connected to the
three CTs and the ST will be connected to the switchyard through individual
generator step up transformers. These transformers will raise the generated
voltage to 230 kV for connection into the PJM interconnected electrical system.
The Facility will obtain its raw water supply requirements from two sources: the
primary source is South River and the Duhernal acquifer is the back-up water
source. The Facility will discharge wastewater to the Middlesex County Utility
Authority wastewater treatment facility.
Electrical power produced by the Project will be sold to Williams Energy
Marketing & Trading Company ("Williams") under the terms of a 20-year Tolling
Agreement. The Tolling Agreement calls for Williams to purchase Facility
capacity, ancillary services, and fuel conversion services pursuant to the terms
of the Tolling Agreement. In addition, the Tolling Agreement provides for the
supply and transport of the natural gas to the Facility by Williams. The natural
gas will be supplied by way of a pipeline to the delivery point at the site.
Following expiration of the 20-year term of the Tolling Agreement, the Facility
will be operated as a merchant power plant. AES Red Oak will be responsible for
the procurement of fuel and will sell its output directly into the PJM power
pool (or pursuant to bilateral contracts).
Under the terms of the EPC Contract, Raytheon Engineers & Constructors ("RE&C"),
will act as the primary Contractor and will be responsible for the engineering,
procurement, and construction of the Project on a turnkey, lump-sum basis.
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AES personnel will operate the Facility pursuant to a Management and Operations
Services Agreement ("Operations Agreement") between AES Sayreville and AES Red
Oak. The Project will purchase CT parts, shop repairs, and scheduled outage
services from SWPC pursuant to the Maintenance Services Agreement.
1.2 CONCLUSIONS
Set forth below are the principal findings and conclusions which Stone & Webster
has reached regarding the Project. For a complete understanding of the
estimates, assumptions, and calculations upon which these findings and
conclusions are based, THIS REPORT SHOULD BE READ IN ITS ENTIRETY.
1. The Facility design, as specified in the EPC Contract, is in accordance
with standard industry practice. RE&C possesses the organization and
personnel to execute its obligations under the EPC Contract and is
familiar with the construction and maintenance of large electrical
generation facilities. The Project construction schedule proposed by RE&C
is achievable and is consistent with the terms of the Tolling Agreement.
2. SWPC possesses the organization and personnel to execute its obligations
under the Maintenance Services Agreement.
3. Stone & Webster views the W501FD technology as a refinement on the W501F
technology, which has been in operation since 1993, and is typical of
normal design improvements by manufacturers. The 501FD technology is
similar to the W501FA and W501FC technology, but incorporates advances
in low NO(x) combustion technology, compressor and blade designs, and
cooling technology. There are approximately 25 W501F technology units
in operation, with over 500,000 hours of operating history, and
additional 68 W501F technology units, which will be operational prior
to or concurrently with the Project. The W501FD design was introduced
to the marketplace in 1998 and the first W501FD units are scheduled to
commence commercial operations in the first half of 2000. Thirty-seven
W501FD's have been sold to date in the United States alone, and 38
W501FD units will be in operation prior to, or concurrently with the
Project. Three W501FC units (LS Power's Whitewater and Cottage Grove
and Empire State Line Unit 2) have upgraded their compressors to the
501FD design and these units have been operating since mid-1999.
4. The steam turbine and electrical generator designs are acceptable and in
accordance with standard industry practice.
5. If designed and constructed in accordance with the EPC Contract and
operated and maintained in accordance with the Maintenance Services
Agreement and the Operations Agreement, the Facility should be capable of
meeting the net output contract requirements specified in the Projected
Operating Results. The useful life of the Project, provided it is
maintained as in the Project Agreements, should exceed the life of the
bonds.
6. The liquidated damages provisions of the EPC Contract are reasonable. The
one year warranty period is acceptable based on the commercial terms of
the EPC Contract in conjunction with the one year warranty in the
Maintenance Services Agreement. These two agreements, although
independent, are complementary and afford the Project a greater
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degree of protection than is available from the EPC Contract alone.
The Performance Testing Plan, as specified in the EPC Contract, is
acceptable, customary, and should adequately demonstrate the Project's
performance.
7. Williams possesses the organization and personnel to execute its
obligations under the Tolling Agreement, and is familiar with the
provision of fuel to, and purchase of electricity from, large electrical
generation facilities.
8. The Facility can feasibly be electrically integrated into the PJM system,
and no known transmission limitations will inhibit the feasible
evacuation of the Facility's full net capacity both under summer and
winter conditions.
9. Stone & Webster will independently verify the design of the water
pipeline when it becomes available. Stone & Webster does not know of any
reason why the Borough of Sayreville should be unable to perform its
obligations under the WSA.
10. AES Sayreville, as an affiliate of AES and with the assistance of SWPC
under the terms of the Maintenance Services Agreement, should be capable
of operating and maintaining the Facility in accordance with standard
industry practices.
11. The technical requirements described in the Project Agreements are
comprehensive, reasonable, and achievable as well as consistent within
and between the various documents.
12. The Phase I environmental site assessments, conducted by TRC, indicated
no significant environmental issues. The assessments were performed in
accordance with standard industry practice, and the results appear
reasonable.
13. A majority of the Project's required permits have been acquired and the
Project's permit acquisition plan for those permits not yet required is
reasonable.
14. AES Red Oak filed for certification of the Facility as an Exempt
Wholesale Generator ("EWG") under the applicable rules of the Federal
Energy Regulatory Commission ("FERC") on September 13, 1999. On November
4, 1999 FERC found that AES Red Oak is an exempt wholesale generator as
defined in section 32 of the Public Utility Holding Company Act of 1935
("PUHCA").
15. Assuming the Facility is constructed, operated, and maintained in
accordance with the terms of the EPC Contract, Tolling Agreement, the
Operations Agreement, and the Maintenance Services Agreement then it is
reasonable to assume that the Facility will be able to operate in a
manner consistent with applicable permit limits for a period at least
equal to the term of the Bonds.
16. The Project's EPC Contract price is competitive relative to similar
facilities and the Project's proposed operating and maintenance expenses
are consistent with other comparable projects.
17. The technical assumptions utilized in the ICF Resources Market Assessment
of PJM and the Red Oak Plant are reasonable.
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18. Stone & Webster reviewed the technical and commercial assumptions and the
calculation methodology of the Project financial pro forma model. The
technical assumptions assumed in the Projected Operating Results are
reasonable and are consistent with the Project Agreements. The financial
pro forma model fairly presents, in our judgment, projected revenues and
projected expenses under the Base Case Assumptions. Therefore, the
Projected Operating Results are a reasonable forecast of the Company's
financial results under the Base Case Assumptions.
19. The principal amount of the Bonds, when combined with the equity
contributions and interest earned during the construction period, should
be sufficient to pay the costs of constructing the project and interest
on the Bonds through the end of the construction period.
20. The projected revenues from the sale of capacity and energy are more than
adequate to pay the annual operating and maintenance expenses (including
provisions for major maintenance), other operating expenses, and debt
service based on Stone & Webster's studies and analyses of the Project
and the assumptions set forth in this Report. The average and minimum
debt service coverage ratios ("DSCR's") for the full term of the Bonds
are 3.16x and 1.55x, respectively. The average and minimum DSCRs during
the PPA period are 1.57x and 1.55x, respectively. The average and minimum
DSCRs during the Post-PPA period for the debt are 7.13x and 6.37x,
respectively.
21. Assuming deficiencies of up to 6% for heat rate and 4% for capacity, the
average DSCRs over the term of the Bonds, after payment of the rebates by
RC&E due to a failure to achieve heat rate and capacity guarantees, are
projected to remain approximately the same as the DSCRs in the Base Case.
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2. SCOPE OF WORK
Stone & Webster was retained to perform a review of the Project in accordance
with a September 24, 1999 agreement with AES Red Oak, Inc. The review was
conducted by Stone & Webster for the purpose of producing this Report on behalf
of Lehman Brothers as Initial Purchaser of certain Rule 144A bonds to be offered
in the United States by AES Red Oak pursuant to rule 144A under the Securities
Act of 1933 as amended to finance the construction and initial start-up and
testing of the Facility, which bonds are to be issued to qualified institutional
buyers and institutional accredited investors and in offshore transactions
complying with Regulation S under the Securities Act of 1933. The scope of the
Review included the following:
- SWPC 501FD CT proposed as the technology basis of the Project
- Projected performance of the Project
- Projected Operating & Maintenance ("O&M") expenses
- Conceptual design and interfaces of the Project
- Project Phase I site assessments
- Issued permits for the Project
- Technical assumptions utilized in the PJM market study of [January 11,
2000], prepared by ICF Resources
- Projected operating results in the Project financial pro forma model
Stone & Webster also reviewed the Tolling Agreement, the Interconnection
Agreement, the EPC Contract, the Maintenance Services Agreement, the WSA, and
the Agreements Relating to Real Estate from a technical and economic standpoint
to assess the adequacy and reasonableness of their terms and conditions. Stone &
Webster has made no determination as to the validity and enforceability of the
Project Agreements. However, for the purposes of this Report, we have assumed
the Project Agreements will be fully enforceable in accordance with their
respective terms and that all parties will comply with the provisions of their
respective agreements.
Stone & Webster conducted a site visit on October 22, 1999 and made general
field observations, specifically the existing above ground condition of the
site. During the review, Stone & Webster reviewed Project information and
interviewed representatives of AES to verify the adequacy of the Facility design
and site and the reasonableness of the technical assumptions.
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3. FACILITY DESIGN
Stone & Webster reviewed the design of the Facility and its major components and
interface designs, as specified in Appendix A of the EPC Contract. Stone &
Webster is of the opinion that the Facility design, as specified in the EPC
Contract, is in accordance with standard industry practice and that, if designed
and constructed in accordance with the EPC Contract and operated and maintained
within standard industry practices, the Facility should be capable of meeting
the net output contract requirements specified in the Projected Operating
Results. The useful life of the Project, provided it is maintained as in the
Project Agreements, should exceed the life of the bonds.
3.1 FACILITY DESCRIPTION
The Facility is designed to have a nominal 832 MW electric generating capacity
at ISO conditions and will consist of the following major equipment and
configuration: three SWPC model W501F Econopac CTs with air cooled generators
firing only natural gas, with each CT exhausting separately to three unfired,
three pressure level reheat HRSGs, each of which provide steam to the
multi-cylinder reheat condensing ST with hydrogen-cooled generator. The Facility
also includes a forced draft cooling tower, one integrated control system, water
treatment facilities, a central control, an electrical switchgear room,
administrative and maintenance buildings, and a 230 kV switchyard. The CTs are
equipped with evaporative inlet air coolers and dry low NO(x) ("DLN") combustion
system. The HRSGs are equipped with CO catalysts to reduce carbon monoxide
emissions and SCR to reduce NO(x) emissions. The facility design includes a 100%
ST bypass.
The CTs, the ST, and their associated generators will be located indoors. The
HRSGs and associated auxiliary equipment will be located outdoors. The Facility
will be dispatchable but will be capable of operating on a continuous basis. Due
to the dispatchable nature of the Facility, operation will include periods of
part-load operation (between 70% and 100% of turbine load) and may require
periodic start-ups and shutdowns.
The Borough of Sayreville will provide the Facility's water supply for cooling,
makeup, and maintenance from the South River reservoir or the Duhernal water
system. Potable water will be supplied by way of an interconnection to the
Borough of Sayreville's treated water pipeline system. The Borough of Sayreville
is responsible for designing the Lagoon Water Pipeline, the Lagoon Pumping
Station, and the Sayreville Interconnection Number 2 (tie-in at Jernee Mill
road). AES Red Oak will arrange for construction of these facilities and deed
the completed facilities back to the Borough of Sayreville. The Facility process
and sanitary wastewater discharge will discharge to the Middlesex County
Utilities Authority ("MCUA") through an existing sewer line that runs along
Jernee Mill Road. The switchyard will tie in the JCP&L system at the 230 kV
transmission line that runs adjacent to the northeast Facility property line.
Major equipment deliveries will be made by the Conrail line that runs adjacent
to the west of the Facility property, near the main entrance. Deliveries and
construction traffic should not be a problem since the Facility is located in an
industrial area of town. The current proposal by Williams, the gas supplier and
power off-taker, is to bring gas to the site by tying into the existing gas main
running along Jernee Mill road, or they may build an approximately 0.5 mile spur
line from the 42-inch Transco main line near the Florida Power and Light Company
to the south of the Facility along the Conrail Raritan River rail line right of
way. Either option will work
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independently. The EPC Contract states that the natural gas conditions at the
site boundary will be 575 psig and 70DEG.F. The pressure at the Transco
42-inch compressor station is typically 800 to 900 psig. This pressure would
have to be let down which will cool the gas. Provision would have to be included
to heat the gas so that it meets the 70DEG.F minimum temperature at the site
boundary. Stone & Webster reviewed pressure data from the Sayreville metering
station for the period April 1, 1998 to March 31, 1999. During that period the
pressure dropped below 550 psig for 39 hours. The pressure was below 600 psig
for 541 hours. Although the EPC Contract specifies 575 psig, pressures down to
525 psig should not result in any load limitations to the operation of the
facility. The water, wastewater, and gas line connections to the Facility from
Jernee Mill road will be buried along the Facility access road inside the
60-foot easement.
The Facility will include the following major structures: a 250 ft x 510 ft open
air switchyard, a fully-enclosed, approximately 81,400 square feet, 65-foot tall
power generation building to house three CTs, generators, and associated
equipment. The three HRSGs, the three 150 feet stacks and auxiliaries will be
located outside immediately west of the power generation building. Other
significant equipment located within the HRSG area includes a 450,000 gallon
service/fire water storage tank, clarifier, and a 100,000 gallon condensate
storage tank. The ten-cell cooling tower will be located north of the power
generation building and AES Red Oak switchyard. The Facility will include site
access drives, a 17-space parking area, and an approximately 9,000 sq. ft.
warehouse/maintenance shop and administration building.
3.2 SITE LOCATION AND DESCRIPTION
The Facility is situated on approximately 62 acres in the Borough of Sayreville,
Middlesex County, New Jersey. The property is located in Sayreville's SED 2 M-2
Heavy Industrial Zone and is currently undeveloped with no utility service.
Access to the site will be by way of approximately one quarter mile, 30 foot
wide existing access roadway from Jernee Mill Road. The access roadway will be
within a 60 foot wide easement. AES Red Oak intends to clear 18 acres of
woodland on the site to use as construction laydown and then will replant 14
acres of this land after construction. The nearly 30 acre foot print of the
Facility will be placed on existing cleared land used by the previous owners,
Mink Run Construction. The balance of the property is considered wetlands and
will not be developed.
The project site is located in southwest Sayreville, east of Jernee Mill Road
and adjacent to the Conrail Raritan River rail line right-of-way. Cheesequake
Road is the nearest road to the east of the site. Undeveloped woodlands are
located adjacent to the north and northwest of the proposed project site. The
Conrail Raritan River west-east rail line lies approximately 1,000 feet north,
with Washington Road and residential streets of Sayreville beyond. The
intersection of the north-south and west-east Conrail Raritan River rail lines
is located approximately 1,000 feet northwest of the subject site. Adjacent to
the northeast and east of the subject site are undeveloped woodlands, and a
large manufacturing plant owned by Hercules, Inc. ("Hercules"). E.I. DuPont de
Nemoirs Company ("DuPont") is located further to the northeast across
Cheesequake Road. To the southeast is a right-of-way for standard power lines
and a steam line owned by Hercules, with undeveloped woodlands beyond. Adjacent
to the south is the fence line of lands also owned by Hercules; this area is
currently inactive but previously contained another large manufacturing
operation of Hercules. To the west of the proposed project site is the Conrail
Raritan River rail line north-south right-of-way, as mentioned above. Another
former industrial site, which is now a vacant grassed/woodlands area owned by
Pfizer, Inc. ("Pfizer"), lies between the railroad and
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Jernee Mill Road. Further west, across Jernee Mill Road is the
Celotex/Sayreville Landfill property.
The October 22, 1999 site visit, combined with a review of Project documents
provided by AES formed the basis for our opinion regarding the site. In
particular, Stone & Webster relied on the ESA reports prepared by TRC
Environmental in July 1999.
Stone & Webster believes that the site is acceptable for the proposed facility.
3.3 COMBUSTION TURBINE GENERATOR
The AES Red Oak will install three SWPC W501F Econopac heavy-duty combustion
turbine generators ("CTG") of the FD design. The FD model is the latest offer in
the F-class CT, which was initially developed under an international partnership
with Mitsubishi Heavy Industries and Rolls Royce. Plants with W501F-class
technology have been in operation since 1993 and have over 500,000 hours of
operation. The FD design was introduced to the market place in 1998 and the
first W501FD will be in commercial operation in the Spring of 2000. The main
difference between the W501FC and W501FD machines is the compressor section.
Three W501FC units (LS Power's Whitewater and Cottage Grove and Empire State
Line Unit 2) have upgraded their compressors to the 501FD design and these units
have been operating since mid-1999.
Stone & Webster prepared a listing of W501F-class CTs, which are in operation or
will be in operation before or in the same year as the Project. The list in the
following table is based on SWPC January 2000 published information.
<TABLE>
<CAPTION>
=============================================================================================================
PROJECT UTILIZING 501F-CLASS
=============================================================================================================
CUSTOMER STATION COUNTRY QUANTITY OPERATION DATE
------------------------------------- ------------------- ---------------- ------------- --------------------
<S> <C> <C> <C> <C>
Florida Power & Light Co. Lauderdale USA 4 1993
------------------------------------- ------------------- ---------------- ------------- --------------------
Korea Electric Power Co. Ulsan Korea 4 1996
------------------------------------- ------------------- ---------------- ------------- --------------------
Tenaska IV Brazos USA 1 1996
------------------------------------- ------------------- ---------------- ------------- --------------------
LS Power Whitewater USA 1 1997
------------------------------------- ------------------- ---------------- ------------- --------------------
LS Power Cottage Grove USA 1 1997
------------------------------------- ------------------- ---------------- ------------- --------------------
Empire State Line Unit 2 USA 1 1997
------------------------------------- ------------------- ---------------- ------------- --------------------
Termosflores Las Flores Columbia 1 1997
------------------------------------- ------------------- ---------------- ------------- --------------------
Termomerilelectrica Merilelectrica Columbia 1 1997
------------------------------------- ------------------- ---------------- ------------- --------------------
Calpine Pasadena I USA 1 1998
------------------------------------- ------------------- ---------------- ------------- --------------------
Termovalle Termovalle Columbia 1 1998
------------------------------------- ------------------- ---------------- ------------- --------------------
Florida Power Corp. Hines USA 2 1998
------------------------------------- ------------------- ---------------- ------------- --------------------
InterGen TermoEmcali Columbia 1 1998
------------------------------------- ------------------- ---------------- ------------- --------------------
CFE El Sauz Mexico 1 1998
------------------------------------- ------------------- ---------------- ------------- --------------------
CFE Hermosillo Mexico 1 1998
------------------------------------- ------------------- ---------------- ------------- --------------------
CFE Huinala Mexico 1 1998
------------------------------------- ------------------- ---------------- ------------- --------------------
Carolina Power & Light USA 1 1999
------------------------------------- ------------------- ---------------- ------------- --------------------
El Dorado Energy El Dorado USA 2 1999
------------------------------------- ------------------- ---------------- ------------- --------------------
KMR Power TermoCandelaria Columbia 2 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
Enron Penuelas Puerto Rico 2 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
</TABLE>
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<TABLE>
=============================================================================================================
PROJECT UTILIZING 501F-CLASS
=============================================================================================================
<S> <C> <C> <C> <C>
PREPA Abengoa Puerto Rico 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
AES Merida Mexico 2 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
Nova Chemical Canada 2 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
CLECO Coughlin USA 3 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
Dynegy Rockingham USA 5 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
LS Power Batesville USA 3 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
Calpine Pasadena II USA 2 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
AES Uruguaiana Brazil 2 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
Dynegy Calasieu USA 1 2000
------------------------------------- ------------------- ---------------- ------------- --------------------
Enron Peakers USA 3 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Dynegy Phase III USA 4 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Calpine Sutter USA 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Seminole Electric Coop USA 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Klamath Falls USA 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Calpine Southpoint USA 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Empire State Line Unit 3 USA 1 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Calpine Lost Pines USA 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Aquilla/Utilcorp Pleasant Valley USA 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
EDF Rio Bravo Mexico 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
EDF CFE Saltillo Mexico 1 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Reliant Desert Basin USA 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Alabama Electric Coop USA 2 2001
------------------------------------- ------------------- ---------------- ------------- --------------------
Philippines Philippines 1 2002
------------------------------------- ------------------- ---------------- ------------- --------------------
Mid America Cordova USA 2 2002
------------------------------------- ------------------- ---------------- ------------- --------------------
Dynegy V USA 5 2002
------------------------------------- ------------------- ---------------- ------------- --------------------
Calpine Baytown USA 3 2002
------------------------------------- ------------------- ---------------- ------------- --------------------
Reliant Echo Star USA 4 2002
------------------------------------- ------------------- ---------------- ------------- --------------------
Total 93
=============================================================================================================
</TABLE>
For AES Red Oak project, each CTG is an indoor installation package CT power
plant. The CTG will be started by electric motor. Instruments and controls are
supplied as part of the CTG package. The CTG control system is a microprocessor
based control system. The CTs will be equipped with DLN combustors and fueled
with natural gas only. The gas fuel specification as indicated in GMS2 Gas
Analysis Report has been acceptable to SWPC as noted in their letter of June 21,
1999 contained in Section V.b of Appendix A to the EPC Contract. Natural gas
compressors are not provided based on the normal range of 600 psig to 700 psig
gas line pressure.
3.3.1 COMPRESSOR SECTION
Appendix A of the EPC Contract states that the compressor is a 16-stage axial
flow design operating at a nominal pressure ratio of 16:1. The compressor design
has been upgraded from the previous 501F engines by increasing the mass flow and
efficiency of the compressor. Increasing the flow area of the first two
compressor stages raised the mass flow. Compressor efficiency gains are obtained
through the use of the advanced airfoil design. The compressor is also equipped
with variable inlet guide vanes to improve the compressor low speed surge
characteristic and to improve part load performance in combined cycle operation.
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As with all W501FD designs, the blade and rotor design allow the blades to be
removed in the field with the rotor in place. The first two stages use 17-4 pH
stainless steel material to maintain strength and safety. The stationary blades
are fabricated into two 180DEG. diaphragms for each stage to facilitate
removal.
Improvements are being made to the W501FD inner shroud design welds on the
compressor stages 1, 2, and 3. The first W501F with the new compressor design
will operate in February 2000, which will give AES Red Oak an opportunity to
benefit from any lessons learned on the improve weld configuration.
3.3.2 COMBUSTOR SECTION
A standard combustion system consists of 16 can-type annular DLN combustors
configured to burn natural gas. The presence or absence of flame and the
uniformity of the fuel distribution between combustors will be monitored by
thermocouples located downstream of the last stage turbine blades. These can
also detect combustor malfunctions when at load. Improvements in the 501FD
include the addition of local cooling in the transition piece between the
combustion outlet and the row 1 turbine stator vane segments to control local
overheating.
3.3.3 TURBINE SECTION
The power turbine is a 4-stage design. The row 1 single vanes are removable,
without any cover lift, through access man-ways within the combustor shell.
ECY768 cobalt base alloy is used for rows 1 and 2 vanes and X45 cast material
for rows 3 and 4 vanes. The new row 4 turbine blade was changed to increase the
maximum output capability of the CT and will use CM247 material.
Each row of vane segments is supported in a separate blade ring, which is keyed
and supported to permit radial and axial thermal response independent of
possible external cylinder distortions. Blade ring distortion can be further
minimized by the use of segmented isolation rings that support the vane segments
and by the use of ring segments over the rotor blades to form a thermal barrier
between the flow path and the blade ring.
The brazing process for W501 F-class row 1 turbine blades and vanes has been
improved and the FD units will have INCO738 material for tip plates to close the
core exits to avoid thermal distress.
The cooling air circuit for the turbine section is the same as those used on the
earlier W501Fs. This cooled and filtered air provides a blanket of protection
from hot blade path gases and eliminates excessive contaminants that could block
critical cooling passages of the rotor blades.
Direct compressor discharge air is used to cool the row 1 vane and inter-stage
compressor bleed air is used to provide cooling air to vane and turbine stages
2, 3, and 4. This cooling should preclude the exposure of inter-stage seals and
disc faces from the hot blade path gases. The row 1 vane, which has the highest
hot blade path gas temperature has a cooling design of combined film cooling
holes and impingement and a trailing edge pin-fin system. Film cooling is used
at the leading edge as well as at selected pressure and suction side locations.
This should limit vane wall thermal gradients and external surface temperatures.
Pin fins are used to increase turbulence and surface area to improve the
trailing edge cooling effectiveness.
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The next highest temperature component is the first stage rotating blade. The
blade is cooled by a combination of convection techniques by way of multi-pass
serpentine passages and pin-fin system in the trailing edge. Air supply for
blade cooling is high pressure compressor discharge air that has been cooled and
filtered and returned to the turbine rotor by way of supply pipes in the
combustor shell. Cooling air flows outward through slots in the blade root and
is conveyed radially through the blade shank. Impingement and shower-head film
cooling are used for the leading edge region.
SWPC continues to optimize the blade cooling circuits. The optimization process
also incorporates lessons learned experience and should result in greater
product integrity.
3.3.4 CTG CONCLUSIONS
The W501FD CT is the latest technology offered by SWPC in the W501 F-class. The
W501FD design combines the latest in low NO(x) combustion technology, advances
in compressor design, blade designs and materials, and cooling schemes. It has
incorporated improvements and lessons learned experience of the prior models
such as W501FA and FC. The result is an advanced design, high-temperature,
efficient, low NO(x), more powerful CT that is based on proven design concepts
that have evolved with the development of the W501 F-class CTs.
The W501F technology was initiated around 1985 as a joint effort project with
Japan's Mitsubishi Heavy Industries. Basically, the W501F technology combines
advanced component and design technology from a variety of different sources
available to the companies and the result is an industrial machine based on
field proven design practices. Today, there are many F-class CTs in operation
with excellent records.
It is our understanding that the nominal rotor inlet temperature ("RIT") will be
the same as current W501Fs, which is approximately 2435DEG.F. The excellent
operating data from the four FP&L's Ft. Lauderdale W501 F- class units has
provided much of the experience that led to the 2435DEG.F materials, coatings,
and cooling arrangements. This experience has been applied to the later W501F
designs where applicable. We also know the predecessor FC model was designed for
a similar firing temperature and appears to be operating well. Based on our
knowledge of the FC designs and its field operating data, we believe SWPC has
the experience to handle the 2435DEG.F RIT temperature as a proven technology.
Stone & Webster views the W501FD technology as a refinement on the W501F
technology, which has been in operation since 1993, and is typical of normal
design improvements by manufacturers. The 501FD technology is similar to the
W501FA and W501FC technology, but incorporates advances in low NO(x) combustion
technology, compressor and blade designs, and cooling technology. There are
approximately 25 W501F technology units in operation, with over 500,000 hours of
operating history and additional 68 W501F technology units, which will be
operational prior to or concurrently with the Project. The W501FD design was
introduced to the marketplace in 1998 and the first W501FD units will commence
commercial operations in the Spring of 2000. Thirty-seven W501FD's have been
sold to date in the United States alone, and 38 W501FD units will be in
operation prior to, or concurrently with the Project. Three W501FC units (LS
Power's Whitewater and Cottage Grove and Empire State Line Unit 2) have upgraded
their compressors to the 501FD design and these units have been operating since
mid-1999.
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3.4 HEAT RECOVERY STEAM GENERATOR
Stone & Webster reviewed the functional specification and scope of supply
provided in the EPC Contract Appendix A. A letter of intent has been signed
between RE&C and Foster Wheeler to provide the HRSGs. Stone & Webster reviewed
the detailed design specifications. The functional specification as included in
Appendix A of the EPC Contract describes the HRSGs as being a horizontal design
configuration, natural circulation, three-pressure level type. Each HRSG will be
installed with a catalyst for NO(x) and CO emission reduction. The HRSGs will
have no duct firing capability. The HRSGs will be designed in accordance with
the ASME BPVC Section 1 for the three HRSG units, Section VIII for Pressure
vessels.
Foster Wheeler's proposal 298-284, dated June 8, 1999, was also reviewed for AES
Red Oak. The HRSGs are manufactured in Canada. The scope of work is well
defined, and includes; the pressure parts (complete economizers, evaporators,
superheaters, reheaters), inlet ducting with expansion joints, insulation,
interconnecting piping, platforms and walkways, SCR and CO catalysts, erection
and start-up assistance and spare parts (start-up). Options are provided for
outlet ducting, stack, silencer, EPA connections and access, and erection. The
HRSG heat transfer layout and details for this application is limited to 50 feet
of finned height. A QA plan is outlined. P&IDs for the major systems are
provided, signifying a standardized HRSG design for this CT class.
Stone & Webster's opinion is that the HRSG scope description is suitable for the
Project and in accordance with standard industry practice.
3.5 STEAM TURBINE
The ST will be a model TC2F two case tandem compound design with a double flow
low pressure element. The ST will be directly connected by a rigid coupling to a
hydrogen inner-cooled generator.
The ST will consist of a primary turbine inlet, combined high pressure ("HP") /
intermediate pressure ("IP") turbine, and the double flow low pressure ("LP")
turbine. The primary steam supply sources to the turbine are main, reheat steam,
and LP admission. The main steam controls the steam flow to the turbine, reheat
steam inlet, and LP admission valves. The HP/IP turbine receives steam from the
main steam and reheat steam supply and converts it to rotational power to drive
the generator. The LP turbine receives steam from the IP exhaust by way of the
crossover piping and the LP admission and converts it to rotational power to
drive the generator. The last stage blade design has been given as being a
33 1/2, this design has a 33 1/2 inch vane section. Stone & Webster assumed in
our evaluation a 66.1 square foot exhaust annulus area.
With respect to operational experience, Toshiba provided an experience list
showing one existing unit of similar configuration. With an assumed exhaust flow
rate of 5.9 lb/kW the resulting exhaust flow is 1,630,000 lb/hr, which leads
Stone & Webster to believe that the exhaust velocity would approach 792 ft/sec
and an exhaust loading of 12,330 lb/hr/sq.ft.. Based on our assumptions these
values are within Toshiba's experience and are considered by Stone & Webster to
be acceptable. Stone & Webster's opinion is that the ST design is acceptable and
in accordance with standard industry practice.
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3.6 ELECTRIC GENERATORS
3.6.1 STEAM TURBINE ELECTRIC GENERATOR
The ST's electric generator is designated by as a model "TAKS - ICH". The
generator will be hydrogen inner-cooled synchronous 3600 rpm, 60 Hz machine
rated at 330,000 kVA at 18 kV. The generator will be designed for a leading
power factor of 0.95 and a 0.85 lagging power factor at the generator terminals
at 60 psig hydrogen gas pressure. The generator will have Class F insulation
with Class B temperature rise for both the stator and the rotor. The stator
winding will be indirect hydrogen cooled and the field will be direct hydrogen
cooled. The generator will have a short circuit ratio of not less than 0.50 at
nominal capacity and is to be fabricated in accordance with ANSI standards
C50.10, C50.13, and C50.14, as appropriate.
Despite the fact that the generator, as described in the EPC Contract, utilizes
a design with no operating experience, it appears to be sized properly. The
generator design from which the proposed generator was most likely developed was
rated at 300,000 kVA, 17 kV, 3600 rpm, and 0.85 P.F.. It was first introduced in
1970 for Korea Electric Power Corp at their Inchon Station. However, only two
units of this design were built (both at Inchon) and operational history is not
available.
According to the Toshiba experience list, all of their operating experience
above 300,000 kVA included (direct) water-cooled stator windings; therefore the
proposed hydrogen cooled design is an evolution in the design. The hydrogen
cooled design results in a longer stator than a water-cooled design. In order to
prevent any potential core vibration that would be transmitted to the stator
frame or foundation Toshiba has included a spring support. Stone & Webster is of
the opinion that the generator design is acceptable
3.6.2 COMBUSTION TURBINE ELECTRIC GENERATOR
The CTs' electric generators are designated as a frame 2-95x200. The generators
will be air-cooled (TEWAC) synchronous 3600 rpm, 60 Hz machines rated at 208,000
kVA at 18 kV. The generators will be capable of providing a 0.85 lagging power
factor and a 0.95 leading power factor (measured at the generator). The
generators will have Class F insulation (with Class F temperature rise) for both
the stator and field winding systems. The generators will have a short circuit
ratio of 0.51 and will fabricated in accordance with ANSI standards C50.10,
C50.13, and C50.14, as appropriate.
The generator appears to be sized properly. The proposed generator was first
applied to the Nova Chemical project in Canada and is currently in
commissioning. The design was created for the 501FD product line, as a
replacement for the hydrogen cooled design (frame 2 - 97 X 122) that was
provided with the previous 501 FC designs. According to SWPC, 45 generators for
the 501FD product line of this design have been sold.
Stone & Webster believes that the generator design is acceptable and in
accordance with standard industry practice.
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3.7 SELECTIVE CATALYTIC REDUCTION
Foster Wheeler Energy Corporation ("FWEC") will provide the SCR. The SCR process
adds diluted ammonia to the flue gas at an automatically controlled rate. This
mixture is then passed through catalyst layers, which converts the NO(x) to
harmless nitrogen and water vapor. The nitrogen and water vapor are then
released through a stack. FWEC currently has 47 SCR installations.
3.8 BALANCE OF PLANT SYSTEMS
Stone & Webster reviewed the general configuration of the Facility BOP systems
identified in this section. These systems although important do not generally
take on as high degree of risk significance as the main power island. Stone &
Webster's BOP system review focused on ensuring that the specific system designs
were consistent with the current industry practice. As is typical of a project
at this phase in design, the final detailed system and component technical
information that is developed during the detailed design phase and is required
to independently verify a system's capabilities was not available for Stone &
Webster's review. The conceptual description of the BOP systems and Stone &
Webster's opinions are described in the following sections.
In general, Stone & Webster is of the opinion that the BOP systems described
below are consistent with present day industry practice and any individual
issues identified during our review are presented in their respective sections.
Based on the review of the EPC Contract, the BOP systems are being designed in
accordance with acceptable codes and standards and with sufficient redundancy,
so that the failure of any critical component will not reduce the Plant's
reliability. RE&C has included in Appendix A to the EPC Contract a satisfactory
vendor bidder list for the BOP equipment.
3.8.1 FEEDWATER SYSTEM
The feedwater system will consist of three 50% capacity HP boiler feed pumps
("BFP") common to all HRSGs, which take suction from the HRSGs LP economizer
outlet. The HP discharge from each pump will be discharged to a common header
and piped to the HP economizer of each HRSG. The interstage discharge from each
pump will discharge to a common header and will be routed to the IP economizer.
A BFP recirculation line with control valve will be provided for each of the
BFPs. A control valve will be provided on each of the HP and IP headers for
respective drum level controls. Each BFP is provided with a warm-up line, which
maintains an idle pump(s) in a ready condition while the other pump(s) are in
operation. Chemical feed equipment will feed amine and oxygen scavenger to the
condensate pump discharge and phosphate to each of the three HRSG drums.
3.8.2 CONDENSATE SYSTEM
The system will consist of two 100% capacity vertical, can type, centrifugal
condensate pumps, which take suction from the condenser hotwell. The condensate
pumps are located in a pit at the ground floor near the condenser hotwell. The
condensate flows from the condenser hotwell into a header. The header
distributes the flow to either condensate pump. A recirculation line located
downstream of the gland steam condenser assures minimum flow through the
condensate pumps.
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Two vent lines are provided for each condensate pump. One from the pump
discharge elbow with a normally closed isolation valve, the other from the high
point of the pump suction can with a locked open isolation valve. The condensate
is deaerated in the condenser in order to remove oxygen and other
non-condensable gases and thus prevent corrosion and prevent equipment from
becoming air-bound. The condensate is chemically treated by injecting ammonia
and hydrazine to adjust the pH level, scavenge residual oxygen, and thus
minimize corrosion.
The Plant is not provided with a separate deaerator and is relying strictly on
the condenser design to remove gases from the condensate. This practice is very
common today. However, it must be recognized that the deaeration performance in
the condenser is reduced during start up and at low load. The cycle chemistry
must be carefully monitored and the use of additional oxygen scavenger during
these periods may be necessary to avoid accelerated corrosion.
The condenser will be a two pass, single shell and tube, deaerating type
specifically designed for steam surface condenser service. The tube material
will be 304 stainless steel. This unit will be designed to condense the steam
from the turbine with circulating water temperature of 93DEG.F while maintaining
3.0 in. Hga pressure. The equipment will be designed and constructed in
accordance with Heat Exchange Institute ("HEI") standards. The condenser is
located below the turbine, between the operating and ground floors.
The air evacuation system is capable of removing air and other non-condensable
gases from the condenser steam space, which includes the condenser volume with
hotwell empty, as well as the condenser neck, and the low pressure turbine
casings, prior to or during plant startup. The system is also able to remove air
in-leakage as well as other non-condensable from the condenser during normal
operation. The system includes one steam jet air ejector for start-up and one
jet air ejector for holding vacuum. The steam jet air ejectors will be designed
to handle the capacity recommended in the HEI Standards for steam surface
condensers and will be sized for 100% capacity. A vacuum breaker line with a
motor operated gate valve is provided to break the vacuum in the condenser in
emergencies.
3.8.3 RAW WATER SYSTEM
The Borough of Sayreville will provide the Facility's water supply for cooling,
makeup, and maintenance from the South River reservoir or the Duhernal well
water system. The Borough of Sayreville is responsible for designing the Lagoon
Water Pipeline, the Lagoon Pumping Station and the Sayreville Interconnection
Number 2 (tie-in at Jernee Mill road). The water balance developed by RE&C
indicates the daily water demand for cooling and potable use is projected at
4.45 mgd at 54DEG.F (4.63 mgd at 92DEG.F). The primary source of Facility
process water is the South River Reservoir, with Duhernal Well water as a
secondary or backup source. The water sources analyses indicate relatively
low dissolved solids, however the differences in the iron content and low pH
requires a system to elevate the pH and precipitate the oxidized iron. RE&C
will provide a solids contact or Lamella-Type clarifier and associated sludge
handling system, consisting of a thickener, belt press or plate filter and
chemical feed system for feeding caustic, sodium hypochlorite, and a
coagulant aid polymer. After clarification, the water will be pumped to the
cooling tower as makeup to the circulating water system. The remaining water
will be stored in the 450,000 gallons fire/service water tank for use as feed
to makeup the demineralizer and plant service water.
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Stone & Webster reviewed recent analyses of water samples from both the
reservoir and the well system. The calcium, sodium and chlorides contents were
slightly higher than the analysis provided to RE&C, but the difference is within
typical fluctuations in water quality and should have not impact the design or
cost of the water treatment system.
The potable water supply will be supplied by way of an interconnection to the
Borough of Sayreville's treated water pipeline system. The potable cold water
distribution system will supply cold water to all sanitary fixtures, kitchen
sinks, laboratory and work sinks, electrical water coolers and emergency
shower/eye-wash units and other equipment of wash-down facilities as required.
The potable hot water and the return circulation systems will supply hot water
to all the above mentioned fixtures requiring hot water. The hot water systems
originate in the domestic hot water heaters (one for each building requiring hot
water) and will distribute water at approximately 130DEG.F. The potable hot
water system will include electric hot water storage heaters capable of
providing sufficient hot water storage and recovery capacity to meet the maximum
probable demand requirements.
3.8.4 CYCLE MAKEUP SYSTEM
The system includes two 100% trains of demineralizer capacity rated at 80 gpm
net. The equipment in each train consists of a 100% pressure filter mentioned in
the raw water description, one reverse osmosis ("RO") unit, and a set of
electro-deionization ("EDI") stacks. The use of the EDI system will eliminate
the necessity of bulk acid and caustic storage, occasional regeneration and the
neutralization and disposal of regenerant waste. Associated equipment includes
anti-scalant and bisulfite chemical feed skids and a chemical cleaning skid for
the RO unit. When one RO is being cleaned the other unit will continue to
operate. The RO reject will be used as cooling tower makeup. The EDI reject
streams will be returned to the inlet of the RO and/or the cooling tower,
depending on chemistry.
3.8.5 BOILER BLOWDOWN SYSTEM
The boiler blowdown system consists of a single atmospheric flash tank. This is
acceptable if the HRSG is designed to cascade the blow down from the HP drum to
the IP drum and from the IP drum to the LP drum. The LP drum blowdown then is
sent to the blowdown tank. The liquid collected in the blowdown tank is sent to
the cooling tower.
3.8.6 CIRCULATING WATER SYSTEM
The circulating water system consists of a ten wet-cell mechanical draft cooling
tower with underground supply and return piping to the power block. The drift
rate of the cooling tower will be 0.0003%. This drift rate complies with the air
permit requirements. There are two 50% capacity circulating water pumps
installed with an additional third pump and motor in the warehouse. The pumps
will be installed in a pump basin adjacent to the cooling tower. The pump basin
floor will be enclosed with a structural steel superstructure. The
superstructure roof will have removable hatch openings, one above each pump for
maintenance purposes. The circulating water chlorination and electrical
buildings will be located on each side of the pumphouse superstructure. Cooling
tower chemical control will utilize sodium hypochlorite injection to control
biological growth, sulfuric acid (as needed) for alkalinity and pH control, and
will have the capability of feeding either corrosion inhibition or scale control
chemicals as needed.
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3.8.7 AUXILIARY COOLING WATER SYSTEM
The auxiliary cooling water system will consist of closed circuit cooling water
system ("CCCWS") and an open circuit cooling water system ("OCCWS") which is the
cooling tower and circulating water system that serves the main steam surface
condenser.
The CCCWS will consist of two 100% capacity closed cooling water pumps, two 100%
closed cooling water plate heat exchangers, and a closed loop cooling water
surge tank. The head tank, which will be originally filled with condensate
quality water from the demineralizer system, will be located at the highest
point of the equipment cooled on the suction side of the pumps and will provide
constant suction conditions for the pumps. The pumps will discharge to a common
header which will forward the heated water to the closed cycle plate type heat
exchangers, after which cooled water will be supplied to the following
equipment: ST auxiliary coolers, CT auxiliary coolers, BFP coolers, air
compressors, etc. The heat load from the CCCWS will be rejected through the
closed cooling water plate heat exchangers to the circulating water system by
way of the supply and return piping.
The OCCWS will supply the equipment that doesn't require condensate quality
water, but requires colder and greater quantities of cooling water. The
following equipment are projected to be cooled by the OCCWS: closed cycle
cooling water heat exchangers; CT and ST lube oil coolers; ST electro-hydraulic
fluid coolers; ST electric generators hydrogen coolers; and CT electric
generator coolers.
The OCCWS flow requirements for the individual equipment are specified by the
respective equipment manufacturers, based on a maximum cooling water temperature
of 93DEG.F. There are two 100% capacity, horizontal, centrifugal, double
suction, motor driven, open cycle auxiliary cooling water pumps arranged in
parallel. The pumps take suction from the condenser inlet block. The heated
water is returned to the condenser outlet block. The rated capacity of each pump
is equal to the total cooling demand of the equipment, plus a 5% flow margin and
a 10% margin on friction loss. Chlorine is added to the circulating water in the
main cooling tower basin to inhibit biofouling.
3.8.8 FIRE PROTECTION SYSTEMS
A complete and integrated fire protection system will be provided for the plant
for effective detection, warning, means of controlling and extinguishing of
fires. The system will consist of underground yard distribution system to serve
the fire hydrants, water based fire suppression systems, standpipe system,
portable fire extinguishers, and fire pumps. The fire protection system will be
engineered and designed in accordance with the requirements of National Fire
Protection Association ("NFPA") codes and all applicable state and local codes
and regulations as guided by NFPA 850 Standard.
Water supply for the fire protection system will be provided from the
fire/service water storage tank. The fire protection portion of the storage tank
capacity will be calculated to supply simultaneously the largest fixed water
based extinguishing system plus 500 gpm for hose stream demand for a duration of
2 hours. The storage tank will be provided with adequate make-up water from the
local water supply system and will be freeze protected.
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Two electric motor driven fire pumps will be provided to ensure 100% capacity
backup of the fire protection system water supply. Each pump will be capable of
delivering total system requirements at design pressure and flow rate with one
pump out of service. Each pump will be rated at 2,500 gpm at 125 psig. Fire
pumps will be housed in a heated, ventilated and protected building. The fire
pumps, fire pump controllers and auxiliary equipment will conform to NFPA 20,
will be listed by United Laboratories ("UL") and/or approved by Factory Mutual
("FM"). The motors for the two 100% capacity fire pumps are wired to separate
independent transmission systems to ensure 100% capacity backup of the fire
protection system water supply.
Water spray systems will be used in the main transformers, auxiliary
transformers, ST lube oil system, cooling tower, and start-up transformer areas.
Wet pipe automatic sprinkler systems will be used in the turbine building areas
and fire pump house area. A fire standpipe and hose system will be installed
inside the turbine building. This system will supply open rack or cabinet type
hose stations, equipped with 1 1/2 in. flat hose, equipped with nozzles suitable
for safe effective use on identified hazards and involved equipment.
Portable fire extinguishers will be provided throughout the plant in accordance
with NFPA requirements and will be UL listed, and/or FM approved and will be
labeled accordingly. Extinguishers will be provided in readily accessible
locations in conformance with NFPA Standard 10. Carbon dioxide will be used in
areas of low-fire hazard or contain small electrical equipment where cleanup
after the fire is a major consideration, such as the control room, laboratories,
switchgear, and turbine building areas.
3.8.9 WASTEWATER SYSTEM
The Facility wastewater discharge including process wastewater and sanitary
wastewater will discharge to MCUA through an existing sewer line that runs along
Jernee Mill Road. Under average operating conditions, the total process
wastewater has been estimated at 266 gpm and will be monitored and sampled for
compliance with the discharge criteria. Where feasible, wastewater will be
recycled within the plant, such as HRSG blowdown and RO reject being recycled to
the cooling tower, otherwise, the waste stream is treated to ensure compliance
with the discharge criteria. The process waste line will be sampled using a
composite sample and have inline pH and residual chlorine analyzers. The
analyzer outputs will be data logged in the DCS Fuel Systems. The wastewater
will be discharged to the sewer utilizing two 100% pumps. The process wastewater
system serves the overall drainage of floors and equipment in general industrial
areas throughout the buildings. Particulate matter and oil typically contaminate
the process wastewater. The process wastewater system also serves enclosed
(diked, curbed) and sprinkler equipment areas where large quantities of oil are
used or stored. The systems will provide for the containment and isolation of
oil wastes (including sprinkler discharge in case of fire) that otherwise could
spread and create significant fire hazard. The process wastewater is discharged
to an oil/water separator that will separate oil for on site storage and
ultimate off site disposal, and discharge water to the plant waste line of site
boundary. Inside the buildings, to the extent possible, all drainage will flow
by gravity. Where relative elevations do not permit gravity flow, eight duplex
sump pumps will be provided. The stormwater drainage system will direct
stormwater runoff to a detention basin designed for all storms up to the
100-year storm.
The sanitary drainage and vent systems serve the removal of wastes from toilet
and shower rooms, food service and kitchen equipment and related floor areas,
and from other facilities of sanitary nature. All fixtures/equipment drained to
the sanitary drainage system are supplied by
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potable water. The sanitary wastes will flow by gravity and will be collected in
a sewage ejector pit from where the waste will be pumped to the site collection
system. The sewage ejector will be automatic, vertical, centrifugal, non-clog
type, designed with duplex arrangements. Both pumps will be sized for the peak
inflow. The anticipated sanitary wastewater flow is anticipated to be
approximately 1700 gpd.
The chemical waste drainage system serves the water treatment building and other
areas where chemicals are stored or handled such as sampling and chemical feed
areas. The waste is drained to a dedicated chemical sump and pumped to the
neutralization tank for treatment. In remote areas, such as the battery rooms or
laboratories where acids are stored or used, the waste is directed to local acid
neutralizing basins and then discharged to the sanitary or industrial waste
drainage systems.
3.8.10 COMPRESSED AIR SYSTEM
The compressed air system includes two 100% oil-free type compressors and
accessories including, two 100% regenerative desiccant type dryers,
intercoolers, and aftercoolers, and one vertical air receiver tank. One local
control panel with remote start/stop capability will be furnished for manual and
automatic control of the compressed air system. The compressors will be heavy
duty, oil-free type and will be supplied as skid mounted packaged units complete
with electric motors, air intake filters, silencers, moisture separators,
intercoolers, and aftercoolers, air receiver isolating and check valves, safety
devices and necessary instrumentation and controls for complete operable units.
Each compressor will be designed to deliver 500 SCFM of air at125 psig. The
compressors will be capable of operating at full load, part load or idling
condition, continuously or intermittently. Each dryer will be designed to
deliver air 300 SCFM of air at 120 psig, with a minus 40DEG. F dewpoint
(although the EPC Contract mistakenly states 40DEG. F), assuming an air inlet
temperature to the dryer of 100DEG.F and 100% relative humidity.
The intercoolers and aftercoolers will be the shell and tube type with removable
tube bundles and will be designed, fabricated, and stamped in accordance with
the ASME Boilers and Pressure Vessel Code, Section VIII, Div. I. The cooling
water used in the intercoolers, aftercoolers, and compressors will be supplied
by the closed cycle cooling water system. Each cooler will cool the maximum air
flow at maximum discharge pressure to within 15DEG.F of the cooling water
temperature. The tubes of the intercoolers and aftercoolers will be made of
seamless stainless steel. The receiver will be vertical with a nominal capacity
of 1200 cubic feet, 150 psig design pressure of welded steel construction.
3.8.11 COMPRESSED GAS STORAGE SYSTEM
The compressed gas storage system will consist of the hydrogen gas system, the
carbon dioxide system, and the nitrogen system. The hydrogen system supplies
hydrogen gas to the hydrogen cooled generators. The carbon dioxide system stores
and transfers carbon dioxide gas to the generator cooling and purge systems for
generator purging. The nitrogen system supplies nitrogen for inerting the HRSGs
and main cycle piping during an extended outage. The compressed gas will be
stored in commercially available cylinders. The compressed gas system will also
include the associated piping and instrumentation.
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3.8.12 AMMONIA STORAGE AND FORWARDING SYSTEM
The ammonia storage and forwarding system will store and supply ammonia for the
SCR. The 19% aqueous ammonia solution will be stored in a 20,000 gallon storage
tank. The tank will provide approximately a six-day supply of ammonia. The tank
is designed per ASME Section VIII for pressures of full vacuum to 50 psig.
Standard safety devices and instrumentation will be installed on the tank. The
tank will be installed inside a containment dike capable of holding full tank
volume. The tank is located adjacent to the plant stacks and is accessible by
tank truck, which will be used for liquid fill.
Two 100% capacity ammonia forwarding pumps, one operating and one standby, will
transfer the aqueous ammonia solution to the aqueous ammonia control injection
skid, which will be located adjacent to each HRSG. The supply pressure to the
control skid will be maintained at constant pressure with pump skid control
valves. Excess liquid will be returned back to the aqueous ammonia storage tank.
The pump skid includes associated piping, block valves, check valves, pressure
and temperature instrumentation.
3.9 FUEL SYSTEM
Williams will provide natural gas to the site by way of a pipeline that connects
to the 42" Transco pipeline. Based on historic pressures, gas supply pressure is
expected to be at or above 575 psig. By receiving the gas at the delivery point
at the site at or above 575 psig and 70DEG.F, it will enable AES Red Oak to
provide 475 psig and 59DEG.F gas at the gas preheater inlet as required by the
EPC Contract.
The fuel gas system inside the site boundary will consist of a redundant gas
filtering station, pressure reducing and gas metering station, one 100% scrubber
and scrubber drain tank. A fuel gas preheater will be provided for each CT to
raise the gas temperature to approximately 280DEG.F. Feedwater from the
respective HRSG's IP economizer will be circulated through the preheater back to
the HRSG IP evaporator. The gas pressure at each CT will be regulated based on
its operating requirements.
3.10 ELECTRICAL SYSTEMS
Stone & Webster reviewed the general configuration of the AES Red Oak electrical
systems identified in this section. Stone & Webster's electrical system review
focused on ensuring that the bus configurations and designs were consistent with
standard industry practice. The detailed system and component technical
information that is developed during the detailed design phase was not available
for review. The conceptual description of the electrical systems, as well as
Stone & Webster findings, are provided in the following sections.
Stone & Webster believes that the electrical system design described below is
consistent with standard industry practice.
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3.10.1 NORMAL STATION SERVICE POWER
Two unit auxiliary transformers from generators GT1 and GT2 will provide power
to the plant auxiliary loads during normal operation. The transformers step down
the voltage from 18 kV to 4.16 kV to two switchgear buses which supply power to
large medium voltage motors and to three double-ended 480V load centers by way
of 4.16kV to 480V transformers. The 480 V load centers supply power to larger
low voltage motors and to motor control centers ("MCC"), which supply smaller
motors and other loads and panels.
3.10.2 EMERGENCY POWER
Emergency power systems also exist to assist plant operations. An emergency MCC
provides 480V power to essential service loads. The emergency MCC has an
automatic transfer switch. Normal power is provided from a plant load center,
but upon loss of power, the back-up source is the 34.5kV-480V
construction/back-up transformer connected to the GPU Energy's 34.5 kV
distribution system.
A plant direct current ("dc") system consisting of 125V dc batteries and an
uninterruptible power supply ("UPS"), powered from the plant dc system, provide
power to STG, HRSG, and switchyard equipment that must be operable during
emergency and loss of utility power conditions. A separate dc system for each
CTG package also provides the necessary dc power required by the CTG. These
systems ensure that equipment such as lube oil pumps and turning gear motors
have power available for a proper cool down process of the turbines during an
emergency trip.
Instrumentation, relaying, control and monitoring circuits required for
emergency shut-down of the plant are also connected to the batteries and/or UPS.
Vital plant equipment such as the distributed control system ("DCS") is supplied
from the UPS, which is powered from the plant dc system.
The plant has no black start capability. Startup of the plant is accomplished by
way of electrical backfeed through one of the unit auxiliary transformers off
the 230 kV system with the generator breaker open.
3.11 SWITCHYARD
Electrical power through the CTG and STG is generated at 18 kV and stepped up to
230 kV for delivery to the switchyard. The plant will electrically interconnect
with the PJM electrical system through two transmission lines, which will tie
into the plant's switchyard.
Four main transformers will be provided for this service. Each CTG and the STG
will be connected to its own two winding, oil filled step up transformer which
increases the voltage from the generator terminals to the interconnecting
voltage at the high side terminals.
Stone & Webster performed a review to determine that the optimum transformer
turns ratio can be achieved with the tap range provided, to deliver reactive
power to, or receive reactive power from the system. Synchronization and
protection of the CTG GT1 and GT2 are achieved by use of the generator breaker.
Synchronization and protection of the STG and CTG GT3 are achieved by the power
circuit breakers in the switchyard. The circuit breakers isolate the power
generating
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station from the interconnecting system. The CTGs and STG will be connected to
the step-up transformers by isolated phase bus duct.
The switchyard is a 230 kV conventional, open air, double bus, single breaker
arrangement with provision for two outgoing transmission lines. The switchyard
will extend from the high voltage terminals of the generator step-up
transformers outgoing transmission circuits. Switchyard protective relays will
interface with the GPU Energy's transmission line protective relays and
communication equipment. SCADA remote terminal units ("RTU"s) will be provided
by GPU Energy to interface with the transmission/distribution control center and
the energy control center. This equipment will be installed in the plant control
room.
The switchyard requirements will also be further defined as part of the
Interconnection Agreement.
3.12 MISCELLANEOUS ELECTRICAL SYSTEMS
Stone & Webster reviewed the descriptions of the communications, lighting,
grounding, cable and raceway, freeze protection and security systems and have no
comments. These system are described in accordance with common industry
practice.
RE&C will provide cathodic protection in accordance with the recommendations of
the Soil Resistivity Survey Report prepared by the Corrosion Engineering
Department of RE&C. In particular, all critical carbon steel piping such as gas
and circulating water lines will be coated and cathodically protected.
3.13 INSTRUMENT AND CONTROL SYSTEMS
The Plant control system is a microprocessor based DCS. The system provides both
analog and digital control capabilities. The system will monitor, alarm, log,
trend plant inputs and provide status of plant equipment. The control consoles
of the DCS provide the control room interface with the plant equipment.
Control, protection and monitoring functions for the CTs are performed by the
ECONOPAC system. The ECONOPAC system is a microprocessor based control system. A
computer processing unit performs the control and logic functions. Input/output
cards provide the interface to field instrumentation and control devices. A
cathode ray tube ("CRT") and graphic display system are also provided.
The ST is provided with a Toshiba digital electro hydraulic control ("EHC")
control system. The digital EHC system performs the operations necessary to
accelerate, synchronize, load, unload and shut the unit down. The plant DCS
system interfaces with both the CT system and the ST system by way of a one-way
data link and hard-wired system.
The proposed SCR system utilizes the DCS for the control function. FWEC will
supply all the necessary logic and permissives information necessary to set up
the required logic in the DCS system. The purpose of the control system is to
assure that the flow of ammonia matches the gas flow and temperature within the
HRSG to provide the necessary NO(x) reduction.
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3.14 CIVIL AND STRUCTURAL DESIGN
The Project's civil and structural design parameters have been appropriately
specified in the EPC Contact. The civil and structural design requirements are
in accordance with applicable sections of the Uniform Code of New Jersey, the
BOCA National Building Code and the results of the preliminary geotechnical
investigation conducted on-site. The EPC Contract has adequately identified the
applicable civil and engineering codes and standards relating to the type of
construction proposed at the site and has adequately defined site specific
design criteria. It is noted that RE&C has accepted the risk of any additional
foundation requirements as necessary based on a detailed geotechnical
investigation to be performed during the design phase of the Project. The
structural design criteria outlined in the EPC Contract appear adequate to
comply with the Project requirements. The materials of construction specified in
the building finish schedule are appropriate for the intended application. The
minimum required strength of materials, stipulated in the design criteria, are
consistent with industry standards. The established loadings and maximum design
conditions comply with the referenced codes, site development requirements and
foundation design criteria. Stone & Webster's opinion is that the structural
design requirements are reasonable and adequate for operation of the Facility as
contemplated in the EPC Contract.
3.14.1 SITE CONDITIONS
The Project site area is approximately 62.7 acres and is zoned M-2 (heavy
industrial). Significant boundary features are the Jersey Central Power and
Light Co. easement and transmission line to the northeast and the Raritan River
Railroad line to the southwest. The topographic high point of the site is about
elevation 87 feet (NGVD) and is located along the transmission line easement.
The lower portion of the south area of the site is at elevation 22 feet, which
is below the 100-year flood reported to be at elevation 23.49 feet. This area
will remain undeveloped.
Previous development in the northern portion of the site has lowered the grade
adjacent to the transmission line easement to approximately elevation 51 to 55
feet. The Facility will be constructed at a plant grade of elevation 55 feet in
this generally flat area. Some offsite fill has been placed in the lower than
grade area. A large portion of the south area of the site, however, will not be
developed due to wetland restrictions.
3.14.2 GEOTECHNICAL EVALUATION
The Parsons Power Group performed a preliminary geotechnical investigation of
the Project site and presented the results in a Preliminary Geotechnical Report,
October 1, 1998. A total of six exploration borings were drilled, logged and
sampled to depths ranging from 37 to 77 feet below existing grade. Soil
descriptions, sampling and laboratory testing results are presented in the
report. Resistivity testing was also performed during this site investigation
and the results are presented in the report.
The exploration borings indicate that the subsurface conditions at the site
generally consist of medium dense to very dense sand with some gravel. The
granular soils overly stiff to very stiff clays and silts. The thickness of the
granular soils generally ranges from approximately 32 to 39 feet except at
Boring B-6 where the thickness is only 10.5 feet. Several feet of the granular
soil deposit have been removed as borrow in the northern part of the Project
site. Standard
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penetration blow counts and the laboratory test results indicate that the site
soils have high shear strength and are overconsolidated.
Under the terms of the EPC Contract, RE&C is responsible to execute a complete
and careful examination of the nature and character of the soils and terrain of
the site to define criteria for design and construction of the Facility.
Stone & Webster believes that the preliminary exploration and testing programs
were conducted in accordance with good engineering practice and were appropriate
for the planned Facility and anticipated site conditions. Stone & Webster's
opinion is that the Project site is suitable for construction of the proposed
Facility.
3.14.3 GROUNDWATER
Groundwater levels were measured during the exploration program. Groundwater
levels are at approximately elevation 40 feet in the area where the Facility
will be located. Groundwater is not expected to affect foundation installation
unless excavations are required below elevation 40 feet. Any significant
excavations below elevation 40 feet will require dewatering, such as by a vacuum
well point system.
3.14.4 WATER SUPPLY
Raw water for the Facility will be supplied by the Borough of Sayreville
primarily from the South River Reservoir and supplemented by the Duhernal water
supply well during periods of low river level. Water will be provided at a
pressure of 60 psig at the site boundary. The raw water will be used for all
fire protection, process water, and service water requirements for the Facility.
Raw water from both sources is relatively low in dissolved solids. However,
differences in the iron content and pH requires that a water treatment system be
designed to treat the worst condition of either raw water source. Stone &
Webster does not consider water quality to present a design problem for the
water treatment systems.
3.14.5 SITE GRADING AND DRAINAGE SYSTEM
The Facility plant site grade will be established at elevation 55 feet. The site
grading and drainage system will be designed to comply with all applicable
federal, regional, and local regulations. Topographic modifications to the site
area may be required to provide positive overall drainage control to protect the
wetlands in the lower portion of the site. Surface drainage onsite will consist
of overland and open channel flow. Storm water from potentially contaminated
areas will be carried through buried piping to the oil water separator and then
to the detention basin for discharge to the natural site drainage areas.
The storm drainage system will be designed for a storm frequency of one in
twenty-five years except for the detention basin that will be designed for a
storm frequency of one in one hundred years. Rainfall intensity will be
determined utilizing the Sandy Hook, NJ intensity/duration curves presented in
the EPC Contract. The Facility main complex area will require only moderately
grading for effective drainage.
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3.14.6 FOUNDATIONS
The site is considered suitable for development of the Facility. The proposed
structures can be placed on conventional mat or spread foundation, established
on the dense to very stiff underlying soils. Off site fill, which was placed in
the main Facility area will have to be removed and replaced with suitable
engineered fill, as required. The excavated onsite natural soils, free of
organic and other deleterious material, are considered suitable for reuse as
structural fill and site grading. RE&C has the responsibility to establish
suitable foundation bearing capacities and foundation preparation that will be
required to comply with the EPC Contract foundation performance requirements.
It is anticipated that the mat foundations established on the dense to very
stiff overconsolidated soils can support the CTs, HRSGs, ST, generators, and
stacks. Some over excavation and replacement with an engineered structural fill
may be required to maintain settlement tolerances for some these foundation
systems. RE&C will establish the foundation preparation and treatment
requirements required for final design.
The support buildings and other lightly loaded structures can be supported on
spread foundations on suitable dense to stiff natural soils or compacted fill.
The above ground storage tanks can be supported on the dense to stiff natural
soils or on structural fill.
The exploration program indicates that no rock excavation is anticipated for
installation of any of the proposed facilities.
3.14.7 STACK
Each HRSG will have an individual stack 150 feet tall. The stacks will be
constructed in accordance with ASME/ANSI standards and will be made from carbon
steel. The location of test ports and sampling platform will meet the specified
emission testing requirements.
3.15 INTERCONNECTIONS
3.15.1 FUEL INTERCONNECTION
The natural gas fuel supply to the Facility will be transported by way of a
pipeline that will be designed to supply a minimum of 575 psig and 70DEG.F
at the delivery point at the site as discussed in Section 3.8 of this Report.
Fuel will be supplied to the Facility by Williams in accordance with the Tolling
Agreement as discussed in Section 5 of this Report. Williams is responsible for
the construction of all gas interconnection and delivery facilities necessary
for delivery of natural gas. Pipeline permitting, design, and construction is
also the responsibility of Williams.
Williams plans to connect the Facility with the Transco Gas Pipeline ("TGPL"),
which is an affiliate of Williams, to provide natural gas services to the
Facility. In addition, Williams may provide additional gas supply from Texas
Eastern and Tennessee as well as TGPL through the New Jersey Natural Gas Co.
("NJNG") distribution system. The TGPL is an extensive long-line transmission
network with facilities that access many of the major gas producing areas in the
U. S., including the Gulf of Mexico, Gulf of Mexico Deep Water, Mobile Bay,
Onshore Texas, and Onshore Louisiana. The other major interstate natural gas
pipelines that connect to TGPL or are near the Sayreville location include Texas
Gas, Koch, Tennessee Gas, and Texas Eastern
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("TETCO"). Canadian supplies are also listed as an option through either the
Niagara, NY import point or the Iroquois pipeline. Clearly, these pipelines and
supply source options provide several choices from many locations.
Distribution systems are required by law to odorize gas in areas of higher
population density for safety purposes; the odorant used is very high in sulfur.
The gas from NJNG can still be used but the higher sulfur content than the fuel
specification will result in the turbine blades requiring more frequent water
washes.
3.15.2 ELECTRICAL INTERCONNECTION
The Facility can feasibly be electrically integrated into the PJM system, and no
known transmission limitations will inhibit the feasible evacuation of the
Facility's full net capacity both under summer and winter conditions.
The Plant will be integrated into the GPU Energy transmission system as follows:
1. The section of the 230 kV bus that ties in the STG unit and one of the CTG
units will connect (by way of a tap) to the Raritan River-Parlin 230 kV
circuit.
2. The section of the bus that ties in the other two CTG units will connect
(by way of a tap) to the Raritan River-South River 230 kV circuit.
Both of the Raritan River-Parlin and Raritan River-South River 230 kV circuits
run on the same towers. Thus, events involving the simultaneous disconnection of
both circuits and therefore the disconnection of the entire Plant are credible,
and need to be simulated in the single contingency (or n-1) analysis of the
transmission system reliability.
The 230 kV substation at the Plant is arranged using a split single bus-single
breaker scheme. In Stone & Webster's experience, these single-bus single-breaker
arrangements are fairly typical of facilities such as this one and has been
reviewed and accepted by GPU Energy.
In addition, the 230 kV bus is split into two disconnected sections; one of the
CTG units and the STG unit are connected to one of the sections of the bus,
while the other two CTG units are connected to the other one. The design does
not allow for the electrical interconnection of the two sections of the 230 kV
bus together. Thus, from a power systems standpoint, the Plant is effectively
split in two. The reason for this interconnection configuration is that the
lines individually cannot handle the full output of the plant. GPU Energy has
participated in the interconnection configuration design, has reviewed the
design configuration to ensure compliance with GPU Energy, PJM, and MAAC
criteria, and has approved the configuration. The forced and planned outages for
each of these lines have been low. Over the last 10 years, there was one forced
outage for 0.37 hours in 1993 and two separate planned outages for a total of
23.95 hours in 1994 for transmission line 1034. There was one forced outage for
0.33 hours in 1993 and one planned outage for 6.17 hours in 1993 for
transmission line 1047. In addition under the terms of the Tolling Agreement,
AES Red Oak will continue to get paid for the first 24 hours of any transmission
outage.
The Plant has been and continues to take the steps necessary for interconnection
with the transmission system of GPU Energy, which includes the following steps:
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FEASIBILITY STUDY: A feasibility study is required to make a preliminary
determination of the type and scope of attachment facilities, local upgrades,
and network upgrades that will be necessary in order to accommodate the
interconnection request, and to provide a preliminary estimate of the time and
cost that will be required to construct these necessary facilities and upgrades,
if any. On April 28, 1999, AES submitted a Feasibility Study Agreement request
to PJM for a feasibility study to be conducted. The Plant is declared as a
Capacity Resource in the request. The feasibility study indicates that the only
problem found with the Plant in service was "an overload of substation equipment
at Freneau on the Parlin-Freneau 230 kV line for the loss of the South
River-Atlantic 230 kV line with the Sayreville-Gillette 2230 kV out for
maintenance near Sayreville. This problem can be remediated for approximately
$40,000."
SYSTEM IMPACT STUDY: PJM, in coordination with the regional transmission owner,
conducted a System Impact Study to identify the system constraints relating to
the interconnection requests being evaluated in the study and the attachment
facilities, local upgrades, and network upgrades necessary to accommodate each
interconnection request. The System Impact Study has been completed. The System
Impact Study refined and more comprehensively estimated each interconnection
customers' cost responsibility for necessary facilities and upgrades than the
estimates provided in the Feasibility Study. The System Impact Study estimated
the transmission and interconnection cost and the associated cost for the
overload of substation equipment at Freneau on the Parlin-Freneau 230 kV line at
$5,198,448 and $38,000, respectively for a total estimated cost of $5,236,448.
The project economic analysis includes $5.236 million for transmission and
interconnection cost.
INTERCONNECTION SERVICE AGREEMENT: In general, Stone & Webster found that the
Interconnection Service Agreement is comparable to other similar agreements with
which Stone & Webster is familiar.
3.15.3 WATER INTERCONNECTION
The Project has a WSA in place to draw water for cooling the Facility from the
Borough of Sayreville. The Borough of Sayreville operates a publicly owned raw
water system that draws on both the South River by way of lagoons and Duhernal
acquifer. The Borough of Sayreville needs to amend its existing permit to
construct a new Lagoon Pumping Station to supply AES Red Oak with up to 4.6
million gpd of untreated water. The existing Duhernal Water Pipeline will be
used as a backup source of water, up to a maximum of 4,600,000 gpd for the plant
when the Lagoons' water level falls below 20 feet and South River water is
unavailable due to low flow or chloride limitations or a break in the lagoons'
water pipeline. AES Red Oak will be responsible for the cost of constructing and
installing the Lagoon Water Pipeline, Lagoon Pumping Station, and the Sayreville
Interconnection Number 2 to the Duhernal Water Pipeline. These costs have been
included in the project economic analysis. Access to both water sources will be
designed and constructed to serve the full Facility needs from either or both
sources.
Stone & Webster does not know of any reason why the Borough of Sayreville would
be unable to perform its obligations under the WSA.
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4. ENVIRONMENTAL AND PERMITTING
Stone & Webster reviewed the environmental documents included in Exhibit II with
regard to this Project:
4.1 ENVIRONMENTAL SITE ASSESSMENT
Stone & Webster reviewed the PASI report prepared by TRC for the subject
property. The PASI report states that the initial site visit by TRC was
conducted during July 1998 and the soil and groundwater sampling was conducted
during September and October 1998. In addition, the NJDEP Preliminary Assessment
Report ("PAR") form, which was attached to the PASI report, is dated 02 April
1999.
The PASI report also referenced and included, as an Appendix, an earlier
Environmental Site Assessment report for the Project site, which was prepared by
Aware Incorporated ("Aware") in June 1988.
According to the PASI report, placement of fill materials on the Project site,
has resulted in residual levels of PCBs, base neutral organic compounds and
metal compounds in shallow soils at this site which are in excess of the NJDEP
SCC. In addition, the shallow groundwater at the Project site contains metal
compounds and general chemistry compounds at concentrations, which are in excess
of the NJDEP GWQC. The results of the PASI were reported to the NJDEP Spill
Hotline on 23 December 1998 and Spill Number 98-12-23-1614-38 was assigned to
this site.
TRC recommended that a Remedial Investigation be performed to further
assess/delineate the soil contamination detected by the PASI and to confirm the
results of the initial round of groundwater sampling. Stone & Webster received a
copy of the Remedial Investigation Report and Remedial Action Workplan
("RI/RAW") for the Forest View Industrial Park site prepared by TRC. The RI/RAW
was submitted to the NJDEP for their review and comments. The RI/RAW represents
a compilation of all the information that has been developed since the PASI and
includes recommended remedial actions. AES Red Oak has completed remediating the
site to industrial use levels. NJDEP completed its review and approved the
RI/RAW on January 10, 2000. The cost for remediation has been included in the
project economic analysis. Approval of RI/RAW provides AES Red Oak protection
under the Brownfield Act.
Information contained in the PASI report indicates that radon is not an issue at
the Project site.
4.2 PERMITTING
Stone & Webster notes that AES Red Oak is responsible for obtaining the
environmental permits and approvals as listed in Appendix F of the EPC Contract.
Separately, TRC prepared a list of environmental permits and approvals required
for this Project as shown in the following table.
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------------------------------ ----------------------- ----------------------- ------------------------------
<S> <C> <C> <C> <C>
Federal Energy Regulatory Exempt Wholesale AES Red Oak Application for EWG
Commission Generator Certification submitted
Certification 9/13/99; Docket
#EG99-229-000. Certification
received on 11/4/99
------------------------------ ----------------------- ----------------------- ------------------------------
U.S. Department of Energy Fuel Use Act AES Red Oak Certification #175 Published
Office of Fossil Fuel Certification in Federal Register Vol. 64.
#126 on 7/1/99 Pg. 35637
------------------------------ ----------------------- ----------------------- ------------------------------
U.S. Department of Notice of AES Red Oak Aeronautical Study
Transportation Federal Construction or #99-AEA-1757-OE
Aviation Administration Alteration - Approved 7/23/99
Combustion Turbine
Stacks
------------------------------ ----------------------- ----------------------- ------------------------------
U.S. Department of Notice of AES Red Oak Aeronautical Study
Transportation Federal Construction or #99-AEA-2094-OE underway
Aviation Administration Alteration - 7/20/99 prior study
Construction Crane #99-AEA-1757-OE Approved
8/3/99
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Bureau of Air Quality Prevention of AES Red Oak Submittals 1/4/99; 7/19/99
Significant and 7/26/99 Facility ID
Deterioration/State #17965 Permit ID# PCP990001
Air Permit assigned. Draft Fact Sheet,
Public Notice and Air
Permit/Compliance Plan
received 11/12/99. Notice of
Opportunity for Public
Comment published in Home
News Tribune and published
in Star Ledger 12/9/99.
Public comment period closes
1/8/00. Final permit issued
on 1/28/00
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Land Use Regulation Freshwater AES Red Oak NJDEP approval 3/22/99
------------------------------ ----------------------- ----------------------- ------------------------------
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<S> <C> <C> <C>
Wetlands Delineation File #1219-90-0002.4 Wetlands
LOI for AES Red Oak Line approved; intermediate
Site resource value determination
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Land Use Regulation Freshwater Wetlands AES Red Oak Submitted 12/15/99. Tied to
Delineation LOI for Stream Encroachment Permit
Site Access Roadway application. Docket
and/or Construction #1219-90-0002.5
Laydown Area
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Land Use Regulation Transition Area AES Red Oak Submitted 12/15/99. Tied to
Element Waiver and Statewide Stream Encroachment Permit
General Permits application. Docket
Basins; Outfall to #1219-90-0002.5
Wetlands; Roadway for
Site
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Land Use Regulation Transition Area AES Red Oak Submitted 12/15/99. Tied to
Element Waiver and Statewide Stream Encroachment Permit
General Permits for application. Docket
Site Access Roadway #1219-90-0002.5
and/or Construction
Laydown Area
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Land Use Regulation Water Quality AES Red Oak Submitted 12/15/99. Tied to
Certification for Site Stream Encroachment Permit
application. Docket
#1219-90-0002.5
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Land Use Regulation Water Quality AES Red Oak Submitted 12/15/99. Tied to
Certification for Stream Encroachment Permit
Site Access Roadway application. Docket
and/or Construction #1219-90-0002.5
Laydown Area
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Bureau of Treatment Works AES Red Oak Submitted to Borough of
------------------------------ ----------------------- ----------------------- ------------------------------
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<S> <C> <C> <C>
Construction and Connection Approval for sewerage Sayreville on 12/15/99.
Signed by Mayor on 12/20/99.
Submitted to MCUA 12/21/99.
Delivered to NJDEP on 1/12/00
and assigned Docket #00-3328-4.
Revised Plan and Profile
drawings delivered to NJDEP
on 2/4/00.
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Land Use Regulation Stream Encroachment AES Red Oak Submitted to Middlesex
Element and Water Quality County Engineers Office on
Encroahment for 10/19/99 for
Stormwater Outfall signature/transmittal to
off Jernee Mill Road NJDEP. Middlesex County
Freeholders approval on
12/15/99. Permit application
submitted to NJDEP on
12/15/99. Original
application signatures form
delivered to NJDEP on
12/21/99. Application
logged in on 12/15/99 and
assigned docket
#1219-90-0002.5 Submitted
revised documentation to D.
Ahdout on 2/4/00
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Dam Safety Section Dam Permit for AES Red Oak Clarification letter request
Detention Basin submitted 10/28/99. NJDEP
(possible) determined detention basin
is Class IV Dam. Letter from
NJDEP forthcoming stating
no permit required. Need to
comply with Class IV Dam
Regulations. Second set of
drawings sent to NJDEP
12/15/99. Letter from NJDEP
dated
------------------------------ ----------------------- ----------------------- ------------------------------
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<S> <C> <C> <C>
12/22/99 received stating no
permit required. Need to
comply with Class IV Dam
Regulations.
------------------------------ ----------------------- ----------------------- ------------------------------
Borough Sayreville and NJDEP Water Connection Point AES Red Oak Submitted to Borough of
approval Sayreville on 12/17/99.
Signed by Mayor on 12/20/99.
Hand delivered to NJDEP on
12/21/99. Assigned Docket
#W-12-99-6311. Application
deemed complete on 12/29/99.
TRC discussed review status
on 2/16/00.
------------------------------ ----------------------- ----------------------- ------------------------------
Middlesex County Utilities Industrial Discharge AES Red Oak Submitted on 10/18/99. Draft
Authority (MCUA) Permit (non-domestic permit #20161 under AES
wastewater discharge review and agreed on permit
permit) language 12/21/99 with MCUA.
Docket is being placed on MCUA
commissioner's 1/6/00 agenda
for approval. Received MCUA
commissioner's approval on
1/27/00.
------------------------------ ----------------------- ----------------------- ------------------------------
Middlesex County Planning Approval of Site Plan AES Red Oak Submitted 7/15/99
Board (MCPB) and Stormwater Application #5Y-5P-130
Drainage Approved 8/16/99. Revised
site plan to be submitted
12/22/99 to address county
planning board conditions.
Maser Consulting submitted
2/3/00 letter on stormwater
impact on downstream
properties to MCPB. The
Performance Bond guarantee
details from MCPB. AES
preparing performance bond
for had delivery to
------------------------------ ----------------------- ----------------------- ------------------------------
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<S> <C> <C> <C>
MCPB on 2/23/00.
------------------------------ ----------------------- ----------------------- ------------------------------
Middlesex County Mosquito Approval of Onsite AES Red Oak Submitted 7/15/99
Control Commission Detention Basin as Approved contained in
part of MCPB Middlesex County Planning
Approval. Board Approval dated 8/16/99
#SY-SP-130
------------------------------ ----------------------- ----------------------- ------------------------------
Conrail/CSX License Agreement to AES Red Oak Submitted on 12/23/99. Under
Cross Railroad with review. Conrail Engineers
access Roadway and reviewed and verbally
for underground piping/profile drawings hand
infrastructure delivered on 2/11/00.
License Agreement for at
Grade Crossing and License
Agreement for Utility Lines
Occupation was executed by
AES & Conrail on 2/18/00
and 2/23/00, respectively.
A 2/18/00 letter approving
license drawings & confirming
application plans etc. meet
Conrail specifications.
------------------------------ ----------------------- ----------------------- ------------------------------
Freehold Soil Conservation Soil Erosion and AES Red Oak Approved 9/27/99 and
Service District Sediment Control Plan included in Memorialized
Certification Resolution dated 10/12/99
------------------------------ ----------------------- ----------------------- ------------------------------
Freehold Soil Conservation NJPDES RFA for AES Red Oak Submitted 10/20/99 Received
Service District Construction 10/21/99 and assigned
Stormwater Discharge application #12-19-00-0023
------------------------------ ----------------------- ----------------------- ------------------------------
Sayreville Planning Board Municipal Site Plan AES Red Oak Submitted 7/15/99 Approved
Approval by Planning Board 9/27/99
Memorialized Resolution
------------------------------ ----------------------- ----------------------- ------------------------------
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<S> <C> <C> <C>
dated 10/12/99. Submittal of
plan revisions/additional
information to CME and Heyer,
Gruel on 1/5/00. Heyer, Gruel
approval received on 1/11/00.
Response to CME 1/13/00
letter submitted on 1/28/00
with CME reviewing revised
site plans. Maser submitted
2/4/00 letter to CME. TRC
submitted supplemental
response to CME on 2/14/00.
Received CME letter dated
2/17/00 requesting additional
information/plan revisions.
Maser submitting response
compliance package by hand
delivery to CME on 2/22/00.
------------------------------ ----------------------- ----------------------- ------------------------------
Sayreville Planning Board Soil Erosion and AES Red Oak Approved 9/27/99 and
(CME) Sediment Control Plan included in Memorialized
Certification Resolution dated 10/12/99.
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Division of Water NJPDES Stormwater AES Red Oak To be submitted prior to
Resources Discharge Permit facility operation
------------------------------ ----------------------- ----------------------- ------------------------------
Middlesex County Roads Road Opening Permit Raytheon Construction approval
Department for Jernee Mill Road
------------------------------ ----------------------- ----------------------- ------------------------------
NJDEP, Bureau of Treatment Works Raytheon Construction approval
Construction and Connection Approval for
oil/water separators
------------------------------ ----------------------- ----------------------- ------------------------------
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<S> <C> <C> <C>
NJDEP, Bureau of Safe Physical Connection Raytheon Construction approval
Drinking Water Permit
------------------------------ ----------------------- ----------------------- ------------------------------
NJ Department of Community Building Construction Raytheon Construction approval
Affairs - Bureau of Approvals
Construction
------------------------------ ----------------------- ----------------------- ------------------------------
Sayreville Town Engineer Building Permits Raytheon Construction approval
------------------------------ ----------------------- ----------------------- ------------------------------
</TABLE>
Information provided by AES indicates that AES Red Oak will not be subject to
the United States Environmental Protection Agency ("USEPA") Risk Management
Program ("RMP") because there will be no RMP regulated materials produced,
stored, or otherwise managed on site.
4.2.1 AIR PERMIT
The final Prevention of Significant Deterioration ("PSD") Air Permit was issued
on January 28, 2000. Stone & Webster reviewed the Air Quality Modeling Analysis
prepared by TRC for this Project. This analysis indicated that atmospheric
emission attributable to this Project should not cause any significant impacts
upon existing air quality, surrounding soil, vegetation, visibility, or the
nearest Class I area (Edwin B. Forsythe National Wildlife Refuge). Stone &
Webster noted that TRC modeled a variety of operating cases so as to provide as
much operational flexibility to AES Red Oak as possible.
The proposed location of the AES Red Oak facility is in an area currently
designated as "attainment" with regard to the National Ambient Air Quality
Standards ("NAAQS") for SO(2), NO(x), CO, and PM(10). Since this Facility
will be classified as a "major" new source of these air pollutants, AES Red
Oak will be required to provide a level of atmospheric emissions control for
these air pollutants that is equivalent to or better than Best Available
Control Technology ("BACT"). In addition, the proposed location of AES Red
Oak is in an area currently designated as "severe non-attainment" for ozone.
Since this Facility will emit more that the threshold of 25 tons per year for
NOx and volatile organic compounds ("VOC"), AES Red Oak will be required to
provide levels of atmospheric emissions control for NO(x) and VOC that are
equivalent to or better than Lowest Achievable Emission Rate ("LAER").
Information provided by RE&C indicates that the following levels of control and
resulting atmospheric emissions will be provided:
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<TABLE>
<CAPTION>
===========================================================================================================
ATMOSPHERIC EMISSIONS AND LEVEL OF CONTROL
-------------------------- -------------------------- -------------------------- --------------------------
POLLUTANT EMISSION RATE CONTROL TECHNOLOGY CONTROL LEVEL
-------------------------- -------------------------- -------------------------- --------------------------
<S> <C> <C> <C>
NO(x) 3.0 ppm SCR LAER
-------------------------- -------------------------- -------------------------- --------------------------
CO 4.0 ppm Oxidation catalyst BACT
-------------------------- -------------------------- -------------------------- --------------------------
VOC 3.0 ppm Oxidation catalyst LAER
-------------------------- -------------------------- -------------------------- --------------------------
SO(2) Note 1 Note 1 BACT
-------------------------- -------------------------- -------------------------- --------------------------
PM(10) Note 2 Note 2 BACT
-------------------------- -------------------------- -------------------------- --------------------------
</TABLE>
Notes:
1. SO(2) emissions are based upon combustion of natural gas containing no
more than 1.5 grains of sulfur per 100 standard cubic feet ("SCF") of
natural gas. Stone & Webster noted that the EPC Contract limits fuel
sulfur content to 0.2 grains per 100 SCF.
2. PM(10) emissions include ammonia salt from reaction of SO(3) and
NH(3), calculated assuming 40% of SO(x) emissions are in the form of
SO(3) and that 100% of SO(3) is converted to ammonium sulfate.
Stone & Webster believes that this Project should be able to comply on a
reliable basis with the emissions rates listed above.
4.2.2 WATER PERMIT
This Project intends to obtain its supply of raw (fresh) water from the Borough
of Sayreville. Stone & Webster has reviewed a copy of the WSA between AES Red
Oak and the Borough of Sayreville, and notes that the South River will be the
primary source of supply for this facility, with the Duhernal reservoir serving
as back-up water supply. This agreement indicates that adequate supplies of
water should be available for the intended purposes.
4.2.3 WASTEWATER PERMIT
This Project intends to discharge all of its liquid effluents to the Middlesex
County Utilities Authority ("MCUA") under the terms of a non-domestic wastewater
discharge pretreatment permit to be issued by MCUA in accordance with the USEPA
Publicly Owner Treatment Works ("POTW") program. Stone & Webster has reviewed
the MCUA's Rules and Regulations for discharges of pretreated wastewater and
notes that they entail compliance with the USEPA's categorical effluent
standards for pretreatment of liquid effluents from fossil-fuel fired steam
generating facilities (40 CFR 423).
Stone & Webster has also reviewed a copy of the application submitted on 18
October 1999 by AES Red Oak to the MCUA for a non-domestic wastewater discharge
permit, and notes that it entails a greater degree of treatment than required by
the USEPA. Specifically, Stone & Webster notes that the application includes a
limit on oil and grease of 25 mg/L. However, the process description attached to
the MCUA application indicates that a simple baffle-type separator (only) will
be provided for the treatment of oily water. Stone & Webster has noted on other
POTW permits that the issuing authority provides for a surcharge (as opposed to
a violation notice and financial penalty) in the event that wastewater exceeds
permitted concentration limits. However, Stone & Webster did not find such
provisions within the MCUA rules and regulations.
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4.2.4 EXEMPT WHOLESALE GENERATOR STATUS
AES Red Oak filed for certification of the Facility as an EWG under the
applicable rules of the FERC on September 13, 1999. Any party or person desiring
to be heard concerning the Red Oak application for exempt wholesale generator
status should file a motion to intervene or comments with FERC on or before
October 8, 1999. On November 4, 1999 the Electric Rates and Corporate Regulation
found that AES Red Oak is an exempt wholesale generator as defined in section 32
of the PUHCA.
4.2.5 FUEL USE ACT CERTIFICATION
AES Red Oak has been approved as a coal-capable facility. This certification
allows AES Red Oak the option to burn gasified coal as an alternate fuel. AES
Red Oak does not have plans to use gasified coal.
4.2.6 WETLANDS DETERMINATION
AES Red Oak has obtained a determination from the NJDEP, which documents that
the property on which this facility will be constructed is not a jurisdictional
wetlands. However, this Project will involve construction on land, which has
been designated as a buffer zone between designated wetlands and non-wetlands.
According to the Environmental Impact Report, a Transition Area Waiver from the
NJDEP is required in accordance with the Freshwater Wetlands Protection Act.
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5. PROJECT AGREEMENTS
Stone & Webster reviewed the primary contracts and agreements associated with
the Project. These included the Tolling Agreement, the Interconnection
Agreement, the EPC Contract, the OMA, the WSA, the Agreement Relating to Real
Estate, and the Maintenance Services Agreement. Stone & Webster reviewed the
agreements from a technical and economic standpoint to assess the adequacy and
reasonableness of their terms and conditions. Legal, financial, and other
important aspects of the agreements associated with the Project were not
considered under this review. This Report describes only portions of the Project
Agreements as needed for the discussion of the Facility's related issues. A
complete description or legal evaluation of the contracts and documents related
to the Facility is beyond the scope of this report, and Stone & Webster is not
providing legal counsel opinions regarding the legal interpretation of any
contract language. Adherence to industry standards and good engineering practice
was assessed where appropriate. Provided below is a summary of our findings for
each of the reviewed agreements.
5.1 POWER PURCHASE AGREEMENT
Stone & Webster reviewed the Tolling Agreement, referred to as the "Fuel
Conversion Services, Capacity and Ancillary Services Purchase Agreement". The
Tolling Agreement is between AES Red Oak and Williams and is dated September 17,
1999. Certain of the provisions of the Tolling Agreement are discussed below.
For a summary of the material terms of the Tolling Agreement, reference is made
to "Description of Project Contracts - Power Purchase Agreement" in the Offering
Memorandum of AES Red Oak with respect to the Bonds to which the Report is
appended (the "Offering Circular").
5.1.1 TERM
The term of the Tolling Agreement is for a period of 20 years after the Contract
Anniversary Date that is the last day of the month in which the Commercial
Operation Date ("COD") occurs. If the COD has not occurred prior to December 31,
2001, Williams has the right to terminate the Tolling Agreement without
liability or responsibility unless any of the following conditions apply:
- AES Red Oak has demonstrated to Williams that the COD will occur no
later than June 30, 2002, and no payment is required ("Free Extension
Option"), or AES Red Oak pays Williams $2.5 million ("First Paid
Extension Option").
- The delay was due to an act or failure to act by Williams.
- AES Red Oak is unable to obtain natural gas for the testing or
operation of the power plant.
In the event AES Red Oak qualifies for the Free Extension Option or elects the
First Paid Extension Option but the COD does not occur by June 30, 2002, except
for a delay caused by Williams, or inability of AES Red Oak to obtain natural
gas, then AES Red Oak can elect to:
- extend the COD to and including June 30, 2003 by giving Williams
written notice of the estimated extension no later than April 30, 2002
and paying Williams $11,000/day for each of the first 60 days beyond
June 30, 2002, $22,000/day between and including 61
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and 120 days after June 30, 2002 and $50,000/day between and including
121 and 365 days after June 30, 2002
And in the case of the Free Extension Option also
- pay Williams an amount equal to the lesser of:
>>actual damages Williams suffers or incurs after December 31, 2001,
or
>>a specified cap of $3 million
In the event AES Red Oak elects the Second Paid Extension Option and the COD
does not occur by June 30, 2003 for any reason except as a result of a delay
caused by Williams or inability of AES Red Oak to obtain natural gas, then
Williams has the absolute right to terminate the Tolling Agreement without
liability or responsibility.
Based on the EPC Contract, if RE&C fails to achieve either Provisional or Final
Acceptance on or before 50 days after the Guaranteed Provisional Acceptance
Date, RE&C will pay AES Red Oak a specified amount per day of delay provided
however, that any provisional acceptance late completion payments will be
reduced by the sum of all gross revenue received by AES Red Oak. This rebate is
the sole and exclusive remedy of AES Red Oak and the sole liability of RE&C
under the EPC agreement for RE&C's delay. Based on the EPC Contract, the total
Contractor's liability associated with a delay in the Guaranteed Provisional
Acceptance Date is a maximum of 13% of the contract price. If the COD is delayed
to June 30, 2003, AES Red Oak would receive a rebate, the amount of which,
together with contingencies, is sufficient to cover the additional payments to
Williams plus one year in debt service after the Guaranteed Provisional
Acceptance Date.
5.1.2 FUEL CONVERSION AND ASSOCIATED SERVICES
Williams is obligated, on an exclusive basis, to supply and transport all of the
natural gas required (1) to generate net electric energy and/or ancillary
services, (2) perform start-ups, (3) perform shutdowns, (4) and operate the
Facility during any period other that during a startup, shutdown, or dispatch
period. Williams will retain title to the gas at all times under conditions
(1) - (3). Title to the gas under condition (4) will transfer to AES Red Oak at
the delivery point. Williams is responsible for all costs and expenses related
to the supply and transportation of the natural gas to the delivery point except
for Facility Testing or any other period other than a Dispatch Period. During
these periods, Williams will sell to AES Red Oak on an exclusive and firm basis
the quantity of natural gas requested by AES Red Oak, and AES Red Oak will pay
Williams the gas price based on the published Transco Z6 (NY) price plus a
transportation charge.
AES Red Oak is responsible for all costs and expenses related to the supply and
transportation of the natural gas from the delivery point within the site
boundary to the Facility. AES Red Oak will perform on an exclusive basis, Fuel
Conversion Services that Williams will take and pay for.
Williams is responsible for the construction of the Gas Interconnection
Facilities up to and including the natural gas delivery point defined to be a
point on the project site. In the event that the Gas Interconnection Facilities
have not been constructed or Williams is unable to deliver gas to the Facility
to support the initial start-up testing, Williams will pay AES Red Oak certain
specified amounts for each day of the delay from the date on which the Facility
would otherwise (but for the absence of gas) be ready for start-up testing until
the gas is delivered to the site. The
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Tolling Agreement includes no requirements for minimum delivery pressure and
temperature however, documentation was provided that indicates that the
pipelines have been able to supply natural gas at the pressure and temperature
required for the operation of the Plant.
5.1.3 TOLLING AGREEMENT PAYMENTS
Williams will pay AES Red Oak for facility capacity, fuel conversion services,
and ancillary services. Each monthly billing payment is the sum of the variable
O&M payment, total fixed payment consisting of an unforced capacity payment,
fuel conversion option demand payment and minimum utilization charge, and the
energy exercise or start-up payment. Details of the pricing definitions and
calculations are specified in Appendix 1 of the Tolling Agreement, and a sample
monthly billing invoice is included in Appendix 8. The Tolling Agreement also
includes the following possible adjustments:
- Fuel conversion volume rebate
- Heat rate bonus or penalty
- Period availability adjustment/credit
- Facility test fuel
- Non-Dispatch payments
- Transporter imbalance penalties/charges
- Basis settlement for alternative delivery point
5.1.4 INTERCONNECTION AND METERING EQUIPMENT
AES Red Oak at its cost and expense will design, construct, install, own, and
maintain the Interconnection Facilities and Protective Gas Apparatus needed to
generate and deliver the net electric energy to the primary delivery point.
Williams is responsible for installing, maintaining, calibrating, and testing
the gas metering equipment. Net electric energy will be metered on an hour-by
hour basis at the metering point. Williams will pay to AES Red Oak the net
amount shown on the monthly statement within 30 days following the end of the
applicable billing month.
5.2 INTERCONNECTION AGREEMENT
Stone & Webster reviewed the Interconnection Agreement dated April 27, 1999 by
and between JCP&L d/b/a GPU Energy and AES Red Oak. Certain provisions of the
Interconnection Agreement are discussed below. For a summary of the material
terms of the agreement, reference is made to "Description of Project Contracts -
Interconnection Agreement" in the Offering Circular.
In general, Stone & Webster found that the Interconnection Agreement is
comparable to other similar agreements with which Stone & Webster is familiar.
We find the transmission operation interconnection requirements for generation
facilities (Appendix C of the Agreement), the system protection and control
interconnection requirements (Appendix D), and the interconnection installation
agreement (Appendix E) to be reasonable.
FERC has accepted for filing the Interconnection Agreement. This order
constitutes FERC's final action. The Interconnection Agreement will continue
until a mutually agreeable termination date
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not to exceed the retirement date for the Facility, unless terminated on an
earlier date by mutual agreement of the Parties.
GPU ENERGY RESPONSIBILITIES
GPU Energy commits to install all of their Interconnection Facilities to the Red
Oak interconnection facilities within 540 days (i.e., 18 months) of the date Red
Oak issues a Notice to Proceed. AES Red Oak issued a notice to proceed on
December 29, 1999. GPU Energy also commits to own, maintain, and operate the GPU
Energy Interconnection Facilities. AES Red Oak will reimburse GPU Energy for all
actual and verifiable costs and expenses directly associated with the
maintenance and operation of the GPU Energy Interconnection Facilities.
Based upon a review of: (1) an interconnection feasibility study performed by
GPU Energy dated December 1, 1998 (which states that "rough estimates" of the
time required to interconnect the plant "would be around a year"), and (2) the
list of required GPU Energy Interconnection Facilities, Stone & Webster's
opinion is that the 540-day target schedule is ample, and therefore should be
achievable. Given the Notice to Proceed was issued December 29, 1999, the GPU
Energy Interconnection Facilities should be completed by June 29, 2001, eight
months before the Guaranteed Provisional Acceptance Date of February 14, 2002.
The Agreement includes a schedule of bonus and penalties for variances with
respect to the target for completion of the GPU Energy Interconnection
Facilities. Stone & Webster finds the schedule of Bonus/Liquidated Damages and
remedies for delays in completion of the GPU Energy Interconnection Facilities
to be reasonable.
Attachment I of Appendix E of the Interconnection Agreement includes the cost
estimates required to implement the GPU Energy Interconnection Facilities. These
costs are in line with those contained in the GPU Energy feasibility study
mentioned earlier. According to the results of the Feasibility Study completed
by the PJM Interconnection, L.L.C., the Plant causes an overload of substation
equipment at Freneau on the Parlin-Freneau 230 kV line (for the loss of the
South River-Atlantic 230 kV line, with the Sayreville-Gillette 230 kV line out
for maintenance near Sayreville). It is estimated that this problem can be
remediated for $38,000 in addition to the transmission and interconnection
estimated cost of $5,198,448 for a total estimated cost of $5,236,448. The
project economic analysis includes $5.236 million for transmission and
interconnection. Stone & Webster finds that the cost estimate is within the
range of similar projects with which we are familiar. These estimates have been
confirmed by the System Impact Study conducted by the PJM Interconnection,
L.L.C., pursuant to Section IV of its Open Access Transmission Tariff (refer to
Section 3.13.2).
RED OAK RESPONSIBILITIES
Red Oak commits to own, maintain, and operate the Red Oak Interconnection
Facilities and Protective Apparatus at its sole cost and expense. Red Oak also
commits to "make or assure that all necessary arrangements have been made under
the applicable tariffs for transmission service, losses and ancillary services
associated with the delivery of the capacity and/or energy produced by the
Facility, which services will not be provided under this Agreement". It is AES
Red Oak's responsibility to deliver power to the primary delivery point and is
responsible to maintain transmission service beyond the primary delivery point
prior to commercial operation. Williams is responsible to enter into the
Transmission Services Agreement prior to the start of operations.
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5.3 ENGINEERING, PROCUREMENT, AND CONSTRUCTION SERVICES
Stone & Webster reviewed the executed EPC Contract dated December 17, 1999
between AES Red Oak and RE&C. Certain provisions of the EPC Contract are
discussed below. For a summary of the material terms of the agreement, reference
is made to "Description of Project Contracts - EPC Agreement" in the Offering
Circular.
The EPC Contract is for a nominal 832 MW (ISO) combined cycle facility to be
located in Sayreville, New Jersey. . We believe the EPC Contract scope
adequately describes the services to be performed and is technically complete.
RE&C's scope of services is presented in detail in Appendix A of the EPC
Contract. Our assessment of RE&C's scope of services and the technical
descriptions are presented in Chapter 3 of this report. The EPC price includes
the agreed to price by AES Red Oak through the date of this Report, but does not
include future scope changes. The total current contract price is $295.7
million.
5.3.1 RE&C RESPONSIBILITIES
RE&C's responsibilities under the EPC Contract include the design, engineering,
procurement, and construction of the facility; startup, training, and testing;
and the supply of all machinery, equipment (excluding operational spare parts),
tools, construction fuels, chemicals, etc. to complete the Project. RE&C will be
responsible for all tasks necessary to complete the Project other than those
specifically assigned to AES Red Oak in Appendix A. RE&C also prepared a Quality
Assurance Plan (Appendix K). RE&C will use this plan to ensure that the
construction and engineering methods and standards required are adhered to or
achieved. RE&C will develop a list of recommended operational non-CT spare parts
and a price list. This list will be delivered to AES Red Oak at a time mutually
agreeable to AES Red Oak and RE&C prior to the scheduled date for PA. Stone &
Webster will review this list and the procurement schedule when the list becomes
available. Particular attention will be given to spares that are considered to
be critical to the operation of the plant in order to achieve availabilities
represented in the pro forma.
RE&C also has certain obligations with respect to labor and personnel,
permitting and permitting support, inspection and expediting, personnel
training, cleanup and waste disposal, security, coordination with other
contractors, and management and supervision of its subcontractors. Stone &
Webster believes that these areas of contractor responsibility have been
addressed adequately in the EPC Contract. RE&C is required to coordinate its
functions with other contractors involved with the Project. RE&C is also
required to arrange for construction-period water supply facilities, but the EPC
Contract does not address the disposal of construction-period sanitary waste
disposal.
RE&C will provide training to AES Sayreville operation staff. Beginning six
months prior to the Project scheduled date for Provisional Acceptance, RE&C will
provide on-site classroom training for AES Sayreville O&M staff. The training
curriculum is more completely described in Appendix A of the EPC Contract. In
addition to RE&C's own training it will also coordinate any Subcontractor
training sessions in a manner sufficient to provide the personnel with an
adequate understanding of the O&M aspects of each dimension of the Project as an
integrated whole. Stone & Webster agrees with this overall approach to preparing
and training the O&M staff.
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Within 30 days after the Commencement Date, RE&C will submit to AES Red Oak a
detailed electronic construction schedule consistent with the overall
construction schedule ("the Project Schedule") outlined in Appendix C of the EPC
Contract. As soon as practical but no later than 60 days after the Commencement
Date, RE&C will provide AES Red Oak with a critical path method ("CPM") schedule
for the Project including activity duration for each major component of the
Services provided by RE&C.
Stone & Webster reviewed the QC Manual provided by RE&C for AES Red Oak dated
March 31, 1999. RE&C appears to have a thorough and complete program in place to
assure that the design requirements as stated in the applicable drawings,
specifications, codes and industry standards are implemented and satisfied. The
QC Manual was complete with the exception of several project specific forms. The
QC Manual clearly states the chain of command and specific responsibilities of
various site positions up to the level reporting to the President of RE&C.
The QC Manual addresses document and change control, procurement, material
control, inspection and testing, non-conformances, special process control
(welding), calibration of measuring and test equipment, and control of
inspection and test records. The program as described in the QC Manual is
reasonable and, if followed, should result in a project that conforms to the
design requirements.
5.3.2 AES RED OAK RESPONSIBILITIES
AES Red Oak is responsible for certain services associated with the EPC
Contract. These activities relate to the appointment of an Owner's
representative; acquisition of the Facility site and access for RE&C;
acquisition of all applicable permits and real estate rights for the facility;
providing startup personnel; arranging for certain construction utilities (waste
disposal after the risk transfer date), fuel, and electrical interconnection
facilities on the utility side. These responsibilities are reasonable and
customary for this type of transaction.
5.3.3 CONSTRUCTION SCHEDULE
AES Red Oak issued a Limited Notice to Proceed ("LNTP") as of June 18, 1999,
which required RE&C to begin the LNTP Services as specified in the Exhibit I,
for an amount not to exceed $1.1 million. The LNTP agreement was revised four
times, resulting in an agreement for increased LNTP services from June 18, 1999
to March 31, 2000 for an amount not to exceed $7.5 million. AES Red Oak has paid
RE&C $4.6 million as a reservation payment for the CTs.
Stone & Webster reviewed the sequencing of events necessary to achieve Final
Acceptance of the Project and the criteria of each milestone. We believe that
the milestone criteria are technically reasonable. The significant milestones
are Mechanical Completion, Provisional Acceptance, Final Acceptance, and Project
Completion. The Performance Tests and the PPA Output Tests are conducted after
Mechanical Completion in order to meet Provisional Acceptance. The Reliability
Run is required in order to meet Final Acceptance. Project Completion occurs
after Final Acceptance.
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5.3.4 CONTRACT PRICE AND PAYMENT SCHEDULE
The contract price (as adjusted for scope changes) will be paid out to RE&C in
installments in accordance with the Payment and Milestone Schedule as outlined
in Appendix B. Appendix B specifies that a CT reservation fee of 1.24% was made
in February 1999, a CTG payment is due January 15, 2000 of 0.34% for a total of
1.59%, and the third payment of 7.63% is due at Financial Closing. Subsequent
monthly installments will continue through Provisional Acceptance as specified
in Appendix B except for the prepayment as provided under letter agreement dated
February 23, 2000.
The payments begin with Provisional Notice to Proceed and continue through
construction according to the Payment and Milestone Schedule (Appendix B).
Retainage in the amount of 10% is withheld from each scheduled payment except
for the project completion payment. Stone & Webster generally experiences
retainage in the order of 5-10% of the contract price, therefore the Project is
at the top of the range of our experience. Upon achieving Final Acceptance of
the Facility and the receipt of documentation that all requirements have been
satisfied, all the retainage may be paid to RE&C, except that AES Red Oak can
hold back an amount equal to $1 million and 150% of the punch list. Within 30
days after the Project Completion all remaining retainage will be paid to RE&C.
AES Red Oak may deduct and set-off against any part of the balance due or to
become due from RE&C to AES Red Oak in connection with this agreement. If this
set-off amount is later determined not to have been due from RE&C, then RE&C
will be entitled to interest on the set-off amount. The EPC Contract allows for
change orders that may be initiated by AES Red Oak or RE&C. The change order
protocol allows for adjustments to both pricing and schedule. The protocol
utilized in this EPC Contract is similar to other contracts with which we are
familiar and is technically acceptable.
5.3.5 PERFORMANCE TESTING PLANS
To demonstrate Final Acceptance, RE&C must demonstrate 100% of the electrical
output and heat rate guarantees during the performance test. Provisional
Acceptance is achieved when RE&C demonstrates in a completed performance test a
level of achievement of 95% (or higher) of the Electrical Output Guarantee and
105% (or lower) of the Heat Rate Guarantee in accordance with the performance
test procedures set forth in Appendix D. RE&C is obligated to pay all
Performance Guarantee Payments, which payment will be a condition precedent to
the effectiveness of RE&C's election of Final Acceptance. In addition,
Mechanical Completion must be satisfied and the Reliability Guarantee achieved.
Also, the reliability run must be completed no later than the occurrence of
Final Acceptance of the Facility.
Stone & Webster reviewed the performance testing plan. The performance tests
will be performed in accordance with PTC-46, the test code for overall plant
performance testing. A plant specific performance test procedure will be written
by RE&C and submitted to AES Red Oak 90 days prior to the test. Stone & Webster
believes that the performance testing plan as specified in the EPC Contract
Appendix D is acceptable, customary, and should adequately demonstrate the
Project's performance.
AES Red Oak can elect Final Acceptance. In this scenario, RE&C is not required
to demonstrate the electrical output and heat rate and has no liability to AES
Red Oak for any performance
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guarantee payments arising thereafter for failure of the Facility to achieve any
or all of the performance guarantees applicable. RE&C can elect Final
Acceptance. In this case, RE&C must have completed a performance test, which
demonstrates at least a level of 95% electrical output guarantee and 105% of the
heat rate guarantee. RE&C is then obligated to pay all of the performance
guarantee payments as determined by the final or most recent completed
performance test. RE&C also must pay any Provisional Acceptance late completion
payments required.
5.3.6 PERFORMANCE GUARANTEES
RE&C is required to design and construct the Facility to achieve certain
guaranteed performance levels in regards to capacity, heat rate, and
reliability. Appendix R includes the performance guarantees at certain
conditions including an ambient temperature of 92DEG.F and new and clean
condition. The net plant output and net plant heat rate performance guarantees
are 766,050 kW and 6,841 Btu/kWh (HHV), respectively. To demonstrate Final
Acceptance, RE&C must demonstrate 100% of the electrical output and heat rate
guarantees during the performance test. The Performance Guarantees are designed
to ensure that the Project's performance meets the operating parameters of the
Tolling Agreement.
5.3.7 WARRANTY PERIOD
The EPC Contract provides a warranty for all machinery, engineering and design,
and for situations involving corrections, additions, repairs or replacements.
With respect to all machinery, equipment, materials, systems, supplies and other
items comprising the Project, the warranty period is the earlier to occur of (i)
12 months following the first to occur of Provisional Acceptance and Final
Acceptance and (ii) with respect to the machinery, equipment, materials,
systems, supplies and other items comprising each unit, the date on which such
unit has operated for 8,000 equivalent operating hours following the first to
occur of Provisional Acceptance and Final Acceptance.
With respect to the engineering and design of the Project and its components, 12
months following the first to occur of Provisional Acceptance, and Final
Acceptance; and in the case of any correction, addition, repair or replacement
to any machinery, equipment, materials, systems, supplies or other items,
including without limitation the engineering or design thereof, during any
existing warranty period, with respect to such machinery, equipment, materials,
systems, supplies or other items, twelve months after the date of such
correction, addition, repair or replacement, but in no event later than 24
months after the originally scheduled expiration date of the applicable initial
warranty period.
In addition, the EPC Contract states that RE&C warrants and guarantees that the
design of the Facility is based on a useful life design objective for a period
not less than 25 years from the commercial operation date. The useful life of
the Project, provided it is maintained as in the Project Agreements, should
exceed the life of the bonds.
Stone & Webster is of the opinion that the warranty period is acceptable based
on the commercial terms of the EPC Contract in conjunction with the Maintenance
Services Agreement. These two agreements, although independent, are
complementary and afford the Project a greater degree of protection that is
available from the EPC Contract alone. The risk posed by the possibility of a
component failure that occurs after the expiration of the one year EPC Contract
warranty has
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been mitigated because the revenues presented in the Projected Operating Results
are sufficient to allow the purchase of replacement components. Component
failures associated with catastrophic failures are generally covered by
insurance policies.
5.3.8 LIQUIDATED DAMAGES
If there is a shortfall in either electrical output or heat rate RE&C will pay
AES Red Oak rebates for failure to meet final performance requirements. RE&C
guarantees to AES Red Oak to demonstrate a performance level equivalent to the
performance guarantees at least by Final Acceptance. RE&C agrees to pay a
specific amount per kilowatt for each kilowatt less than the electrical output
guarantee as of Final Acceptance. The output rebate should be sufficient to
motivate RE&C to meet their electrical output guarantee.
RE&C will pay to AES Red Oak specified rebate amounts for each Btu/kWh that the
heat rate exceeds the heat rate guarantee as of Final Acceptance. The heat rate
rebates are sufficient to motivate RE&C to meet their heat rate guarantees.
RE&C guarantees that Provisional Acceptance will occur on or before the
Guaranteed Provisional Acceptance Date. If RE&C fails to achieve Provisional
Acceptance by the Guaranteed Provisional Acceptance Date, then RE&C will pay AES
Red Oak a specified dollar amount per day. The Provisional Acceptance Late
Completion Payments cannot exceed 13% of the contract price. If Final Acceptance
does not occur on or before the Guaranteed Final Acceptance Date, the
Provisional Acceptance Late Completion Payments, together with contingencies and
prefunded IDC, will be sufficient to cover the Williams payment plus debt
service commitment for approximately one year after the Guaranteed Provisional
Acceptance Date.
The total aggregate Performance Guarantee Payment is equal to the lesser of the
aggregate total of the Performance Guarantee Payments or the total liquidated
damages subcap less all Provisional Acceptance Late Completion Payments. The
total liquidated damages subcap, including the Performance Guarantee Payment and
all Provisional Acceptance Late Completion Payments, cannot exceed 34% of the
contract price.
Stone & Webster believes, based on its review, that the liquidated damages
provisions are sufficient to motivate RE&C to meet their contractual
obligations.
5.4 DEVELOPMENT AND OPERATIONS SERVICES AGREEMENT
Stone & Webster reviewed the Operations Agreement between AES Red Oak and AES
Sayreville. Certain provisions of the agreement are discussed below. For a
summary of the material terms of the agreement, reference is made to
"Description of the Project Contracts - Operations Agreement" in the Offering
Circular.
Under the Operations Agreement AES Sayreville is obligated to provide personnel
and support services required by AES Red Oak to supervise the development and
construction of the Project until the COD and to maintain and operate the
Facility following the COD through the remaining term of the agreement. The
agreement commences on the execution date and terminates the last day of the
month in the 32nd anniversary of the execution date.
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Stone & Webster is of the opinion that the Operations Agreement is reasonable
and believes that each Party is capable of fulfilling all of its obligations
therein.
5.5 SERVICES AGREEMENT
Stone & Webster reviewed the Services Agreement between AES and AES Sayreville.
Certain provisions of the agreement are discussed below. For a summary of the
material terms of the agreement, reference is made to "Description of the
Project Contracts - Services Agreement" in the Offering Circular.
AES will provide certain personnel and support services to AES Sayreville in
order for AES Sayreville to perform its obligations under the Operations
Agreement. The Services Agreement commences on the execution date and terminates
the last day of the month in the 32nd anniversary of the execution date.
Stone & Webster is of the opinion that the Services Agreement is reasonable and
believes that each Party is capable of fulfilling all of its obligations
therein.
5.6 WATER SUPPLY AGREEMENT
Stone & Webster reviewed the WSA between AES Red Oak and the Borough of
Sayreville. Certain provisions of the agreement are discussed below. For a
summary of the material terms of the agreement, reference is made to
"Description of the Project Contracts - Water Supply Agreement" in the Offering
Circular.
The final agreement executed on December 22, 1999. The Borough of Sayreville
operates a publicly owned raw water system that draws on both the South River by
way of lagoons and the Duhernal acquifer. The existing Lagoons' pumping station
is currently permitted for 1,000,000 gpd. The Borough of Sayreville will use its
best efforts to amend its existing permit in order to construct a new Lagoon
Pumping Station to supply AES Red Oak with up to 4,600,000 gpd of untreated
water. The existing Duhernal Water Pipeline will be used as a backup source of
water, up to a maximum of 4,600,000 gpd for the plant when the Lagoons' water
level falls below 20 feet and South River water is unavailable due to low flow
or chloride limitations or a break in the lagoons' water pipeline. In the event
of a break in the infrastructure, AES has the right to contract with approved
contractors to step in and remedy the interruption if the Borough fails to
restore full service within a reasonable amount of time. AES Red Oak will pay
the Borough of Sayreville monthly for water used, at a specified rate which
covers both the Borough's O&M costs and past infrastructure or acquisition
costs. AES Red Oak will be responsible for the cost of constructing and
installing the Lagoon Water Pipeline, Lagoon Pumping Station, and the Sayreville
Interconnection Number 2 to the Duhernal Water Pipeline. The point of delivery
is located at or inside the Project property. The term of this Agreement is 30
years with no more than four successive five-year extensions.
Stone & Webster's opinion is that the WSA is technically reasonable and believes
that each Party is capable of fulfilling all of its obligations therein.
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5.7 AGREEMENTS RELATING TO REAL ESTATE
Stone & Webster reviewed the Amended and Restated Option Agreement and Contract
for Purchase and Sale between AES Red Oak and Forest View Industrial Park, Inc.
("Forest View"), dated June 24, 1998, the Temporary Construction License Option,
Agreement between AES Red Oak and Hercules Inc. ("Hercules"), dated October 30,
1999, and the License Agreement between GPU Energy and AES Red Oak dated
November 8, 1999. Certain provisions of the agreements are discussed below. For
a summary of the material terms of the agreement, reference is made to
"Description of Project Contracts - Agreements Relating to Real Estate" in the
Offering Circular.
AMENDED AND RESTATED OPTION AGREEMENT AND CONTRACT FOR PURCHASE AND SALE BETWEEN
AES RED OAK AND FOREST VIEW
Forest View the equitable owner of the 62.7-acre property of which approximately
37.34 acres is buildable, the rest being designated as State regulated wetlands
and wetlands transition area. AES Red Oak has entered into on option to purchase
the property on which it intends to build the Project. The agreement addresses
certain rights to investigate the property during the option period, real estate
transfer, access and easement agreements, and certain soil removal actions
during the option period. Forest View has obtained a Letter of Non-applicability
from the NJDEP that the Industrial Site Recovery Act does not apply to this
property. As of April 30, 1999 AES Red Oak has the exclusive control and
possession of the property for the remainder of the option period through the
closing date. The option period has been extended past the original date of
December 24, 1998, and can be extended twice more until April 1, 2000. During
this time, AES Red Oak has the right, at its own cost, to obtain all licenses,
permits and approvals to construct and operate a power plant. The permitted use
of the property does not have to be expanded under the Zoning Ordinance of the
Borough of Sayreville. AES Red Oak may determine at its sole discretion during
the option period not to purchase this property. If AES Red Oak exercises its
option to purchase, the agreement becomes a binding Purchase and Sale Agreement.
As of December 1999, AES Red Oak's investigations of the site have not revealed
anything that would cause them to modify the agreement or abandon the site.
Based on other real estate agreements evaluated by Stone & Webster, the terms of
this agreement appear reasonable.
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TEMPORARY CONSTRUCTION LICENSE OPTION AND AGREEMENT BETWEEN AES RED OAK AND
HERCULES
Hercules, as owner of property adjacent to the AES Red Oak site, has agreed to
grant AES Red Oak an option to acquire a temporary license to a portion of
Hercules' property (License Area). The License Area will be used by AES Red Oak
to store non-hazardous construction material and equipment, and for a parking
lot in connection with construction activities. If AES Red Oak exercises the
option, they will pay Hercules $100,000. The expiration of the option is the
earlier of (1) the Effective Date on which the option is exercised, or (2)
February 28, 2000 if the option is not exercised. The term of the license is
thirty months from the Effective Date. During the license term, AES Red Oak has
the right to construct temporary improvements but not permanent structures or
improvements. At the end of the license term, AES Red Oak is to return the
property to the condition it was in immediately prior to the Effective Date. AES
Red Oak is not obligated to remove any parking improvements constructed unless
requested to do so by Hercules. During the term of the option, AES Red Oak has
the right to enter the License Area to perform inspections and tests including
environmental sampling, in order to determine if the License Area is suitable
for AES Red Oak's purposes.
AES Red Oak will indemnify, defend and save harmless Hercules from all fines,
suits, procedures, claims and actions of any kind as a result of spills or
discharges of substances or hazardous wastes at the License Area during the
license term. AES Red Oak will be responsible for any cleanup required of spills
or discharges caused by AES Red Oak. Hercules will indemnify and hold AES Red
Oak harmless from and against any and all loss, cost, damage, liability and
expense arising from (1) any condition within the License Area existing as of
the Effective Date of the license, or (2) any damage to property, or for injury
to or death of any person arising from any such pre-existing condition.
Based on other real estate agreements evaluated by Stone & Webster, the terms of
this agreement appear reasonable.
5.8 MAINTENANCE PROGRAM PARTS, SHOP REPAIRS AND SCHEDULED OUTAGE TFA
SERVICES CONTRACT
Stone & Webster reviewed the Maintenance Services Agreement dated December 8,
1999 between AES Red Oak and SWPC for the Project. Certain provisions of the
agreement are discussed below. For a summary of the material terms of the
agreement, reference is made to "Description of Project Contracts - Maintenance
Program Parts, Shop Repairs and Scheduled Outage TFA Services Contract" in the
Offering Circular.
SWPC agrees to provide the parts and technical field services required to
conduct the major maintenance on the CTs. SWPC also provides a warranty for its
parts and advice. In exchange, AES Red Oak pays SWPC a fee established on a per
equivalent hour basis. Under the terms of the Maintenance Services Agreement,
all major maintenance and parts are to be provided by SWPC, even if the
particular item is not covered by the original equipment warranty or some
provision of this services agreement. The Maintenance Services Agreement
obligates SWPC to notify AES Red Oak of any engineering or design defects that
develop in the 501F fleet and provide remedial action.
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The Maintenance Services Agreement provides CT major maintenance (including all
scheduled outages) and spare parts for this Project in a reasonable manner for
12 scheduled outages (approximately 96,000 EBH) or approximately the initial 16
years of operation. This service provided by the original equipment
manufacturer's trained personnel reduces the risk of using improper parts or
maintenance being conducted improperly on the CTs. The Maintenance Services
Agreement provides risk mitigation by providing a warranty on parts and services
provided as part of the Agreement. The warranty period ends with the earlier of
one year from date of installation of the part, 8000 equivalent base operating
hours, or 250 starts of the CT, three years from the date of delivery of the
original new program part or miscellaneous hardware except the warranties expire
no later than one year after the termination or conclusion of the term.
If during the term an unscheduled outage occurs within 1,000 EBHs of a scheduled
outage and the services were to be provided during the upcoming scheduled outage
then the scheduled outage would be moved up in time. If during the term an
unscheduled outage occurs which is the result of a new program part or
miscellaneous hardware, shop repair failure, a program part not achieving its
expected life, or the failure of a service than SWPC will provide the parts and
services as established in the Maintenance Services Agreement discounted by any
part life credit and established credit capped at a maximum annual amount. If
during the term an unscheduled outage occurs for reasons other than these
discussed above then SWPC will provide the parts and services as established in
the Maintenance Services Agreement discounted by any part life credit and
established credit capped at a maximum annual amount.
The Maintenance Services Agreement levelizes the major maintenance parts costs
and indexes costs to the type of CT operation in a reasonable and consistent
fashion. Under the agreement, AES Red Oak is responsible for labor and
supervision of labor for the major maintenance activities and the normal and
routine maintenance for the CTs. These costs are included in the operation and
maintenance budget and are accounted for in the Project's Projected Operating
Results. SWPC's scope of supply requirements under the Maintenance Services
Agreement are reasonable and consistent with standard industry practice.
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6. PRINCIPAL PROJECT PARTICIPANTS
Stone & Webster reviewed the major Project participants and believe each should
be capable of fulfilling their obligations to one another as specified in the
various contracts and agreements of the Project.
6.1 AES RED OAK, LLC
AES Red Oak is a limited liability company, organized and existing under the
laws of Delaware. AES Red Oak was formed to develop, own, and operate the
Project. AES Red Oak is a special purpose project company and a subsidiary of
AES Red Oak, Inc. AES Red Oak Inc. is a wholly owned subsidiary of AES.
Stone & Webster believes that AES Red Oak, as an affiliate of AES and with the
assistance of SWPC under the terms of the Maintenance Services Agreement, should
be capable of operating and maintaining the Facility in accordance with standard
industry practices.
6.2 AES SAYREVILLE, LLC
AES Sayreville is a Delaware limited liability company and a wholly owned
subsidiary of AES Red Oak, Inc. AES Sayreville will manage the development,
construction, operations and maintenance of the Project pursuant to the
Operations Agreement between AES Sayreville and AES Red Oak. Stone & Webster
believes that AES Sayreville, as an affiliate of AES, should be capable of
managing the development and construction of the Project.
6.3 WILLIAMS ENERGY MARKETING & TRADING COMPANY
Williams is the Project's power purchaser and fuel supplier. Williams is a
corporation organized and existing under the laws of the State of Delaware and
is a wholly owned subsidiary of the Williams Companies. The Williams Companies,
through its subsidiaries, is engaged in the transportation and sale of natural
gas and petroleum products, and is engaged in energy commodity trading and
marketing.
Stone & Webster believes that Williams possesses the organization and personnel
to execute its obligations under the Tolling Agreement, and is familiar with the
provision of fuel and purchase of electricity from large electrical generation
facilities.
6.4 RAYTHEON ENGINEERS & CONSTRUCTORS
RE&C is the Project's EPC Contractor. RE&C is a subsidiary of the parent
organization, Raytheon Company ("Raytheon"). Throughout its more than 75-year
history, the Raytheon has developed defense technologies and converted those
technologies for use in commercial markets. Today, Raytheon is focused on three
core business segments: defense and commercial electronics; business aviation
and special mission aircraft; and engineering and construction.
Raytheon acquired more than a dozen well-known engineering and construction
firms to form RE&C. In 1998 Raytheon had worldwide sales of more than $19
billion and more than 100,000 employees. Raytheon has served customers in more
than 80 countries. RE&C offers full-service
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engineering and construction services to clients worldwide. RE&C has 14,000
employees of which 8,000 are professional employees based in over 35 offices
worldwide and 6,000 craft and construction workers employed at approximately 300
project locations. In 1998 RE&C had $2.1 billion in sales.
Stone & Webster believes that RE&C possesses the organization, personnel, and
programs to execute its obligations under the EPC Contract.
6.5 SIEMENS WESTINGHOUSE POWER CORPORATION
SWPC is the Project's major equipment supplier. SWPC is a newly formed Delaware
corporation that was formed in 1998 when Siemens Corporation acquired the
Westinghouse Power Generation business from the CBS Corporation in August 1998.
SWPC, headquartered in Orlando, Florida, is the regional business division for
the Americas and operates engineering and manufacturing centers in North
America.
Siemens Corporation owns all of the SWPC stock and is an industry leader in
telecommunications; energy and power; transportation; information systems and
other products. For the first nine months of fiscal year 1997/1998 Siemens' U.S.
businesses, with more than 55,000 employees, recorded sales of $7.0 billion.
Siemens AG, based in Berlin and Munich, owns all of the Siemens Corporation
stock and is one of the world's largest electrical engineering and electronics
companies and employs over 400,000 people worldwide in more than 190 countries.
Stone & Webster believes that SWPC possesses the organization and personnel to
execute its obligations to provide the equipment as specified under the EPC
Contract to RE&C and execute its obligations under the Maintenance Services
Contract.
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7. ASSESSMENT OF PROJECTED OPERATING RESULTS
7.1 OVERVIEW
The Projected Operating Results consist of a pro forma financial model for AES
Red Oak (the "Base Case"). Stone & Webster has reviewed the assumptions, data,
and the calculations necessary to support the cash flow projections of the cash
flow available for debt service. Stone & Webster has verified that the
underlying model assumptions are consistent with the expected performance and
the commercial terms of the Project Agreements. Stone & Webster has validated
key calculations to ensure that the resulting revenues, expenses, cash flow, and
DSCRs were correctly calculated. Stone & Webster has reviewed the Projected
Operating Results and compared them to data provided in the Project Agreements,
data provided to Stone & Webster and power industry public information. Stone &
Webster has not reviewed the tax and depreciation assumptions, which were
provided by AES Red Oak, and financing assumptions, including the amortization
schedule and interest rates, which were provided by Lehman Brothers.
Lastly, Stone & Webster performed several sensitivities to determine the impact
of certain variables on the DSCRs. The Projected Operating Results for the Base
Case and the sensitivity cases are included in Exhibit I of this Report. The
Projected Operating Results are calculated in nominal dollars based on an
assumed inflation rate of 3% per annum.
7.2 PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
In preparing this Report and the conclusions contained herein, Stone & Webster
has made certain assumptions with respect to the conditions, which may exist, or
events, which may occur in the future. While Stone & Webster believes these
assumptions to be reasonable for the purpose of this Report, they are dependent
on future events, and actual conditions may differ from those assumed. In
addition, Stone & Webster has used and relied on information provided to us by
sources that we believe to be reliable. Stone & Webster believes that the use of
this information and assumptions is reasonable for the purposes of our Report.
However, some assumptions may vary significantly due to unanticipated events and
circumstances. To the extent that actual future conditions may differ from those
assumed in this Report, or provided to us by others, the actual results will
vary from those forecast. This Report summarizes our work up to the date of the
Report and changes in conditions occurring or that became known after such date
could affect the Projected Operating Results.
The principal considerations and assumptions related to the Projected Operating
Results are listed below:
1. Stone & Webster has assumed that the Project will be designed and built in
accordance with the design specifications and the construction schedule
dictated in the EPC contract.
2. The electricity market energy and capacity price projections, which are
relevant during the post PPA period were prepared by ICF Resources for
Lehman Brothers, in its capacity as an Initial Purchaser, using a market
simulation model. Stone & Webster reviewed the technical inputs to the ICF
Resources model and found them to be reasonable. Stone & Webster did not
independently verify the methodology used by ICF Resources to develop the
energy or capacity price forecasts nor verify the accuracy of the
forecasts.
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3. Stone & Webster has made no determination as to the validity and
enforceability of any contract, agreement, rule, or regulation as
applicable to the Facility and its operations. For the purposes of this
Report, Stone & Webster has assumed that all contracts, agreements, rules,
or regulations will be valid and fully enforceable in accordance with the
terms and that all parties will comply with the provisions of their
respective agreements.
4. Williams will arrange for the procurement and delivery of the fuel to the
Facility and will purchase all available capacity, ancillary services, and
energy from AES Red Oak in accordance with the Tolling Agreement.
5. Stone & Webster has reviewed the capital and O&M budgets for AES Red Oak.
We have assumed that the Facility will operate and be maintained in
accordance with the Operations Agreement, O&M and capital budgets, standard
industry practice, and in a safe and environmentally responsible manner.
6. Stone & Webster has assumed for purposes of the Projected Operating Results
that AES Red Oak will operate the Facility pursuant to the Tolling
Agreement through the end of the first quarter of 2022 and as a merchant
plant for the term of the Bonds.
7. Stone & Webster has assumed that the maintenance will be performed by AES
Sayreville in accordance with the Operations Agreement and by SWPC in
accordance with the Maintenance Services Agreement.
8. The natural gas prices are inputs to the ICF Resources model. It is assumed
that the fuel will be available in sufficient quantities and at the prices
forecasted for the period covered in the Projected Operating Results.
9. Stone & Webster has assumed that all licenses, permits, and approvals
required to construct and operate the Project which have not been obtained
will be obtained in a timely basis and any changes that may be required to
any permits will not materially affect the design, operation, cost, or
maintenance of the Project.
10. Stone & Webster has assumed that AES Red Oak will be able to purchase
emission allowances, to the extent any are required, on an as needed basis
to comply with the emission limits. We have assumed that emission offsets
will be available for purchase at the prices forecasted in the Projected
Operating Results. Stone & Webster has not evaluated the feasibility or
cost of AES Ironwood implementing alternate strategies for complying with
its emission limits.
11. Stone & Webster has not evaluated the non-operating expenses projected by
AES Red Oak including property and capital franchise taxes, insurance, and
general and administrative expenses.
7.3 PROJECT COST
Stone & Webster evaluated AES Red Oak's estimate for the total Project costs
included in the pro forma financial model. The Projected Operating Results Base
Case total Project construction costs are estimated to be $425.56 million
(excluding contingency) or approximately $511/kW (net, ISO) in the pro forma
financial model. The breakdown of the total Project costs is provided in the
following table:
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<TABLE>
<CAPTION>
========================================================================
TOTAL PROJECT COSTS
($ ,000)
========================================================================
<S> <C>
EPC Contract(1) $295,700
Infrastructure / Other Hard Costs 12,816
Lenders & LOC Fees 6,182
Development & Startup Costs 24,115
Net Interest During Construction 68,974
Hedge Settlement Cost 13,349
Other Soft Costs 4,421
Contingency 14,194
---------------------------------------------------- -------------------
TOTAL PROJECT COSTS $439,750
==================================================== ===================
(1) Red Oak prepaid $4.6 million
</TABLE>
Stone & Webster evaluated the Project's lump sum fixed price for the EPC
Contract of $295.7 million (including adjustments and the $4.6 million that Red
Oak prepaid), which is equivalent to approximately $355/kW (net). The EPC
Contract price is competitive relative to similar facilities.
The non-EPC portion of the total Project cost includes infrastructure costs,
start-up costs, insurance, financing costs including IDC as well as lenders,
legal, and consultants fees, and working capital. The subtotal of the non-EPC
portion of the total Project cost, excluding contingency, equals $129.9 million,
or 29.5% of the total Project costs, which is within the range of other similar
projects.
The Project development costs represent approximately 5% of the total Project
cost, which is reasonable for a project of this type. The financial model
assumes approximately a 3.2% contingency in the total Project cost, which based
on our experience, is typical of similar projects.
The financial model currently has $1.5 million in its capital budget for the
initial spare parts. AES Red Oak intends to identify those operational spare
parts approximately one year before commercial operations. In addition, there
are $4.96 million worth of CT maintenance spares imbedded in the Maintenance
Service Agreement, which will be available during the first 8000 EBH.
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7.4 POWER PRODUCTION
Stone & Webster evaluated the technical assumptions associated with the
performance of the Project for electricity production. The Base Case assumes a
832 MW net Facility capacity at site conditions, a 95% average availability
factor, and 75.3% average capacity factor over the 30-year term of the Bond
issue. Availability Factor is defined as the total hours in a year (i.e., 8760)
minus planned maintenance hours and forced outage hours. Capacity factor is
defined as the actual hours of operation (i.e., dispatched) over the year.
The Base Case assumes that the Facility will continue to operate as a merchant
facility after the expiration of the 20-year PPA. Under the merchant operation
the Facility capacity is assumed to operate at a degraded net full load Facility
capacity at site conditions while operating on natural gas.
7.4.1 POWER PLANT AVAILABILITY
Power plant availability is a function of many variables, including design and
construction quality, operation and maintenance practices, and fuel quality. In
order to be conservative, the Base Case assumes a lower availability factor in
year one than in subsequent years. AES Red Oak projects the availability factor
to be 92% in the first year and an average of 95% in subsequent years.
7.4.2 CAPACITY FACTOR
The Facility capacity factor is based on ICF Resources's economic dispatch of
AES Red Oak within the context of its PJM market study. Stone & Webster did not
independently verify the methodology that ICF Resources used to develop the
capacity factor nor verify the accuracy of the forecast. ICF Resources projected
for the Base Case that the AES Red Oak will have an average capacity factor of
75.3% during the term of the PPA and the post PPA period.
7.4.3 CAPACITY
The Base Case Projected Operating Results are based on the net Facility capacity
operating on natural gas at site conditions adjusted to 92DEG.F and including
degradation. The Base Case model assumes a 3% degradation factor for output at
48,000 operating hours, which is based on the following assumptions:
- Performing compressor maintenance during the "hot path" outages
- Performing frequent compressor water wash maintenance
- The natural gas fuel meets SWPC requirements
- The Plant will be located in an area where the ambient air will not
adversely affect the CT
- The CTs will be operated and maintained in accordance with SWPC
operating procedures
Stone & Webster considers the assumed degradation to be within the range of
expected degradation for such power generation facilities based on the planned
maintenance schedule.
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7.5 REVENUES
Williams is obligated for a period of 20 years from the COD to purchase the
Facility capacity, approximately 766 MW at 92DEG.F when firing on natural gas
pursuant to the PPA. Williams will pay AES Red Oak for the Facility capacity,
fuel conversion services, and ancillary services provided under the PPA. The
Project revenues are calculated based on the pricing and payment structure
defined in Appendix 1 of the PPA. The PPA revenues for the first full calendar
year (Year 2003) are $78 million.
Williams pays AES Red Oak for facility capacity, fuel conversion services, and
ancillary services. The payments include the sum of the Variable O&M Payment and
the Total Fixed Payment. The Total Fixed Payment consists of an unforced
capacity payment, fuel conversion option demand payment, minimum utilization
charge, and the energy exercise or start-up payment. Williams provides fuel to
the Project for conversion into energy. Consequently, the Project is not
responsible for the cost of fuel. Rather Williams pays a fee to AES Red Oak to
convert the fuel into energy. The Fuel Conversion Rates are escalated annually
at the Gross Domestic Product Implicit Price Deflator ("GDPIPD"). The Base Case
assumes a GDPIPD of 3%.
In addition to the fuel conversion revenue, Williams is required to pay AES Red
Oak an energy efficiency bonus or penalty ("HRB/HRP"). The energy efficiency
bonus or penalty is based on the difference between the Heat Rate Target ("HRT")
and the actual Facility Heat Rate ("FHR"), net electric energy delivered, and
the natural gas price index.
If the Project Equivalent Availability Factor ("EAF") as defined in Appendix 1
to the PPA is greater than 85% for each Summer Peak Period, Winter Peak Period,
and Non-peak Period there is a Peak Period Adjustment ("PAA") payable to AES Red
Oak. The Period Availability Credit ("PAC") will be calculated as a credit to
Williams for each Summer Peak Period, Winter Peak Period, and a Non-Peak Period
based on if the EAF is lower than 95% in the peak periods and 87.8% in the non
peak periods. The Base Case assumes that the EAF is not expected to fall below
these levels and therefore the PAC is projected to be zero for the 20-year term
of the PPA.
The Base Case assumes a 2% degradation factor for heat rate at 48,000 hours of
operation, which is standard for similar facilities. Stone & Webster considers
the assumed degradation to be within the range of expected degradation for such
power generation facilities.
After 20 years from COD at the end of the PPA term, the Base Case assumes that
the Project net capacity and energy will be sold into the PJM system for a
period through and beyond the maturity of the Bonds. ICF Resources estimated the
Base Case first merchant operating year (2022) AES Red Oak plant-specific energy
and capacity market price projections in 1998 dollars at $25.0/MWh and
$52.0/kW/yr, respectively. The total operating revenue for the first full
merchant calendar year (Year 2023) is $333.1 million.
7.6 OPERATING EXPENSES
The estimated Project expenses during the PPA period consist of non-fuel fixed
and variable expenses. The natural gas will be supplied and transported to the
Project under the terms established in the PPA. During the PPA period, Williams
will arrange for the procurement and delivery of the natural gas to the Facility
fuel delivery point. After the PPA period, AES Red Oak will be responsible for
the procurement and
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delivery of all the fuel to the Facility.
In the pro forma, the estimated O&M expenses are in nominal dollars reflecting
an assumed 3% inflation per year. The first full calendar year (Year 2003) fixed
and variable non-fuel O&M expenses total $14.986 million and are detailed in the
following table.
<TABLE>
<CAPTION>
===========================================================================
ESTIMATED NON-FUEL O&M EXPENSES
(2003 $ ,000)
===========================================================================
<S> <C>
Fixed O&M $ 4,456
Variable O&M 1,436
Annual Maintenance 7,950
Water Cost 344
Property Taxes 800
-------------------------------------------------------- ------------------
TOTAL NON-FUEL O&M EXPENSES $14,986
======================================================== ==================
</TABLE>
Stone & Webster reviewed the O&M assumptions utilized in the Projected Operating
Results. The information reviewed included assumptions and forecasts for unit
performance; staffing functions and levels; annual O&M budget summary; and unit
overhaul plans and schedules. Stone & Webster compared the information with its
experience with plants of similar configuration and Utility Data Institute cost
and staffing information for similar plants. Stone & Webster considers these
Project assumptions to be reasonable and comparable to other facilities of
similar design.
7.6.1 MAINTENANCE SCHEDULE
All maintenance work and spare parts replacement for the CT during the first
48,000 hours of the Facility operations will be provided by SWPC through the
Maintenance Services Agreement and thereafter will be the responsibility of AES
Red Oak. The O&M schedule and budget assumes that each CT accumulates 8000 EBH
each year. SWPC's recommended frequency for annual inspections, hot gas path
inspections, and major overhauls are being used. In addition, AES Red Oak has
included in the schedule and budget a "cover lift" for every hot gas path
inspection in order to restore any performance degradation experienced since the
previous major overhaul. Stone & Webster believes that AES Red Oak's planned
overhaul and maintenance schedule is reasonable and adequate to support its
operational and business objectives.
7.6.2 OPERATIONS AND MAINTENANCE BUDGET
Stone & Webster reviewed the non-fuel fixed, variable, and major maintenance
expenses in the Projected Operating Results. Stone & Webster believes that the
O&M budget is sufficient to support the planned staffing level, the maintenance
and overhaul schedule, and the Project's performance and business objectives.
B-63
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[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
7.6.3 O&M STAFFING LEVELS
AES Red Oak's planned functional positions and staffing levels were reviewed and
are considered satisfactory to operate and maintain the Facility safely in
accordance with the operational and regulatory requirements. The staffing levels
compare favorably with and are typical of those found in similarly configured
plants that Stone & Webster has reviewed. Our review also included the resume of
the proposed Project Plant Manager, who appears qualified to perform
satisfactorily for AES Red Oak. Stone & Webster believes that the staffing
levels are adequate to support AES Red Oak's operational and business
objectives.
7.6.4 EMISSION COMPLIANCE COSTS
The Projected Operating Results include an emission compliance limit cost. AES
Red Oak will be required to purchase allowances for all SO(2) emitted from the
Facility and for all NO(x) emitted from the Facility after 2003. The Base Case
assumes that the Project will need approximately 138 tons of NO(x) allowances
per year at the current market value of $3,000 per ton for a vintage 1999
allowance. NO(x) allowance costs in the year 2003 are projected to be $.466
million. The Base Case assumes that the Project will need approximately 104
tons of SO(2) allowances per year, commencing at COD in year 2002, at the
current market value of $225 per ton. The SO(2) allowance cost for 2002 is
$0.026 million. Both the NO(x) and SO(2) allowance costs are projected to
increase at 3% per annum.
7.6.5 FUEL EXPENSE
In operating year 21, the term of the PPA will end and AES Red Oak will be
responsible for providing the fuel for the Facility to operate as a merchant
plant. The Base Case assumes that the fuel will be purchased at the price
stipulated in the ICF Resources report. The delivered natural gas price will
start at $2.59/mmBtu in real 1998$'s in year 2002 and increases to $3.04/mmBtu
in real 1998$'s in the first merchant operating year, 2022. The fuel expense
assumed during the post PPA period is based on the Facility heat rate at ISO
conditions, the Facility capacity factor, and the unit cost of fuel. The fuel
expense for the first full calendar year of merchant operation is $207.7
million. When AES Red Oak becomes a merchant plant, the fuel expense will be the
single largest expense.
The ICF Resources report assumes that the fuel expenses are in 1998$'s and are
escalated at 3%. The unit fuel costs assumed in the ICF Resources report are
shown in the following table.
B-64
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[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
========================================================
FUEL PRICE FORECAST
========================================================
DELIVERED NATURAL GAS
YEAR ($1998/MMBTU)
------------------- -----------------------------------
<S> <C>
2022 3.04
2023 3.04
2024 3.04
2025 3.04
2026 3.04
=================== ===================================
</TABLE>
7.7 FINANCING ASSUMPTIONS
Lehman Brothers provided the financing assumptions for the $439.75 million
Project cost. The source of funds will consist of $55.75 million in equity and
$384 million in debt. The capital cost items are allocated monthly during the
construction period to calculate releases of Bond proceeds and interest during
construction ("IDC"). The combined annual debt service (principal plus interest,
annual administrative and LOC fees) during the post construction period ranges
from a low of $15.4 million in 2026 to a high of $43.0 million in 2009.
7.8 PROJECTED OPERATING RESULTS
The Projected Operating Results are shown in Exhibit I of this Report. On the
basis of our studies and analyses of the Project, the Project Agreements and the
assumptions set forth in this Report, the projected revenues from the sale of
fuel conversion services, capacity, and ancillary services are more than
adequate to pay the annual O&M expenses (including provisions for major
maintenance), other operating expenses, and debt service.
The Base Case indicate the following DSCRs:
<TABLE>
<CAPTION>
==================================================================================
BASE CASE
DEBT SERVICE COVERAGE
==================================================================================
MINIMUM AVERAGE
--------------------------- --------------------------- --------------------------
<S> <C> <C>
PPA PERIOD
--------------------------- --------------------------- --------------------------
1.55x 1.57x
--------------------------- --------------------------- --------------------------
POST PPA TERM
--------------------------- --------------------------- --------------------------
6.37x 7.13x
--------------------------- --------------------------- --------------------------
FULL TERM OF THE BONDS
--------------------------- --------------------------- --------------------------
1.55x 3.16x
=========================== =========================== ==========================
</TABLE>
B-65
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[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
7.9 SENSITIVITY ANALYSES
Due to uncertainties necessarily inherent in relying on assumptions and
projections, it should be anticipated that actual operating results would
differ, perhaps, materially, from those assumed and described herein. In order
to demonstrate the impact of certain circumstances on the Projected Operating
Results, certain sensitivity analyses have been developed by Stone & Webster. It
should be noted that other examples could have been considered, and those
presented are not intended to reflect the full extent of possible impacts on the
Project.
Stone & Webster performed several sensitivity analyses using the pro forma
financial model by varying the following Project specific key input parameters
including power plant availability, heat rate degradation factors, and O&M
costs.
7.9.1 PROJECT SENSITIVITIES
The three Project sensitivities include increasing the Base Case O&M costs,
increasing the Base Case heat rate, and decreasing the Base Case availability.
OPERATION AND MAINTENANCE COST SENSITIVITY - The Base Case O&M costs were
increased by 10%. The resulting average and minimum DSCRs for the PPA term, the
post PPA term, and the full term of the Bonds are summarized in the following
table.
<TABLE>
<CAPTION>
==================================================================================
SENSITIVITY CASE 1
OPERATION AND MAINTENANCE
DEBT SERVICE COVERAGE RATIOS
==================================================================================
MINIMUM AVERAGE
--------------------------- --------------------------- --------------------------
<S> <C> <C>
PPA TERM
--------------------------- --------------------------- --------------------------
1.52x 1.54x
--------------------------- --------------------------- --------------------------
POST PPA TERM
--------------------------- --------------------------- --------------------------
6.27x 7.03x
--------------------------- --------------------------- --------------------------
FULL TERM OF THE BONDS
--------------------------- --------------------------- --------------------------
1.52x 3.11x
=========================== =========================== ==========================
</TABLE>
B-66
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[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
HEAT RATE DEGRADATION FACTORS - To test the sensitivity of the Projected
Operating Results to heat rate, Stone & Webster increased the Base Case heat
rate by 5% (ignoring liquidated damages 'buy-downs'). The resulting average and
minimum DSCRs for the PPA term, the full term, and the post PPA term are
summarized in the following table.
<TABLE>
<CAPTION>
==================================================================================
SENSITIVITY CASE 2
HEAT RATE DEGRADATION
DEBT SERVICE COVERAGE RATIOS
==================================================================================
MINIMUM AVERAGE
--------------------------- --------------------------- --------------------------
<S> <C> <C>
PPA TERM
--------------------------- --------------------------- --------------------------
1.31x 1.36x
--------------------------- --------------------------- --------------------------
POST PPA TERM
--------------------------- --------------------------- --------------------------
5.71x 6.45x
--------------------------- --------------------------- --------------------------
FULL TERM OF THE BONDS
--------------------------- --------------------------- --------------------------
1.31x 2.81x
=========================== =========================== ==========================
</TABLE>
AVAILABILITY FACTOR SENSITIVITY - To test the pro forma sensitivity the Base
Case availability assumption was changed. The Base Case availability is 92% for
the first year and ranges from 93.6% to 95.4% for the remaining life of the
Facility. The Facility availability was reduced each year by 3.5%. The resulting
average and minimum DSCRs for the PPA term, the full term, and the post PPA term
are summarized in the following table.
<TABLE>
<CAPTION>
==================================================================================
SENSITIVITY CASE 3
AVAILABILITY FACTOR
DEBT SERVICE COVERAGE RATIOS
==================================================================================
MINIMUM AVERAGE
--------------------------- --------------------------- --------------------------
<S> <C> <C>
PPA TERM
--------------------------- --------------------------- --------------------------
1.52x 1.53x
--------------------------- --------------------------- --------------------------
POST PPA TERM
--------------------------- --------------------------- --------------------------
6.36x 7.14x
--------------------------- --------------------------- --------------------------
FULL TERM OF THE BOND
--------------------------- --------------------------- --------------------------
1.52x 3.13x
=========================== =========================== ==========================
</TABLE>
7.9.2 ICF RESOURCES SENSITIVITIES
In addition, sensitivity of the Project results was assessed for the three
sensitivity cases, Low Gas Price Case, a High Gas Price Case, and an Overbuild
Case. The Low Gas Price, High Gas Price, and the Overbuild Case scenarios were
taken from the ICF Resources forecasts. Stone & Webster applied the three ICF
Resources "macroeconomic" sensitivities to the Base Case.
B-67
<PAGE>
[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
HIGH GAS PRICE - The natural gas prices were uniformly increased by $0.50 per
mmBtu (in 1998$) above the Base Case levels. The resulting average and minimum
DSCRs for the post PPA term are summarized in the following table.
<TABLE>
<CAPTION>
======================================================
SENSITIVITY CASE 5 - HIGH GAS PRICE
DEBT SERVICE COVERAGE RATIOS
======================================================
MINIMUM AVERAGE
--------------------------- --------------------------
<S> <C> <C>
POST PPA TERM
--------------------------- --------------------------
6.29x 7.00x
=========================== ============ =============
</TABLE>
LOW GAS PRICE - The natural gas prices were uniformly decreased by $0.50 per
mmBtu (in 1998$) below the Base Case levels. The resulting average and minimum
DSCRs for the post PPA term are summarized in the following table.
<TABLE>
<CAPTION>
======================================================
SENSITIVITY CASE 4 - LOW GAS PRICE
DEBT SERVICE COVERAGE RATIOS
======================================================
MINIMUM AVERAGE
--------------------------- --------------------------
<S> <C> <C>
POST PPA TERM
--------------------------- --------------------------
6.43x 7.19x
=========================== ============ =============
</TABLE>
OVERBUILD - The overbuild scenario assumes that plants will be built to meet
peak demand and reserve requirements of the Base Case through 2020 and an
additional unexpected infusion of building on the order of 10% of peak, above
and beyond the Base Case requirements in 2020.
<TABLE>
<CAPTION>
======================================================
SENSITIVITY CASE 6 - OVERBUILD
DEBT SERVICE COVERAGE RATIOS
======================================================
MINIMUM AVERAGE
--------------------------- --------------------------
<S> <C> <C>
POST PPA TERM
--------------------------- --------------------------
5.56x 6.99x
=========================== ============ =============
</TABLE>
7.10 LIQUIDATED DAMAGES ANALYSES
Stone & Webster reviewed the impact on the average DSCRs if RE&C fails to pass
certain performance tests and there is a long-term performance deficiency over
the term of the Bonds. It was assumed that the performance rebates paid to AES
Red Oak by RE&C would be used to buy down the Bonds on a pro rata basis. The
analysis was performed to demonstrate that the liquidated damages for the
guaranteed net electrical output and guaranteed net heat rate are sufficient to
maintain the DSCRs at the same level as projected in the Base Case.
It is projected that the average DSCRs over the term of the Bonds, after payment
of the liquidated damages due to a failure to achieve the guaranteed net
electrical output or the guaranteed net heat rate, will generally remain at the
same level as the average DSCRs in the Base Case for deficiencies up to
approximately 4% in net electrical output and 6% in net heat rate.
B-68
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[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
RE&C is required to pay liquidated damages for a delay in the Facility
completion. RE&C will pay AES Red Oak $108,000 for each day after the required
Facility completion date that the Facility completion is not achieved. The
liquidated damages for a delay in the Facility completion cannot exceed 13% of
the contract price. Such payment, together with contingencies, will be
sufficient to cover the Williams payment plus debt service commitment for one
year after the Guaranteed Provisional Acceptance Date.
B-69
<PAGE>
[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
EXHIBIT I
Base Case
Increased O&M Sensitivity (Case #1)
Increased Heat Rate Sensitivity (Case #2)
Decreased Availability Sensitivity (Case #3)
High Gas (Case #4)
Low Gas (Case #5)
Overbuild (Case #6)
B-70
<PAGE>
EXHIBIT I
AES RED OAK PROJECTED OPERATING RESULTS
BASE CASE
<TABLE>
<CAPTION>
PPA Period
-----------------------------------------------------------------------------------
Year Ending December 31, 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------------------------
Annual Generation (GWh) 5,615 6,068 6,035 6,029 6,103 6,006 5,953 6,010 5,946 5,826 5,831
-----------------------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 71.3 78.0 76.6 76.6 79.2 77.2 77.6 80.3 78.9 78.5 81.2
Merchant Revenues - - - - - - - - - - -
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
Total Operating Revenues 77.2 84.4 83.0 82.9 85.7 83.6 83.9 86.8 85.3 84.8 87.7
-----------------------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - - - -
Fixed O&M 3.9 4.5 4.6 4.7 4.9 5.0 5.2 5.3 5.5 5.6 5.8
Variable O&M 1.3 1.4 1.9 2.0 2.0 2.1 2.1 2.2 2.2 2.3 2.3
Annual Maintenance 7.0 7.9 8.2 8.5 8.7 8.9 7.0 4.4 4.6 4.6 4.7
Water cost 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Property tax 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Expenses 19.2 21.4 22.2 22.7 23.2 23.6 21.9 19.6 19.9 20.1 20.5
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 58.0 63.0 60.8 60.2 62.4 60.0 62.1 67.2 65.4 64.7 67.2
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 374.0 371.7 365.7 360.8 355.9 349.1 343.3 335.5 323.6 311.7 299.1
Principal and Interest 37.8 41.0 39.6 39.0 40.4 38.8 40.2 43.5 42.3 41.9 42.9
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
-----------------------------------------------------------------------------------
Total Debt Service 38.1 41.5 40.0 39.4 40.8 39.2 40.6 43.9 42.8 42.3 43.3
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.52x 1.52x 1.52x 1.53x 1.53x 1.53x 1.53x 1.53x 1.53x 1.53x 1.55x
-----------------------------------------------------------------------------------
<CAPTION>
PPA PERIOD
---------------------------------------------------------------------
Year Ending December 31, 2013 2014 2015 2016 2017 2018 2019 2020 2021
---------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
---------------------------------------------------------------------
Annual Generation (GWh) 5,703 5,619 5,609 5,444 5,309 5,288 5,119 4,992 4,961
---------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 79.1 79.2 82.0 80.1 79.5 82.3 80.0 79.7 82.5
Merchant Revenues - - - - - - - - -
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Total Operating Revenues 85.5 85.5 88.4 86.5 85.8 88.7 86.3 86.0 89.0
---------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - -
Fixed O&M 6.0 6.2 6.4 6.5 6.7 6.9 7.2 7.4 7.6
Variable O&M 2.3 2.4 2.4 2.4 2.5 2.5 2.5 2.5 2.6
Annual Maintenance 4.8 4.9 4.9 5.0 5.0 5.1 5.1 5.2 5.2
Water cost 0.4 0.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Expenses 20.7 21.0 21.4 21.6 21.8 22.2 22.4 22.7 23.1
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 64.7 64.5 67.0 64.9 64.0 66.5 63.9 63.3 65.9
---------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 284.2 269.5 253.8 235.0 215.8 195.3 171.1 146.4 119.5
Principal and Interest 41.4 40.9 42.5 41.0 40.6 42.2 40.6 40.2 41.8
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
---------------------------------------------------------------------
Total Debt Service 41.8 41.3 43.0 41.6 41.0 42.6 41.0 40.6 42.2
---------------------------------------------------------------------
---------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.55x 1.56x 1.56x 1.56x 1.56x 1.56x 1.56x 1.56x 1.56x
---------------------------------------------------------------------
<CAPTION>
POST PPA PERIOD
-----------------------------------------------------------------
Year Ending December 31, 2022* 2023 2024 2025 2026 2027 2028 2029
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------
Annual Generation (GWh) 4,832 4,714 4,672 4,538 4,493 4,507 4,431 4,375
-----------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 13.0 - - - - - - -
Merchant Revenues 276.8 333.1 340.1 342.0 348.6 358.9 363.9 370.3
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
-----------------------------------------------------------------
Total Operating Revenues 290.9 333.1 340.1 342.0 348.6 358.9 363.9 370.3
-----------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel 172.6 207.7 210.6 211.9 216.6 221.8 225.4 229.7
Fixed O&M 7.8 8.1 8.3 8.5 8.8 9.1 9.3 9.6
Variable O&M 2.6 2.6 2.6 2.7 2.7 2.8 2.8 2.9
Annual Maintenance 5.3 5.3 5.4 5.4 5.6 5.7 5.8 5.9
Water cost 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Expenses 190.2 224.6 227.8 229.4 234.5 240.2 244.3 249.1
-----------------------------------------------------------------
-----------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 100.7 108.5 112.3 112.5 114.1 118.7 119.6 121.2
-----------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 88.2 80.6 71.1 60.7 50.4 39.6 27.4 14.3
Principal and Interest 16.0 7.0 17.0 15.8 15.4 15.6 15.3 15.2
LOC & Administrative Fees 0.2 0.3 0.3 0.2 0.2 0.2 0.2 0.2
-----------------------------------------------------------------
Total Debt Service 16.2 17.2 17.3 16.1 15.6 15.8 15.5 15.5
-----------------------------------------------------------------
-----------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 6.20x 6.30x 6.50x 7.00x 7.30x 7.50x 7.70x 7.84x
-----------------------------------------------------------------
* PPA cash flows continue through the first two months of 2022.
AVERAGE DEBT COVERAGE DURING PPA 1.54x
MINIMUM DEBT COVERAGE DURING PPA 1.52x
AVERAGE DEBT COVERAGE POST PPA 7.04x
MINIMUM DEBT COVERAGE POST PPA 6.20x
AVERAGE DEBT COVERAGE DURING 3.11x
BOND TERM
</TABLE>
B-71
<PAGE>
EXHIBIT I
AES RED OAK PROJECTED OPERATING RESULTS
INCREASED O&M SENSITIVITY (CASE #1)
<TABLE>
<CAPTION>
PPA PERIOD
-----------------------------------------------------------------------------------
Year Ending December 31, 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------------------------
Annual Generation (GWh) 5,615 6,068 6,035 6,029 6,103 6,006 5,953 6,010 5,946 5,826 5,831
-----------------------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 71.3 78.0 76.6 76.6 79.2 77.2 77.6 80.3 78.9 78.5 81.2
Merchant Revenues - - - - - - - - - - -
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
Total Operating Revenues 77.2 84.4 83.0 82.9 85.7 83.6 83.9 86.8 85.3 84.8 87.7
-----------------------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - - - -
Fixed O&M 4.3 4.9 5.0 5.2 5.4 5.5 5.7 5.9 6.0 6.2 6.4
Variable O&M 1.4 1.6 2.1 2.2 2.2 2.3 2.3 2.4 2.5 2.5 2.5
Annual Maintenance 7.0 7.9 8.2 8.5 8.7 8.9 7.2 4.9 5.0 5.1 5.2
Water cost 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Property tax 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Expenses 19.8 22.0 22.9 23.4 23.9 24.3 22.8 20.8 21.1 21.4 21.8
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 57.5 62.4 60.1 59.6 61.7 59.3 61.1 66.0 64.2 63.5 65.9
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 374.0 371.7 365.7 360.8 355.9 349.1 341.3 335.5 323.6 311.7 299.1
Principal and Interest 37.8 41.0 39.6 39.0 40.4 38.8 40.2 43.5 42.3 41.9 42.9
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
-----------------------------------------------------------------------------------
Total Debt Service 38.1 41.5 40.0 39.4 40.8 39.2 40.6 43.9 42.8 42.3 43.3
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.51x 1.51x 1.50x 1.51x 1.51x 1.51x 1.51x 1.50x 1.50x 1.50x 1.52x
-----------------------------------------------------------------------------------
<CAPTION>
PPA PERIOD
---------------------------------------------------------------------
Year Ending December 31, 2013 2014 2015 2016 2017 2018 2019 2020 2021
---------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
---------------------------------------------------------------------
Annual Generation (GWh) 5,703 5,619 5,609 5,444 5,309 5,288 5,119 4,992 4,961
---------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 79.1 79.2 82.0 80.1 79.5 82.3 80.0 79.7 82.5
Merchant Revenues - - - - - - - - -
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Total Operating Revenues 85.5 85.5 88.4 86.5 85.8 88.7 86.3 86.0 89.0
---------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - -
Fixed O&M 6.6 6.8 7.0 7.2 7.4 7.6 7.9 8.1 8.3
Variable O&M 2.6 2.6 2.7 2.7 2.7 2.7 2.8 2.8 2.8
Annual Maintenance 5.3 5.4 5.4 5.5 5.5 5.6 5.6 5.7 5.7
Water cost 0.4 0.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Expenses 22.0 22.4 22.8 23.0 23.3 23.7 23.9 24.2 24.6
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 63.4 63.2 65.6 63.5 62.5 65.1 62.4 61.8 64.4
---------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 284.2 269.5 253.8 235.0 215.8 195.3 178.1 146.4 119.5
Principal and Interest 41.4 40.9 42.5 41.2 40.6 42.2 40.6 40.2 41.8
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
---------------------------------------------------------------------
Total Debt Service 41.8 41.3 43.0 41.6 41.0 42.6 41.0 40.6 42.2
---------------------------------------------------------------------
---------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.52x 1.53x 1.53x 1.53x 1.53x 1.53x 1.52x 1.52x 1.52x
---------------------------------------------------------------------
<CAPTION>
POST PPA PERIOD
-----------------------------------------------------------------
Year Ending December 31, 2022* 2023 2024 2025 2026 2027 2028 2029
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------
Annual Generation (GWh) 4,832 4,714 4,672 4,538 4,493 4,507 4,431 4,375
-----------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 13.0 - - - - - - -
Merchant Revenues 276.8 333.1 340.1 342.0 348.6 358.9 363.9 370.3
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
-----------------------------------------------------------------
Total Operating Revenues 290.9 333.1 340.1 342.0 348.6 358.9 363.9 370.3
-----------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel 172.6 207.7 210.6 211.9 216.6 221.8 225.4 229.7
Fixed O&M 8.6 8.9 9.1 9.4 9.7 10.0 10.3 10.6
Variable O&M 2.8 2.9 2.9 2.9 3.0 3.1 3.1 3.2
Annual Maintenance 5.8 5.9 5.9 6.0 6.1 6.2 6.4 6.5
Water cost 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Expenses 191.8 226.2 229.4 231.1 236.3 241.95 246.1 251.0
-----------------------------------------------------------------
-----------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 99.1 106.9 110.6 110.9 112.4 116.9 117.8 119.3
-----------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 88.2 80.6 71.1 60.7 50.4 39.6 27.4 14.3
Principal and Interest 16.0 17.0 17.0 15.8 15.4 15.6 15.1 15.2
LOC & Administrative Fees 0.2 0.3 0.3 0.2 0.2 0.2 0.2 0.2
-----------------------------------------------------------------
Total Debt Service 16.2 17.2 17.1 16.1 15.6 15.8 15.5 15.5
-----------------------------------------------------------------
-----------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 6.10x 6.21x 6.41x 6.90x 7.19x 7.39x 7.38x 7.72x
-----------------------------------------------------------------
* PPA cash flows continue through the first two months of 2022.
AVERAGE DEBT COVERAGE DURING PPA 1.52x
MINIMUM DEBT COVERAGE DURING PPA 1.50x
AVERAGE DEBT COVERAGE POST PPA 6.94x
MINIMUM DEBT COVERAGE POST PPA 6.10x
AVERAGE DEBT COVERAGE DURING 3.06x
BOND TERM
</TABLE>
B-72
<PAGE>
EXHIBIT I
AES RED OAK PROJECTED OPERATING RESULTS
INCREASED HEAT RATE SENSITIVITY (CASE #2)
<TABLE>
<CAPTION>
PPA PERIOD
-----------------------------------------------------------------------------------
Year Ending December 31, 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------------------------
Annual Generation (GWh) 5,615 6,068 6,035 6,029 6,103 6,006 5,953 6,010 5,946 5,826 5,831
-----------------------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 65.5 71.3 69.7 69.3 71.7 69.6 69.6 72.0 70.4 69.7 72.2
Merchant Revenues - - - - - - - - - - -
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
Total Operating Revenues 71.4 77.7 76.1 75.7 78.1 75.9 75.9 78.5 76.8 76.1 78.6
-----------------------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - - - -
Fixed O&M 3.9 4.5 4.6 4.7 4.9 5.0 5.2 5.3 5.5 5.6 5.8
Variable O&M 1.3 1.4 1.9 2.0 2.0 2.1 2.1 2.2 2.2 2.3 2.3
Annual Maintenance 7.0 7.9 8.2 8.5 8.7 8.9 7.0 4.4 4.6 4.6 4.7
Water cost 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Property tax 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Expenses 19.2 21.4 22.2 22.7 23.2 23.6 21.9 19.6 19.9 20.1 20.5
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 52.2 56.3 53.8 53.0 54.9 52.4 54.1 58.9 56.9 56.0 58.1
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 374.0 371.7 365.7 360.8 355.9 349.1 343.3 335.5 323.6 311.7 299.1
Principal and Interest 37.8 41.0 39.6 39.0 40.4 38.8 40.2 43.5 42.3 41.9 42.9
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
-----------------------------------------------------------------------------------
Total Debt Service 38.1 41.5 40.0 39.4 40.8 39.2 40.6 43.9 42.8 42.3 43.3
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.37x 1.36x 1.35x 1.35x 1.34x 1.33x 1.33x 1.34x 1.33x 1.32x 1.34x
-----------------------------------------------------------------------------------
<CAPTION>
PPA PERIOD
---------------------------------------------------------------------
Year Ending December 31, 2013 2014 2015 2016 2017 2018 2019 2020 2021
---------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
---------------------------------------------------------------------
Annual Generation (GWh) 5,703 5,619 5,609 5,444 5,309 5,288 5,119 4,992 4,961
---------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 69.9 69.7 72.2 70.3 69.4 72.0 69.7 69.2 71.9
Merchant Revenues - - - - - - - - -
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Total Operating Revenues 76.3 76.0 78.6 76.6 75.8 78.5 76.1 75.5 78.3
---------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - -
Fixed O&M 6.0 6.2 6.4 6.5 6.7 6.9 7.2 7.4 7.6
Variable O&M 2.3 2.4 2.4 2.4 2.5 2.5 2.5 2.5 2.6
Annual Maintenance 4.8 4.9 4.9 5.0 5.0 5.1 5.1 5.2 5.2
Water cost 0.4 0.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Expenses 20.7 21.0 21.4 21.6 21.8 22.2 22.4 22.7 23.1
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 55.6 55.0 57.2 55.0 53.9 56.2 53.6 52.8 55.3
---------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 284.2 269.5 253.8 235.0 215.8 195.3 171.1 146.4 119.5
Principal and Interest 41.4 40.9 42.5 41.2 40.6 42.2 40.6 40.2 41.8
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
---------------------------------------------------------------------
Total Debt Service 41.8 41.3 43.0 41.6 41.0 42.6 41.0 40.6 42.2
---------------------------------------------------------------------
---------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.33x 1.33x 1.33x 1.32x 1.32x 1.32x 1.31x 1.30x 1.31x
---------------------------------------------------------------------
<CAPTION>
POST PPA PERIOD
-----------------------------------------------------------------
Year Ending December 31, 2022* 2023 2024 2025 2026 2027 2028 2029
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------
Annual Generation (GWh) 4,832 4,714 4,672 4,538 4,493 4,507 4,431 4,375
-----------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 11.3 - - - - - - -
Merchant Revenues 276.8 333.1 340.1 342.0 348.6 358.9 363.9 370.3
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
-----------------------------------------------------------------
Total Operating Revenues 289.2 333.1 340.1 342.0 348.6 358.9 363.9 370.3
-----------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel 181.2 218.1 221.1 222.5 227.4 232.9 236.7 241.2
Fixed O&M 7.8 8.1 8.3 8.5 8.8 9.1 9.3 9.6
Variable O&M 2.6 2.6 2.6 2.7 2.7 2.8 2.8 2.9
Annual Maintenance 5.3 5.3 5.4 5.4 5.6 5.7 5.8 5.9
Water cost 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Expenses 198.8 235.0 238.3 240.0 245.4 251.3 255.6 260.6
-----------------------------------------------------------------
-----------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 90.3 98.1 101.7 101.9 103.3 107.6 108.3 109.7
-----------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 88.2 80.6 71.1 60.7 50.4 39.6 27.4 14.3
Principal and Interest 16.0 17.0 17.0 15.8 15.4 15.6 15.3 15.2
LOC & Administrative Fees 0.2 0.3 0.3 0.2 0.2 0.2 0.2 0.2
-----------------------------------------------------------------
Total Debt Service 16.2 7.2 17.3 16.1 15.6 15.8 15.5 15.5
-----------------------------------------------------------------
-----------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 5.56x 5.70x 5.89x 6.34x 6.61x 6.80x 6.97x 7.10x
-----------------------------------------------------------------
* PPA cash flows continue through the first two months of 2022.
AVERAGE DEBT COVERAGE DURING PPA 1.33x
MINIMUM DEBT COVERAGE DURING PPA 1.30x
AVERAGE DEBT COVERAGE POST PPA 6.37x
MINIMUM DEBT COVERAGE POST PPA 5.56x
AVERAGE DEBT COVERAGE DURING 2.77x
BOND TERM
</TABLE>
B-73
<PAGE>
EXHIBIT I
AES RED OAK PROJECTED OPERATING RESULTS
DECREASED AVAILABILITY SENSITIVITY (CASE #3)
<TABLE>
<CAPTION>
PPA PERIOD
-----------------------------------------------------------------------------------
Year Ending December 31, 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------------------------
Annual Generation (GWh) 5,615 6,068 6,035 6,029 6,103 6,006 5,953 6,010 5,946 5,826 5,831
-----------------------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 69.3 76.0 74.8 74.8 77.4 75.6 75.9 78.6 77.3 76.9 79.6
Merchant Revenues - - - - - - - - - - -
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Revenues 75.3 82.4 81.2 81.1 83.8 81.9 82.2 85.0 83.7 83.2 86.0
-----------------------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - - - -
Fixed O&M 3.9 4.5 4.6 4.7 4.9 5.0 5.2 5.3 5.5 5.6 5.8
Variable O&M 1.3 1.4 1.9 2.0 2.0 2.1 2.1 2.2 2.2 2.3 2.3
Annual Maintenance 7.0 7.9 8.2 8.5 8.7 8.9 7.0 4.4 4.6 4.6 4.7
Water cost 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Property tax 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Expenses 19.2 21.4 22.2 22.7 23.2 23.6 21.9 19.6 19.9 20.1 20.5
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 56.0 61.0 58.9 58.4 60.6 58.3 60.3 65.4 63.8 63.1 65.6
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 384.0 381.6 375.4 370.1 365.1 358.0 351.9 343.7 331.2 318.7 305.6
Principal and Interest 36.2 39.7 38.2 37.6 39.1 37.5 39.0 42.5 41.4 41.0 42.2
LOC & Administrative Fees 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
-----------------------------------------------------------------------------------
Total Debt Service 36.7 40.2 38.7 38.1 39.6 38.0 39.5 43.0 41.9 41.6 42.7
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.53x 1.52x 1.52x 1.53x 1.53x 1.53x 1.53x 1.52x 1.52x 1.52x 1.53x
-----------------------------------------------------------------------------------
<CAPTION>
PPA PERIOD
---------------------------------------------------------------------
Year Ending December 31, 2013 2014 2015 2016 2017 2018 2019 2020 2021
---------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
---------------------------------------------------------------------
Annual Generation (GWh) 5,703 5,619 5,609 5,444 5,309 5,288 5,119 4,992 4,961
---------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 77.6 77.7 80.5 78.8 78.2 81.0 78.8 78.5 81.4
Merchant Revenues - - - - - - - - -
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Revenues 84.0 84.1 86.9 85.1 84.5 87.4 85.2 84.9 87.8
---------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - -
Fixed O&M 6.0 6.2 6.4 6.5 6.7 6.9 7.2 7.4 7.6
Variable O&M 2.3 2.4 2.4 2.4 2.5 2.5 2.5 2.5 2.6
Annual Maintenance 4.8 4.9 4.9 5.0 5.0 5.1 5.1 5.2 5.2
Water cost 0.4 0.4 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Expenses 20.7 21.0 21.4 21.6 21.8 22.2 22.4 22.7 23.1
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 63.3 63.0 65.5 63.5 62.7 65.2 62.7 62.2 64.8
---------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 290.0 274.6 258.2 238.5 218.4 196.9 171.6 146.4 119.5
Principal and Interest 40.7 40.4 42.2 40.9 40.5 42.3 40.2 39.4 41.2
LOC & Administrative Fees 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
---------------------------------------------------------------------
Total Debt Service 41.2 40.9 42.7 41.4 41.0 42.9 40.7 39.9 41.7
---------------------------------------------------------------------
---------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.54x 1.54x 1.53x 1.53x 1.53x 1.52x 1.54x 1.56x 1.55x
---------------------------------------------------------------------
<CAPTION>
POST PPA PERIOD
-----------------------------------------------------------------
Year Ending December 31, 2022* 2023 2024 2025 2026 2027 2028 2029
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------
Annual Generation (GWh) 4,832 4,714 4,672 4,538 4,493 4,507 4,431 4,375
-----------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 12.9 0 0 0 0 0 0 0
Merchant Revenues 276.8 333.1 340.1 342.0 348.6 358.9 363.9 370.3
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Revenues 290.8 333.1 340.1 342.0 348.7 358.9 364.0 370.3
-----------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel 172.6 207.7 210.6 211.9 216.6 221.8 225.4 229.7
Fixed O&M 7.8 8.1 8.3 8.5 8.8 9.1 9.3 9.6
Variable O&M 2.6 2.6 2.6 2.7 2.7 2.8 2.8 2.9
Annual Maintenance 5.3 5.3 5.4 5.4 5.6 5.7 5.8 5.9
Water cost 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Expenses 190.2 224.6 227.8 229.4 234.5 240.2 244.3 249.1
-----------------------------------------------------------------
-----------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 100.5 108.5 112.3 112.6 114.1 118.7 119.6 121.2
-----------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 88.2 80.6 71.1 60.7 50.4 39.6 27.4 14.3
Principal and Interest 15.5 16.5 16.6 15.5 15.1 15.4 15.2 15.2
LOC & Administrative Fees 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3
-----------------------------------------------------------------
Total Debt Service 15.8 16.8 17.0 15.8 15.4 15.7 15.5 15.5
-----------------------------------------------------------------
-----------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 6.36x 6.44x 6.63x 7.12x 7.40x 7.57x 7.73x 7.84x
-----------------------------------------------------------------
* PPA cash flows continue through the first two months of 2022.
AVERAGE DEBT COVERAGE DURING PPA 1.53x
MINIMUM DEBT COVERAGE DURING PPA 1.52x
AVERAGE DEBT COVERAGE POST PPA 7.14x
MINIMUM DEBT COVERAGE POST PPA 6.36x
AVERAGE DEBT COVERAGE DURING 3.13x
BOND TERM
</TABLE>
B-74
<PAGE>
EXHIBIT I
AES RED OAK PROJECTED OPERATING RESULTS
HIGH GAS PRICE SENSITIVITY (CASE #4)
<TABLE>
<CAPTION>
PPA PERIOD
-----------------------------------------------------------------------------------
Year Ending December 31, 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------------------------
Annual Generation (GWh) 5,035 5,421 5,372 5,347 5,436 5,372 5,347 5,421 5,387 5,314 5,354
-----------------------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 69.4 75.0 73.7 73.4 76.1 74.4 74.4 77.3 76.1 75.7 78.6
Merchant Revenues - - - - - - - - - - -
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Revenues 75.3 81.5 80.1 79.7 82.5 80.8 80.8 83.7 82.4 82.0 85.0
-----------------------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - - - -
Fixed O&M 3.9 4.5 4.6 4.7 4.9 5.0 5.2 5.3 5.5 5.6 5.8
Variable O&M 1.1 1.3 1.7 1.7 1.8 1.9 1.9 2.0 2.0 2.1 2.1
Annual Maintenance 6.3 7.1 7.3 7.5 7.8 8.0 8.2 5.5 4.1 4.2 4.3
Water cost 0.3 0.3 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.4 0.4
Property tax 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Expenses 18.4 20.4 21.1 21.5 22.0 22.4 22.8 20.4 19.2 19.5 19.9
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 56.9 61.1 59.0 58.3 60.5 58.4 58.0 63.3 63.3 62.6 65.2
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 374.0 371.7 365.7 360.8 355.9 349.1 341.3 335.5 323.6 311.7 299.1
Principal and Interest 37.8 41.0 39.6 39.0 40.4 38.8 40.2 43.5 42.3 41.9 42.9
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
-----------------------------------------------------------------------------------
Total Debt Service 38.1 41.5 40.0 39.4 40.8 39.2 40.6 43.9 42.8 42.3 43.3
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.49x 1.47x 1.48x 1.48x 1.48x 1.49x 1.33x 1.44x 1.48x 1.48x 1.50x
-----------------------------------------------------------------------------------
<CAPTION>
PPA PERIOD
---------------------------------------------------------------------
Year Ending December 31, 2013 2014 2015 2016 2017 2018 2019 2020 2021
---------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
---------------------------------------------------------------------
Annual Generation (GWh) 5,271 5,228 5,253 5,117 5,008 5,005 4,862 4,758 4,688
---------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 76.9 76.9 80.0 78.3 77.7 80.8 78.7 78.4 81.3
Merchant Revenues - - - - - - - - -
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Revenues 83.3 83.3 86.4 84.7 84.1 87.3 85.1 84.8 87.8
---------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - -
Fixed O&M 6.0 6.2 6.4 6.5 6.7 6.9 7.2 7.4 7.6
Variable O&M 2.2 2.2 2.3 2.3 2.3 2.4 2.4 2.4 2.4
Annual Maintenance 4.4 4.5 4.6 4.7 4.7 4.8 4.9 4.9 4.9
Water cost 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.5
Property tax 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Expenses 20.2 20.5 20.9 21.1 21.4 21.8 22.0 22.3 23.6
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 63.1 62.8 65.5 63.6 62.7 65.5 63.1 62.5 65.1
---------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 284.2 269.5 253.8 235.0 215.8 195.3 171.1 146.4 119.5
Principal and Interest 41.4 40.9 42.5 41.2 40.6 42.2 40.6 40.2 41.8
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
---------------------------------------------------------------------
Total Debt Service 41.8 41.3 43.0 41.6 41.0 42.6 41.0 40.6 42.2
---------------------------------------------------------------------
---------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.51x 1.52x 1.52x 1.53x 1.53x 1.54x 1.54x 1.54x 1.54x
---------------------------------------------------------------------
<CAPTION>
POST PPA PERIOD
-----------------------------------------------------------------
Year Ending December 31, 2022* 2023 2024 2025 2026 2027 2028 2029
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------
Annual Generation (GWh) 4,526 4,378 4,301 4,141 4,126 4,164 4,118 4,092
-----------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 12.8 - - - - - - -
Merchant Revenues 291.6 348.5 353.5 353.1 361.2 373.1 379.6 387.5
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Revenues 305.5 348.5 353.5 353.1 361.2 373.1 379.6 387.5
-----------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel 188.9 225.2 226.1 225.4 231.9 239.1 244.8 251.2
Fixed O&M 7.8 8.1 8.3 8.5 8.8 9.1 9.3 9.6
Variable O&M 2.4 2.4 2.4 2.4 2.5 2.6 2.6 2.7
Annual Maintenance 4.9 5.0 4.9 4.9 5.1 5.2 5.4 5.5
Water cost 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Expenses 206.0 241.5 242.6 242.1 249.2 256.9 263.0 269.9
-----------------------------------------------------------------
-----------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 99.5 107.1 110.9 111.0 112.0 116.2 116.5 117.5
-----------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 88.2 80.6 71.1 60.7 50.4 39.6 27.4 14.3
Principal and Interest 16.0 17.0 17.0 15.8 15.4 15.6 15.1 15.2
LOC & Administrative Fees 0.2 0.3 0.3 0.2 0.2 0.2 0.2 0.2
-----------------------------------------------------------------
Total Debt Service 16.2 17.2 17.3 16.1 15.6 15.8 15.5 15.5
-----------------------------------------------------------------
-----------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 6.33x 6.22x 6.42x 6.90x 7.17x 7.34x 7.50x 7.61x
-----------------------------------------------------------------
* PPA cash flows continue through the first two months of 2022.
AVERAGE DEBT COVERAGE DURING PPA 1.50x
MINIMUM DEBT COVERAGE DURING PPA 1.43x
AVERAGE DEBT COVERAGE POST PPA 6.91x
MINIMUM DEBT COVERAGE POST PPA 6.13x
AVERAGE DEBT COVERAGE DURING 3.05x
BOND TERM
</TABLE>
B-75
<PAGE>
EXHIBIT I
AES RED OAK PROJECTED OPERATING RESULTS
LOW GAS PRICE SENSITIVITY (CASE #5)
<TABLE>
<CAPTION>
PPA PERIOD
-----------------------------------------------------------------------------------
Year Ending December 31, 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------------------------
Annual Generation (GWh) 6,136 6,766 6,734 6,733 6,812 6,660 6,633 6,692 6,616 6,557 6,638
-----------------------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 72.9 81.0 79.6 79.8 82.4 80.1 80.8 83.6 82.1 82.1 85.0
Merchant Revenues - - - - - - - - - - -
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Revenues 78.9 87.4 85.9 86.1 88.8 86.4 87.2 90.0 88.4 88.4 91.5
-----------------------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - - - -
Fixed O&M 3.9 4.5 4.6 4.7 4.9 5.0 5.2 5.3 5.5 5.6 5.8
Variable O&M 1.4 1.6 2.1 2.2 2.3 2.3 2.4 2.4 2.5 2.6 2.6
Annual Maintenance 7.7 8.9 9.2 9.5 9.8 9.4 4.8 4.9 5.1 5.2 5.3
Water cost 0.3 0.5 0.5 0.5 0.5 0.5 0.6 0.6 0.6 0.6 0.6
Property tax 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Expenses 20.1 22.6 23.6 24.1 24.7 24.5 20.0 20.5 20.8 21.1 21.6
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 58.8 64.8 62.4 62.0 64.1 62.0 67.1 69.5 67.6 67.3 69.8
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 374.0 371.7 365.7 360.8 355.9 349.1 341.3 335.5 323.6 311.7 299.1
Principal and Interest 37.8 41.0 39.6 39.0 40.4 38.8 40.2 43.5 42.3 41.9 42.9
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
-----------------------------------------------------------------------------------
Total Debt Service 38.1 41.5 40.0 39.4 40.8 39.2 40.0 43.9 42.8 42.3 43.3
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.54x 1.56x 1.56x 1.58x 1.57x 1.58x 1.46x 1.58x 1.58x 1.59x 1.61x
-----------------------------------------------------------------------------------
<CAPTION>
PPA PERIOD
---------------------------------------------------------------------
Year Ending December 31, 2013 2014 2015 2016 2017 2018 2019 2020 2021
---------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
---------------------------------------------------------------------
Annual Generation (GWh) 6,568 6,545 6,608 6,465 6,354 6,379 6,224 6,117 6,114
---------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 82.9 83.6 86.7 84.9 84.6 87.7 85.2 85.4 88.6
Merchant Revenues - - - - - - - - -
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Revenues 89.3 89.9 93.2 91.2 90.9 94.1 91.6 91.7 95.0
---------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - -
Fixed O&M 6.0 6.2 6.4 6.5 6.7 6.9 7.2 7.4 7.6
Variable O&M 2.7 2.8 2.9 2.9 3.0 3.0 3.1 3.1 3.2
Annual Maintenance 5.5 5.7 5.8 5.9 6.0 6.1 6.2 6.3 6.4
Water cost 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6
Property tax 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Expenses 22.0 22.4 22.9 23.2 23.5 23.9 24.2 24.5 25.0
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 67.3 67.5 70.2 68.1 67.4 70.2 67.4 67.2 70.0
---------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 284.2 269.5 253.8 235.0 215.8 195.3 171.1 146.4 119.5
Principal and Interest 41.4 40.9 42.5 41.2 40.6 42.2 40.6 40.2 41.8
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
---------------------------------------------------------------------
Total Debt Service 41.8 41.3 43.0 41.6 41.0 42.6 41.0 40.6 42.2
---------------------------------------------------------------------
---------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.61x 1.63x 1.64x 1.64x 1.64x 1.65x 1.65x 1.66x 1.66x
---------------------------------------------------------------------
<CAPTION>
POST PPA PERIOD
-----------------------------------------------------------------
Year Ending December 31, 2022* 2023 2024 2025 2026 2027 2028 2029
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------
Annual Generation (GWh) 5,989 5,877 5,858 5,722 5,599 5,550 5,392 5,261
-----------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 14.0 - - - - - - -
Merchant Revenues 285.1 344.1 352.4 355.4 359.8 367.8 370.3 374.2
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Revenues 300.2 344.1 352.4 355.4 359.8 367.8 370.3 374.2
-----------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel 178.9 216.1 220.0 222.3 224.7 227.6 228.8 230.6
Fixed O&M 7.8 8.1 8.3 8.5 8.8 9.1 9.3 9.6
Variable O&M 3.2 3.3 3.3 3.4 3.4 3.4 3.5 3.5
Annual Maintenance 6.5 6.6 6.7 6.8 6.9 7.0 7.0 7.1
Water cost 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.7
Property tax 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Expenses 198.5 235.1 239.4 242.1 244.8 248.1 249.7 251.9
-----------------------------------------------------------------
-----------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 101.7 109.0 113.0 113.3 114.9 119.7 120.7 122.3
-----------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 88.2 80.6 71.1 60.7 50.4 39.6 27.4 14.3
Principal and Interest 16.0 17.0 17.0 15.8 15.4 15.6 15.3 15.2
LOC & Administrative Fees 0.2 0.3 0.3 0.2 0.2 0.2 0.2 0.2
-----------------------------------------------------------------
Total Debt Service 16.2 17.2 17.3 16.1 15.6 15.8 15.5 15.5
-----------------------------------------------------------------
-----------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 6.26x 6.33x 6.54x 7.05x 7.35x 7.56x 7.77x 7.92x
-----------------------------------------------------------------
* PPA cash flows continue through the first two months of 2022.
AVERAGE DEBT COVERAGE DURING PPA 1.61x
MINIMUM DEBT COVERAGE DURING PPA 1.54x
AVERAGE DEBT COVERAGE POST PPA 7.10x
MINIMUM DEBT COVERAGE POST PPA 6.26x
AVERAGE DEBT COVERAGE DURING 3.18x
BOND TERM
</TABLE>
B-76
<PAGE>
EXHIBIT I
AES RED OAK PROJECTED OPERATING RESULTS
OVERBUILD SENSITIVITY (CASE #6)
<TABLE>
<CAPTION>
PPA PERIOD
-----------------------------------------------------------------------------------
Year Ending December 31, 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------------------------
Annual Generation (GWh) 5,615 6,068 6,035 6,029 6,103 6,006 5,953 6,010 5,946 5,826 5,831
-----------------------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 71.3 78.0 76.6 76.6 79.2 77.2 77.6 80.3 78.9 78.5 81.2
Merchant Revenues - - - - - - - - - - -
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Revenues 77.2 84.4 83.0 82.9 85.7 83.6 83.9 86.8 85.3 84.8 87.7
-----------------------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - - - -
Fixed O&M 3.9 4.5 4.6 4.7 4.9 5.0 5.2 5.3 5.5 5.6 5.8
Variable O&M 1.3 1.4 1.9 2.0 2.0 2.1 2.1 2.2 2.2 2.3 2.3
Annual Maintenance 7.0 7.9 8.2 8.5 8.7 8.9 7.0 4.4 4.6 4.6 4.7
Water cost 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Property tax 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.0 6.4 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
-----------------------------------------------------------------------------------
Total Operating Expenses 19.2 21.4 22.2 22.7 23.2 23.6 21.9 19.6 19.9 20.1 20.5
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 58.0 63.0 60.8 60.2 62.4 60.0 62.1 67.2 65.4 64.7 67.2
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 374.0 371.7 365.7 360.8 355.9 349.1 343.3 335.5 323.6 311.7 299.1
Principal and Interest 37.8 41.0 39.6 39.0 40.4 38.8 40.2 43.5 42.3 41.9 42.9
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
-----------------------------------------------------------------------------------
Total Debt Service 38.1 41.5 40.0 39.4 40.8 39.2 40.6 43.9 42.8 42.3 43.3
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.52x 1.52x 1.52x 1.53x 1.53x 1.53x 1.53x 1.53x 1.53x 1.53x 1.55x
-----------------------------------------------------------------------------------
<CAPTION>
PPA PERIOD
---------------------------------------------------------------------
Year Ending December 31, 2013 2014 2015 2016 2017 2018 2019 2020 2021
---------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
---------------------------------------------------------------------
Annual Generation (GWh) 5,703 5,619 5,609 5,444 5,309 5,288 5,119 4,580 4,643
---------------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 79.1 79.2 82.0 80.1 79.5 82.3 80.0 78.1 81.2
Merchant Revenues - - - - - - - - -
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Revenues 85.5 85.5 88.4 86.5 85.8 88.7 86.3 84.4 87.6
---------------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel - - - - - - - - -
Fixed O&M 6.0 6.2 6.4 6.5 6.7 6.9 7.2 7.4 7.6
Variable O&M 2.3 2.4 2.4 2.4 2.5 2.5 2.5 2.3 2.4
Annual Maintenance 4.8 4.9 4.9 5.0 5.0 5.1 5.1 4.7 4.9
Water cost 0.4 0.4 0.5 0.5 0.5 0.5 0.5 0.4 0.4
Property tax 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Fuel Conversion Volume Rebate 6.4 6.3 6.4 6.4 6.3 6.4 6.4 6.3 6.4
---------------------------------------------------------------------
Total Operating Expenses 20.7 21.0 21.4 21.6 21.8 22.2 22.4 22.0 22.5
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 64.7 64.5 67.0 64.9 64.0 66.5 63.9 62.4 65.1
---------------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 284.2 269.5 253.8 235.0 215.8 195.3 171.1 146.4 119.5
Principal and Interest 41.4 40.9 42.5 41.2 40.6 42.2 40.6 40.2 41.8
LOC & Administrative Fees 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
---------------------------------------------------------------------
Total Debt Service 41.8 41.3 43.0 41.6 41.0 42.6 41.0 40.6 42.2
---------------------------------------------------------------------
---------------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 1.55x 1.56x 1.56x 1.56x 1.56x 1.56x 1.56x 1.54x 1.54x
---------------------------------------------------------------------
<CAPTION>
POST PPA PERIOD
-----------------------------------------------------------------
Year Ending December 31, 2022* 2023 2024 2025 2026 2027 2028 2029
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
-----------------------------------------------------------------
Annual Generation (GWh) 4,612 4,590 4,640 4,597 4,540 4,542 4,453 4,386
-----------------------------------------------------------------
NET OPERATING REVENUES ($MILLION)
PPA Revenues 12.9 - - - - - - -
Merchant Revenues 255.4 316.8 333.4 345.7 351.9 361.6 366.1 372.0
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Revenues 269.3 316.8 333.4 345.7 351.9 361.6 366.1 372.0
-----------------------------------------------------------------
OPERATING EXPENSES ($MILLION)
Fuel 164.1 201.5 208.4 213.9 218.2 223.0 226.3 230.2
Fixed O&M 7.8 8.1 8.3 8.5 8.8 9.1 9.3 9.6
Variable O&M 2.5 2.5 2.6 2.7 2.8 2.8 2.9 2.9
Annual Maintenance 5.0 5.2 5.3 5.5 5.6 5.7 5.8 5.9
Water cost 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Property tax 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Fuel Conversion Volume Rebate 1.0 - - - - - - -
-----------------------------------------------------------------
Total Operating Expenses 181.3 218.1 225.5 231.6 236.3 241.5 245.2 249.6
-----------------------------------------------------------------
-----------------------------------------------------------------
CASH FLOW AVAILABLE FOR DEBT SERVICE ($MILLION) 88.0 98.7 107.9 114.1 115.6 120.1 120.9 122.4
-----------------------------------------------------------------
ANNUAL DEBT SERVICE ($MILLION)
Facility Bonds
B-O-Y Balance Outstanding 88.2 80.6 71.1 60.7 50.4 39.6 27.4 14.3
Principal and Interest 16.0 17.0 17.0 15.8 15.4 15.6 15.1 15.2
LOC & Administrative Fees 0.2 0.3 0.3 0.2 0.2 0.2 0.2 0.2
-----------------------------------------------------------------
Total Debt Service 16.2 17.2 17.3 16.1 15.6 15.8 15.5 15.5
-----------------------------------------------------------------
-----------------------------------------------------------------
ANNUAL DEBT SERVICE COVERAGE 5.42x 1.73x 6.25x 7.30x 7.40x 7.59x 7.78x 7.92x
-----------------------------------------------------------------
* PPA cash flows continue through the first two months of 2022.
AVERAGE DEBT COVERAGE DURING PPA 1.54x
MINIMUM DEBT COVERAGE DURING PPA 1.52x
AVERAGE DEBT COVERAGE POST PPA 6.90x
MINIMUM DEBT COVERAGE POST PPA 5.42x
AVERAGE DEBT COVERAGE DURING 3.07x
BOND TERM
</TABLE>
B-77
<PAGE>
[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
EXHIBIT II
AES RED OAK DOCUMENT LOG
1. Maintenance Program Parts, Shop Repairs and Scheduled outage TFA Services
Contract with Attachments received November 18, 1999
2. Generation Facility Transmission Interconnection Agreement between Jersey
Central Power & Light Company d/b/a GPU Energy and AES Red Oak, L.L.C.
3. Fuel Conversion Services, Capacity and Ancillary Services Purchase
Agreement by and between AES Red Oak, L.L.C. and Williams Energy marketing
& Trading Company
4. Water Supply Agreement by and between AES Red Oak, L.L.C. and Borough of
Sayreville, dated as of October, 1999
5. Appendix 1 - Pricing
6. Appendix 2 - Confidentiality Agreement
7. Appendix 5 - Guaranty by The AES Corporation
8. Appendix 6 - Guaranty by The Williams Companies, Inc.
9. Appendix 8 - Sample Monthly Billing Invoice
10. Agreement for Engineering, Procurement and Construction Services between
AES Red Oak, L.L.C. ("owner") and Raytheon Engineers & Constructors, Inc.
("Contractor") - (DRAFT of 9/10/99)
11. Letter of Transmittal dtd 09/10/99 rev. - Preliminary & Final Site Plan
12. Fax dtd 10/20/99 Preliminary Geo-technical Report Rev. 0, 10/01/98
13. Fax dtd 10/21/99 Appendix 4.B Preliminary Single-Line Diagram showing
Electric Delivery Points
14. Raytheon Constructors Inc. Project Quality Control Manual Rev 0 dated March
31, 1999
15. AES Red Oak Project Procedures Manual dated Sep 99
16. Transmittal of Answers to Stone & Webster questions dtd 11/15/99 - RB0006,
File #6.3.1
17. Response to Stone & Webster's Independent Technical Review (Req dtd
11/3/99) ltr dtd 11/9/99 (RG604-99)
18. Raytheon letter response on steam turbine technical description dated
November 18, 1999
19. Memo from Bart Rossi to Anna Raptis dated November 10, 1999 on outstanding
Stone & Webster questions
20. Letter of transmittal dated November 17, 1999 from Jeff Brightman of RE&C
to Debra Richert of Stone & Webster
21. Letter of transmittal dated November 18, 1999 from Jeff Brightman of RE&C
to Debra Richert of Stone & Webster
22. Received Appendix D, H, I-1, I-2, I-3, L, O, and V by e-mail dated November
29, 1999
23. Received Appendix D, H, I-1, I-2, I-3, L, M, O, and V by letter dated
November 29, 1999
24. Received guarantee heat balance by letter dated November 29, 1999
25. Transmittal of Answers to Stone & Webster dated December 1, 1999 from Jeff
Brightman of RE&C to Debra Richert of Stone & Webster
26. Transmittal of Answers to Stone & Webster dated December 1, 1999 from Jeff
Brightman of
B-78
<PAGE>
[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
RE&C to Debra Richert of Stone & Webster
27. Remedial Investigation Report and Remedial Action Workplan (RI/RAW) dated
November 1999
28. Transmittal of Answers to Stone & Webster dated December 2, 1999 from Jeff
Brightman of RE&C to Debra Richert of Stone & Webster
29. Transmittal of Answers to Stone & Webster dated December 3, 1999 from Jeff
Brightman of RE&C to Debra Richert of Stone & Webster
30. Maintenance Program Parts, Shop Repairs and Scheduled outage TFA Services
Contract with Attachments received December 8, 1999
31. Revised Staffing Plan received by e-mail on December 6, 1999
32. Financial Guaranty of Owner's Pre-Financial Closing Date Payment
Obligations
33. October 15, 1999 letter of agreement between AES and RE&C
34. Transmittal of Answers to Stone & Webster dated December 13, 1999 from Jeff
Brightman of RE&C to Debra Richert of Stone & Webster
35. Memo from Anna Raptis of AES to Debra Richert of Stone & Webster dated
December 9, 1999 on exempt wholesale generator status
36. Transmittal of Answers to Stone & Webster dated December 9, 1999 from Jeff
Brightman of RE&C to Debra Richert of Stone & Webster
37. Final Prevention of Significant Deterioration (PSD) Permit dated
January 28, 2000
38. Red Oak Fact Sheet
39. Environmental Impact Report
40. AES Red Oak list of permits and approvals required
41. FAA Crane approval
42. FAA Stack approval
43. Fuel Use Acceptance Certificate
44. Middlesex County Planning Board Approval
45. Exempt Wholesale Generator Application
46. Gas Line Route and Gas compressor information
47. Fish & Wild Life Information
48. Wetlands Delineation
49. PJM Interconnection queue correspondence
50. C-Project Schedule
51. E-Approved Subcontractors List
52. F-Applicable Permits
53. G-Real Estate Rights
54. K-Quality Assurance Plan
55. N-Construction Progress Milestones
56. P-Table of Submittals and Approvals
57. Q-List of Key Personnel
58. S-Environmental Requirements
59. U-Certain Equipment and/Subcontractors
60. W-Project Procedures Manual
B-79
<PAGE>
[LOGO] Stone & Webster AES RED OAK PROJECT
Management Consultants, Inc. Independent Technical Review
--------------------------------------------------------------------------------
61. FAX received 10/22/99 - Preliminary & Final Site Plan
62. FAX received 11/1/99 re':
1. 2nd ltr - wetlands
2. information - chemical storage
3. four ltrs - soil condition
4. application for non-domestic discharge permit
63. Gas Pressure Information
64. Agreement with The Middlesex County Sewerage Authority
65. Temporary Construction License Option and Agreement dated October __, 1999
66. Water Analysis
67. Fuel Plan provided by Williams
68. License Agreement dated November 8, 1999
69. Transmittal of Answers to Stone & Webster questions dtd 11/15/99 - RB0006,
File #6.3.1
70. Response to Stone & Webster's Independent Technical Review (Req dtd
11/3/99) ltr dtd 11/9/99 (RG604-99)
B-80
<PAGE>
--------------------------------------------------------------------------------
ANNEX C
INDEPENDENT MARKET ASSESSMENT
--------------------------------------------------------------------------------
C-1
<PAGE>
INDEPENDENT LENDERS' MARKET
ASSESSMENT OF PJM
AND THE RED OAK PLANT
Prepared for:
Lehman Brothers
Prepared by:
ICF Resources Incorporated
February 24, 2000
C-2
<PAGE>
THIS REPORT WAS PRODUCED BY ICF CONSULTING (ICF) IN ACCORDANCE WITH AN AGREEMENT
WITH AES ENTERPRISE, INC. (AES), WHO PAID FOR ICF'S SERVICES IN PRODUCING THE
REPORT. CLIENT'S USE OF THIS REPORT IS SUBJECT TO THE TERMS OF THAT AGREEMENT.
IMPORTANT NOTICE:
REVIEW OR USE OF THIS REPORT BY ANY PARTY OTHER THAN THE CLIENT CONSTITUTES
ACCEPTANCE OF THE FOLLOWING TERMS. READ THESE TERMS CAREFULLY. THEY CONSTITUTE A
BINDING AGREEMENT BETWEEN YOU AND ICF RESOURCES, INC ("ICF"). BY YOUR REVIEW OR
USE OF THE REPORT, YOU HEREBY AGREE TO THE FOLLOWING TERMS.
ANY USE OF THIS REPORT OTHER THAN AS A WHOLE AND IN CONJUNCTION WITH THIS
DISCLAIMER IS FORBIDDEN.
THIS REPORT MAY NOT BE COPIED IN WHOLE OR IN PART OR DISTRIBUTED TO ANYONE. THIS
REPORT AND INFORMATION AND STATEMENTS HEREIN ARE BASED IN WHOLE OR IN PART ON
INFORMATION OBTAINED FROM VARIOUS SOURCES. ICF MAKES NO ASSURANCES AS TO THE
ACCURACY OF ANY SUCH INFORMATION OR ANY CONCLUSIONS BASED THEREON. ICF BEARS NO
RESPONSIBILITY FOR THE RESULTS OF ANY ACTIONS TAKEN ON THE BASIS OF THIS REPORT.
THE REPORT IS PROVIDED AS IS.
NO WARRANTY, WHETHER EXPRESS OR IMPLIED, INCLUDING THE IMPLIED WARRANTIES OF
MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE IS GIVEN OR MADE BY ICF IN
CONNECTION WITH THIS REPORT.
C-3
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
EXECUTIVE SUMMARY ..................................................... 1
Background ......................................................... 1
The PJM Market Structure ........................................... 1
The Modeling Approach .............................................. 2
Key Assumptions .................................................... 3
Summary of Base Case Forecasts ..................................... 7
Summary of Low Gas Price Case Forecasts ............................ 13
Summary of High Gas Price Case Forecasts ........................... 16
Summary of Overbuild Case Forecasts ................................ 19
Conclusions ........................................................ 22
CHAPTER ONE Regional Wholesale Markets - An Overview .................. 23
Introduction ....................................................... 23
Approach - Geographic Scope ........................................ 23
Transmission Constraints ........................................... 23
Transmission Tariffs ............................................... 26
CHAPTER TWO The PJM Regional Wholesale Market ......................... 27
Introduction ....................................................... 27
Market Structure - Participants .................................... 27
Transmission Within PJM ............................................ 28
Transmission With Neighboring Regions .............................. 29
Capacity and Generation Mix ........................................ 31
Supply and Demand Balance .......................................... 33
Historical Energy Prices ........................................... 35
Historical Firm Prices ............................................. 36
CHAPTER THREE The Evolving Market Structures for PJM .................. 42
Introduction ....................................................... 42
Summary of PJM Market Structure .................................... 42
PJM PX Markets ..................................................... 42
Energy and Capacity ................................................ 45
Retail Access ...................................................... 46
Transmission ....................................................... 47
</TABLE>
i
<PAGE>
<TABLE>
<S> <C>
Structure of Market Transactions - PX versus Bilateral ............. 52
CHAPTER FOUR Regional Assumptions Underlying Electric Revenues Forecast 55
Modeling ........................................................... 55
Methodology ........................................................ 55
Regional Assumptions ............................................... 62
Fuel Prices ........................................................ 66
Nuclear Performance and Retirements ................................ 86
Load Growth and Reserve Margins .................................... 90
New Power Plant Characteristics .................................... 93
Financing of New Power Plants ...................................... 96
CHAPTER FIVE Electric Revenues Forecast ............................... 102
APPENDIX A Annual Price Results ....................................... A-1
APPENDIX B Deregulation of the Electric Utility Industry .............. B-1
</TABLE>
ii
<PAGE>
EXECUTIVE SUMMARY
BACKGROUND
The Red Oak Facility is an 832 MW (net) gas-fired combined cycle plant that
is being developed by AES, Red Oak , L.L.C.. ("AES") and is expected on-line by
March 2002. The Facility has a 20-year tolling agreement -from 2002 through 2022
and thereafter will sell all or part of its capacity into the wholesale power
market at prevailing market prices.
ICF Resources Incorporated ("ICF") has prepared an independent assessment
of (i) the Facility's dispatch and revenue profile from 2002 through 2030; and
(ii) the wholesale power market in the Pennsylvania-New Jersey-Maryland (PJM)
region, specifically in PJM East, for this period. This assessment assumes the
plant is a merchant facility selling into the PJM East spot market(1). ICF's
efforts have been directed by Lehman Brothers ("Lehman") as lead manager for the
Rule 144a bond financing for the Project. The results of this analysis will be
utilized as the basis for the Facility financial projections.
This report includes an overview of the PJM marketplace, the Facility's
dispatch and revenue profile, and a description of the key assumptions and
methodology underlying ICF's assessment. This chapter provides a summary of
ICF's assessment.
THE PJM MARKET STRUCTURE
PJM is approximately the same size electrically as California and Texas and
more than twice the size of the New England Power Pool (NEPOOL). However, it has
been in the forefront of integrating operations across utility territories.
Before deregulation, PJM was the largest multi-utility, centrally dispatched
electric control area in North America and the fourth largest in the world. PJM
became the first operational Independent System Operator (ISO) in the US on
January 1, 1998, managing the PJM Open Access Transmission and facilitating the
PJM Interchange Energy Market.
The PJM Interconnection encompasses all of New Jersey, Delaware and the
District of Columbia, the majority of Maryland and Pennsylvania(2) and the
Delmarva Peninsula area of Virginia.(3) PJM is bordered on the north by the New
York Power Pool (NYPP), on the west by the Eastern and Central Area Reliability
Council (ECAR) and on the south by Virginia and Carolinas (VACAR).
There are transmission links between PJM and the three surrounding regions
of ECAR, VACAR and NYPP which allow for inter-regional power imports and
exports. PJM has an extensive internal transmission network. Nonetheless,
occasionally there are internal transmission constraints. Notably, during a
small fraction of the year, PJM East can become isolated from the rest of PJM,
i.e., no more power can be imported into PJM East. In order to
-------------------
(1) Spot is defined as transactions lasting one year or less.
(2) Small areas of Western Pennsylvania and Maryland are within ECAR.
(3) The majority of Virginia is in VACAR and ECAR.
1
<PAGE>
reflect the transmission constraints and the potential for transmission
congestion, PJM has implemented a unique locational marginal pricing (LMP)
scheme with 1,744 nodes with the goal of capturing all possible price
differences in the grid. In spite of this node-by-node approach, the internal
transmission constraints generally divide the region into three sub-regions:
East, West and South.
PJM operates three markets - the energy market, the capacity credit market
(CCM), and the firm transmission rights (FTR) market. The energy market is a
spot market in which all buyers and sellers must participate and settlements are
performed based on hourly-integrated locational marginal prices. The CCM is a
mandatory auction of capacity credit to support the retail market. Both monthly
and day-ahead auctions are held. The FTR market commenced last, as of April 15,
1999. The markets for ancillary services are not currently operational. Pricing
of ancillary services is either determined by the PJM Office of Interconnection
(PJM-OI) or determined based on market clearing prices in the energy market.
THE MODELING APPROACH
To provide projections of wholesale energy prices and the Facility's
dispatch profile, ICF developed a model-based representation of the PJM system
using its Integrated Planning Model (IPM-C- ). To account for the influences of
interconnections with neighboring systems (i.e., imports and exports of power),
a larger regional model was used.
The model covers the Northeast U.S. and parts of the Midwest(4).
Specifically, this model treats endogenously(5) the following 15 sub-regions:
- PJM-West - Ontario
- PJM-East - ECAR-Southern
- PJM-South - ECAR-MECS
- PJM-Homer City - VACAR - CP&L
- NYPP-Upstate - VACAR - SCEG
- NYPP-Downstate - VACAR - VEPCo
- NYPP-LILCo - VACAR - Duke
- NEPOOL
The model also has exogenous(6) inputs - e.g., inputs for interaction with
Quebec and other U.S. parts of the Eastern Interconnect.
-------------------
(4) PJM is located in one of the three U.S. synchronized AC power grids or
interconnects: the Eastern Interconnect. The other two are the Western and
Texas grids. Power flows between these grids is very limited. Even within
these grids, there are significant limitations necessitating additional
regional disaggregation. The regions modeled are a large portion of the
entire eastern interconnect and captures all key interactions.
(5) Model solves these regions simultaneously, and flows across regions are
determined as an output of the model.
(6) Model input specification.
2
<PAGE>
EXHIBIT ES-1
LOCATION OF RED OAK
A map of the United States with the PJM Region shaded
[GRAPHIC]
A larger regional model was used to obtain greater accuracy. PJM is
actually part of a grid known as the Eastern Interconnect, which is even larger
than the 15 regions modeled. Of course, the more distant from PJM the sub-region
of the grid, the less of an effect it has. Nonetheless, imports from and exports
to nearby areas are important for PJM. The PJM region can export about 20
percent of its peak load to neighboring regions like ECAR, NYPP, and VACAR.
Thus, PJM contrasts with other more transmission isolated areas such as Texas.
KEY ASSUMPTIONS
The key assumptions used for the model runs include peak and annual energy
demand growth, planning reserve margin, new plant builds and financing costs.
Other assumptions include delivered gas prices, residual and distillate oil
prices, coal prices including transportation, nuclear retirements and capacity
factors, plant availability, environmental emissions and allowance prices. The
assumptions used are summarized under the categories of capacity, energy,
environmental, and transmission assumptions in a later chapter and in Exhibits
ES-2, ES-3, ES-4, and ES-5, respectively.
3
<PAGE>
EXHIBIT ES-2
PJM CAPACITY PRICE RELATED ASSUMPTIONS(7)
<TABLE>
<CAPTION>
Parameter Treatment - Base Case
<S> <C>
1999 Weather Normalized Net Peak Demand(1) (GW) 47.6
Annual Peak Growth 1999 - 2005 (%) 2.0%
Annual Peak Growth 2006 - 2020 (%) 2.0%
1998 Net Energy for Load(2) (GWh) 249,247
Annual Energy Growth 1999 - 2005 (%) 2.0%
Annual Energy Growth 2006 - 2020 (%) 2.0%
Planning Reserve Margin (%)(3)
2000 19.5
2003 19.0
2010 15.0
2020 15.0
New Power Plant Builds CT CC
Capital Costs (1998$/kW)
2000 368 583
2005 368 583
2010 350 555
2015 333 528
2020 317 502
2025 317 502
2030 317 502
Fixed O&M (1998$/kW/yr) 9.8 16.0
Financing Costs for New Builds
Debt/Equity Ratio (%) 50/50
Nominal Debt Rate (%) 8.5
Nominal After Tax Return on Equity (%) 14.0
Income Taxes (%) 41.3
Other Taxes(4) (%) - East/West/South 0.5/0.7/1.5
General Inflation Rate (%) 3.0
Levelized Real Capital Charge Rate (%)
East/West/ South 12.7/12.9/13.5
New Builds Firm Builds Plus Additional Builds
Required to Meet to Reserve Margin
Requirements
Firmly Planned Builds (MW)
By 2000 250
2001 824
2002 0
Total by 2002 1,074
Economic Retirements Save non-fuel O&M only - Select
nuclear and fossil units
</TABLE>
(1) Reflects weather normalized summer peak demand for 1999 reported by PJM
(2) Historical 1998 net energy reported by PJM in "February 1999 Load Report"
(3) Reserve margin decreases at a steady rate between 2003 and 2010.
(4) Includes property taxes and insurance.
-------------------
(7) Most parameters affect both energy and capacity prices but we have separated
them for expositional purposes.
4
<PAGE>
EXHIBIT ES-3
PJM ENERGY PRICE-RELATED ASSUMPTIONS
<TABLE>
<CAPTION>
Parameter Treatment - Base Case
<S> <C>
Delivered Natural Gas Prices (1998$/MMBtu)
2000 2.55
2005 2.66
2010 2.78
2015 2.92
2020 3.03
2025 3.03
2030 3.03
Delivered Oil Prices (1998$/MMBtu) CRUDE DELIVERED DELIVERED
(1998$/bbl) 1% RESID DISTILLATE
(1998$/MMBtu) (1998$/MMBtu)
2000 18.0 2.57 3.97
2005 18.5 2.84 4.06
2010 19.5 3.19 4.22
2015 19.5 3.19 4.22
2020 19.5 3.19 4.22
2025 19.5 3.19 4.22
2030 19.5 3.19 4.22
Coal Prices Minemouth CENTRAL CENTRAL
(1998$/Ton) APPALACHIAN PENNSYLVANIA BAILEY
(0.7% Sulfur, (1.5-2.0% Sulfur, (1.25% Sulfur,
12,000 Btu/lb) 12,500 Btu/lb) 12,500 Btu/lb)
2000 24.70 22.36 24.55
2005 23.97 22.54 23.26
2010 23.49 22.31 23.00
2015 22.52 22.07 22.40
2020 20.58 21.85 21.80
2025 18.81 21.63 21.22
2030 17.18 21.42 20.65
Coal Transportation Annual Real Price Decrease (%) 2.0
Nuclear Capacity Factor (%)
PJM West Average 82
PJM East Average 75
PJM South Average 80
Nuclear Retirements End of 40 yr license
</TABLE>
5
<PAGE>
EXHIBIT ES-3
ENERGY PRICE-RELATED ASSUMPTIONS (CONTINUED)
<TABLE>
<CAPTION>
Parameter Treatment - Base Case
<S> <C> <C>
New Power Plant Builds CT CC
Heat Rate (Btu/kWh)
2000 10,905 6,928
2005 10,671 6,753
2010 10,443 6,583
2015 10,219 6,417
2020 10,000 6,255
2025 10,000 6,097
2030 10,000 6,000
Variable O&M(1) (1998$/MWh) 2.3 1.1
Availability (%) 92 92
Non-Utility Generators (MW) 2000 2010
Dispatchable 1,112 5,008
Non-Dispatchable(2) 3,896 0
TOTAL 5,008 5,008
Existing Power Plant Availability (%)
Coal Steam 85
Oil/Gas Steam 85
Variable O&M (1998$/MWh) CC CT OIL/GAS UNSCRUBBED SCRUBBED
STEAM COAL COAL
Range(3) 0.8-4.1 0.8-6.0 2.5-6.5(3) 1.0-4.1 2.1-5.1
</TABLE>
-----------------------------
(1) Values specified correspond to an 80 percent capacity factor for combined
cycles and 15 percent capacity factor for combustion turbines.
(2) Decreasing gradually over time.
(3) Inversely correlated with capacity factor.
EXHIBIT ES-4
ENVIRONMENTAL-RELATED ASSUMPTIONS
<TABLE>
<CAPTION>
Parameter Treatment
<S> <C>
SO(2) Regulations Phase II Acid Rain(1)
NO(x) Regulations NO(x) OTR (2)
CO(2) Regulations None
Mercury Regulations None
SO(2) NO(x)
Starts at around $200/ton and Starts at levels below late
Allowance Prices (1998$/ton) increases rapidly in real terms 1998/early 1999 levels and
through 2020. increases in real terms through
2020.
</TABLE>
-----------------------------
(1) No Tightened SO(2) Regulations
(2) SIP Call not analyzed as part of Base Case
6
<PAGE>
EXHIBIT ES-5
PJM TRANSMISSION-RELATED ASSUMPTIONS
<TABLE>
<CAPTION>
Parameter Treatment
<S> <C>
Intra-Regional Transmission
West to East (GW) 6.2
East to West (GW) 2.0
West to South (GW) 4.1
South to West (GW) 2.4
Inter-Regional Transmission
Total Import Capability (GW) 8.4
Total Export Capability (GW) 10.7
</TABLE>
SUMMARY OF BASE CASE FORECASTS
PJM EAST FIRM PRICE FORECAST
The forecast of firm ( i.e., PJM East all-in all-hours average) market
prices is graphically shown in Exhibit ES-6 in real (1998$) and nominal dollars.
Actual data points for individual years are shown in Exhibit ES-7, detail in
Appendix A. The price shown provides for maximum revenues available to a plant
in the market, i.e., a plant must be dispatched in all hours to realize this
price. Our forecast of firm prices comprises the two unbundled products of
electrical energy and capacity. Next, we separately discuss both elements of
firm prices to assess Red Oak's competitive position in the separate markets for
energy and capacity.
EXHIBIT ES-6
SUMMARY OF FIRM(8) PRICE FORECAST - BASE CASE
A Line Graph Illustrating Price Forecast for a Base Case Between the
years 2002 and 2027
[GRAPHIC]
-------------------
(8) This price is for all hours supply and it is firm unit contingent i.e. it is
backed by a specific unit.
7
<PAGE>
EXHIBIT ES-7
SUMMARY OF FIRM ALL-IN(1) PRICE FORECAST ($/MWh) - BASE CASE
<TABLE>
<CAPTION>
Year Annual Average
Firm Price for
Energy
(1998 $)
<S> <C>
2002 29.9
2005 30.5
2010 30.4
2015 30.4
2020 29.8
2025 29.1
2030 28.6
</TABLE>
-----------------
(1) Firm Price = Sum of Energy Price and
Capacity Price at 100 percent load factor.
PJM EAST ENERGY PRICE FORECAST
The competitive market electrical energy price equals the short-run
variable costs (primarily fuel) of the last unit dispatched in a given hour. The
electrical energy price is also the most important determinant of which units
operate in each hour. In each hour, if a plant's variable costs are less than
the electrical energy price, the plant is dispatched.(9) Consistent with
historical evidence of electrical energy prices in PJM East, our near-term
forecast, i.e., in 2002, shows an annual average electrical energy price of
approximately $24.0/MWh (1998$) as shown in Exhibit ES-8. This is reflective of
some hours in which higher cost coal units are on the margin, and some hours in
which gas-fired units, particularly gas steam units, are on the margin.
EXHIBIT ES-8
PJM EAST ELECTRICAL ENERGY PRICE FORECAST ($/MWh) - BASE CASE
<TABLE>
<CAPTION>
Year Annual Average - All Hours
(1998$)
<S> <C>
2002 24.0
2005 24.1
2010 24.5
2015 24.7
2020 24.4
2025 23.7
2030 23.2
</TABLE>
Annual average energy prices initially increase slightly in real-terms,
going from approximately $24.0/MWh in 2002 to $24.7/MWh in 2015 before
decreasing gradually to $23.2/MWh (1998$) in 2030. The initial real price
increase is associated with a number of partially offsetting factors. Upward
price pressure is exerted by a number of factors. In the near-term, it reflects
the transition from coal to gas on the margin in increasing hours, as coal is
gradually replaced as the most common price-setting unit. Also, there is a
reduction in PJM West imports due to increasing demand requirements there and in
other neighboring regions, thus there
-----------------
(9) This simplification is generally appropriate except when certain operational
constraints exist, e.g., minimum turndown requirements.
8
<PAGE>
is a greater requirement for local gas-fired generation. Additionally, the
increasing prices also reflect increasing environmental allowance prices for
SO(2) and NO(x) emissions.
Partially mitigating these upward price pressures is the addition of
new efficient, low-variable cost combined cycle units to the system. Thus,
prices increase very minimally.
In the longer-term, the real price decrease is the result of the net
downward price pressure from the continued addition of new, efficient, combined
cycle units to the system. In addition, Henry Hub gas prices are forecasted to
remain flat in real terms after 2020, eliminating the upward pressure of
increasing gas prices on energy prices.
PJM CAPACITY PRICE FORECAST
Capacity augments the reliability of the power grid. All suppliers of
end-use power must arrange to have first call on enough megawatts to meet
planned peak reserve levels. The capacity price is set in equilibrium by the
cost recovery requirements of new units not earned through sales in the
electrical energy market. Markets are in equilibrium when the need for megawatts
equals the supply.
The forecast for capacity prices in the PJM region is shown in Exhibit
ES-9 and commences at approximately $52/kW/yr (1998$) in 2002. PJM's existing
resources are not sufficient to meet projected demand in 2002 and thus new
builds are required to meet demand growth and reserve margin requirements.
Capacity prices are projected to be highest in 2005 at approximately $56/kW/yr
(1998$) and to decline steadily in real terms to $47/kW/yr (1998$) before
stabilizing after 2020. This is largely correlated to the underlying trend in
capital costs for new plants, i.e., declining capital costs between 2005 and
2020 and flat capital costs in real terms thereafter.(10)
EXHIBIT ES-9
PJM ANNUAL CAPACITY PRICE FORECAST(1) ($/kW-YR) - BASE CASE
<TABLE>
<CAPTION>
Pure Capacity Price
Year (1998 $)
<S> <C>
2002 52.0
2005 56.0
2010 52.0
2015 50.0
2020 47.0
2025 47.0
2030 47.0
</TABLE>
-----------------------------
(1) Firm electricity price is the sum of
the electrical energy and pure capacity
prices. Since pure capacity prices are
in $/kW/yr, and energy prices in $/MWh,
$/kW/yr must be allocated to the hours
in question. See Chapter 3 for more
information.
-------------------
(10) The small increase in capacity prices between 2002 and 2005 is associated
with the introduction of new power plant technology (i.e., slightly better
gas plants) after 2005. Plants anticipate the lower prices due to this
technological improvement and entrants in 2005 seek to recover more sooner.
See later discussion.
9
<PAGE>
In light of the relatively high energy prices that prevail in the
region, absent near-term timing constraints (i.e., from 2002 onwards), the
economic decision would be for the build mix to be comprised largely of new
combined cycles, as shown in Exhibit ES-10. Accordingly, we anticipate that
capacity prices throughout the horizon will be driven by these new and efficient
units. The capacity prices associated with these low variable cost units reflect
their high level of dispatch and their ability to earn significant profits
VIS~A~VIS the energy price. This substantial energy margin considerably offsets
the cost recovery required through the capacity price.
EXHIBIT ES-10
FORECASTED CAPACITY ADDITIONS IN PJM (1) (MW) - BASE CASE
<TABLE>
<CAPTION>
Combined Cycles Combustion Turbines
Year Planned Unplanned Planned Unplanned Total
<S> <C> <C> <C> <C> <C>
1999 - 2002 970 1,290 0 1,026 3,286
2003 - 2005 0 3,899 0 1,262 5,161
2006 - 2010 0 5,864 0 0 5,864
2011 - 2015 0 9,500 0 1,418 10,918
2016 - 2020 0 6,770 0 2,970 9,740
2021 - 2025 0 9,895 0 2,049 11,944
2026 - 2030 0 8,490 0 1,066 9,556
Total 970 45,708 0 9,791 56,469
</TABLE>
-----------------------------
(1) Does not include104 MW expansion of Muddy Run pumped storage plant which ICF
treats as a firm build.
DISCUSSION OF FACILITY DISPATCH - BASE CASE
We anticipate that the Facility will be dispatched according to
competitive system economics in the PJM marketplace. As such, the Facility will
be dispatched based on its variable cost relative to other power plants in the
region.
We evaluated a single aggregated unit for the Red Oak power plant as
there was little difference in heat rate or other operating characteristics
across the three units comprising the Red Oak Facility. A summary of plant
characteristics is shown in Exhibit ES-11.
10
<PAGE>
EXHIBIT ES-11
SUMMARY OF RED OAK PLANT CHARACTERISTICS
<TABLE>
<CAPTION>
Parameter Treatment
<S> <C>
Capacity(1) (MW) 832
Heat Rate (Btu/kWh)(2) 6,700
Fuel Natural Gas
Delivered Fuel Price (1998$/MMBtu)
2002 2.55
2005 2.66
2010 2.78
2015 2.92
2020 3.03
2025 3.03
2030 3.03
Availability (%) 95
Variable O&M (1998$/MWh)(3) 0.8 - 4.3
Minimum Turndown (%) 25
NO(x) Rate (lbs/MMBtu) 0.02
</TABLE>
-----------------------------
(1) ISO undegraded.
(2) HHV, expected (vs. guaranteed).
(3) Inversely correlated with capacity factor.
Red Oak is very competitive due to its low heat rate of 6,700 Btu/kWh as
compared with the PJM current system average of approximately 10,500 Btu/kWh. It
is even competitive with many coal plants, particularly in the summer and
shoulder seasons when gas prices are discounted, and in the later years when
environmental costs become more burdensome for coal plants. Its dispatch remains
above 80 percent through 2014, and then declines gradually thereafter to
approximately 61 percent in 2030. The decline in dispatch is generally
attributable to the addition of newer, more efficient combined cycle units to
the system to meet growing demand requirements. These units displace Red Oak
somewhat, particularly during off-peak hours. Consequently, in the outer years,
Red Oak's dispatch is largely concentrated during peak and intermediate load
hours and the realized price is thus higher than the simple all-hours annual
average price.
EXHIBIT ES-12
RED OAK DISPATCH - BASE CASE RED
<TABLE>
<CAPTION>
Available Time Realized Energy Price
Year(1) Dispatched (%) 1998$/MWh
<S> <C> <C>
2002 84.2 25.0
2005 85.1 24.8
2010 83.3 25.2
2015 78.1 25.7
2020 70.5 25.7
2025 63.8 25.3
2030 61.3 24.8
</TABLE>
The PJM supply curves for the years 2002 and 2020 winter and summer periods
are shown in Exhibits ES-13 and ES-14. Throughout the forecast horizon, the Red
Oak Facility is very competitively positioned vis~a~vis coal plants,
particularly in the summer months. It is
11
<PAGE>
also considerably more competitive than the large amount of existing oil/gas
steam plants, and existing and new turbines
EXHIBIT ES-13
PJM ILLUSTRATIVE PEAK HOUR SUPPLY CURVES - 2002 - BASE CASE
Line graph comparing summer peak hours supply versus the winter peak hours
supply measured in MW Units up to 50,000 MW.
[CHART]
EXHIBIT ES-14
PJM ILLUSTRATIVE PEAK HOUR SUPPLY CURVES - 2020 - BASE CASE
Line graph comparing summer peak hours supply versus the winter peak hours
supply measured in MW Units up to 80,000 MW.
[CHART]
12
<PAGE>
SUMMARY OF LOW GAS PRICE CASE FORECASTS
FIRM PRICE FORECAST(11) - LOW GAS PRICE CASE
On average, around-the-clock firm prices are approximately 10 percent lower
in the Low Gas Case compared to the Base Case. Most of the reduction is
associated with lower market energy prices as is discussed further in this
section. The forecast of firm market prices is graphically shown in Exhibit
ES-15 in real 1998 dollars. Actual data points for individual years are shown in
Exhibit ES-16.
EXHIBIT ES-15
SUMMARY OF FIRM PRICE FORECAST - LOW GAS PRICE CASE
[GRAPHIC]
Line graph illustrating firm market prices per year for the
years 2002 through 2027
EXHIBIT ES-16
SUMMARY OF FIRM(1) ALL-IN PRICE FORECAST ($/MWh) - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
Year Annual Average Firm
Price for Energy
(1998 $)
<S> <C>
2002 26.7 (-3.2)
2005 27.2 (-3.3)
2010 27.2 (-3.2)
2015 27.2 (-3.2)
2020 26.6 (-3.2)
2025 26.0 (-3.1)
2030 25.6 (-3.0)
</TABLE>
(1) Firm Price = Sum of Energy Price and Capacity
Price at 100 percent load factor.
( ) shows change from Base Case.
-------------------
(11) This price is for all hours supply and it is firm unit contingent i.e. it
is backed by a specific unit.
13
<PAGE>
PJM EAST ENERGY PRICE FORECAST - LOW GAS PRICE CASE
Our near-term forecast, i.e., in 2002, in this case shows an annual average
electrical energy price of approximately $21.3/MWh (1998$) as shown in Exhibit
ES-17. This price is $2.7/MWh lower than in the Base Case and is reflective of a
gas price $0.50/MMBtu lower than in the Base Case. In certain hours when coal is
on the margin, the lower gas price has almost no effect on the market-clearing
price. In hours when gas is on the margin, the lower gas price has a greater
effect the higher the marginal unit heat rate. In certain seasons where oil/gas
steam units burning oil are on the margin in the Base Case these units switch to
burning gas in the Low Gas Case. In this event, the fuel price decreases may be
less than $0.50/MMBtu.
EXHIBIT ES-17
PJM EAST ELECTRICAL ENERGY PRICE FORECAST ($/MWh) - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
Annual Average - All Hours
Year (1998$)
<S> <C>
2002 21.3 (-2.7)
2005 20.9 (-3.2)
2010 21.0 (-3.5)
2015 21.3 (-3.4)
2020 21.1 (-3.3)
2025 20.5 (-3.2)
2030 20.1 (-3.1)
</TABLE>
( ) shows change from Base Case.
The energy price differential remains on average approximately $3 to
$3.5/MWh (1998$) relative to the Base Case. While gas prices increasingly
influence the marginal unit, the marginal unit heat rate generally improves over
time, thereby reducing the gas price effect.
Through 2015, annual average energy prices remain relatively constant in
real terms, with very minor fluctuations due to offsetting effects associated
with a number of factors similar to those in the Base Case. Exerting upward
price pressure is the transition from coal to gas on the margin in increasing
hours, the reduction in PJM West imports due to increasing demand requirements
there and in other neighboring regions, increasing environmental allowance
prices for SO(2) and NO(x) emissions, and slightly increasing gas prices. The
addition of new, efficient, low-variable cost combined cycle units to the
system exerts offsetting downward pressure on prices. Together, these effects
keep the energy prices from fluctuating any more than $0.40/MWh (1998$)
through 2020.
After 2020, Henry Hub gas prices are forecasted to no longer increase in
real terms, eliminating the upward pressure of increasing gas prices on energy
prices. The absence of this upward pressure causes prices to decrease slightly
from 2020 through 2030.
PJM CAPACITY PRICE FORECAST - LOW GAS PRICE CASE
The forecast for capacity prices in the PJM region in this case is shown in
Exhibit ES-18 and is very similar to the Base Case. While energy prices are
lower than in the Base Case, variable costs for new marginal gas-fired units are
also lower due to the lower gas prices. Consequently, new units are largely
hedged to moderate changes in the gas price, and capacity prices are also
largely unaffected.
14
<PAGE>
EXHIBIT ES-18
PJM ANNUAL CAPACITY PRICE FORECAST ($/kW-YR) - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
Pure Capacity Price
Year (1998 $)
<S> <C>
2002 47.0 (-5.0)
2005 55.0 (-1.0)
2010 54.0 (+2.0)
2015 52.0 (+2.0)
2020 48.0 (+1.0)
2025 48.0 (+1.0)
2030 48.0 (+1.0)
</TABLE>
--------------------
( ) shows change from Base Case
The build mix in the Low Gas Price Case is very similar to that of the Base
Case. In total over the forecast horizon, approximately 2,700 MW fewer combined
cycles are projected to come on-line and instead a larger number of combustion
turbine builds are projected.
EXHIBIT ES-19(1)
FORECASTED CAPACITY ADDITIONS IN PJM - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
Combined Cycles Combustion Turbines
Year Planned Unplanned Planned Unplanned Total
<S> <C> <C> <C> <C> <C>
1999-2002 970 4,528 0 0 5,498
2003-2005 0 3,489 0 1,673 5,162
2006-2010 0 4,926 0 938 5,864
2011-2015 0 8,204 0 2,683 10,887
2016-2020 0 4,470 0 4,023 8,493
2021-2025 0 8,987 0 2,023 11,010
2026-2030 0 8,409 0 1,147 9,556
Total 970 43,013 0 12,487 56,470
</TABLE>
-----------------------------
(1) Does not include 104 MW expansion of Muddy Run pumped storage plant which
ICF treats as a firm build.
DISCUSSION OF FACILITY DISPATCH - LOW GAS PRICE CASE
Red Oak is even more competitive with respect to the overall merit order in
PJM in the Low Gas Price Case. Relative to other gas-fired units, its relative
position is unchanged. However, relative to coal-fired and oil-fired units, its
lower gas costs allow it to displace some of these units. On average, Red Oak is
projected to economically dispatch at an approximately 10 percent greater
capacity factor.
15
<PAGE>
EXHIBIT ES-20
RED OAK DISPATCH - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
Year Available Time Realized Energy Price
Dispatched (%) 1998$/MWh
<S> <C> <C>
2002 93.8 ( +9.6) 21.4
2005 95.1 (+11.8) 20.9
2010 92.7 ( +9.4) 21.1
2015 92.0 (+13.9) 21.4
2020 86.4 (+15.9) 21.5
2025 80.4 (+16.6) 21.0
2030 72.8 (+11.5) 20.8
</TABLE>
---------------------
( ) shows change from Base Case.
SUMMARY OF HIGH GAS PRICE CASE FORECASTS
FIRM PRICE FORECAST(12) - HIGH GAS PRICE CASE
Converse to the Low Case, around-the-clock firm prices are approximately 10
percent higher than in the Base Case. The forecast of firm market prices is
graphically shown in Exhibit ES-21 in real and nominal dollars. Actual data
points for individual years are shown in Exhibit ES-22.
EXHIBIT ES-21
SUMMARY OF FIRM PRICE FORECAST - HIGH GAS PRICE CASE
A Line Graph illustrating a forecast of firm market prices per year
for the years 2002 through 2027
[GRAPHIC]
--------------------
(12) This price is for all hours supply and it is firm unit contingent i.e. it
is backed by a specific unit.
16
<PAGE>
EXHIBIT ES-22
SUMMARY OF FIRM "ALL-IN"(1) PRICE FORECAST ($/MWh) - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
Year Annual Average Firm Price
for Energy
(1998 $)
<S> <C>
2002 31.9 (+2.0)
2005 33.5 (+3.0)
2010 33.7 (+3.3)
2015 33.7 (+3.3)
2020 33.0 (+3.2)
2025 32.2 (+3.1)
2030 31.6 (+3.0)
</TABLE>
------------------------
(1) Firm Price = Sum of Energy Price and Capacity Price at
100 percent load factor.
( ) shows change from Base Case.
PJM EAST ENERGY PRICE FORECAST - HIGH GAS PRICE CASE
The High Gas Price Case assumes higher gas prices of $0.50/MMBtu relative
to the Base Case. Our near-term forecast, i.e., in 2002, in this case shows an
annual average electrical energy price of approximately $26.0/MWh (1998$) as
shown in Exhibit ES-23. This price is $2/MWh higher than in the Base Case. The
Higher gas price has less of an impact than the same differential in the Low Gas
Case as oil/gas steam units on the margin burning gas in the Base Case are
protected from higher gas prices in certain seasons from an oil price ceiling,
as oil prices are unchanged in this scenario. No comparable ceiling is available
to single fuel steam units and a less binding ceiling is applicable for combined
cycle and combustion turbine units due to the considerably higher distillate
price.
EXHIBIT ES-23
PJM EAST ELECTRICAL ENERGY PRICE FORECAST ($/MWh) - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
Annual Average - All Hours
Year (1998$)
<S> <C>
2002 26.0 (+2.0)
2005 26.9 (+2.8)
2010 27.9 (+3.4)
2015 27.9 (+3.2)
2020 27.6 (+3.2)
2025 26.8 (+3.1)
2030 26.2 (+3.0)
</TABLE>
( ) shows change from Base Case.
Annual average energy prices initially increase in real-terms, from
approximately $26.0/MWh in 2002 to $27.9/MWh in 2015 before decreasing to
$26.2/MWh (1998$) in 2030. The energy price differential relative to the Base
Case remains in the $2.8 to $3.4/MWh range from 2005 to 2030.
17
<PAGE>
PJM CAPACITY PRICE FORECAST - HIGH GAS PRICE CASE
The forecast for capacity prices in the PJM region in this case is shown in
Exhibit ES-24 is very similar to the Base Case, again due to the unchanged
capital and financing cost structure for new builds, and the relatively hedged
position of new units to changes in gas prices.
EXHIBIT ES-24
PJM ANNUAL CAPACITY PRICE FORECAST ($/kW-YR) - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
Pure Capacity Price
Year (1998 $)
<S> <C> <C>
2002 52.0 ()
2005 58.0 (+2)
2010 51.0 (-1)
2015 51.0 (+1)
2020 47.0 ()
2025 47.0 ()
2030 47.0 ()
</TABLE>
--------------------
( ) shows change from Base Case.
The build mix in the High Gas Price Case is also very similar to that of
the Base Case, the only net difference being approximately 1,000 MW fewer
combined cycles and greater combustion turbines over the entire forecast
horizon.
EXHIBIT ES-25
FORECASTED CAPACITY ADDITIONS IN PJM(1) - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
Combined Cycles Combustion Turbines
Year Planned Unplanned Planned Unplanned Total
<S> <C> <C> <C> <C> <C>
1999 - 2002 970 0 0 1,625 2,595
2003 - 2005 0 2,985 0 2,177 5,162
2006 - 2010 0 7,086 0 0 7,086
2011 - 2015 0 9,222 0 1,133 10,355
2016 - 2020 0 7,299 0 2,817 10,116
2021 - 2025 0 10,314 0 1,285 11,599
2026 - 2030 0 7,889 0 1,667 9,556
Total 970 44,795 0 10,704 56,469
</TABLE>
--------------------------
(1) Does not include 104 MW expansion of Muddy Run pumped storage plant which
ICF treats as a firm build.
DISCUSSION OF FACILITY DISPATCH - HIGH GAS PRICE CASE
Red Oak is slightly less competitive with respect to the overall PJM merit
order in the High Gas Price Case due to its higher variable costs. Again, its
relative position is unchanged relative to other gas-fired units, but
potentially disadvantaged relative to coal- and oil-fired units. Capacity
factors are between 4 and 9 percent lower than in the Base Case, but are still
never below 55 percent.
18
<PAGE>
EXHIBIT ES-26
RED OAK DISPATCH - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
Year Available Time Realized Energy Price
Dispatched (%) 1998$/MWh
<S> <C> <C>
2002 75.5 (-8.7) 28.0
2005 75.5 (-9.6) 28.9
2010 75.5 (-7.8) 29.5
2015 73.2 (-4.9) 29.4
2020 67.2 (-3.3) 29.3
2025 58.2 (-5.6) 28.9
2030 57.7 (-3.6) 28.2
</TABLE>
----------------------
( ) shows change from Base Case.
SUMMARY OF OVERBUILD CASE FORECASTS
FIRM PRICE FORECAST(13) - OVERBUILD CASE
The Overbuild Case was structured with builds as necessary to meet peak
demand and reserve requirements of the Base Case through 2020, and an additional
unexpected infusion of builds on the order of 10 percent of aggregate peak
demand, above and beyond the additions included in the Base Case in 2020(14).
The forecast of firm market prices is graphically shown in Exhibit ES-27 in real
and nominal dollars. Actual data points for individual years are shown in
Exhibit ES-28.
EXHIBIT ES-27
SUMMARY OF FIRM PRICE FORECAST - OVERBUILD CASE
A line graph illustrating a forecast of firm market prices per year
for the years 2002 through 2027
[GRAPHIC]
-------------------
(13) This price is for all hours supply and it is firm unit contingent i.e. it
is backed by a specific unit.
(14) In the Base Case, PJM was building approximately 1,700 MW for export
purposes. In the Overbuild Case, we assumed a 10 percent overbuild of peak
relative to local demand requirements. Thus, approximately 7,500 MW of
builds above and beyond local requirements were infused, resulting in
approximately 5,800 MW of additional builds relative to the Base Case.
19
<PAGE>
EXHIBIT ES-28
SUMMARY OF FIRM(1) PRICE FORECAST - OVERBUILD CASE
<TABLE>
<CAPTION>
Annual Average Firm Price
Year for Energy
(1998 $/MWh)
<S> <C>
2002 29.9 ()
2005 30.5 ()
2010 30.4 ()
2015 30.4 ()
2020 29.0 (-0.8)
2025 29.1 ()
2030 28.6 ()
</TABLE>
----------------------
(1) Firm Price = Sum of Energy Price and Capacity Price at 100 percent
load factor.
( ) shows changes from Base Case.
PJM EAST ENERGY PRICE FORECAST - OVERBUILD CASE
Energy prices are unchanged until 2020. In this year, the additional builds
of approximately 5,800 MW in PJM are largely comprised of combined cycles, thus
making available an even greater amount of low cost energy to the system. Energy
prices thus decrease by $1.3/MWh (1998$) in this year.
EXHIBIT ES-29
PJM EAST ELECTRICAL ENERGY PRICE FORECAST - ($/MWh)
<TABLE>
<CAPTION>
Annual Average - All Hours
Year (1998$)
<S> <C>
2002 24.0 ()
2005 24.1 ()
2010 24.5 ()
2015 24.7 ()
2020 23.1 (-1.3)
2025 23.6 (-0.1)
2030 23.1 (-0.1)
</TABLE>
--------------------
( ) shows changes from the Base Case.
By 2025, projected demand growth is sufficient to absorb the overbuild, and
energy prices are very similar to those in the Base Case.
PJM CAPACITY PRICE FORECAST - OVERBUILD CASE
Capacity prices are also unchanged until 2020. In 2020, PJM has more
capacity than required to meet local requirements. However, the excess can be
absorbed by neighboring regions, and thus capacity still has considerable
(although lesser) value and is derived as the price of capacity in the export
region net firm transmission costs. Thus, the 2020 capacity price is
approximately 15 percent lower than in the Base Case. By 2025, demand growth
absorbs the excess, and once again, new builds are required for the system. The
forecast for capacity prices in the PJM region in this case is shown in Exhibit
ES-30.
20
<PAGE>
EXHIBIT ES-30
PJM ANNUAL CAPACITY PRICE FORECAST ($/kW-YR) - OVERBUILD CASE
<TABLE>
<CAPTION>
Pure Capacity Price
Year (1998 $)
<S> <C>
2002 52.0 ()
2005 56.0 ()
2010 52.0 ()
2015 50.0 ()
2020 41 (-6)
2025 48 (+1)
2030 48 (+1)
</TABLE>
--------------------
( ) shows change from Base Case.
EXHIBIT ES-31
FORECASTED CAPACITY ADDITIONS IN PJM(1) - OVERBUILD CASE
<TABLE>
<CAPTION>
Combined Cycles Combustion Turbines
Year Planned Unplanned Planned Unplanned Total
<S> <C> <C> <C> <C> <C>
1999-2002 970 1,290 0 1,026 3,286
2003-2005 0 3,899 0 1,262 5,161
2006-2010 0 5,864 0 0 5,864
2011-2015 0 9,500 0 1,418 10,918
2016-2020 4,045 6,770 1,774 2,970 15,559
2021-2025 0 5,963 0 1,105 7,068
2026-2030 0 8,409 0 1,148 9,557
Total 5,015 41,695 1,774 8,929 57,413
</TABLE>
-----------------------
(1) Does not include 104 MW expansion of pumped storage plant which ICF treats
as a firm build.
DISCUSSION OF FACILITY DISPATCH - OVERBUILD CASE
In 2020, there is a larger number of more efficient combined cycle units in
the system relative to Red Oak, as compared to the Base Case. Thus, in certain
marginal hours in 2020, Red Oak is displaced and its overall capacity factor is
approximately 6 percent lower than in the Base Case.
EXHIBIT ES-32
RED OAK DISPATCH - OVERBUILD CASE
<TABLE>
<CAPTION>
Realized Energy
Year Available Time Price
Dispatched (%) 1998$/MWh
<S> <C> <C>
2002 84.2 () 25.0
2005 85.1 () 24.8
2010 83.3 () 25.2
2015 78.1 () 25.7
2020 64.7 (-5.8) 24.2
2025 64.6 (+0.8) 25.2
2030 61.3 () 24.7
</TABLE>
--------------------
( ) shows changes from the Base Case.
21
<PAGE>
CONCLUSIONS
The principal findings of this analysis are as follows:
- The PJM wholesale electricity markets presents attractive
opportunities for new gas-fired plants, especially efficient,
low variable cost plants like Red Oak.
- The Red Oak Facility dispatch position on the supply curve
will be highly competitive and well below most coal plants in
the summer and shoulder seasons during the post-PPA period
(and during the term of the power purchase agreement) due to
the facility's high efficiency, low production costs, and the
influence of demand growth in conjunction with unit
retirements.
- The Red Oak Facility has a physical hedge because when its
fuel costs increase, so does its revenues. This occurs to the
extent gas is used by competing marginal price-setting units.
- The PJM market like many other markets in the U.S., is rapidly
approaching a potential shortage. As soon as next year,
additional capacity beyond what is already under construction
is required to maintain reliability of the system. If weather
conditions are more extreme, or outages are greater than
expected, the gap between supply and demand requirements may
be even wider. And plants like Red Oak which require a short
lead time to be operational are well positioned to provide
reliability support to the grid, and to earn the associated
capacity revenue credits.
- Furthermore, Red Oak is less significantly affected by any
overbuild which might occur in PJM as compared to more
transmission isolated regions because of the ability within
PJM to export to multiple neighboring regions.
22
<PAGE>
CHAPTER ONE
REGIONAL WHOLESALE MARKETS AN OVERVIEW
--------------------------------------------------------------------------------
INTRODUCTION
The premises of the analysis of the Facility include: (i) definition of
the appropriate marketplace for the Facility will nearly always be the PJM
marketplace, (ii) it is necessary to account for the influences of surrounding
marketplaces via inter-regional transmission imports and exports, and (iii) it
is also necessary to simultaneously analyze the competition within the
marketplace among different power producers.
APPROACH - GEOGRAPHIC SCOPE
In general, the analysis of marketplace prices starts with an
identification of the product and the definition of the geographic scope of the
market. In this case, the products are hourly electrical energy and annual pure
capacity; the sum of the average of all 8,760 hourly prices and the annual
capacity price equal the annual firm wholesale power price. In this case, the
identification of the geographic area is that area in which a single price would
prevail for each of the products. This chapter will discuss geographic scope,
and Chapter Four will discuss the definition and analysis of the products.
There are two principal reasons why prices in different geographical
areas would not be equal. The first is that it may not be physically possible to
transport the product from one area to another. For example, the price of power
might be $20/MWh in one area and $25/MWh in another due to different supply
characteristics such as different fuel costs or different marginal fuel mixes.
However, the key is that one cannot arbitrage the market by buying for $20/MWh,
transporting and selling for $25/MWh because of physical transmission
constraints, i.e., the lines are already full. The second is that there may be
transportation costs (e.g., transmission tariffs) that make bringing the product
from one area to the other too costly. For example, the possibility of buying
power for $20/MWh and paying $10/MWh for transmission does not help bring two
regions' prices closer together.
TRANSMISSION CONSTRAINTS
Nearly all of the U.S. and Canada's population is served by one of the
continent's four interconnected grids (see Exhibit 1-1). In these grids, all
generators are approximately synchronized together. Also, in these grids,
generators are connected via high voltage transmission systems. Power flows
between these large grids are expensive relative to intra-grid flows, and the
capacity for such transfers is limited. The four grids are as follows:
- THE EASTERN INTERCONNECT - This is the largest of the four, in
terms of both geographic area and capacity, and extends from
eastern New Mexico to Florida, Saskatchewan Canada, and
eastern Canada. The marketplace analyzed in this study is part
of this grid.
23
<PAGE>
- THE WESTERN INTERCONNECT - This is the second largest grid and
covers the western contiguous US and much of western Canada.
This grid is also called the Western System Coordinating
Council or WSCC grid.
- ERCOT - Covering most of Texas, ERCOT is separate for
primarily political reasons.
- HYDRO QUEBEC - This region is also separate for primarily
political reasons.
EXHIBIT 1-1
INTERCONNECTED GRIDS IN THE U.S. AND CANADA
A Map of the United States and Canada divided into the Eastern and Western
Interconnect Regional Grids
[GRAPHIC]
Even within these synchronized grids, there are substantial limitations
on the amount of power that can flow between subregions. For example, in ICF
modeling, there are approximately 23 major marketplace regions within the U.S.
portion of the Eastern Interconnect (see Exhibit 1-2). Typically, each region in
the Eastern Interconnect is linked to its neighbors by 1 to 7 GW of transfer
capability. This transfer capability compares to peak demand levels of 25 to 75
GW. A key consideration in sizing these links was the chance that during peak
demand periods, there would be an amount of unused generation in the neighboring
area equal to the size of the tie line. This meant that the tie line would
decrease the amount of required local reserves.
In some cases, lines were additionally built for more year-round power
flows from low-cost sources of generation. These considerations notwithstanding,
inter-regional flows can affect prices; hence, the precision of a study of
market conditions is enhanced by such accounting. In the PJM analysis, power
flows are determined for 16 regions.
24
<PAGE>
EXHIBIT 1-2
SELECTED U.S. REGIONAL MARKETS
A map of the United States and Canada divided into each Regional Market
[GRAPHIC]
Note, within these regional markets, line congestion is very
infrequent. As is discussed, in PJM, there are few periods with significant line
constraints.
The modeling undertaken in this effort simultaneously determines the
economic utilization of existing transmission lines and existing power plants.
This modeling accounts for the constraints of power flow into and out of
regions. For example, if a neighboring region has lower electrical energy
prices, the model would import power from the lower price region, all else
equal, until the line constraints become binding or until the price difference
is less than the transmission tariff. Similarly, if the rights to firm capacity
are available in a neighboring region, it would be imported in lieu of
constructing new units, subject to the limitations of the lines.
The modeling solves transmission while also determining an economic
capacity expansion plan for generators. The two considerations in setting this
expansion are (i) maintaining grid reliability by maintaining generation reserve
margins and (ii) minimizing costs for capital, fuel, and O&M. Specifically, the
model uses a multi-year dynamic linear program.
The model is not used, however, to determine the construction of new
power lines. This is because few new transmission lines are expected to be
constructed. This, in turn, is because:
- The costs of new power lines are generally very high relative
to the economic savings potential. This is in part because
over time, the differences in average electrical energy prices
across regions diminishes due to the increasing use of natural
gas in nearly all regions as new power plants are built.
25
<PAGE>
- The costs of new power lines are very large relative to the
costs of new gas pipelines. This is still true in spite of
advances in thyristor and other electronics designed to
facilitate transmission. Thus incremental power needs can be
most economically met via the construction of new gas power
plants close to the load combined with new gas pipelines.
- It is significantly more difficult to site and receive
regulatory approvals for new power lines than it is for new
gas pipelines. This appears in part due to public concerns
about the health and aesthetic aspects of power lines and
their visibility. Gas pipelines are underground and do not
elicit similar safety and health concerns.
- Most, though not all, opportunities for using lines to
increase grid reliability (e.g., taking advantage of peak load
diversity) have already been exploited.
TRANSMISSION TARIFFS
As mentioned above, another factor affecting the degree of separation
between geographic markets is inter-regional transmission tariffs. For example,
a low-cost region might not be able to export power to a high-cost region even
if line constraints are not binding because several charges have to be paid to
transmission owners along the way. Transmission tariffs are regulated by FERC
and subject to cost of service (i.e., cost plus) limits in many cases. The
modeling accounts for the costs of transmission between regions, as well as line
constraints.
26
<PAGE>
CHAPTER TWO
THE PJM REGIONAL WHOLESALE MARKET
--------------------------------------------------------------------------------
INTRODUCTION
One of the premises of this analysis is that the Facility will need to
compete in the deregulated and competitive PJM wholesale power market. In
particular, the Facility will compete in the PJM East market. Prices in the
marketplace will reflect supply and demand conditions. This chapter endeavors to
provide an overview of the PJM marketplace. Additional details on the supply and
demand fundamentals not covered in this chapter are discussed in the Assumptions
section of Chapter 4.
MARKET STRUCTURE - PARTICIPANTS
The Pennsylvania-New Jersey-Maryland Interconnection (PJM) encompasses
all of New Jersey, Delaware, and the District of Columbia, the majority of
Maryland and Pennsylvania, and the Delmarva Peninsula area of Virginia. PJM also
makes up the Mid-Atlantic Area Council (MAAC), a NERC sub-region.
PJM has a unique history. It was the largest centrally dispatched
multi-utility electric system in North America. In contrast, few utilities in
the U.S. achieved such a high degree of integration. Historically, PJM operated
as a tight pool under terms of a 1956 Interconnection Agreement with central
dispatch. Under the old structure, utilities offered to buy and sell electricity
at bid and ask prices set equal to costs determined using government cost
accounting systems. PJM used these prices to determine dispatch and clearing
prices. Clearing prices were based on a split-savings approach which was
designed to be fair and to approximate the outcome of a situation in which there
were only a few players each with some market power. For example, if one utility
plant could produce at $20/MWh and another at $30/MWh, the lower-cost plant
would operate and be paid $25/MWh by the owner of the higher-cost plant.
PJM has traditionally been comprised of 10 major investor owned
systems, one holding company, and several municipal and cooperative system
associate members. The major investor-owned utilities include General Public
Utilities (GPU)(15), Public Service Electric and Gas (PSE&G), Philadelphia
Electric Company (PECO), Pennsylvania Power and Light (PP&L), Baltimore Gas and
Electric (BG&E), Potomac Electric Power Company (PEPCO), and Conectiv.(16) The
service territories for these utilities and other smaller utilities are
illustrated in Exhibit 2-1.
---------------------
(15) With Pennsylvania Electric, Metropolitan Edison and Jersey Central Power
and Light as the main GPU operating companies.
(16) A merger of Atlantic City Electric Company and Delmarva.
27
<PAGE>
EXHIBIT 2-1
MAJOR PARTICIPANTS IN PJM
A map of Pennsylvania showing PJM areas currently served by PJM Major
Participants
[GRAPHIC]
However, recent power plant divestitures involving three of the main
companies - GPU, Conectiv, and PEPCo - have introduced or will introduce new
players to the generation sector. GPU has essentially completed its departure
from the generation business by recently selling its Oyster Creek nuclear
generating facility to AmerGen. It had already divested its interest in Homer
City, Three Mile Island, Seneca, and the remainder of its fossil-fueled and
hydroelectric assets. Purchasing companies were Edison Mission Energy, AmerGen,
FirstEnergy, and Sithe. In addition, Conectiv is currently auctioning 2,200 MW
of nuclear and non-strategic baseload fossil generation assets. PEPCO has also
indicated plans to divest its assets.
In addition, PJM has had a non-utility sector involving cogeneration
power plants. This sector emerged during the 1980s and 1990s.
TRANSMISSION WITHIN PJM
This history of complex centralized coordination facilitated the rapid
development of a highly integrated regional transmission structure. Most of the
highest voltage lines were jointly owned and were used by PJM to facilitate
central dispatch. The old central dispatch structure was replaced on January 1,
1998 when the PJM Interconnection became the first operational Independent
System Operator (ISO) in the U.S. The PJM ISO is now responsible for the
operation and control of the bulk electric power system throughout PJM.
PJM has an extensive internal transmission network and backbone of 500
kV lines. Nonetheless, PJM experiences some internal transmission constraints.
These constraints can be tight enough to cause internal price differences,
primarily between the West and the East. The
28
<PAGE>
predominant power flow has historically run west to east as capacity deficient
East PJM is fed power by capacity-long, coal-rich PJM West and coal-rich ECAR.
EXHIBIT 2-2
PJM INTRA-REGIONAL TRANSMISSION (GW)
A map of Pennsylvania divided into coal rich regional grids
[GRAPHIC]
PJM handles internal transmission constraints in a unique manner. In an
attempt to reflect internal PJM constraints and the potential for transmission
congestion, PJM has implemented what is known as a Locational Marginal Pricing
(LMP) scheme. The goal has been to capture all possible price differences in the
grid by determining a separate hourly spot price for each node. There are 1,744
nodes each of which has its own price. This pricing function is discussed more
in Chapter 3, but the key is the integration of a centralized utility industry
power pricing function with transmission constraints. To date, few differences
have been observed across most nodes. In fact, PJM itself is moving towards the
use of averages. For example, the PJM West Hub(17) is an average of about 200
nodes and is now the focal point for trading and future contracts. In this
study, these constraints are modeled by dividing PJM into three sub-regions,
East, West, and South as shown in Exhibit 2-1(18). We use a very similar
approach to that of PJM in determining prices, but because we analyze
neighboring regions and much longer time periods, we focus on the key intra-PJM
differences. We model and analyze Red Oak as part of PJM East.
TRANSMISSION WITH NEIGHBORING REGIONS
PJM is part of the integrated Eastern Interconnect in the U.S. Direct
links exist with the three surrounding regions of ECAR, NYPP, and VACAR, as
shown in Exhibits 2-3 and 2-4(19). These links equal 15 to 20 percent of total
PJM peak, and if power is available in neighboring regions, PJM can utilize
imported power to supplement local generation. Historically, PJM has
------------------
(17) A subset of the ICF characterization of PJM West.
(18) We additionally model Homer City as to separate sub region due to its
unique structure with equal access to both PJM and NYPP.
(19) Note, we model these regions as well as NEPOOL, and Ontario for a total of
15 subregions.
29
<PAGE>
been a net importer of low cost power from ECAR, i.e., coal-by-wire. However,
the tight capacity situation in the Midwest has recently reversed this trend,
especially during peak periods, and PJM has recently become a power exporter to
ECAR.
EXHIBIT 2-3
NORTHEAST TOTAL TRANSFER CAPABILITY (MW)
A map highlighting the states with highest peak transfer capabilities in
terms of MW
[GRAPHIC]
Physically, the primary interconnections between PJM and neighboring
systems consist of: (i) two 500 kV interconnections in southwestern PJM with APS
in ECAR (thus the key ECAR tie is controlled by APS), (ii) one 345 kV
interconnection in northwestern PJM with Cleveland Electric (i.e., FirstEnergy)
in ECAR (smaller than the APS tie), (iii) one 500 kV and one 345 kV
interconnections with NYPP at Orange and Rockland Ramapo substation, (iv) two
345 kV interconnections with NYPP via NYSEG-owned transmission lines connecting
NYSEG to the Homer City plant, and (v) several 500 kV and 230 kV lines
connecting southern PJM to the VACAR region. The Homer City plant was owned in
part by New York State Electric and Gas (NYSEG) and has an unusual status of
being part of NYPP as well as PJM. The plant is modeled as such in this study.
EXHIBIT 2-4
PJM TOTAL EXPORT TRANSFER CAPABILITY
[GRAPHIC]
<TABLE>
<CAPTION>
Source Regions Approximate Transmission
Capability (MW)
<S> <C>
NYPP 3,200
ECAR 3,300
VACAR 3,600
Total 10,100
Total Peak Demand in PJM
(Weather Normalized) 49,000
Export Capability/Total Peak 21%
</TABLE>
30
<PAGE>
CAPACITY AND GENERATION MIX
PJM as a whole has a diverse supply mix with significant amounts of
coal, nuclear, oil/gas steam and combustion turbine capacity. Base load units
(coal and nuclear) are operated much more than peaking units (combustion
turbines, and oil/gas steam). For example coal and nuclear generation combined
accounted for about 85 percent of total generation in 1997, as illustrated in
Exhibit 2-5.
EXHIBIT 2-5
REGIONAL CAPACITY AND GENERATION MIX - 1997
2 separate pie charts; one showing capacity by type of fuel; one showing
generation output by type of fuel
[GRAPHIC]
Source: Data from 1998 NERC ESOD which reports only firm capacity
PJM coal capacity is relatively diverse in terms of delivered costs.
Plants located in the coal fields of Appalachia have delivered costs as low as
$1.00/MMBtu and other eastern PJM plants have costs as high as $1.75/MMBtu. This
is in part due to some of the highest dollar per ton-mile rail rates in the U.S.
More than 30 percent of PJM capacity is gas and/or oil-fired. PJM has
less oil/gas steam generation than New York or New England, but more than ECAR
or VACAR. Oil/gas steam units drive the marginal price for a portion of the
year, especially during periods of East-West congestion. This is because these
units are located primarily in PJM East.
PJM also has a relatively heavy reliance on generation from NUGs, which
account for about 10 percent of the total capacity.(20) Although NUGs are
located throughout PJM, about two-thirds of them are located in and supply power
to PJM East.
The capacity mixes of PJM East and PJM West differ significantly. In
PJM West, coal makes up a larger percentage of the total capacity mix,
approximately 60 percent. Conversely, capacity in PJM East is more
predominantly oil/gas steam. Furthermore, PJM West has direct
-------------------
(20) Source: ICF Consulting.
31
<PAGE>
access to coal imports from neighboring ECAR, and PJM-South has direct access to
coal power in VACAR. PJM East does not have access to similarly cheap coal
imports, except from PJM West. This creates a potentially interesting congestion
consequence - a limited ability to displace PJM East oil/gas power with coal
power from PJM West.
The capacity and generation mix in PJM will be increasingly influenced by
natural gas over time as almost all economic build decisions are effectively
either gas-fired combined cycles or combustion turbines. As can be seen in
Exhibits 2-6, 2-7, and 2-8 the gas share of generation increases to
approximately 22 percent in 2002, 59 percent in 2020, and 71 percent in 2025.
EXHIBIT 2-6
PROJECTED REGIONAL CAPACITY AND GENERATION MIX - 2002
2 pie charts; one illustrating regional capacity by type of fuel; one
illustrating regional generation by fuel type for the year 2002
[GRAPHIC]
EXHIBIT 2-7
PROJECTED REGIONAL CAPACITY AND GENERATION MIX - 2020
2 pie charts one illustrating projected regional capacity by fuel type; one
illustrating projected generation by fuel type for the year 2020
[GRAPHIC]
32
<PAGE>
EXHIBIT 2-8
PROJECTED REGIONAL CAPACITY AND GENERATION MIX - 2025
2 pie charts; one illustrating projected regional capacity by fuel type for
the year 2025; one illustration projected regional generation by fuel type for
the year 2025
[GRAPHIC]
SUPPLY AND DEMAND BALANCE
PJM is a summer peaking system with approximately 50 GW of peak demand. This
is roughly comparable in size to ERCOT and more than twice the size of
NEPOOL. Exhibit 2-9 summarizes the historical trend in peak demand and energy
in PJM. Note, peak demand reached record levels in 1999 in part due to very
hot weather.
EXHIBIT 2-9
HISTORICAL PEAK DEMAND AND ENERGY GROWTH RATES IN PJM
<TABLE>
<CAPTION>
Energy
Peak Peak Annual Annual Interruptible
Demand(1) Growth Rate Energy(1) Growth Rate Load(2)
Year (MW) (%) (GWh) (%) (GW)
-----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1999 51,550 +6.5 N/A N/A N/A
1998 48,397 -2.0 249,247 +2.3 2,298
1997 49,406 +11.5 243,649 +0.1 2,239
1996 44,302 -8.7 243,328 +0.2 2,014
1995 48,524 +5.5 242,797 +2.0 1,970
1994 45,992 -0.9 238,061 +1.0 1,845
1993 46,429 +6.4 235,664 +4.3 1,571
1992 43,622 -4.9 225,906 -1.0 1,449
1991 45,870 +7.8 228,236 +3.4 1,388
1990 42,544 +2.4 220,772 -1.3 1,184
</TABLE>
-------------------
(1) Source: PJM-ISO
(2) Source: NERC ES&D; includes interruptible direct control load management.
33
<PAGE>
EXHIBIT 2-9 (CONT.)
HISTORICAL PEAK DEMAND AND ENERGY GROWTH RATES IN PJM
<TABLE>
<CAPTION>
Year Peak Annual Growth Rate Energy Annual Growth
(%) Rate (%)
<S> <C> <C>
Historical Annual Average Growth Rates (%)
10 Year Averages
1989 - 1998 1.4 1.3
1988 - 1997 2.2 1.7
1987 - 1996 1.8 2.2
1986 - 1995 2.8 2.5
1985 - 1994 2.8 2.6
1976 - 1998 Rolling
Average 2.9 2.7
5 Year Averages
1993 - 1998 1.1 1.1
1992 - 1997 2.8 1.5
1991 - 1996 -0.5 1.3
1990 - 1995 2.8 1.9
1989 - 1994 2.2 1.3
1976 - 1998 Rolling
Average 3.1 2.8
</TABLE>
-------------------
(1) Source: PJM-ISO
(2) Source: NERC ES&D; includes interruptible direct control load management.
PJM load and energy requirements have been growing robustly on average
over the last twenty or so years. As would be expected, there have been periods
and individual years of significant growth (up to 12 percent), and individual
years of stagnant or negative growth in this time horizon. Similar to other
regions, very little capacity has been added since the early 1990s.
Consequently, it is very close to being in demand and supply balance (see
Exhibit 2-10).
PJM has recently received considerable interest in terms of potential
new construction. Approximately 13 GW of new capacity has been announced,
although only approximately 7 percent or so of these announcements have actually
materialized in terms of permitting and actual construction.
EXHIBIT 2-10
1999 PJM SUPPLY AND DEMAND BALANCE
<TABLE>
<CAPTION>
Demand for Gigawatts Supply of Gigawatts
<S> <C> <C> <C>
Peak Demand 49.7 Existing Capacity(3) 56.9
Interruptible/
Controllable Load(1) 2.2 Net Firm Exports 0.6
Net Peak Demand(2) 47.5 Inoperable Capacity 0
Reserve Margin 20.0% 9.5 New Builds 0
Total Need 57.0 TOTAL Supply 56.3
Expected Reserve Margin (%): 19.1%
Deficit Gigawatts: 0.7
</TABLE>
-------------------
(1) Source: PJM Load Forecast Report, February 1999.
(2) Weather normalized 1999 summer peak reported by PJM.
(3) 1999 NERC ES&D.
Unlike NERC, which projects only a slight capacity need in the
near-term, ICF forecasts a greater level of capacity need for the period
beginning 2000. ICF foresees a need of close to 2
34
<PAGE>
GW by 2000 and over 6 GW by 2005. Yet as of October 1999, only approximately 1
GW was under construction, and for on-line dates by 2001.
In order to meet this greater need, additional capacity will need to be
built in addition to the power plants that have already broken ground.
HISTORICAL ENERGY PRICES
Historically, the PJM marketplace has had relatively high costs of
producing energy. For example, in 1996, PJM marginal costs were among the
highest in the nation among the government reported system lambdas in the United
States. System lambdas are a measure of the short run variable costs of
incremental or marginal electrical energy production. Due to its dependency on
more costly coal and oil/gas steam units on the margin, PJM was the fourth most
expensive region out of eighteen (see Exhibit 2-11). The only regions with
higher system lambdas were regions with even higher dependency on oil/gas steam
units. This 1996 system lambda data provides insights into the competitive
electrical energy prices, as it reflects pre-market tightening prices, i.e., it
maps to the electrical energy component of prices and does not incorporate the
capacity component.
EXHIBIT 2-11
1996 SYSTEM LAMBDAS (1998$)(1)
A bar graph illustrating energy prices by region
[CHART]
-----------------------
(1) Average of 8760 Hourly System Lambdas reported by FERC in Form 714
35
<PAGE>
HISTORICAL FIRM PRICES
Exhibit 2-12 summarizes recent Power Markets Week (PMW) spot prices
which we tend to think of as being generally representative of firm prices
(i.e., bundled energy and capacity). An alternate proxy for firm prices made
available more recently is the sum of the average Locational Marginal Price
(LMP) and Capacity Credit Market (CCM) price.
The PMW Index for PJM began in 1996 (see Exhibit 2-12), and separated
into two indices when PJM began its locational marginal pricing in April of
1998. Prices in both the summer of 1997 and the summer of 1998 obtained higher
maximum levels than prices in 1996, reflective of steady market tightening and
an increasing capacity component. Still as mentioned, these maximum prices were
considerably below those elsewhere in the U.S. (see Exhibit 2-13). There are
several explanations for this. First, the region has been slower in absorbing
excess capacity relative to other regions in the Eastern Interconnect - e.g.,
PJM has lagged market tightness in the Midwest. Second, it is one of the few
regions that actually enforces a high planning reserve margin. The consequences
of the high reserve margin is discussed in further detail later in the chapter.
EXHIBIT 2-12
PJM HISTORICAL PRICES TIME SERIES
A line graph illustrating marginal pricing by year for the fiscal operating
years 1996-1999
[CHART]
Source: January 1996 - May 1998 Power Markets Week (reported weekly average
prices)
April 1998 - August 1999 PJM Average LMP (weekly average of hourly prices)
36
<PAGE>
EXHIBIT 2-13
POWER MARKETS WEEK 1999 AVERAGE WEEKLY ON-PEAK INDEX(1)
OF SPOT ELECTRICITY PRICES - (JANUARY - NOVEMBER 1999)
A bar graph illustrating power peak weeks by region
[CHART]
-----------------------
(1) Weekly On-Peak Index is a weighted average of reported on-peak
electricity prices for each week
There was an improvement in price discovery in PJM in 1998. This
increase in documentation beyond newsletter reports was associated with the
initiation of the PJM Locational Marginal Prices (LMPs) on April 1, 1998. Again,
this information clearly showed that 1998 price spikes were not as large as
other price spikes in the Eastern Interconnect.
However measured, in 1999, PJM spot prices exploded with prices
reaching as high as the PJM price cap of $1,000/MWh. This was associated with
the following conditions: (i) supply and demand finally coming into balance in
PJM; (ii) hotter than normal weather conditions prevailing; and (iii)
neighboring markets, particularly ECAR, exerting pressure on local generation
resources.
EXHIBIT 2-14
HISTORICAL PJM PRICES
<TABLE>
<CAPTION>
1996 1997 1998 1999 YTD(1)
------------- ------------ ---------------- ----------------
<S> <C> <C> <C> <C>
Price (nominal
$/MWh) 20.0 20.6 21.7 29.2
Components Energy/Firm Energy/Firm Energy/Firm Energy/Firm
Source PMW(2) PMW(2) PMW(2) (Jan-Mar) LMP(3) (Jan-Nov)
LMP 3 (Apr- Dec)
</TABLE>
-------------------
(1) Through November 30, 1999.
(2) Average of weekly average prices
(3) Average of hourly prices
37
<PAGE>
CAPACITY PRICES
In 1999, trading began in a separate installed capacity market. PJM is
distinct from its Southern and Western neighbors in having a regularly enforced
and high planning reserve margin. This planning reserve requirement has been in
the 20 percent range for several years. The principle consequence of a planning
reserve margin that is enforced and is high (i.e., above approximately 15
percent is considered high) is to suppress price spikes. This fact is not as
apparent as it could be in PJM because the two neighboring markets of ECAR and
VACAR do not have enforceable reserve margins and have experienced a tremendous
erosion of reserve levels.
A deregulated power market cannot function on a sustained basis if
price spikes are suppressed and there is no compensating mechanism to ensure
that new entrants earn enough to cover costs. Hence, PJM has instituted this
capacity requirement and trading for a capacity product. Thus, there are two
separate markets - an energy market and a Capacity Credit Market. These markets
are described in detail in Chapter 3.
Exhibits 2-15, and 2-16 illustrate trading volumes and prices in the
Capacity Credit Market (CCM). Market clearing capacity credits for monthly
trading periods have been approximately $25 to $30/kW/yr. The day-ahead market
generally has been trading at one fifth or less of monthly market clearing
prices.
However, while PJM has implemented separate markets for energy and
capacity, LMP prices seem to be reaching levels that are higher than variable
costs alone imply. There are two pieces of evidence supporting this view. First,
we believe LMP prices above the $70 - $80/MWh range include a fixed cost
recovery component that should theoretically be included in the capacity price.
If energy prices are capped at $70/MWh, annual energy prices decrease by
approximately $1.5/MWh. This would translate into a capacity price adder of
approximately $10 to $12/kW/yr bringing the total capacity price to $40/kW/yr.
Second, in addition, there are periods of time in which the prices are under
$70/MWh, but still higher than marginal electrical energy costs. In all such
instances, there is additional contribution to plant revenue beyond competitive
electrical sales.
As a rough estimate, LMPs in 1999 have averaged $29/MWh versus our
estimate of competitive electrical energy prices of about $24/MWh. This
difference is equal to about $40 to $50/kW/yr. When added to the $25 to
$30/kW/yr of the monthly capacity market reflected in Exhibit 2-15, this results
in a total effective capacity price of $65 to $80/kW/yr relative to our forecast
of approximately $52/kW/yr. In other words, new power plants, especially new
combined cycles like Red Oak would receive more revenue from energy sales which
otherwise needs to be captured in either the capacity market or when the price
spikes occur pushing prices above $70/MWh.
PJM, like all fully operating central ISOs with mandatory power
exchanges, have further complicated the picture by instituting price caps. For
example, PJM has a $1,000/MWh price cap and has set limits for capacity prices.
If the capacity and energy price is capped, more reliability problems and
associated price spikes will need to occur to generate sufficient revenue to
support entry.
38
<PAGE>
EXHIBIT 2-15
RANGE OF MONTHLY CAPACITY TRADING IN PJM
A line graph illustrating the maximum and minimum monthly capacity trading by
month for the year 1999
[CHART]
EXHIBIT 2-16
PJM DAILY CAPACITY MARKET
A line graph illustrating the daily capacity market prices by month for the
year 1999
[CHART]
39
<PAGE>
EXHIBIT 2-17
MONTHLY PJM LMP PRICES - 1999
<TABLE>
<CAPTION>
Month PJM Eastern Hub Western Hub Western Interface
Hub
<S> <C> <C> <C> <C>
January 1999 19.94 19.92 19.93 19.902
February 1999 16.60 16.67 16.51 16.51
March 1999 19.61 19.67 19.59 19.59
April 1999 21.44 21.41 21.43 21.43
May 1999 22.68 22.39 22.13 22.48
June 1999 37.10 36.99 36.78 36.86
July 1999 91.67 93.09 89.98 89.94
August 1999 31.77 33.82 31.59 31.74
September 1999 22.06 22.36 21.43 21.54
October 1999 20.52 20.75 19.72 19.74
November 1999 16.60 17.40 16.38 16.35
December 1999
</TABLE>
CORRELATION BETWEEN POWER AND FUEL PRICES
The following figure shows time series of fuel and power prices. The
data confirms that in off-peak seasons prior to April 1998, average peak power
prices are partially explained by trends in natural gas prices. When the June
through August peak periods are removed, the correlation between natural gas and
the PJM composite average peak prices is 0.46. (A correlation coefficient of 1.0
would reflect perfect correlation, and a correlation coefficient of 0.0 would
reflect complete absence of correlation.)
EXHIBIT 2-18
PJM POWER PRICES VS. FUEL COSTS
A line graph showing fuel prices and fuel costs by month for the years
1996-1998
[CHART]
Sources: Power Markets Week, Natural Gas Week, Platt's Oilgram
Annual average PJM peak indices and Henry Hub prices do not indicate
much linkage. Even though gas prices were falling, power prices rose in 1997.
This is because the pure capacity component increased as the markets tightened
and historically high peak demand conditions were experienced. PJM average
annual peak prices increased further in 1998 at the same time that average Henry
Hub gas prices decreased. In 1999, similar trends prevailed
40
<PAGE>
further substantiating the limited correlation between power and fuel prices
-during peak periods. As indicated above, however, when the peak periods are
removed, the correlation coefficient between gas and electricity is 0.46 on a
scale of 0.0 to 1.0.
41
<PAGE>
CHAPTER THREE
THE EVOLVING MARKET STRUCTURES FOR PJM
--------------------------------------------------------------------------------
INTRODUCTION
The premises of this study related to market structures are several.
First, no matter where a generator is located within the PJM East marketplace it
is able to serve buyers at the same or almost the same transmission costs as
other generators on a non-discriminatory basis. Thus, there is a market-clearing
price applicable to all PJM East plants. Second, generators will be able to make
sales at competitive electrical energy and pure capacity prices and they will
account for practically all revenues. A fuller discussion of the definition and
determination of competitive electrical energy and pure capacity prices is
contained later in this report. Pure capacity, in particular, is an
analytically-oriented term. Thus, an explanation of how the marketplace will
function in terms of these two prices is an important goal of this chapter. As
it turns out, PJM has separate energy and capacity markets which facilitate this
explanation.
SUMMARY OF PJM MARKET STRUCTURE
It is useful to summarize the structure of the PJM market through an
example. Consider the situation of a entity responsible for supplying a customer
load in PJM with a summer peak of 1,000 MW. Assuming a 20% reserve margin, the
entity would have an installed capacity requirement of 1,200 MW. This
requirement would then be derated by multiplying the installed capacity
requirement by one minus a PJM-wide average forced outage rate, resulting in an
unforced capacity requirement. Assuming a 5% PJM-wide average forced outage
rate, the unforced capacity requirement would be 1,140 MW. The entity would then
have to certify to PJM that they control 1,140 MW of unforced capacity. Each
resource's unforced capacity is derated by its five year average forced outage
rate. (21) The entity can obtain this unforced capacity in a PJM market or
bilaterally. Second, the entity has to buy electrical energy in each hour to
meet the customer load from the PJM Power Exchange (PX). If the entity wants to
purchase in the spot market, it must designate its requirements node by node
(there are 1,744 nodes in PJM) and pay the nodal spot price determined by PJM.
The entity recognizes that the PJM-provided spot price can vary location by
location, i.e., node-by-node, if there is internal PJM congestion.
Alternatively, the entity can purchase power bilaterally subject to PJM
scheduling and other requirements. Third, the entity must purchase from PJM any
required ancillary services.
PJM PX MARKETS
The PJM PX market is structured as having three product markets:
- Interchange Energy Market
- Capacity Credit Market (CCM)
------------------
(21) ICF does not derate each resource's capacity in calculating capacity
prices. This would increase the capacity price as fixed cost recovery would
be spread over less MW. This does not change the overall dollar amount needed
to cover fixed costs, only the way it is accounted.
42
<PAGE>
- Firm Transmission Rights (FTR)
THE PJM ENERGY MARKET
On April 1, 1997 PJM opened its spot energy market, known as the PJM
Interchange Energy Market. This entitled PJM members to purchase energy from the
PJM spot market and sell the energy to a Load Serving Entity (LSE) within the
PJM control area. LSEs will be discussed in further detail below. The market
prices for these energy exchanges are derived from the Locational Marginal
Pricing Market (LMP) which was introduced on April 1, 1998.
EXHIBIT 3-1
PJM ENERGY MARKET - ILLUSTRATIVE SUPPLY OFFERS
A line graph illustrating market demand based on prices
[GRAPHIC]
43
<PAGE>
EXHIBIT 3-2
PRICE SETTING IN PJM
<TABLE>
<CAPTION>
OFFER PRICE DELIVERY
---------- ------------- ---------------
<S> <C> <C> <C>
Pre-April 1, 1997 Cost Based Split Savings Anywhere in PJM
April 1, 1997 to
April 1, 1998 Cost Based for Utilities Marginal or last offer chosen Node by Node
Current Market Based Marginal or last offer chosen Node by Node
</TABLE>
Under the current system, suppliers receive the market clearing price
equal to the last bid chosen in each hour. These bids do not have to be cost
based. Buyers are separate and specify only a quantity and pay the clearing
price.
Prior to 1997, PJM operated a central dispatch, tight power pool.
Offers to sell power were made based on reported costs. Offers chosen to supply
power split the savings achieved by buyers. Prior to allowing non-cost based
offers, but after April 1, 1997, the price received by all participants was the
offer price of the last unit.
Under the current system, The Office of the Interconnection administers
the energy market within PJM. Only market sellers are eligible to submit offers
to the Office of the Interconnection for the sale of electric energy or related
services in the PJM Interchange Energy Market. Market sellers must comply with
the prices, terms and operating characteristics of all Offer Data submitted to
and accepted by the PJM Interchange Energy Market. Similarly, only market buyers
are eligible to purchase energy or related services in the PJM Interchange
Energy Market and they must comply with all requirements for making purchases
from the PJM Interchange Energy Market.
The Office of Interconnection schedules and dispatches generation
economically on the basis of least-cost, security-constrained dispatch and the
prices and operating characteristics offered by market sellers. This continues
until sufficient generation is dispatched to serve the PJM Interchange Energy
Market energy purchase requirements under normal system conditions of the market
buyers. Without any internal transmission constraints, the clearing price for
energy bought and sold in the PJM Interchange Energy Market reflects the single
clearing price in accordance with Exhibit 3-1. In the event of congestion,
hourly locational marginal prices prevail at each load and generation bus. This
is discussed below.
Spot Market Energy purchased by an external market buyer is delivered
to a bus or busses at the border of the PJM Control Area. Further delivery of
the energy is the responsibility of the external market buyer. Market
participants may enter into bilateral contracts for the purchase or sale of
energy to or from each other or any other entity. IT IS UNLIKELY BUT
THEORETICALLY CONCEIVABLE THAT THERE WOULD BE NO TRANSACTIONS IN THE SPOT MARKET
IF ALL TRANSACTIONS ARE CONDUCTED BILATERALLY. Market participants must have
Spot Market Backup with respect to all bilateral transactions curtailed or
interrupted for any reason. However, a market participant may elect in the
day-ahead scheduling process not to have Spot Market Backup.
CAPACITY CREDIT MARKET
Each LSE must meet reserve margin obligations. These are currently set
at 20% of expected peak load. One might expect that the reserve margin would be
specified node-by-node.
44
<PAGE>
This is because the nodal system is designed to address the potential for
congestion. A megawatt that is not available due to internal PJM congestion
would not contribute to reliability. However, current rules are such that most
megawatts anywhere on the PJM grid can be used to meet any node's needs. To
minimize this problem, new entrants are required to pay for transmission system
upgrades to minimize this problem. This system might be modified over time to
more fully address the congestion problem. Options include more capacity reserve
margins or elimination of the capacity market.
This capacity requirement is regularly enforced and suppresses price
spikes. For example, in the extreme, at very high planning reserve margins,
e.g., 30 to 40 percent price spikes would almost never occur at all. The spikes
are needed to provide entrants recompense for their costs. PJM compensates by
having a separate capacity product market.
The PJM Capacity Credit Markets allow market participants to buy and
sell Capacity Credits at market clearing prices that are established by the PJM
Capacity Credit Markets and made public by the Office of the Interconnection. A
member shall become eligible to participate in any of the PJM Capacity Credit
Markets by becoming a market buyer or a market seller. Only market sellers are
eligible to submit Sell Offers and, likewise, only market buyers are eligible to
submit Buy Bids. An entity subject to an Accounted-For Obligation may use
Capacity Credits to meet all or part of its Accounted-For Obligation. A megawatt
of Capacity Credit satisfies a megawatt of Accounted-For Obligation. A Capacity
Credit is equal to a megawatt of unforced capacity from capacity resources. A
resource's unforced capacity is equal to its installed capacity multiplied by 1
minus its five-year historical average forced outage rate.
Sell Offers and Buy Bids must specify:
- The quantity of Capacity Credits offered or desired, in
increments of 0.1 megawatt;
- The minimum price, in dollars and cents per megawatt per day,
that will be accepted or paid;
- Whether the offer or bid is for a Fixed Block or an Up-To
Block;
- For a PJM Daily Capacity Credit Market conducted on a Friday
or the day before a Holiday, the dates on which the Capacity
Credits may be used or are desired;
- For a PJM Monthly Capacity Credit Market, the month or months
for which the Capacity Credits may be used or are desired.
A PJM Daily Capacity Market will be conducted each business day. The
Market will clear Sell Offers and Buy Bids for Capacity Credits for use the next
business day, and for each of any intervening weekend days or Holidays. A PJM
Monthly Capacity Credit Market will also be conducted. This Market will clear
Sell Offers and Buy Bids for Capacity Credits for use in each of the following
twelve months.
ENERGY AND CAPACITY
In some respects, the PJM PX market corresponds fairly neatly with the
premise of this study, namely that power plants receive energy and capacity
revenues. This is because PJM has
45
<PAGE>
separate capacity and energy markets. However, there are some complexities.
First, PJM enforces its reserve margin, but two of the three surrounding markets
(ECAR and VACAR) do not. Thus, the reserve margin does not suppress price spikes
as well as if ECAR and VACAR had similar approaches. Thus, energy prices are
more likely to reach levels above the short-run variable costs of the marginal
unit. Second, PJM has set its reserve margin at 20 percent which suppresses
spikes, but not completely. Thus, some capacity component of prices may be in
the energy market.
Ancillary services are discussed later.
RETAIL ACCESS
Retail access refers to the ability to sell power to end-users
directly. FERC does not regulate retail access. Rather, each state regulates
retail access. The PJM market is one of the most advanced in terms of retail
access. Accordingly, PJM does not refer to utilities as having obligations to
actual end-users of electricity, but rather refers to load serving entities
(LSEs) which can be either companies affiliated with utilities or independent
retail marketers.
EXHIBIT 3-3
SUMMARY OF STATE RESTRUCTURING PROVISIONS
<TABLE>
<CAPTION>
State Access Date Stranded Divestiture Mandatory Rate
Cost Recovery Provisions Reductions
<S> <C> <C> <C> <C>
Partial recovery
through CTC's. Divestiture
Pennsylvania Began 1/1/99 Specific amount of permitted, but not None
recoverable costs required
were left to the
PUC.
Allowed to recover
Maryland July 2000 as determined by PUC Not Required 3% rate reduction
Allows potential Not Required, but
recovery of stranded BPU given power to
New Jersey Began 8/1/99 costs but does not order divestiture to 5% rate reduction
guarantee it alleviate market
power
Began 10/1/99 for
large customers; 7.5% for Conectiv
1/15/00 for medium- Allowed to recover customers; rate
Delaware sized customers; as determined Not required freeze for coop
10/1/00 for by PSC customers
residential
customers
</TABLE>
46
<PAGE>
Exhibit 3-3 above, provides a summary of the state-level restructuring
provisions for PJM. Most states are requiring full access to load soon with some
transition.
The advantages of end users being able to buy and participate in the
deregulated markets from the perspective of generators are several. First, this
increases the number of buyers and supports a more liquid market. In contrast,
if only regulated utilities participate in the wholesale market's buy side, they
could act as monopsonists and depress prices. Note, this study assumes the
markets are competitive in part because of deregulation. Second, there could be
changes in the wholesale market that will be hidden until deregulation is
complete. This is because retail access is usually accompanied by stranded cost
recovery, end of cost-plus regulation of generation and often divestiture.
Examples include demand-side effects (e.g., greater incentive to cut peak demand
or greater demand growth as efficiency and lack of stranded cost recovery lowers
prices) and supply-side effects (retirements of inefficient plants or greater
incentives for efficient generation). Overall, we believe our modeling
anticipates these changes as is discussed in the Assumptions and Approach
sections of Chapter 4. Finally and most importantly, until the demand side of
the business is deregulated, it will not face risk. For example, cost plus
retail supply is risk free. Once it faces risk, then there will be a buy side
for risk management instruments such as forward contracts which facilitate open
access.
EXHIBIT 3-4
STATUS OF RETAIL DEREGULATION - SUMMARY
A map of the United States divided by level of deregulation
[GRAPHIC]
TRANSMISSION
As mentioned in Chapter 2, PJM moved quickly to a multi-utility
regional ISO rather than having utility-specific ISOs. The PJM ISO has developed
a method of handling transmission that is consistent with FERC orders related to
electricity transmission. In particular, FERC requires transmission owners to
provide non-discriminatory access to their available transmission capacity. More
particularly, utilities can allocate their grid capacity to support supply of
existing ratepayers. However, additional capacity must be supplied on a
non-discriminatory basis.
47
<PAGE>
The rules set forth in the PJM Tariff adhere to these orders, but in a
relatively unusual manner in two respects. First, the utilities have eliminated
utility-by-utility tariffs and pancaking of transmission charges. Under the
current PJM Tariff, each PJM transmission owner, either directly or through
subsidiaries, owns and operates certain transmission facilities that are
interconnected with the transmission facilities of certain other Parties within
PJM. The Parties have coordinated the operation of their respective transmission
facilities within a single control area. The Parties transferred responsibility
for administering the PJM Tariff and certain operating responsibilities,
particularly scheduling, system control and dispatch services, to an Independent
System Operator. Transmission owners within PJM are: PSE&G, PECO Energy Company,
Pennsylvania Power Light Company, Baltimore Gas and Electric Company, Jersey
Central Power & Light Company, Metropolitan Edison Company, Pennsylvania
Electric Company, Potomac Electric Power Company, Atlantic City Electric
Company, Delmarva Power & Light Company and UGI Utilities, Inc.
TRANSMISSION PRICING
Second, PJM has taken a unique approach to congestion by employing
nodal pricing in their tariff. However, before discussing congestion, we note
that other aspects appear similar to FERC orders being implemented across the
U.S. Specifically, PJM currently offers three primary transmission services
under the PJM Open Access Transmission Tariff (OATT) implemented on April 1,
1997.
1. Firm Point-to-Point Service
2. Non-Firm Point-to-Point Service
3. Network Integration Transmission Service
Point-to-Point Transmission Services is for the receipt of energy and
capacity at Points of Receipt to be sent to designated Points of Delivery. This
can be purchased as either firm or non-firm transmission services. Firm
transmission can be purchased as either short-term or long-term, short-term firm
transmission service being purchased for periods of 1 month and long-term firm
transmission service being purchased for at least one year. Non-firm
transmission service does not have these options and can only be bought for
periods ranging from one hour to one month.
Network Customers who need transmission to serve load within PJM are
eligible for Network Integration Transmission Service. This service was designed
to allow Network Customers to integrate, economically dispatch, and regulate
current and planned Network Resources to serve its Network Load. Network
Customers are also allowed to use this service for non-designated resources on
an as-available basis without facing an additional charge. Customers using this
service face a monthly charge related to the rate associated with the zone the
Network Customer's load is located in and the daily load of the Network Customer
located within the zone.
48
<PAGE>
CONGESTION
There are limits to the grid's ability to move power. When these limits
are binding, this is referred to as congestion. In most of the U.S., utilities
cut flows on congested lines based on priority oriented rules. This usually
requires generation dispatch to change. As mentioned, PJM has taken a unique
approach. Generators are not entitled to a particular transmission path, but
only the price at the grid node resulting from central dispatch in the energy
market. This re-dispatch economically resolves congestion though prices on one
side of a congested interface may be low and prices on the other side might be
high (see Exhibit 3-5). In the illustration in Exhibit 3-5, typically the nodal
price is $10/MWh, but when imports are unavailable to meet incremental demand
due to congestion, the price rises to $20/MWh.
EXHIBIT 3-5
CONGESTION RAISES PRICES - AN ILLUSTRATIVE EXAMPLE
Redispatch Increases Prices Potentially Dramatically
From the Buyer's Perspective
2 line graphs one showing Import Demand and one showing Local
Demand
[GRAPHIC]
FIXED TRANSMISSION RIGHTS
In April 1999 PJM held its first Fixed Transmission Right Auction
(FTR). FTRs were created to provide PJM market participants with a method for
price certainty when moving energy across the PJM system. They are associated
with specific transmission paths and may be purchased by any PJM transmission
customer or member. FTRs entitle the holder to a stream of revenues or charges
based on hourly energy price differences. FTRs were designed to complement LMP
(Locational Marginal Pricing), the pricing mechanism of the PJM energy market.
FTRs are available with firm transmission services and may be traded separately
from the transmission service, either bilaterally or through the auction
process.
In order to be granted an FTR by PJM, you must be a PJM Firm
Transmission Service customer, meaning you are using either Network Integration
Service or Firm Point-to-Point Transmission Service. To participate in the FTR
Auction or in FTR secondary trading, you must be a PJM member or a Transmission
Customer. Anyone may buy and sell FTRs on the
49
<PAGE>
secondary market outside of eFTR - an internet FTR trading site - but PJM Grid
Accounting makes the proper billing adjustments only for eFTR transactions.
The FTR auction provides a method of auctioning the residual FTR
capability that remains on the PJM Transmission System after network and
long-term Point-to-Point Transmission Service FTRs have been awarded. The
auction also allows Market Participants an opportunity to offer for sale any
FTRs that they currently hold. PJM holds the auction once a month. FTRs acquired
in an auction entitle the holder to credits for transmission congestion charges
for one calendar month. Each auction consists of an on-peak and off-peak
auction.
FTRs that are awarded during auction may then be freely traded on the
secondary market. The PJM FTR secondary trading market is a bilateral trading
system that facilitates the trading of existing FTRs between PJM members. The
FTR secondary market allows trading of existing FTRs only. FTRs cannot be
reconfigured in the secondary market.
INTERCONNECTS, TRANSMISSION EXPANSION AND TRANSMISSION TARIFFS
PJM approves transmission interconnects and other transmission
expansion projects. These then are approved by FERC and as necessary by the
affected states. Revenues under the PJM transmission system are reconciled with
rate of return regulation. They provide no special funding or direct incentives
for upgrade of constraints. Also, requirements are set for new plants for system
upgrades if they want to qualify for reserve margin megawatts.
ANCILLARY SERVICES
FERC requires not only provisions of access, but also provision of
ancillary services such as scheduling, reactive supply and voltage control,
operation of OASIS (Open Access Same Time Information System), regulation and
frequency, energy imbalance and others.
PJM requires ancillary services to be purchased with transmission
service to maintain reliability within and among the Control Areas affected by
the transmission service. The Transmission customer is required to purchase and
the Transmission Provider is required to provide, the following Ancillary
Services (i) Scheduling, System Control and Dispatch, and (ii) Reactive Supply
and Voltage Control from Generation Sources.
- SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE - required to
schedule the movement of power through, out of, within, or
into a Control Area. This service is the primary function of
PJM Interconnection, L.L.C.
- REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION SOURCES
SERVICE - helps maintain transmission voltages on the
Transmission Provider's transmission facilities within
acceptable limits. This is accomplished by generation
facilities under the control of the control area operator
which operate to produce or absorb reactive power. Network
Customers face a different charge for delivery to each PJM
zone and can be charged monthly, weekly, daily, or hourly
rate.
50
<PAGE>
PJM requires the Transmission Provider to offer to provide or
offer to arrange the following Ancillary Services only to the
Transmission Customer serving load within the Transmission
Provider's Control Area (i) Regulation and Frequency Response,
(ii) Energy Imbalance, (iii) Operating Reserve - Spinning,
(iv) Operating Reserve Supplemental.
- REGULATION AND FREQUENCY RESPONSE SERVICE - necessary to
provide for the continuous balancing of resources with load
and for maintaining scheduled Interconnection frequency. This
Service is accomplished by committing online generation whose
output is raised or lowered as necessary to follow changes in
load. The Transmission Provider must offer this service when
the transmission service is used to serve load within its
control Area, and the Transmission Customer can accept this
offer or purchase it from an alternative source. Each
regulating unit receives an hourly credit for regulation
supplied.
- ENERGY IMBALANCE SERVICE - provided when a difference occurs
between the scheduled and actual delivery of energy to a load
located within a Control Area over a single hour. The
Transmission Provider must establish a deviation band of
+/-1.5 percent of the scheduled transaction to be applied
hourly to any energy imbalances that occurs as a result of the
Transmission Customer's scheduled transaction. For energy
imbalances within this band the Transmission Provider and
Transmission Customer will compensate each other for all
imbalances. Excess supply would result in the Transmission
Provider being charged 80% of the LMP at the Point of Delivery
and insufficient supply would result in the Transmission
Customer being charged 120% of the LMP. If outside the
aforementioned band, Transmission Provider is charged 70% of
the LMP and the Transmission Customer is charged at the higher
of 150% of the LMP or $100/MWh. All differences between the
hourly LMP and the payments made (when the Transmission
Customer does not provide enough energy to meet its schedule)
are allocated on a pro rata basis among the suppliers in
proportion to the energy they supply to the PJM Interchange
Energy Market during that hour.
- OPERATING RESERVES - both Spinning and Supplemental, are
needed to serve load immediately in the event of a system
contingency. Prices are calculated at the end of each
Operating Day and are determined by comparing the total
offered price for start-up and no-load fees and Spot Market
Energy, decided on the basis of the resource's actual output
or available and requested time and type of operation, to the
total value of that resource's Spot Market Energy. If the
total offered price exceeds the total value, the difference
will be credited to the Market Seller. The sum of these
credits, less any payments received from another Control Area
for Operating Reserves, is the cost of Operating Reserves for
the PJM Control Area for each Operating Day. These costs are
allocated and charged to each Market Participant in proportion
to the sum of its (i) deliveries of energy to load within PJM;
and (ii) deliveries of energy sales from within PJM to load
outside of PJM, not including bilateral transactions for which
it elected not to receive Spot Market Backup.
51
<PAGE>
STRUCTURE OF MARKET TRANSACTIONS - PX VERSUS BILATERAL
The basic premise of this study is that competitive supply and demand
fundamentals will determine the market price and that whatever structure is in
place will not prohibit participants from in the long run earning a competitive
return on capital. For example, this study assumes that there will not be
binding price caps affecting entrant returns or a return to rate of return
regulation. However, there are numerous market structures which can be
consistent with prices set by engineering economic fundamentals.
Most of the U.S. relies primarily on an over-the-counter bilateral
structure for transactions. Usually, a third party broker or marketer buys and
sells power and arranges for transmission. Over the last few years, the majority
of these transactions are ultimately on both sides, between integrated
utilities. More recently, some of the transactions have started to include sales
to retail marketers selling to the end-users. As shown in Exhibit 3-6, there are
a huge amount of transactions already in place. Most are bilateral.
EXHIBIT 3-6
VOLUME OF FERC LICENSED POWER MARKETING TRANSACTIONS (SALES) - U.S. TOTAL
<TABLE>
<CAPTION>
Year Volume of Trading by Increase in Percent
Power Marketers (MWh) Compared to Previous Year
<S> <C> <C>
1995 27,622,884 ---
1996 233,997,930 747
1997 1,213,283,604 419
1998 2,318,247,848 90
1999 YTD July 1,114,560,675 NA
</TABLE>
Source: Power Markets Week
In many of the markets, there are published indices (e.g., Power
Markets Week) which report market conditions. For most of these markets, these
published indices reflect the existence of significant over-the-counter
liquidity for short-term wholesale sales (see Exhibit 3-7). PJM has reported
indices supporting price discovery and market efficiency.
52
<PAGE>
EXHIBIT 3-7
POWER MARKETS WEEK INDICES
A map of the United States divided into Power Markets
[GRAPHIC]
In addition, there have developed private, voluntary futures exchange
markets which further support power plant access to buyers. In these markets,
sellers can offer power, especially on-peak power for each day for a given
month, for up to the next twelve or so months. The first and most successful
futures markets were for delivery of power at two western locations: Palo Verde,
Arizona and the California-Oregon Border (COB). In addition, in the East, there
are several newer futures contracts:
- Into PJM (NYMEX) - West PJM. Note, this contract should be
very useful for PJM-East and Red Oak both for hedging and
price discovery. Thus, PJM is a fairly developed market even
before considering the PJM PX.
- Into Cinergy (NYMEX) - This market is in ECAR and is for
delivery into the Indianapolis and Cincinnati areas.
- Commonwealth Edison (CBOT)
- TVA (CBOT)
PJM has taken a different approach from most of the U.S., further
improving price discovery and potentially efficiency and liquidity. PJM has a
Power Exchange (PX) in which bidders offer electricity to a centrally run
utility industry exchange. PXs are spot or cash markets rather than a forward or
futures market. Exchange transactions are standardized to attract participation
and are theoretically designed to complement bilaterals (e.g., contracts for
differences). PJM has one of the four exchanges in the U.S. In addition,
California, NEPOOL and New York have or plan to have them. Participation in the
PJM PX is mandatory for operating generators as it is in NEPOOL though bilateral
transactions are permitted and recognized as a form of participation.
Both approaches (i.e., utility industry PX and bilateral non-industry
approaches) are consistent with our underlying modeling as long as there are no
price caps or a return to rate of
53
<PAGE>
return regulation. In either market structure, competitive prices especially in
the long run, will reflect supply and demand fundamentals - i.e., prices will
equal marginal costs.
Deregulation affects many other wholesale market issues, one which is
mentioned briefly here. Some markets separate capacity and energy and ancillary
services. Others do not. This is discussed further in a later chapter. However,
either market is theoretically consistent with the premise of this study.
54
<PAGE>
CHAPTER FOUR
REGIONAL ASSUMPTIONS UNDERLYING ELECTRIC REVENUES FORECAST
--------------------------------------------------------------------------------
Chapter Four has two principal sections. The first section presents the
study modeling and methodology, and the second presents our input assumptions.
MODELING
ICF Resources' IPM-TM- is a production cost simulation model focusing
on analyzing wholesale power markets and assessing competitive market prices of
electrical energy, based on an analysis of the fundamentals relating to supply
and demand. The model also projects plant generation levels, new power plant
construction, fuel consumption, and inter-regional transmission flows. The model
determines appropriate production, and therefore production costs and prices,
using a linear programming optimization routine with dynamic effects (i.e., it
looks ahead at future years and simultaneously evaluates decisions over
specified years). All major factors affecting wholesale electricity prices are
covered in this model, including detailed modeling of existing and planned
units, with careful consideration of fuel prices, environmental allowance and
compliance costs, and operating constraints. Based on looking at the
supply/demand balance in the context of the various factors discussed above,
IPM-TM- projects the hourly spot price of electric energy within a larger
wholesale power market. IPM-TM- also projects the annual pure capacity price.
The IPM-TM- addresses a wide range of issues including:
- Projection of competitive market prices.
- Estimating the dispatchability of specific units.
- Assessment of the revenues and costs of merchant power plants.
- Projection of purchase prices for blocks of power.
- Understanding the reasons for long-term dispatch patterns
within power pools.
- Assessing the impact of different variables on dispatch
patterns and energy-related measures.
METHODOLOGY
The following discussion presents ICF's modeling approach, which
assumes a perfectly competitive market. To the extent that the market is not
competitive, prices and plant revenues will be higher than indicated in this
report.
55
<PAGE>
ENERGY AND CAPACITY PRICING APPROACH
The value of a power plant is assessed within a regional market by
examining the applicable forecast revenues and costs associated with operating
the plant. Power plants provide two primary unbundled products: (i) electrical
energy, and (ii) pure capacity. Pure capacity increases the reliability of
electrical energy. The sum of the spot price of unbundled electric energy and
the spot price of unbundled capacity is the spot market price of firm
electricity (see Exhibit 4-1). Firm is defined as unit contingent. These two
products have been individually analyzed and their prices are summarized in this
report.
Note, plants may be able to sell ancillary services in addition to
and/or instead of energy and capacity. However, plants will only be able to earn
revenues equal to those if only energy and capacity sales were made, but not
more - i.e., they can earn this given amount in one of several combination of
sales (e.g., some ancillary and some energy/capacity) but cannot earn in total
more. This is discussed further later in this chapter.
EXHIBIT 4-1
FIRM POWER PRICES ARE THE SUM OF ENERGY AND CAPACITY
[GRAPH] A Line graph comparing long and short term energy capacity
- AN ILLUSTRATIVE EXAMPLE OF A SMOOTH TRANSITION TO EQUILIBRIUM
VALUATION APPROACH
Valuation in its most mechanical form is a two-step process. First, in
equilibrium, capacity revenues are based on the capacity of the plant and the
annual pure capacity price.
CAPACITY REVENUES = CAPACITY (kW) x PURE CAPACITY PRICE ($/kW/YR)
56
<PAGE>
Second, energy revenues are based on three factors: (i) the capacity of
the plant, (ii) the level of dispatch of the plant, and (iii) the energy price
during hours the plant operates. The level of dispatch, in turn, depends on the
bid. In a competitive market, the bid price reflects the variable component of
fuel price and variable O&M costs of the plant.
ENERGY REVENUES = CAPACITY (MW) x HOURS OF OPERATION (HOURS) x REALIZED
ENERGY PRICE ($/MWh)
While all available power plants receive similar revenues for capacity
(on a per kW basis), energy revenues will vary across plants.
Note that we use this approach even for markets where no separate
capacity market exists. This ultimately derives from the empirical finding by
ICF that no market in the U.S. in equilibrium will be reliable without a premium
above electrical energy prices. Thus, unless the price is made sufficient in
some manner in the long run, the grid cannot be operated reliably.
In a competitive market, the hourly dispatch of a plant will be based
on economics. That is, if the plant's variable costs are lower than the hourly
market price, the plant will be dispatched.(1) The margin it will earn will be
the difference between the price in that hour and the variable cost.
ENERGY PRICING
Competitive wholesale or spot electric energy prices are determined on
an hourly basis by the intersection of supply (the available generating
resources) and demand (Exhibit 4-2). In each hour, the prevailing spot price of
electric energy will be approximated by the short-run marginal cost of
production of the most expensive unit operating in that hour(2). Thus, the spot
electric energy price in the bulk power market in a given hour is equal to the
marginal energy cost in that hour. Note that prices are determined hourly
because power cannot be readily stored. These competitive electrical energy
prices are also known in the industry as system lambdas, economy energy, and
interruptible power.
--------
(1) Some units will be dispatched at minimum turndown levels due to operational
limitations.
(2) When the price exceeds this level, it is defined as the hourly pure capacity
price. See pure capacity pricing discussion.
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<PAGE>
EXHIBIT 4-2
ILLUSTRATIVE SUPPLY CURVE FOR ELECTRICAL ENERGY
A bar graph showing electrical energy supply by time of day
[GRAPH]
Note: Cogeneration units can have a wide range of heat rates. The most efficient
gas cogeneration units are more competitive than gas-fired combined cycles. Coal
plants can have a wide range of fuel and emission costs. Gas-fired combined
cycles can be more competitive than coal plants, particularly in summer months.
Additional detailed dimensions of this problem include:
- Treatment of power imports and exports. Thus, not only is
power analysis complicated by hourly product markets and
prices, but also by geographically diverse product markets and
prices.
- Operational constraints including minimum run times, start
times, and start-up costs.
- The opportunity cost of using environmental allowances.
PURE CAPACITY PRICING
Exhibit 4-3 illustrates supply and demand equilibrium for megawatts,
the point at which existing power plant supply is equal to the level of peak
demand plus reserve requirements. Our derivation of pure capacity prices
(described in this section) reflects these equilibrium conditions. In other
words, the ICF IPM-TM- model used here will build to meet reserve margin if the
market is short of capacity and may retire if the region is long.
58
<PAGE>
EXHIBIT 4-3
EQUILIBRIUM IN THE CAPACITY MARKET
[GRAPH] A line graph showing peak demand and existing capacity
Equilibrium is defined usually as a condition in which there is
sufficient capacity to meet a planning reserve margin over expected system peak.
However, some regions rely more on operating reserve requirements than on
planning reserve requirements. Either way, significant reserves are needed. That
is, planning reserve requirements are set to ensure that there are enough
operating reserves at peak. Thus, the fact that the model is estimating a
separate capacity price is appropriate even for markets without separate
planning reserve requirements.
Capacity increases the reliability of electrical energy supply.
Consequently, the power price structure must be high enough to ensure that
sufficient pure capacity exists (i.e., units which almost never operate are
available and are purely for reserve). To the extent that prices are above
system lambda (i.e., above the competitive electrical energy price or the
marginal variable cost of the last unit dispatched), this premium is the pure
capacity price. The pure capacity market is not entirely separate from the
energy market, but is linked.
ICF uses a sophisticated linear programming based computer modeling
approach to forecasting capacity prices in which all model output is
simultaneously determined. However, it is useful to describe this approach using
seven steps.
In Step 1, the annualized costs (capital related and annual fixed
non-fuel O&M) of the least costly type of additional megawatts are estimated. In
the model, these costs are calculated for numerous new plant options (e.g.,
simple and combined cycles of different vintages, and coal plants).
Step 2 is to account for the energy sales profit of new power plants
(i.e., the fact that new plants may not provide strictly pure capacity). For
example, if a new power plant can make
59
<PAGE>
profit on electrical energy sales, this diminishes the price premium (i.e., the
pure capacity price) required to build the necessary megawatts for reliability.
For example, if a new combustion turbine can make $10/kW/yr in energy profit and
it costs $57/kW/yr to build, the pure capacity price is $47/kW/yr.
The formula for the step 2 adjustment is more complicated than Step 1
because all new potential entrants - e.g., both combined cycles and simple
cycles - can profit from energy sales and all are potential marginal sources of
megawatts. The pure capacity price is driven by the lower capacity price
required of the two plants, as shown in the following, simplified formula:
<TABLE>
<S><C>
------------------------------------------------------------------------
If (C(x) - X) less than or equal to (C(y) - Y), then P = C(x) - X
If (C(x) - X) greater than or equal to (C(y) - Y), then P = C(y) - Y
------------------------------------------------------------------------
Where:
X = Energy sales profits of a new combustion turbine
Y = Energy sales profits of a new combined cycle
C(x) = Annual fixed costs of a new combustion turbine
C(y) = Annual fixed costs of a new combined cycle
P = Pure Capacity Price
------------------------------------------------------------------------
</TABLE>
Under Step 3, the model makes decisions to import or export firm
megawatts. Thus, the equilibrium in the capacity market is determined by
simultaneously answering three questions: (1) how much reserves are required in
a regional marketplace (with reference to planning reserve requirements or
market revealed reserve needs and accounting for demand growth); (2) how much
can be traded; and (3) what, if any, retirements occur (see Step 4). We
highlight trading of firm capacity rights for megawatts in the capacity pricing
discussion because exporters are at a disadvantage to local generation since
additional transmission charges are required on firm capacity purchases from
other regions.
In Step 5, we analyze whether the very last existing units in the
dispatch order should be retired if the pure capacity price is not sufficient to
allow them to cover their net fixed, non-fuel, cash-going-forward costs after
energy sales. In addition, the competitive market price for pure capacity will
be less than the required capacity payment for new entrants in cases of excess
capacity unless sufficient retirements occur to bring the market into
equilibrium. In this case, the net cost of new plants must be greater than or
equal to the cost of the most expensive units on a discounted multi-year basis.
Our model is distinguished by its ability to make decisions including retirement
decisions. It does this by incorporating expectations about the future through
solving all years simultaneously and calculate net present values for existing
units.
Step 6 addresses the multi-year nature of new power plant investment.
The decision on whether to add new capacity to the system and the type of
capacity to be added depend on the long term potential for recovery of costs
associated with the investment. If the capital costs associated with new power
plants are correctly anticipated to be lower in the future such that the price
of pure capacity in those years will also be lower, an additional premium in the
early years would be warranted and necessary to compensate for lower profits in
the out years. Otherwise, the price will be sufficient for the later entrants to
recover costs and earn a return but not the earlier entrants. This issue exists
with some saliency due to several factors including the
60
<PAGE>
possibility that the real costs of new gas power plants and their heat rates
will continue to decrease.
Step 7 addresses the response to interruptible load, market power and
forward trading. The impact of these would be to create a capacity price floor.
PRICING IN THE VERY LONG RUN - REBUILT SYSTEM
In order to illustrate our view on capacity expansion, it is helpful to
understand our view of how electrical energy and capacity prices will be
determined in the very long run. Over time, demand growth and retirements of
existing units will create a situation in which new power plants are required to
meet demand in every hour of the year.
Eventually, the entire system relevant for marginal analysis could be
rebuilt. We hypothesize that the system would be rebuilt with gas-fired combined
cycles and combustion turbines. In this case, there would be only two unique
energy prices: the price set by a combustion turbine; and the price set by a
combined cycle. In every hour of the year, one of these prices would be the
market-clearing price.
EXHIBIT 4-4
PRICING IN THE VERY LONG RUN - REBUILT SYSTEM -
LONG RUN EQUILIBRIUM IN 8,761 MARKETS
[GRAPH] A line graph showing energy prices by hours of energy used
The build mix between combined cycles and combustion turbines would be
based on economics. The annual average energy price would be somewhere in
between the price set by each type of plant.
In this rebuilt system, combustion turbines would not make any profits
in the electrical energy markets. Every time they ran, they would be setting the
market-clearing price. Thus their economic profits would be zero.
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<PAGE>
As a result, the fixed costs of a combustion turbine would always set
the pure capacity price.
REBUILT SYSTEM APPROACH COMPARED TO NEAR TERM
CAPACITY EXPANSION APPROACH
While a rebuilt system is not required until the very long term, some
capacity expansion is required in the near term. As described in the five-step
approach to capacity pricing, this additional capacity is brought on-line
following a methodology similar to the long-term approach.
The fixed costs of the new power plants, net of any energy profits that
they earn, set the pure capacity price. Thus, while in the long run, the pure
capacity price is always set equal to the fixed costs of a new combustion
turbine, in the near term it could be different.
The new power plants are added in such a way as to minimize costs. That
is, the mix between combined cycles and combustion turbines is optimized to
result in the lowest pure capacity prices.
REGIONAL ASSUMPTIONS
This section focuses on the key assumptions underlying the analysis.
The major determinants influencing energy and capacity prices in PJM include:
<TABLE>
<CAPTION>
----------------------------------------------- ------------------------------------ ---------------------------------
ENERGY PRICING CAPACITY PRICING TRANSMISSION
----------------------------------------------- ------------------------------------ ---------------------------------
<S> <C> <C>
- Fuel Prices - Load Growth - Transfer Capability
Gas - Reserve Margin - Transmission Pricing
Oil - New Power Plant
Coal Characteristics
- Environmental Compliance - Financing of New Power
- Nuclear Plant Characteristics Plants
- Existing Unit Characteristics
----------------------------------------------- ------------------------------------ ---------------------------------
</TABLE>
The assumptions used are summarized under the categories of capacity,
energy, environmental, and transmission assumptions in Exhibits 4-5, 4-6, 4-7,
and 4-8, respectively. We modeled all of the northeastern regions (PJM, NYPP,
NEPOOL, ECAR, VACAR, Ontario and their sub-regions), but focus on the PJM
region. We modeled 2002, 2005, 2010, 2015, 2020, 2025, and 2030. We consider in
our model the following seasons:
- Summer: June, July, and August (92 Days)
- Winter: January, February, and December (90 Days)
- Winter Shoulder: March, April, October, and November (122
Days)
- Summer Shoulder: May and September (61 Days)
62
<PAGE>
EXHIBIT 4-5
PJM CAPACITY PRICE RELATED ASSUMPTIONS3
<TABLE>
<CAPTION>
-------------------------------------------------------------- -------------------------------------------
PARAMETER TREATMENT - BASE CASE
-------------------------------------------------------------- -------------------------------------------
<S> <C>
1999 Weather Normalized Net Peak Demand(1) (GW) 47.6
Annual Peak Growth 1999 - 2005 (%) 2.0%
Annual Peak Growth 2006 - 2020 (%) 2.0%
-------------------------------------------------------------- -------------------------------------------
1998 Net Energy for Load(2) (GWh) 249,247
Annual Energy Growth 1999 - 2005 (%) 2.0%
Annual Energy Growth 2006 - 2020 (%) 2.0%
-------------------------------------------------------------- -------------------------------------------
Planning Reserve Margin (%)(3)
2000 19.5
2003 19.0
2010 15.0
2020 15.0
-------------------------------------------------------------- -------------------------------------------
New Power Plant Builds CT CC
Capital Costs (1998$/kW)
2000 368 583
2005 368 583
2010 350 555
2015 333 528
2020 317 502
2025 317 502
2030 317 502
Fixed O&M (1998$/kW/yr) 9.8 16.0
-------------------------------------------------------------- -------------------------------------------
Financing Costs for New Builds
Debt/Equity Ratio (%) 50/50
Nominal Debt Rate (%) 8.5
Nominal After Tax Return on Equity (%) 14.0
Income Taxes (%) 41.3
Other Taxes4 (%) - East/West/South 0.5/0.7/1.5
General Inflation Rate (%) 3.0
Levelized Real Capital Charge Rate (%)
East/West/ South 12.7/12.9/13.5
-------------------------------------------------------------- -------------------------------------------
Firm Builds Plus Additional Builds
New Builds Required to Meet to Reserve Margin
Requirements
-------------------------------------------------------------- -------------------------------------------
Firmly Planned Builds (MW)
By 2000 250
2001 824
2002 0
Total by 2002 1,074
-------------------------------------------------------------- -------------------------------------------
Economic Retirements Save non-fuel O&M only - Select nuclear
and fossil units
-------------------------------------------------------------- -------------------------------------------
</TABLE>
(1) Reflects weather normalized summer peak demand for 1999 reported by PJM
(2) Historical 1998 net energy reported by PJM in "February 1999 Load Report"
(3) Reserve margin decreases at a steady rate between 2003 and 2010.
(4) Includes property taxes and insurance.
---------------------
(3) Most parameters affect both energy and capacity prices but we have separated
them for expositional purposes.
63
<PAGE>
EXHIBIT 4-6
PJM ENERGY PRICE-RELATED ASSUMPTIONS
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
PARAMETER TREATMENT - BASE CASE
----------------------------------------------------------------------------------------------------------
<S> <C>
Delivered Natural Gas Prices (1998$/MMBtu)
2000 2.55
2005 2.66
2010 2.78
2015 2.92
2020 3.03
2025 3.03
2030 3.03
----------------------------------------------------------------------------------------------------------
Delivered Oil Prices (1998$/MMBtu) Crude Delivered Delivered
----- --------- ---------
(1998$/bbl) 1%Resid Distillate
--------- ----------
(1998$/MMBtu) (1998$/MMBtu)
2000 18.0 2.57 3.97
2005 18.5 2.84 4.06
2010 19.5 3.19 4.22
2015 19.5 3.19 4.22
2020 19.5 3.19 4.22
2025 19.5 3.19 4.22
2030 19.5 3.19 4.22
----------------------------------------------------------------------------------------------------------
Coal Prices Minemouth (1998$/Ton) Central Central
Appalachian Pennsylvania Bailey
----------- ------------ ------
(0.7%Sulfur, (1.5-2.0%Sulfur, (1.25%Sulfur,
12,000 Btu/lb) 12,500 Btu/lb) 12,500 Btu/lb)
2000 24.70 22.36 24.55
2005 23.97 22.54 23.26
2010 23.49 22.31 23.00
2015 22.52 22.07 22.40
2020 20.58 21.85 21.80
2025 18.81 21.63 21.22
2030 17.18 21.42 20.65
----------------------------------------------------------------------------------------------------------
Coal Transportation Annual Real Price Decrease (%) 2.0
----------------------------------------------------------------------------------------------------------
Nuclear Capacity Factor (%)
PJM West Average 82
PJM East Average 75
PJM South Average 80
----------------------------------------------------------------------------------------------------------
Nuclear Retirements End of 40 yr license
----------------------------------------------------------------------------------------------------------
</TABLE>
64
<PAGE>
EXHIBIT 4-6
ENERGY PRICE-RELATED ASSUMPTIONS (CONTINUED)
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
PARAMETER TREATMENT - BASE CASE
----------------------------------------------------------------------------------------------------------------------
<S> <C>
New Power Plant Builds CT CC
Heat Rate (Btu/kWh) -- --
2000 10,905 6,928
2005 10,671 6,753
2010 10,443 6,583
2015 10,219 6,417
2020 10,000 6,255
2025 10,000 6,097
2030 10,000 6,000
Variable O&M(1) (1998$/MWh) 2.3 1.1
Availability (%) 92 92
----------------------------------------------------------------------------------------------------------------------
Non-Utility Generators (MW) 2000 2010
---- ----
Dispatchable 1,112 5,008
Non-Dispatchable(2) 3,896 0
TOTAL 5,008 5,008
----------------------------------------------------------------------------------------------------------------------
Existing Power Plant Availability (%)
Coal Steam 85
Oil/Gas Steam 85
----------------------------------------------------------------------------------------------------------------------
Variable O&M (1998$/MWh) Oil/gas Unscrubbed Scrubbed
CC CT Steam Coal Coal
-- -- ----- ---- ----
Range(3) 0.8-4.1 0.8-6.0 2.5-6.53(3) 1.0-4.1 2.1-5.1
----------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Values specified correspond to an 80 percent capacity factor for combined
cycles and 15 percent capacity factor for combustion turbines.
(2) Decreasing gradually over time.
(3) Inversely correlated with capacity factor.
EXHIBIT 4-7
ENVIRONMENTAL-RELATED ASSUMPTIONS
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
PARAMETER TREATMENT
-----------------------------------------------------------------------------------------------------------
<S> <C>
SO(2) Regulations Phase II Acid Rain(1)
-----------------------------------------------------------------------------------------------------------
NO(x) Regulations NOx OTR(2)
-----------------------------------------------------------------------------------------------------------
CO(2) Regulations None
-----------------------------------------------------------------------------------------------------------
Mercury Regulations None
-----------------------------------------------------------------------------------------------------------
SO(2) NO(X)
----- -----
Starts at around $200/ton Starts at levels below
Allowance Prices (1998$/ton) and increases rapidly in late 1998/early 1999
real terms through 2020. levels and increases in
real terms through 2020.
-----------------------------------------------------------------------------------------------------------
</TABLE>
(1) No Tightened SO(2) Regulations
(2) SIP Call not analyzed as part of Base Case
65
<PAGE>
EXHIBIT 4-8
PJM TRANSMISSION-RELATED ASSUMPTIONS
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
PARAMETER TREATMENT
----------------------------------------------------------------------------------------------------------------------
<S> <C>
Intra-Regional Transmission
West to East (GW) 6.2
East to West (GW) 2.0
West to South (GW) 4.1
South to West (GW) 2.4
----------------------------------------------------------------------------------------------------------------------
Inter-Regional Transmission
Total Import Capability (GW) 8.4
Total Export Capability (GW) 10.7
----------------------------------------------------------------------------------------------------------------------
</TABLE>
FUEL PRICES
GAS PRICES
Natural gas prices are a key driver of marginal energy costs and will
become even more important over time as new combined cycle and combustion
turbine units increasingly constitute the marginal unit on the system.
U.S. natural gas prices have increased significantly in real terms over
the last 50 to 60 years. This has reflected depletion including such trends as
decreasing importance of associated gas-i.e., a by-product of oil production.
In the 1970s and early 1980s, natural gas prices were superheated by two key
developments: (i) U.S. government wellhead price controls which became binding
by 1970 and (ii) oil price increases.
EXHIBIT 4-9
HISTORICAL NATURAL GAS WELLHEAD PRICES (1940-1994) - U.S.$
[GRAPH] A line graph illustrating annual gas prices for the years 1940-1994
66
<PAGE>
Gas prices have decreased since their highs in 1982 of about $3.8/MMBtu
(1998$). We believe that recent prices, i.e., during the 1990s after
deregulation are much more representative of the future than those for pre-1985,
especially 1970 to 1985, when regulatory distortions were at their height. In
recent years, prices at Henry Hub, the most important U.S. Hub in terms of
volume, have not followed a clear trend in our view.
EXHIBIT 4-10
HISTORICAL HENRY HUB PRICES (1998$)
[GRAPH] A line graph showing average gas price per month
Sources: 1980 to 1988 are Wellhead Gas Prices from Monthly Energy Review,
March 1996
1989 to 1998 are Henry Hub Prices from Natural Gas Week
The natural gas price forecasts were derived in part from results from
ICF's North American Natural Gas Analysis System (NANGAS). The NANGAS model has
descriptive and analytic capability that allows assessment of gas resources and
markets from reservoir to burner-tip, working from a database of more than
17,000 US and Canadian reservoirs.
The NANGAS model also contains: explicit characterizations of the
performance and market penetration rate of E&P technologies; detailed
regional/sectoral/seasonal demand criteria; site-specific investment, operating
and environmental compliance cost; and a pipeline network simulation that
analyzes supply, demand, and transportation interactions consistently and
comprehensively.
As mentioned, there is insufficient evidence that the higher prices at
Henry Hub realized in mid-1999 would indicate a sustained high price, or a trend
of significantly increasing prices. This is in part because our engineering
reservoir simulation analysis on gas supply supports only very modest
sustainable real (inflation adjusted) gas price increases. The recent history of
high prices may be explained as reflecting a short-term tight market situation.
67
<PAGE>
The Base Case (as shown in Exhibit 4-11) incorporates real Henry Hub
natural gas prices increasing at approximately 1 percent per annum between 2000
and 2010 (in real terms). This modest growth is in spite of large increases in
gas use for power generation forecast by ICF (see Exhibit 4-12).
EXHIBIT 4-11
HENRY HUB FORECASTS - BASE CASE
(1998$/MMBTU)
<TABLE>
<CAPTION>
--------------------------------------------- -------------------------------------------
YEAR BASE CASE
--------------------------------------------- -------------------------------------------
<S> <C>
2002 2.28
--------------------------------------------- -------------------------------------------
2005 2.34
--------------------------------------------- -------------------------------------------
2010 2.44
--------------------------------------------- -------------------------------------------
2015 2.56
--------------------------------------------- -------------------------------------------
2020 2.70
--------------------------------------------- -------------------------------------------
2025 2.70
--------------------------------------------- -------------------------------------------
2030 2.70
-----------------------------------------------------------------------------------------
</TABLE>
Source: ICF
EXHIBIT 4-12
NATURAL GAS OUTLOOK
[GRAPH] A line graph showing demand for Natural Gas by year compared to
commodity price by year for the years 1995-2010
68
<PAGE>
U.S. demand will not consume all the new incremental gas supplies; some
will be used in Canada. Even so, some U.S. basins will lose some market to
Canadian producers. However, Canadian producers will lose some market share on
the West Coast.
We believe gas prices will be driven by the costs of exploration and
production, and large amounts of low cost resources exist in the U.S. demand for
natural gas is expected to increase 50% between now and 2010 with most of the
increase to come from electric utilities and industrial customers. During the
same period, electric power demand for natural gas is projected to grow from 15%
to 32% of the U.S. total.
ICF's NANGAS Model simultaneously determines a complete set of basis
differentials for all supply and demand areas. However, to simplify
presentation, we discuss delivered prices in terms of their basis difference
from Henry Hub.
EXHIBIT 4-13
PJM DELIVERED NATURAL GAS PRICES - ICF BASE CASE FORECAST
(1998$/MMBtu)
<TABLE>
<CAPTION>
------------------------------------- --------------------------------------------------
PARAMETER TREATMENT
------------------------------------- --------------------------------------------------
<S> <C> <C> <C>
Hub Price
2002 2.28
2005 2.34
2010 2.44
2015 2.56
2020 2.70
2025 2.70
2030 2.70
------------------------------------- --------------------------------------------------
Basis Differential EAST WEST SOUTH
---- ---- -----
2002 0.31 0.28 0.26
2005 0.31 0.28 0.26
2010 0.34 0.31 0.29
2015 0.36 0.33 0.31
2020 0.33 0.30 0.28
2025 0.33 0.30 0.28
2030 0.33 0.30 0.28
------------------------------------- --------------------------------------------------
Total Delivered
2002 2.59 2.56 2.54
2005 2.66 2.63 2.61
2010 2.78 2.75 2.73
2015 2.92 2.89 2.87
2020 3.03 3.00 2.98
2025 3.03 3.00 2.98
2030 3.03 3.00 2.98
------------------------------------- --------------------------------------------------
</TABLE>
We believe that Henry Hub is the marginal source for gas in the PJM
area during a significant portion of the year. We utilize an annual average
basis differential in the range of $0.26-$0.36/MMBtu (1998$). We assume a
slightly lower basis differential for PJM as compared to the 1995-1998 average.
The differential was particularly high in 1996 due to the spike in delivered gas
prices, which we consider a deviation from the long-term equilibrium. Therefore,
the assumptions for basis differential are based on the trend during the 1997-98
period. In
69
<PAGE>
addition, we incorporated the price effect of potential gas pipeline expansions
into the Northeast. Trends in pipeline expansion and basis differences are
discussed in the following graphics.
EXHIBIT 4-14
PJM RECENT HISTORICAL GAS PRICE DIFFERENTIALS
(1998$/MMBtu)
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------
YEAR TOTAL HENRY HUB BASIS DIFFERENTIAL
DELIVERED(1)
-----------------------------------------------------------------------------
<S> <C> <C> <C>
Annual Avg. 1995 2.34 1.82 0.52
-----------------------------------------------------------------------------
Annual Avg. 1996 3.41 2.78 0.63
-----------------------------------------------------------------------------
Annual Avg. 1997 2.95 2.56 0.39
-----------------------------------------------------------------------------
Annual Avg. 1998 2.38 2.11 0.27
-----------------------------------------------------------------------------
1995 - 1998 Avg. 2.77 2.32 0.45
-----------------------------------------------------------------------------
</TABLE>
(1) Delivered to New York City Gate
Source: Natural Gas Week Monthly price series.
The gas market analysis assumes there is a single market clearing price
for delivered gas in all periods. In other words, all gas is "firm" in that the
price is enough to ensure delivery (i.e., there are no liquidity problems)
though consumers can decide to not purchase during peak periods. The seasonality
reflects variation in both commodity and transportation prices. ICF computed
average price across four seasons and these average seasonal price differentials
are presented in Exhibit 4-15.
EXHIBIT 4-15
PJM AVERAGE GAS PRICE SEASONALITY
<TABLE>
<CAPTION>
---------------------------------- -----------------------------------
DELIVERED NATURAL GAS(2)
DIFFERENTIAL FROM
SEASON(1) ANNUAL AVERAGE
(1998$/MMBtu)
---------------------------------- -----------------------------------
<S> <C>
Summer -0.29
---------------------------------- -----------------------------------
Winter +0.38
---------------------------------- -----------------------------------
Winter Shoulder +0.05
---------------------------------- -----------------------------------
Summer Shoulder -0.18
---------------------------------- -----------------------------------
</TABLE>
(1) Summer includes June, July, and August; Winter includes
December, January, and February, Winter Shoulder includes
March, April, October, and November; Summer Shoulder includes
May and September.
(2) ICF calculations based on 1995 - 1998 New York City Gate prices
reported in Natural Gas Week.
In response to anticipated increase in demand by utility and industrial
customers, several gas pipeline expansion projects have been planned for 1999
and 2000. The gas pipeline expansion projects include Alliance, Northern Border,
Sable Island, Millennium, Vector, TransCanadian Pipeline (TCPL), Transco
Expansion, and Florida Gas Transmission Company Phase IV. The expected increase
in gas pipeline capacity by 2000 will ease any concerns for capacity constraint.
This will help prevent gas prices from increasing significantly.
70
<PAGE>
EXHIBIT 4-16
FORECASTS EXPANSION OF NORTH AMERICA PIPELINE CAPACITY ALONG MAJOR
TRANSMISSION CORRIDORS
[GRAPH] Bar graph illustrating expansion projects per year for the years 1995
through 2010
EXHIBIT 4-17
GAS PIPELINE EXPANSION PROJECTS
[MAP] Map of United States shaded in different shades of gray illustrating
expansion projects
71
<PAGE>
EXHIBIT 4-18
DOMINO EFFECT OF GAS FROM CANADA AND GULF OF MEXICO
[MAP] A map of the United States showing gas demand by region
EXHIBIT 4-19
GAS TRANSPORTATION ROUTES FROM THE GULF OF MEXICO AND ALBERTA
[MAP] Map of United States showing transportation routes
72
<PAGE>
OIL PRICES
Oil prices are important in PJM, especially during the winter when gas
prices are high relative to residual fuel oil prices. During this time, the
dual-fuel capability steam units typically burn residual fuel (i.e., #6 oil)
rather than gas. Our modeling incorporates an SO(2) cost adder in the dispatch
cost for all oil and coal units to achieve compliance with the acid rain
regulations, as appropriate.
In the 1970s and 1980s, the oil crisis had large impacts throughout the
world markets. Oil prices remained high through the mid-80s when they dropped to
levels of about half their previous levels. With the exception of the Gulf War
period, and to a lesser extent this past year, oil prices remained fairly stable
through the late 1980s and early 1990s.
EXHIBIT 4-20
HISTORICAL CRUDE OIL PRICES (1998$/bbl)
[GRAPH] A line graph showing Crude Oil Prices by year for the years 1900-1999
73
<PAGE>
EXHIBIT 4-21
HISTORICAL OIL PRICES 1990-1998 (1998$/bbl)
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
ARAB LIGHT CIF US GULF 1% RESID NY HARBOR(2) NY RESID DISCOUNT
COAST(1) RELATIVE TO CRUDE
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
1990 27.1 23.8 88%
-----------------------------------------------------------------------------------------------------
1991 22.0 17.4 80%
-----------------------------------------------------------------------------------------------------
1992 21.9 16.9 78%
-----------------------------------------------------------------------------------------------------
1993 18.9 15.9 85%
-----------------------------------------------------------------------------------------------------
1994 17.9 15.9 89%
-----------------------------------------------------------------------------------------------------
1995 19.2 16.8 88%
-----------------------------------------------------------------------------------------------------
1996 22.0 19.8 91%
-----------------------------------------------------------------------------------------------------
1997 20.7 17.2 84%
-----------------------------------------------------------------------------------------------------
1998 13.6 12.3 91%
-----------------------------------------------------------------------------------------------------
1999 18.3 15.5 85%
-----------------------------------------------------------------------------------------------------
Average 20.0 17.1 85%
(1990 - 1998)
-----------------------------------------------------------------------------------------------------
</TABLE>
(1)Source: Platt's Oilgram Arab Light (FOB) with ICF transportation adder
(0.45*125.4/71.7) + (0.32*Crude).
(2)Source: Platts Oilgram 1% Resid New York Harbor.
(3)67 Cents/bbl (1998$) is the assumed transportation cost of 1% Resid NY
to New England.
Oil prices dropped significantly in 1998 crude prices in late 1998 fell
below $12/bbl. However, prices have rebounded significantly. In October of 1999,
prices were approximately $23/bbl. In 1998 oil prices were depressed by economic
recession in Southeast Asia, large amounts of OECO oil stocks, and the reentry
of Iraq in the marketplace. These events combined to bring Arab Light Crude
prices below $10/bbl.
Since March of 1999, oil prices have risen to 1997 levels. This price
rebound has been driven by OPEC production cuts which have cut daily oil
production by approximately 3 percent. The OPEC nations to this point have shown
remarkable production restraint which has driven Arab Light Crude prices over
$23/bbl.
74
<PAGE>
EXHIBIT 4-22
HISTORICAL CORRELATION BETWEEN HENRY HUB NATURAL GAS PRICES
AND NEW YORK HARBOR 1% RESID PRICES
A Line Graph showing Natural Gas per year for the years 1989-1999
[GRAPH]
ICF oil price forecasts are based on our analysis and assessment of current
conditions in the world markets for oil. Note therefore that competition in
North America between gas and oil is only one part of worldwide inter-fuel
competition. Thus, the correlation between gas and oil is complex. In the
long-term we do not forecast significantly higher oil prices, i.e., base case
crude priced more expensive than $20 - $25/bbl, as sustainable. In the very
long-term, residual fuel prices should trend toward levels that are consistent
with full refinery processing costs.
EXHIBIT 4-23
OIL PRICES (1998$/bbl) - ICF BASE CASE FORECAST
<TABLE>
<CAPTION>
-----------------------------------------------------------
YEAR CRUDE(1) RESIDUAL 1%(2)
-----------------------------------------------------------
BASE BASE
-----------------------------------------------------------
<S> <C> <C>
2002 18.2 16.0
-----------------------------------------------------------
2005 18.5 16.7
-----------------------------------------------------------
2010 19.5 18.5
-----------------------------------------------------------
2015 19.5 19.4
-----------------------------------------------------------
2020 19.5 19.4
-----------------------------------------------------------
2025 19.5 19.4
-----------------------------------------------------------
2030 19.5 19.4
-----------------------------------------------------------
</TABLE>
(1) Arab Light CIF U.S. Gulf Coast
(2) NY Harbor Residual 1%
75
<PAGE>
EXHIBIT 4-24
LONG RUN OIL PRODUCT PRICE OUTLOOK
A line graph showing long run oil prices per year for the years 1985-2019
[GRAPH]
Product prices are derived from crude prices based on both engineering cost
relationships and historical price correlations. Projected prices for 1%
residual oil and distillate are shown in Exhibit 4-25.
76
<PAGE>
EXHIBIT 4-25
PJM DELIVERED OIL PRICES - BASE CASE
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
ANNUAL AVERAGE PRICE
(1998$/MMBtu)
------------------------------------------------------------------
NY HARBOR COMMODITY TRANSPORTATION TOTAL DELIVERED
--------------------------------------------------------------------------------------
<S> <C> <C> <C>
1% RESIDUAL OIL
2002 2.54 0.10 2.64
2005 2.66 0.10 2.76
2010 2.94 0.10 3.04
2015 3.09 0.10 3.19
2020 3.09 0.10 3.19
2025 3.09 0.10 3.19
2030 3.09 0.10 3.19
--------------------------------------------------------------------------------------
DISTILLATE
2002 3.88 0.13 4.01
2005 3.93 0.13 4.06
2010 4.09 0.13 4.22
2015 4.09 0.13 4.22
2020 4.09 0.13 4.22
2025 4.09 0.13 4.22
2030 4.09 0.13 4.22
--------------------------------------------------------------------------------------
</TABLE>
COAL PRICES
Coal is very important for PJM, particularly in PJM West, in the near-term.
The importance of coal units may be even higher if unexpectedly high
availabilities and higher megawatt outputs are achieved through refurbishment of
existing plant. We already incorporate average availabilities of 85 percent,
which is consistent with the national average and reflects improvements over the
previous years.
EXHIBIT 4-26
WIPM-TM- COAL SUPPLY REGIONS
A map of the United States showing coal supply regions
[MAP]
77
<PAGE>
Unlike gas, coal prices have decreased in real terms over the last 50
years. This reflects: (i) increased economies of scale especially in surface
mining in the West; (ii) new technologies, especially longwall mining; (iii)
improved technology in such areas as continuous mining; and (iv) lower
transportation costs facilitating access to lower minemouth cost coal.
EXHIBIT 4-27
40-YEAR HISTORICAL AVERAGE COAL PRICES
A Line graph showing 40 year historical coal prices for the years 1950-1990
[GRAPH]
Rapid labor productivity growth has been continuing even recently.
Productivity growth continues throughout the forecast though we expect it to
slow.
78
<PAGE>
EXHIBIT 4-28
U.S. COAL MINE LABOR PRODUCTIVITY IMPROVEMENT OVER TIME
A Bar graph illustrating coal production by year for the years 1985-2015
[GRAPH]
Source: Coal Industry Annual 1994; Table 48
Note: Productivity is weighed by production at the end of each period
(1)May have been affected by the 1993 coal strike.
The Central Appalachian coal price has declined significantly over the past
decade. Between 1993 and 1998, prices decreased by more than 15% in real terms.
The price for Central Appalachian low-sulfur coal was not affected upward by
utility Phase I Acid Rain compliance that went into effect in January 1995. This
was because of the flexibility the utilities had for complying with Phase I
regulation including switching to low-sulfur coal, purchasing SO2 allowances,
and coal blending. Productivity increases and intense competition from Powder
River Basin and Northern Appalachia coals are key factors that have prevented
the price for Central Appalachian coal from increasing.
79
<PAGE>
EXHIBIT 4-29
HISTORICAL CENTRAL APPALACHIAN COAL PRICE TREND
A Line graph illustrating price trend by year for the years 1988-1999
[GRAPH]
A Rail Cost Adjustment Factor - adjusted for productivity (RCAF) is the
best measure of rail costs; it has been declining in recent years. In contrast,
general inflation has continued. We forecast a 2% decrease in real rail costs.
We also assume that coal on coal competition will continue in the Wyoming PRB
and that rail on rail competition will continue between Union Pacific and
Burlington Northern railroads. This does not directly affect PJM coal that is
mostly from Appalachia, but indirectly puts downward price pressure on Central
Appalachia minemouth coal prices.
80
<PAGE>
EXHIBIT 4-30
RAIL TRANSPORTATION COSTS - RAIL DEREGULATION AND COMPETITION
A Line graph illustrating Rail transportation cost by fiscal year
[GRAPH]
The most important coal types in PJM and NYPP are Central Pennsylvania mid
sulfur coal, Monongahela "Bailey type" coal (1.5% sulfur), and Southern West
Virginia/East Kentucky compliance coal in Eastern PJM. Price projections for
these coals are provided in Exhibit 4-31.
81
<PAGE>
EXHIBIT 4-31
REPRESENTATIVE COAL PRICES - MINEMOUTH (1998$/TON)
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
COAL TYPE AVERAGE ANNUAL PRICE (1998$/TON)
----------------------------------------------------------------------------------------------------------
<S> <C>
CENTRAL PA (1.5-2.0% SULFUR, 12,500 Btu/LB)
2002 22.43
2005 22.54
2010 22.31
2015 22.07
2020 21.85
----------------------------------------------------------------------------------------------------------
WESTERN PA HIGH SULFUR (2.0-3.0% SULFUR, 12,500 Btu/LB)
2002 20.72
2005 20.06
2010 19.85
2015 19.64
2020 19.44
----------------------------------------------------------------------------------------------------------
WESTERN PA (MONONGAHELA) MID SULFUR (1.25-1.5% SULFUR, 13,00 Btu/LB)
2002 24.02
2005 23.26
2010 23.01
2015 22.39
2020 21.80
----------------------------------------------------------------------------------------------------------
CENTRAL APPALACHIA (0.7% SULFUR, 12,000 Btu/LB)
2002 24.41
2005 23.98
2010 23.49
2015 22.52
2020 20.58
----------------------------------------------------------------------------------------------------------
</TABLE>
We assume declining coal prices in real terms due to continued improvements
in productivity such that prices are relatively unchanged on a nominal basis.
This analysis also assumes that coal markets remain as competitive as they are
at present, which is a likely outcome, but not the only outcome. Transportation
prices are derived also assuming continued competition. We project
transportation prices to decline at a rate of 2 percent per annum in real terms.
In a competitive market, coal purchased under long term contracts at above
market prices cannot be intentionally recovered. As such, we expect that when
plant owners operate and bid, they will price coal at current market conditions.
ENVIRONMENTAL COMPLIANCE
SO(2)
This analysis incorporates the effects of federal acid rain SO(2)
controls - i.e., Title IV of the Clean Air Act. Title IV of the Clean Air Act
sets as its primary goal the reduction of annual SO(2) emissions by 10 million
tons below 1980 levels. To achieve these reductions, the law
82
<PAGE>
requires a two-phase tightening of the restrictions placed on fossil fuel-fired
power plants. Phase II, which begins in the year 2000, tightens the annual
emissions limits imposed on large, higher emitting plants and also sets
restrictions on smaller, cleaner plants fired by coal, oil, and gas,
encompassing over 2,000 units in all. The program affects existing utility units
serving generators with an output capacity of greater than 25 megawatts and all
new utility units.
EXHIBIT 4-32
HISTORICAL SO(2) ALLOWANCE PRICES
A Line graph showing Historical SO(2) Allowance Prices By Year for the
years 1994-1999
[GRAPH]
Phase I and Phase II allowance prices have risen sharply in the past year
in anticipation of Phase II implementation. According to the emissions allowance
tracking index released by the CLEAN AIR COMPLIANCE REVIEW, prices have moved
from the $100/ton range late in 1997 to a high of more than $200/ton in August
this year. Currently the price of SO(2) allowances is trading at approximately
$180/ton.
Allowance prices over the long-term will be based on the marginal cost of
reductions in SO(2) emissions in a national marketplace. We project an allowance
price of $218/ton (in real 1998$) in 2000 in the Base Case with significant real
price escalation through 2015.
83
<PAGE>
NO(x) OTR
Another important regulation that we incorporate into our is the Ozone
Transport Commission (OTC) NO(x) Budget Program. We project OTR NO(x)
allowance prices will be in the $1,000 to $1,500/ton range in the near-term,
and are expected to rise in real terms thereafter due to increasing demand
and the exhaustion of low-cost compliance options.
EXHIBIT 4-33
NO(x) POLICY REGIONS
A map of the eastern United States illustrating NO(x) Policy Region
[MAP]
POST COMBUSTION NO(x) CONTROLS
Post-combustion controls for NO(x) can be used on both coal and oil/gas
units. The capital cost for post-combustion control technology range from a
low of $9.60/kW for coal cyclone boilers with high NO(x) emission rates using
SNCR to a high of $71.8/kW for coal boilers with low NO(x) emission rates
applying SCR technology.
84
<PAGE>
EXHIBIT 4-34
POST COMBUSTION NO(x) CONTROLS FOR COAL PLANTS (1998$)
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
POST-COMBUSTION CONTROL TECHNOLOGY CAPITAL FIXED O&M VARIABLE O&M PERCENT GAS PERCENT
($/kW) ($/kW/YR) (MILLS/kWh) USE REMOVAL
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SCR 70.5 6.20 0.25 -- 70%
(Low NO(x) Rate)
--------------------------------------------------------------------------------------------------------------
SCR 72.7 6.45 0.40 80%
(High NO(x) Rate)
--------------------------------------------------------------------------------------------------------------
SNCR 16.8 0.25 0.83 40%
(Low NO(x) Rate)
--------------------------------------------------------------------------------------------------------------
SNCR 9.7 0.14 1.28 35%
(High NO(x) Rate - Cyclone)
--------------------------------------------------------------------------------------------------------------
SNCR 19.2 0.29 0.89 35%
(High NO(x) Rate - Other)
--------------------------------------------------------------------------------------------------------------
Natural Gas Reburn 32.8 0.50 -- 16% 40%
(Low NO(x))
--------------------------------------------------------------------------------------------------------------
Natural Gas Reburn 32.8 0.50 -- 16% 50%
(High NO(x))
--------------------------------------------------------------------------------------------------------------
</TABLE>
Source: "Analyzing Electric Power Generation Under the CAAA", Office of Air and
Radiation, US EPA, March 1998.
EXHIBIT 4-35
POST-COMBUSTION NO(x) CONTROLS FOR EXISTING OIL/GAS STEAM BOILERS
AND NEW COMBINED-CYCLE (1998$)
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
POST-COMBUSTION CONTROL TECHNOLOGY CAPITAL ($/kW) FIXED O&M VARIABLE O&M PERCENT
($/kW/YR) (MILLS/kWh) REMOVAL
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
SCR 28.4 0.88 0.1 60%
--------------------------------------------------------------------------------------------------------------
SNCR 9.5 0.15 0.44 50%
--------------------------------------------------------------------------------------------------------------
Gas Reburn 20.0 0.30 0.03 50%
--------------------------------------------------------------------------------------------------------------
</TABLE>
These cost estimates were taken from EPA and tend to be mid-range estimates
for both cost and performance. In the SIP Call debate, mid-west utilities have
offered NO(x) pollution control cost estimates significantly higher than EPA's
estimates. In contrast, pollution control equipment vendors have provided much
lower cost estimates.
OTHER ENVIRONMENTAL REGULATIONS
In addition to the Ozone Transport Region rules applicable in the
Northeast, EPA finalized its Ozone Transport rulemaking on September 24, 1998.
Under this so-called "SIP Call" rule, EPA intends to establish a NO(x) emissions
trading system for 22 eastern states and the District of Columbia. The SIP Call
emission limits are tied to a 0.15 lb/MMBtu emission rate and will yield an
emissions cap approximately equal to the Phase III level for OTR states. To
date, EPA has not specified how the overlapping OTR and SIP Call NO(x) emission
programs will interact.
No analysis in this report incorporates the SIP Call rule in part because
it will likely be challenged in court by electric utilities, coal producers, and
other parties. However, if implemented, it will likely raise the power prices
even more than NO(x) OTR regulations in the summer and increase the value of new
gas plant relative to levels estimated herein.
85
<PAGE>
Other regulations not incorporated in our Base Case are possible. Tightened
SO(2) regulations (e.g., tightened PM (particulate) standards, visibility
initiatives, legislative action) could raise allowance prices but our case
already incorporates a dramatic turnaround in SO(2) allowance prices, which if
true, may tend to mitigate the potential for these controls.
The largest impact and the least likely over the next decade are
significant and binding CO(2) regulations. Kyoto notwithstanding, we have not
incorporated CO(2) controls in our post-2010 analysis. However, if stringent
CO(2) controls are implemented, it could greatly affect fuel use patterns in
favor of gas over coal even at existing plants, raise gas prices above
forecast levels, and have other major power price consequences.
NUCLEAR PERFORMANCE AND RETIREMENTS
Nuclear capacity currently accounts for about 23 percent of utility
capacity in PJM and in 1996, about 34 percent of total generation. The
performance, i.e., output or availability of PJM's nuclear facilities has varied
over the last decade. However, capacity factors were much lower in 1996 and 1997
due to extended outages at Salem 1 and 2. Salem units 1 and 2 were removed from
the NRC watch list (category 3) in July 1998.
EXHIBIT 4-36
U.S. HISTORICAL NUCLEAR CAPACITY FACTOR
A Line graph showing nuclear capacity by year
[GRAPH]
The adjusted average between 1991 and 1998 varies between 77 and 83 percent
in the PJM sub-regions. Deregulation provides incentives for plant operators to
increase availability.
86
<PAGE>
For this reason, ICF projects future nuclear performance at levels consistent
with recent historical levels, net extended outages.
PJM's nuclear facilities performance (with the exception of Salem 1 and 2)
has been very strong during the 1990s, especially when compared to that of the
mid-to-late 1980s. ICF projects that the efficient operation and strong
performance will continue in the future. Capacity factors are expected to
average in the high 70s and low 80s throughout the long term.
EXHIBIT 4-37
PJM NUCLEAR POWER PLANT CAPACITY FACTORS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------
PJM EAST(2) PJM WEST(1) PJM SOUTH(1)
------------------------------------------------------------------------------
<S> <C> <C> <C>
Base Case(1) 77%(2) 83% 81%
------------------------------------------------------------------------------
Historical 1991 - 1997 77% 83% 81%
------------------------------------------------------------------------------
</TABLE>
(1)Base Case figures based on the average of capacity factors for the years 1991
- 1998.
(2)For PJM East we do not take into account capacity factor for Salem for years
in which it had outage for a period greater than 6 months.
Generally, we model nuclear plants as retiring at the end of their 40-year
operating license. However, several plants have retired prior to the termination
of their license for poor performance or safety reasons. For the Base Case, we
assume that all plants retire at the end of the expiration of their 40-year
nuclear licenses, with the exception of the following plants, which will retire
immediately: Maine Yankee, Connecticut Yankee, and Millstone 1.
87
<PAGE>
EXHIBIT 4-38
PJM NUCLEAR UNIT CHARACTERISTICS
<TABLE>
<CAPTION>
------------------------------------ ------------------------ ------------------------ ------------------------
Unit Region Retirement Year Capacity (MW)
------------------------------------ ------------------------ ------------------------ ------------------------
<S> <C> <C> <C>
Oyster Creek PJM East 2010 619
------------------------------------ ------------------------ ------------------------ ------------------------
Salem 1 PJM East 2016 1,106
------------------------------------ ------------------------ ------------------------ ------------------------
Salem 2 PJM East 2021 1,106
------------------------------------ ------------------------ ------------------------ ------------------------
Hope Creek 1 PJM East 2026 1,031
------------------------------------ ------------------------ ------------------------ ------------------------
Limerick 1 PJM East 2024 1,105
------------------------------------ ------------------------ ------------------------ ------------------------
Limerick 2 PJM East 2029 1,115
------------------------------------ ------------------------ ------------------------ ------------------------
Peach Bottom 2 PJM West 2013 1,093
------------------------------------ ------------------------ ------------------------ ------------------------
Peach Bottom 3 PJM West 2014 1,093
------------------------------------ ------------------------ ------------------------ ------------------------
Three Mile Island PJM West 2014 786
------------------------------------ ------------------------ ------------------------ ------------------------
Susquehanna 1 PJM West 2022 1,090
------------------------------------ ------------------------ ------------------------ ------------------------
Susquehanna 2 PJM West 2024 1,094
------------------------------------ ------------------------ ------------------------ ------------------------
Calvert Cliffs 1 PJM South 2014 835
------------------------------------ ------------------------ ------------------------ ------------------------
Calvert Cliffs 2 PJM South 2016 840
------------------------------------ ------------------------ ------------------------ ------------------------
</TABLE>
In the short run, unexpected early retirements could lead to high
prices but in the longer-run, they could decrease prices. This is because
combined cycles with higher availabilities increase the total amount of low-cost
infra-marginal supply.
In our analysis, we have considered the option to economically retire
early (before license expiration) if the unit cannot cover its fixed costs. This
is determined endogenously within the model in part through an evaluation of the
potential future revenues stream for each plant - i.e., the criteria is net
present value being negative leads to retirement. This increases the ability of
the grid to absorb new builds and does not allow for price spikes if the
retirement decision is unexpected. The short-run variable cost of nuclear power
(i.e., fuel) is low (approximately 5 to 8 mills/kWh). Nuclear power's low
variable cost coupled with the high cost of shutting down and restarting a
nuclear reactor, means that PJM's nuclear plants generally will be fully
utilized when available. Further, these units can earn substantial energy sales
profits. On the other hand, historical fixed O&M expenses of nuclear plants in
PJM are very high, between $85 and $160/kW/yr (1998$), on average 35 percent
higher than the national average for similar units. High fixed costs combined
with unpredictable availability could lead to early economic retirements in a
deregulated market.
GENERAL UNIT CHARACTERISTICS
Coal and oil/gas steam units are expected to attain an average annual
availability of 85%. Steam units are restricted in their cycling via minimum
turndown requirements.
As shown in Exhibit 4-44, variable non-fuel O&M varies. Generally,
scrubbed coal units cost $1.0/MWh more to operate than unscrubbed units and
approximately $1.5/MWh more than oil- and gas-fired units. All units used for
peak cycling incur an additional cost associated with quick start-up.
88
<PAGE>
EXHIBIT 4-39
VARIABLE O&M AND TURNDOWN ASSUMPTIONS
<TABLE>
<CAPTION>
-------------------------------- ---------------------------- ----------------------------
UNIT TYPE VARIABLE O&M MINIMUM TURNDOWN
(1998$/MWh)(1) (%)
-------------------------------- ---------------------------- ----------------------------
<S> <C> <C>
Coal
-------------------------------- ---------------------------- ----------------------------
Scrubbed 2.1 - 5.1 40 (average)
-------------------------------- ---------------------------- ----------------------------
Unscrubbed 1.0 - 4.1 40 (average)
-------------------------------- ---------------------------- ----------------------------
Oil/Gas Steam 0.5 - 8.2 20 (average)
-------------------------------- ---------------------------- ----------------------------
Combined Cycles 0.5 - 5.2 35 (average)
-------------------------------- ---------------------------- ----------------------------
Combustion Turbines 0.2 - 6.0 0
-------------------------------- ---------------------------- ----------------------------
Nuclear 1.0 0
-------------------------------- ---------------------------- ----------------------------
Hydro 0.0 Varies
-------------------------------- ---------------------------- ----------------------------
Pumped Storage 0.0 0
-------------------------------- ---------------------------- ----------------------------
</TABLE>
(1) Including startup/cycling costs for oil/gas steam units, Non-Fuel variable
O&M is an inverse function of the capacity factor
OIL/GAS STEAM PLANT RETIREMENTS
Most oil/gas steam units have an economic retirement option specified
in the ICF model. On net, if the future stream of profits earned from energy and
capacity sales are not sufficient to cover the fixed costs of these units, the
model will choose to retire them. Note, this is similar to treatment of nuclear
units.
NUGs
PJM has a moderately high amount of NUG capacity compared to the
national average.
89
<PAGE>
EXHIBIT 4-40
PJM NUG CAPACITY
<TABLE>
<CAPTION>
------------------------------------------ ------------------ ------------------ ------------------ ------------------
PJM WEST PJM EAST PJM SOUTH TOTAL
------------------------------------------ ------------------ ------------------ ------------------ ------------------
<S> <C> <C> <C> <C>
NUG Capacity (MW)
Gas-Fired 341 2,188 116 2,645
Coal-Fired 337 341 67 745
Other(1) 731 741 146 1,618
Total 1,409 3,270 329 5,008
------------------------------------------ ------------------ ------------------ ------------------ ------------------
Dispatchable NUG Capacity (MW)
1998 - 2000 364 695 53 1,112
2005 1,093 2,374 243 3,716
2010 1,458 3,213 337 5,008
------------------------------------------ ------------------ ------------------ ------------------ ------------------
Average Heat Rate of Dispatchable NUGs
in 2000(2) 6,200 6,700 5,600 6,500
------------------------------------------ ------------------ ------------------ ------------------ ------------------
</TABLE>
(1) Coal, oil and non-purchased fuel like blast furnace gas, refinery gas, etc.
(2) Soutce: ICF proprietary Cogen set, etc.
Approximately 10 percent of the generating capability in PJM in NUG
capacity, about 60 percent of which is located in PJM East. We anticipate that
all natural gas-fired NUG capacity, approximately 50 percent, will gradually
become dispatchable by 2010 as existing contracts will expire.
LOAD GROWTH AND RESERVE MARGINS
EXHIBIT 4-41
PJM ELECTRICITY DEMAND AND RESERVE MARGIN ASSUMPTIONS
<TABLE>
<CAPTION>
------------------------------------------------------------- --------------------
PARAMETER TREATMENT
------------------------------------------------------------- --------------------
<S> <C>
1999 Net Energy for Load(1) (GWh) 254,232
Annual Energy Growth 2000 - 2030 (%) 2.0%
------------------------------------------------------------- --------------------
1999 Weather Normalized Net Peak Demand(2) (GW) 47.6
Annual Peak Growth 2000 - 2030 (%) 2.0%
------------------------------------------------------------- --------------------
Planning Reserve Margin (%)(3)
2000 19.5
2003 19.0
2010 15.0
2020 15.0
------------------------------------------------------------- --------------------
</TABLE>
(1) Grown from actual 1998 net energy requirements
(2) Reflects weather normalized summer peak demand for 1999 adjusted for
interruptible load.
(3) Reserve Margin from 2000 to 2003 taken from Obligation Reserves set by the
Reliability Committee in April '99. Deescalates to 15% between 2003 and 2010.
90
<PAGE>
EXHIBIT 4-42
PJM HISTORICAL PEAK DEMAND AND ENERGY GROWTH RATES
<TABLE>
<CAPTION>
--------------------- -------------- ----------------- ------------- -------------------- ----------------
PEAK PEAK ANNUAL ENERGY ANNUAL INTERRUPTIBLE
YEAR DEMAND(1) GROWTH RATE ENERGY(1) GROWTH RATE LOAD(2)
(MW) (%) (GWh) (%) (GW)
--------------------- -------------- ----------------- ------------- -------------------- ----------------
<S> <C> <C> <C> <C> <C>
1999 51,550 +6.5 N/A N/A N/A
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1998 48,397 -2.0 249,247 +2.3 2,298
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1997 49,406 +11.5 243,649 +0.1 2,239
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1996 44,302 -8.7 243,328 +0.2 2,014
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1995 48,524 +5.5 242,797 +2.0 1,970
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1994 45,992 -0.9 238,061 +1.0 1,845
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1993 46,429 +6.4 235,664 +4.3 1,571
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1992 43,622 -4.9 225,906 -1.0 1,449
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1991 45,870 +7.8 228,236 +3.4 1,388
--------------------- -------------- ----------------- ------------- -------------------- ----------------
1990 42,544 +2.4 220,772 -1.3 1,184
--------------------- -------------- ----------------- ------------- -------------------- ----------------
</TABLE>
(1) Source: PJM-ISO
(2) Source: NERC ES&D; includes interruptible direct control load management.
HISTORICAL PEAK DEMAND AND ENERGY GROWTH RATES IN PJM
<TABLE>
<CAPTION>
------------------------------------ ---------------------------------- ----------------------------------
YEAR PEAK ANNUAL GROWTH RATE ENERGY ANNUAL GROWTH
(%) RATE (%)
----------------------------------------------------------------------------------------------------------
<S> <C> <C>
Historical Annual Average Growth Rates (%)
----------------------------------------------------------------------------------------------------------
10 Year Averages
------------------------------------ ---------------------------------- ----------------------------------
1989 - 1998 1.4 1.3
------------------------------------ ---------------------------------- ----------------------------------
1988 - 1997 2.2 1.7
------------------------------------ ---------------------------------- ----------------------------------
1987 - 1996 1.8 2.2
------------------------------------ ---------------------------------- ----------------------------------
1986 - 1995 2.8 2.5
------------------------------------ ---------------------------------- ----------------------------------
1985 - 1994 2.8 2.6
------------------------------------ ---------------------------------- ----------------------------------
1976 - 1998 Rolling 2.9 2.7
Average
------------------------------------ ---------------------------------- ----------------------------------
(5) Year Average
------------------------------------ ---------------------------------- ----------------------------------
1993 - 1998 1.1 1.1
------------------------------------ ---------------------------------- ----------------------------------
1992 - 1997 2.8 1.5
------------------------------------ ---------------------------------- ----------------------------------
1991 - 1996 -0.5 1.3
------------------------------------ ---------------------------------- ----------------------------------
1990 - 1995 2.8 1.9
------------------------------------ ---------------------------------- ----------------------------------
1989 - 1994 2.2 1.3
------------------------------------ ---------------------------------- ----------------------------------
1976 - 1998 Rolling
Average 3.1 2.8
----------------------------------------------------------------------------------------------------------
</TABLE>
(1) Source: PJM-ISO
(2) Source: NERC ES&D; includes interruptible direct control load management.
PJM LOAD GROWTH
The impact of high demand growth in the near term would be to
accelerate the transition from coal to gas on the margin, thus increasing
electrical energy prices. Conversely, lower demand growth would slow this
transition. The impact of high demand growth would however generally be in the
form of lower electrical energy prices in the longer term, as more builds
including more combined cycles would be built in response. Combined cycles
generally act to depress prices due to their high efficiencies. Conversely, the
impact of low demand growth tends to be slightly higher prices in the long run
as fewer combined cycles are built. The rolling ten-year average since 1980 is
approximately 2.4 percent for both peak and energy. The ten-year
91
<PAGE>
averages have been relatively stable except in the last two to three years.
Region-wide load growth forecasts, based on individual member filings,
anticipate much lower demand growth rates through 2005 (approximately 1.6
percent annually).
Our peak demand level for 1999 reflects a weather normalized forecast.
This level of approximately 47.6 GW is considerably lower than the peak demand
actually observed thus far in 1999 (51.5 GW). This discrepancy can be explained
by extreme weather conditions experienced this summer. PJM utilizes a Weighted
Temperature Humidity Index (WTHI) of 83.3 as a basis for its weather normalized
peak index forecasts. During the summer peak on July 6, 1999, the WTHI was 85.3.
This deviation is reflective of a 1 in 20 occurrence. Consequently, we utilize
the weather normalized value as our basis. Our modeling assumption is that loads
will grow at a rate lower than recent historical growth rates. It is an average
of the long-term historical growth rates and the NERC forecasts.
Our base case modeling assumption is that loads will grow at a rate
lower than recent historical growth rates. It is an average of the long-term
historical growth rates and the NERC forecasts. Our Base Case forecast is for
long-term annual average peak demand growth of 2.0 percent in PJM for the period
1999-2030. Our forecast for energy requirements is consistent.
PJM PLANNING RESERVE MARGIN
Operating reserves which are different from planning reserves cannot be
avoided without jeopardizing the grid's stability. However, planning reserve
margins combined with peak load growth determine the demand for megawatts. Note,
this is because capacity demand and import availability are uncertain and more
reserves are needed to ensure availability operating reserves. The market or the
industry can set total reserve levels even though only the industry can set
operating reserves.
EXHIBIT 4-43
PEAK OPERATING RESERVES - ILLUSTRATIVE
<TABLE>
<CAPTION>
------------------------------------------------------- -------------------------- --------------------------
CATEGORY GW IMPLIED RESERVE
MARGIN
------------------------------------------------------- -------------------------- --------------------------
<S> <C> <C>
Expected Peak 10.3 3
------------------------------------------------------- -------------------------- --------------------------
Less Interruptible 0.3 --
------------------------------------------------------- -------------------------- --------------------------
Net Expected Peak 10.0 0
------------------------------------------------------- -------------------------- --------------------------
Plus Operating Reserves 10.5 5
------------------------------------------------------- -------------------------- --------------------------
Plus Expected Plant Outages 11.4 14
------------------------------------------------------- -------------------------- --------------------------
Plus Above Average Outage 11.7 17
------------------------------------------------------- -------------------------- --------------------------
Plus Higher than Average Demand 12.5 25
------------------------------------------------------- -------------------------- --------------------------
Less Imports ? ?
------------------------------------------------------- -------------------------- --------------------------
</TABLE>
Generally, a lower reserve margin results in fewer capacity additions.
Conversely, a higher reserve margin would result in greater capacity additions.
As capacity additions in PJM can comprise of combined cycles (especially in the
medium- and long-term), greater additions resulting from a higher reserve margin
to depress energy prices somewhat. Conversely, a lower reserve margin tends to
increase energy prices as less combined cycles are built and in any given hour
there is a greater chance that inexpensive units will be required to meet
demand.
92
<PAGE>
Currently, the PJM Reliability Committee has established a 20% reserve
margin for the 1999/2000 planning period, 19.5% for the 2000/2001 planning
period, and 19% for the 2001-2002 planning period. We anticipate that this
reserve level will tend down to 15 percent by 2010, consistent with the general
national trend of decreasing reserve margins. The trend of decreasing reserve
margins may be attributable to a number of factors, including increasing unit
availabilities and lower outages. Utilities are less willing to build and
regulators are less willing to authorize new builds. Additionally, there may
also be willingness on part of some customers to accept lower reliability.
Note, PJM may eventually eliminate the planning reserve margin and
separate capacity markets. However, we believe the 15 percent is consistent with
the reserves that would result from market forces. Further, the elimination of
the requirement would not change the equilibrium total revenues to plants but
could shift revenues between products, e.g., from capacity to energy.
NEW POWER PLANT CHARACTERISTICS
New power plant characteristics drive decisions on the mix of new
builds, affecting both energy and capacity prices. Note, all these parameters
are dynamically and endogenously determined. Heat rates have been decreasing
over time, the Base Case assumptions with respect to combined cycle and
combustion turbine units reflect this trend. With the exception of the recent
tight market, capital costs of new gas plants have also been falling in real
terms. We expect this to eventually resume. Thus, technological improvement is
assumed to be enough in the long term to lower both cost and heat rates.
We assume that there is some variation in capital costs across the
U.S., due to variation primarily in site labor and site material costs. The
Northeast (New England and New York) and California generally have higher costs,
and Southern TVA, and Florida typically have lower than the U.S. average.(4)
PJM's costs are approximately the same as the U.S. average.
--------
(4) Our estimates for the regions are partially derived from AEO 1999 regional
multipliers. This assumes a breakdown of total EPC costs as follows: 65%
factory equipment, 20% site labor, and 15% site materials.
93
<PAGE>
EXHIBIT 4-44
PJM NEW POWER PLANT CHARACTERISTICS (1998$)
<TABLE>
<CAPTION>
---------------------------------------- -----------------------------------------------------------------------------
PARAMETER TREATMENT
---------------------------------------- -------------------------------------- --------------------------------------
NEW COMBINED CYCLES NEW COMBUSTION TURBINES
---------------------------------------- -------------------------------------- --------------------------------------
<S> <C> <C>
Capital Cost ($/kW)
2002 583 368
2005 583 368
2010 555 350
2015 529 333
2020 503 317
2025 503 317
2030 503 317
Levelized(1) 2002 - 2030 562 357
---------------------------------------- -------------------------------------- --------------------------------------
Fixed O&M ($/kW/yr) 16.0 9.8
Non-Fuel Variable O&M ($/MWh) 1.1(1) 2.3(2)
---------------------------------------- -------------------------------------- --------------------------------------
Heat Rate (Btu/kWh)
2002 6,928 10,905
2005 6,753 10,671
2010 6,583 10,443
2015 6,417 10,219
2020 6,255 10,000
2025 6,097 10,000
2030 6,000 10,000
Levelized 2002 - 2030 6,657 10,556
---------------------------------------- -------------------------------------- --------------------------------------
Availability (%) 92 92
---------------------------------------- -------------------------------------- --------------------------------------
</TABLE>
(1) Corresponds to 80 percent capacity factor.
(2) Corresponds to 15 percent capacity factor.
We allow the model to optimize over the market analysis period, the
selection of new units based on the economics of these new units and the overall
system. However, we do restrict this selection in the near-term as a typical
combined cycle unit requires a lead-time of two or more years prior to coming
on-line. Given the longer lead-time required for a combined cycle versus a
combustion turbine unit, we assume that a limited number of new combined cycle
units are possible before 2001. Exhibit 4-45 shows the model restrictions placed
on unplanned builds.
EXHIBIT 4-45
UNPLANNED BUILD RESTRICTIONS
<TABLE>
<CAPTION>
----------------- ------------------------------------------ -----------------------------------------
YEAR COMBUSTION TURBINE RESTRICTION COMBINED CYCLE RESTRICTION
----------------- ------------------------------------------ -----------------------------------------
<S> <C> <C>
2001 No Yes (Only those under construction)
----------------- ------------------------------------------ -----------------------------------------
Post 2001 No No
----------------- ------------------------------------------ -----------------------------------------
</TABLE>
94
<PAGE>
EXHIBIT 4-46
PJM ANNOUNCED CAPACITY (AS OF AUGUST 5, 1999)
A table illustrating capacity as of August 1999
[PICTURE]
95
<PAGE>
New capacity assumptions reflect the likelihood that additional
capacity will be on-line in the near-term. Thus, although there are many
announced projects in PJM, we have considered only a portion as available for
modeling purposes. The decision to include a unit in the Base Case is based on
whether or not construction is underway or close to being underway. We emphasize
the extent to which plants are actually under construction in part because the
model often builds additional capacity based on economic criteria. The above
table summarizes which units are included in the model. We have included a total
of 1,074 MW of firm capacity coming on-line by 2001 in the model.
The above table includes announced builds as of beginning of November
1999.
FINANCING OF NEW POWER PLANTS
A major source of uncertainty with respect to new power plant
characteristics is the financing structure of merchant power plants. The Base
Case incorporates a 50 percent debt and 50 percent equity financing, a nominal
after-tax rate of return on equity of 14 percent, and an interest rate on debt
of 9 percent, resulting in a levelized, real annual capital charge rate of 12.9
percent in PJM West, 12.7% in PJM East, and 13.5% in PJM South. Exhibit 4-47
summarizes the derivation of the annual real fixed charge rate.
EXHIBIT 4-47
CALCULATION OF THE ANNUAL REAL FIXED CHARGE RATE (ARFCR)
<TABLE>
<CAPTION>
----------------------------------------------------------------------- -------------- --------------- ---------------
PJM WEST PJM EAST PJM SOUTH
----------------------------------------------------------------------- -------------- --------------- ---------------
<S> <C> <C> <C>
INPUT ASSUMPTIONS
----------------------------------------------------------------------- -------------- --------------- ---------------
Debt Life (years) 15
----------------------------------------------------------------------- -------------- --------------- ---------------
Book Life (years) 23
----------------------------------------------------------------------- -------------- --------------- ---------------
After Tax Equity Rate (%) 14.0
----------------------------------------------------------------------- -------------- --------------- ---------------
Equity Ratio (%) 50.0
----------------------------------------------------------------------- -------------- --------------- ---------------
Nominal Debt Rate (%) 8.5
----------------------------------------------------------------------- -------------- --------------- ---------------
Debt Ratio (%) 50.0
----------------------------------------------------------------------- -------------- --------------- ---------------
Income Tax Rate (%) 41.3
----------------------------------------------------------------------- -------------- --------------- ---------------
Inflation (%) 3.0
----------------------------------------------------------------------- -------------- --------------- ---------------
Other Taxes/Insurance (%) 0.7 0.5 1.5
----------------------------------------------------------------------- -------------- --------------- ---------------
OUTPUT
----------------------------------------------------------------------- -------------- --------------- ---------------
Nominal Weighted Average After Tax Cost of Capital 9.5
----------------------------------------------------------------------- -------------- --------------- ---------------
Real Weighted Average After Tax Cost of Capital 6.3
----------------------------------------------------------------------- -------------- --------------- ---------------
Levelized Real Fixed Charge Rate (%) 12.9 12.8 13.5
----------------------------------------------------------------------- -------------- --------------- ---------------
</TABLE>
Based on our research we have found no property tax in New Jersey and
an annuity tax rate of 1.2% in Maryland and 2% in Pennsylvania. In Pennsylvania,
property tax is levied only on land and building and not on the machinery.
Assuming this constitutes about 20 percent of total cost, we use a property tax
rate of 0.4 percent for Pennsylvania in the capital charge rate computation. We
found no such exemption for machinery in Maryland.
We focus on the financing structure for marginal megawatts available in
the spot market in a given year, i.e., spot merchant megawatts. This is a risky
business relative to past power practices, and hence, there is little power
industry history that is relevant. Even the recent "merchant" deals have large
non-merchant components. Thus, it is as if the most relevant deals are the
combination of two separate but hidden deals: (1) pure merchant or spot portion,
and (2) the non-merchant or PPA portion. Our price forecast is for spot
transactions. The marginal
96
<PAGE>
megawatt in this market is the pure merchant spot megawatt. Thus, the relevant
analogy is not readily apparent even from current deals. We propose using, as an
analogy, a financing loosely based on average U.S. industrial conditions, i.e.,
not based on the power industry, but overall industry conditions.
EXHIBIT 4-48
MERCHANT POWER PLANTS AND U.S. INDUSTRIAL NORMS
<TABLE>
<CAPTION>
------------------------------------------------------------ ---------------------------------------------------------
PARAMETER 1985 - 1995
------------------------------------------------------------ ---------------------------------------------------------
<S> <C>
30 Year Treasuries 8.0%
------------------------------------------------------------ ---------------------------------------------------------
Corporate Bonds 9.3%
------------------------------------------------------------ ---------------------------------------------------------
Inflation 3.4%
------------------------------------------------------------ ---------------------------------------------------------
Debt Share 40%(1),(2)
------------------------------------------------------------ ---------------------------------------------------------
After Tax Return on Equity 12(1)
------------------------------------------------------------ ---------------------------------------------------------
</TABLE>
(1) 1990 - 1995 average.
(2) 40 percent is a reasonable estimate even to the extent it does not include
non-recourse debt; this amounts to about one percent of total investment in the
U.S. Sources are for U.S. business investment Census Bureau, Annual Capital
Expenditures Survey; project finance/non-recourse debt, Project Finance
International. Note, U.S. utilities report debt share of 45 percent, higher than
U.S. average. Further, in 1996 and 1997, 19 and 12 percent of total U.S. power
investment (generation and T&D) was non-recourse, respectively.
Source: Standard & Poor's Analyst Handbook, 1996. S&P Industrials contains 400
companies in 17 industrial groups.
TRANSMISSION
TRANSMISSION WITHIN PJM
The utilities within the PJM system are interconnected via a high
voltage system made up of 500 kV and smaller lines. Due to internal transmission
constraints, PJM is modeled as three subregions -- East, West and South. We
additionally model Homer City separately due to its unique position as part of
both PJM and NYPP. Transmission capabilities between the subregions are shown in
Exhibit 4-49. Note, just as PJM's LMP system results in price differences when
intra-PJM lines are constrained, our model also calculates prices in each PJM
region.
EXHIBIT 4-49
PJM INTRA-REGIONAL TRANSMISSION (GW)
[GRAPH] A MAP OF PENNSYLVANIA SHOWING TRANSMISSION BY REGION
97
<PAGE>
INTER-REGIONAL TRANSMISSION
Transfer capacity between regions is dynamic and varies significantly
on an hourly, daily, and seasonal basis depending on many factors, including
base transfer levels (primarily associated with firm power contracts), as well
as unit and transmission system performance.
Exhibit 4-50 summarizes the total transfer capability among the major
power markets in the Northeast, Middle-Atlantic, and eastern mid-west regions.
Available transmission capacity leaving PJM is about 9.0 GW and entering is
about 7.5 GW. Export capability is roughly 20 percent of PJM's system peak load.
Major links exists with the three surrounding regions of ECAR, NYPP,
and VACAR. The most interesting of these interconnections is with ECAR.
Historically, PJM has been a net importer of low cost coal power from ECAR.
However, the June 1998 capacity crisis situation in the Midwest reversed this
situation and PJM has recently become a power exporter to ECAR.
EXHIBIT 4-50
TOTAL TRANSFER CAPABILITY (MW)
[GRAPH]
A Map of New England, New York, Ontario, Pennsylvania, North Carolina,
South Carolina and Virginia showing transferability regions.
Our current approach is to take a simple average of reported power
transmission limits.(5)
Furthermore, in our analysis, we assume no major large new
inter-regional or inter-subregional lines are added. This reflects: (i) the high
costs of power lines relative to natural gas pipelines; (ii) increasing
construction of new gas power plants decreasing price differentials between
regions and decreasing economic incentives for lines; (iii) inability of
thyristor and
--------------------------
(5) Our model is not a load flow model. Rather, the model takes limits as
exogenous and simulates inter-regional economic flows simultaneously with
dispatch, and capacity expansion.
98
<PAGE>
other technologies to inexpensively upgrade lines beyond the 10 percent
discussed above; and (iv) difficulties in siting and environmental approvals.
EXHIBIT 4-51
HISTORICAL TOTAL TRANSFER CAPABILITY (MW)
[GRAPH]
A map of Ontario, New England, Pennsylvania, New York State, North
Carolina, South Carolina and Virginia showing transfer regions.
TRANSMISSION PRICING
We do not include transmission charges in a given region since we are
focused on the generation market and transmission charges are an add-on paid by
customers. For example, customers in PJM East might pay $32/MWh but we calculate
only the $30/MWh received by generators. However, it is necessary to account for
the added charges faced by inter-regional flows. The key is to distinguish
between three types of inter-regional transmission charges:
- Losses which are a minimum
- Congestion-derived locational price differences
- Transmission charges which act as a floor propping up prices
above a competitive outcome (a competitive outcome would
include the first two charges only.)
We typically apply the first two charges, the competitive charges, to
within-ISO or within-likely-future-potential ISO movements and the last charge
is used as a floor for between-ISO movements.
Currently, PJM has the only Locational Marginal Pricing (LMP) system
currently providing hourly prices for 1,744 nodes. The LMP algorithm is
compatible with our linear programming based model; both capture transmission
constraint effects in the same way.
99
<PAGE>
However, we propose analyzing 4 PJM regions (East, West, South, and Homer City)
rather than each node for the following reasons:
- Users of our results, especially the financial community,
usually find that working with regional averages is more
manageable and adequate for this analysis.
- PJM itself is moving towards the use of averages. For example,
"PJM West" is an average of about 200 nodes and is now
proposed for the focal point for trading and proposed future
contracts.
- The cost of analyzing each node over many years is prohibitive
relative to the value such analysis yields. In fact, to date,
few differences have been observed across most nodes. As shown
in the attached tables, the differences are unobservable. This
is not to say there are none or will be none, but rather
proportionality of effort should be considered.
- There are models that generate 1,744 nodal prices. However,
these cannot be used for quick scenario analysis and can be
very cumbersome to use by lenders. Also, they can only be
solved one year at a time (e.g., 2000, then 2005, etc.). Our
approach solves all years simultaneously. Thus, we can
incorporate the fact that decisions reflect expectations. Only
our approach provides a reasonable retirement, capacity
expansion, and capacity price forecast over the many years
that are associated with powerplant financing.
- Our broad four-region approach is widely accepted by
decision-makers and the financial, legal and regulatory
community because it captures the key transmission issues,
especially PJM East versus PJM West. We have vetted this issue
repeatedly with leading PJM utilities over 20 years.
ICF estimates of inter-regional transmission pricing incorporate both a
transmission charge and a line loss. Transmission charges between regions are
based on the charge to connect to the importing regions grid and deliver power.
Inter-regional line losses are assumed to be 1 percent per 100 miles.
Intra-regional transmission is assumed to be at a postage stamp rate
and to include transmission losses.
100
<PAGE>
EXHIBIT 4-52
TRANSMISSION PRICING
<TABLE>
<CAPTION>
---------------------------------------------- --------------------------------------- ----------------------------
REGIONAL TRANSMISSION TRANSMISSION CHARGE (1998$/MWh) LINE LOSSES (%)
-------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
INTER-REGIONAL
---------------------------------------------- --------------------------------------- ----------------------------
Ontario to ECAR 3.0 2.0
---------------------------------------------- --------------------------------------- ----------------------------
ECAR to Ontario 2.0 2.0
---------------------------------------------- --------------------------------------- ----------------------------
ECAR to PJM West 2.5 Peak; 1.9 Off-Peak 3.0
---------------------------------------------- --------------------------------------- ----------------------------
PJM West to Upstate New York 4.6 Peak; 3.3 Off-Peak 2.0
---------------------------------------------- --------------------------------------- ----------------------------
PJM East to Downstate New York 4.0 Peak; 3.8 Off-Peak 1.0
---------------------------------------------- --------------------------------------- ----------------------------
Upstate New York to PJM West 5.1 2.0
---------------------------------------------- --------------------------------------- ----------------------------
Downstate New York to PJM East 4.6 1.0
---------------------------------------------- --------------------------------------- ----------------------------
NEPOOL to Downstate New York 5.3 Peak; 5.1 Off-Peak 2.0
---------------------------------------------- --------------------------------------- ----------------------------
Downstate New York to NEPOOL 0.6 2.0
---------------------------------------------- --------------------------------------- ----------------------------
PJM South to VACAR(2) 3.1 Peak; 1.4 Off-Peak 1.0
---------------------------------------------- --------------------------------------- ----------------------------
INTRA-REGIONAL
---------------------------------------------- --------------------------------------- ----------------------------
MECS to Southern ECAR 0.0 2.0
---------------------------------------------- --------------------------------------- ----------------------------
PJM West to PJM East(1) 0.0 3%Peak; 2 %Off-Peak
---------------------------------------------- --------------------------------------- ----------------------------
PJM West to PJM South(1) 0.0 3%Peak; 2% Off-Peak
---------------------------------------------- --------------------------------------- ----------------------------
Upstate New York to Downstate New York(1) 0.0 5.0
---------------------------------------------- --------------------------------------- ----------------------------
Downstate New York to Long Island(1) 0.0 3.0
---------------------------------------------- --------------------------------------- ----------------------------
</TABLE>
(1) Limits shown are multi-directional.
(2) Charges into VACAR is the average of charges into the sub-regions of
VACAR - Duke, Carolina Power & Light, SCEG, and VIEPCO.
Source: PJM Power Pool, NEPOOL ISO; phone conversations with power purchasers,
sellers and transmission system operators
101
<PAGE>
CHAPTER FIVE
ELECTRIC REVENUES FORECAST
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
SUMMARY OF BASE CASE FORECASTS
PJM EAST FIRM PRICE FORECAST(6)
The forecast of firm ( i.e., PJM East all-in all-hours average) market
prices is graphically shown in Exhibit 5-1 in real (1998$) and nominal dollars.
Actual data points for individual years are shown in Exhibit 5-2, detail in
Appendix A. The price shown provides for maximum revenues available to a plant
in the market, i.e., a plant must be dispatched in all hours to realize this
price. Our forecast of firm prices comprises the two unbundled products of
electrical energy and capacity. Next, we separately discuss both elements of
firm prices to assess Red Oak's competitive position in the separate markets for
energy and capacity.
EXHIBIT 5-1
SUMMARY OF FIRM(7) PRICE FORECAST - BASE CASE
[GRAPH]
A Line Graph Firm Price Forecast by Year for the years 2002-2027
-------------------
(7) This price is for all hours supply and it is firm unit contingent i.e. it is
backed by a specific unit.
102
<PAGE>
EXHIBIT 5-2
SUMMARY OF FIRM ALL-IN(1) PRICE FORECAST ($/MWh) - BASE CASE
<TABLE>
<CAPTION>
-----------------------------------------------
ANNUAL AVERAGE FIRM
YEAR PRICE FOR ENERGY
(1998 $)
-----------------------------------------------
<S> <C>
2002 29.9
-----------------------------------------------
2005 30.5
-----------------------------------------------
2010 30.4
-----------------------------------------------
2015 30.4
-----------------------------------------------
2020 29.8
-----------------------------------------------
2025 29.1
-----------------------------------------------
2030 28.6
-----------------------------------------------
</TABLE>
(1) Firm Price = Sum of Energy Price and
Capacity Price at 100 percent load factor.
PJM EAST ENERGY PRICE FORECAST
The competitive market electrical energy price equals the short-run
variable costs (primarily fuel) of the last unit dispatched in a given hour. The
electrical energy price is also the most important determinant of which units
operate in each hour. In each hour, if a plant's variable costs are less than
the electrical energy price, the plant is dispatched.(8) Consistent with
historical evidence of electrical energy prices in PJM East, our near-term
forecast, i.e., in 2002, shows an annual average electrical energy price of
approximately $24.0/MWh (1998$) as shown in Exhibit 5-3. This is reflective of
some hours in which higher cost coal units are on the margin, and some hours in
which gas-fired units, particularly gas steam units, are on the margin.
EXHIBIT 5-3
PJM EAST ELECTRICAL ENERGY PRICE FORECAST ($/MWh) - BASE CASE
<TABLE>
<CAPTION>
-----------------------------------------------
YEAR ANNUAL AVERAGE - ALL HOURS
(1998$)
-----------------------------------------------
<S> <C>
2002 24.0
-----------------------------------------------
2005 24.1
-----------------------------------------------
2010 24.5
-----------------------------------------------
2015 24.7
-----------------------------------------------
2020 24.4
-----------------------------------------------
2025 23.7
-----------------------------------------------
2030 23.2
-----------------------------------------------
</TABLE>
Annual average energy prices initially increase slightly in real-terms,
going from approximately $24.0/MWh in 2002 to $24.7/MWh in 2015 before
decreasing gradually to $23.2/MWh (1998$) in 2030. The initial real price
increase is associated with a number of partially offsetting factors. Upward
price pressure is exerted by a number of factors. In the near-term, it reflects
the transition from coal to gas on the margin in increasing hours, as coal is
gradually replaced as the most common price-setting unit. Also, there is a
reduction in PJM West imports due to increasing demand requirements there and in
other neighboring regions, thus there is a greater requirement for local
gas-fired generation. Additionally, the increasing prices also reflect
increasing environmental allowance prices for SO(2) and NO(x) emissions.
-------------------
(8) This simplification is generally appropriate except when certain operational
constraints exist, e.g., minimum turndown requirements.
103
<PAGE>
Partially mitigating these upward price pressures is the addition of new
efficient, low-variable cost combined cycle units to the system. Thus, prices
increase very minimally.
In the longer-term, the real price decrease is the result of the net
downward price pressure from the continued addition of new, efficient, combined
cycle units to the system. In addition, Henry Hub gas prices are forecasted to
remain flat in real terms after 2020, eliminating the upward pressure of
increasing gas prices on energy prices.
PJM CAPACITY PRICE FORECAST
Capacity augments the reliability of the power grid. All suppliers of
end-use power must arrange to have first call on enough megawatts to meet
planned peak reserve levels. The capacity price is set in equilibrium by the
cost recovery requirements of new units not earned through sales in the
electrical energy market. Markets are in equilibrium when the need for megawatts
equals the supply.
The forecast for capacity prices in the PJM region is shown in Exhibit 5-4
and commences at approximately $52/kW/yr (1998$) in 2002. PJM's existing
resources are not sufficient to meet projected demand in 2002 and thus new
builds are required to meet demand growth and reserve margin requirements.
Capacity prices are projected to be highest in 2005 at approximately $56/kW/yr
(1998$) and to decline steadily in real terms to $47/kW/yr (1998$) before
stabilizing after 2020. This is largely correlated to the underlying trend in
capital costs for new plants, i.e., declining capital costs between 2005 and
2020 and flat capital costs in real terms thereafter.(9)
EXHIBIT 5-4
PJM ANNUAL CAPACITY PRICE FORECAST(1) ($/kw-YR) - BASE CASE
<TABLE>
<CAPTION>
-----------------------------------------------
YEAR PURE CAPACITY PRICE
(1998 $)
-----------------------------------------------
<S> <C>
2002 52.0
-----------------------------------------------
2005 56.0
-----------------------------------------------
2010 52.0
-----------------------------------------------
2015 50.0
-----------------------------------------------
2020 47.0
-----------------------------------------------
2025 47.0
-----------------------------------------------
2030 47.0
-----------------------------------------------
</TABLE>
(1) Firm electricity price is the sum of the
electrical energy and pure capacity prices.
Since pure capacity prices are in $/kW/yr, and
energy prices in $/MWh, $/kW/yr must be
allocated to the hours in question. See Chapter
3 for more information.
In light of the relatively high energy prices that prevail in the region,
absent near-term timing constraints (i.e., from 2002 onwards), the economic
decision would be for the build mix to be comprised largely of new combined
cycles, as shown in Exhibit 5-5. Accordingly, we anticipate that capacity prices
throughout the horizon will be driven by these new and efficient
-----------------------
(9) The small increase in capacity prices between 2002 and 2005 is associated
with the introduction of new power plant technology (i.e., slightly better
gas plants) after 2005. Plants anticipate the lower prices due to this
technological improvement and entrants in 2005 seek to recover more sooner.
See later discussion.
104
<PAGE>
units. The capacity prices associated with these low variable cost units reflect
their high level of dispatch and their ability to earn significant profits
VIS~A~VIS the energy price. This substantial energy margin considerably offsets
the cost recovery required through the capacity price.
EXHIBIT 5-5
FORECASTED CAPACITY ADDITIONS IN PJM(1) (MW) - BASE CASE
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
YEAR COMBINED CYCLES COMBUSTION TURBINES TOTAL
--------------------------------------------------------------------------
PLANNED UNPLANNED PLANNED UNPLANNED
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1999 - 2002 970 1,290 0 1,026 3,286
----------------------------------------------------------------------------------------------------
2003 - 2005 0 3,899 0 1,262 5,161
----------------------------------------------------------------------------------------------------
2006 - 2010 0 5,864 0 0 5,864
----------------------------------------------------------------------------------------------------
2011 - 2015 0 9,500 0 1,418 10,918
----------------------------------------------------------------------------------------------------
2016 - 2020 0 6,770 0 2,970 9,740
----------------------------------------------------------------------------------------------------
2021 - 2025 0 9,895 0 2,049 11,944
----------------------------------------------------------------------------------------------------
2026 - 2030 0 8,490 0 1,066 9,556
----------------------------------------------------------------------------------------------------
TOTAL 970 45,708 0 9,791 56,469
----------------------------------------------------------------------------------------------------
</TABLE>
(1) Does not include104 MW expansion of Muddy Run pumped storage plant which ICF
treats as a firm build.
DISCUSSION OF FACILITY DISPATCH - BASE CASE
We anticipate that the Facility will be dispatched according to competitive
system economics in the PJM marketplace. As such, the Facility will be
dispatched based on its variable cost relative to other power plants in the
region.
We evaluated a single aggregated unit for the Red Oak power plant as there
was little difference in heat rate or other operating characteristics across the
three units comprising the Red Oak Facility. A summary of plant characteristics
is shown in Exhibit 5-6.
105
<PAGE>
EXHIBIT 5-6
SUMMARY OF RED OAK PLANT CHARACTERISTICS
<TABLE>
<CAPTION>
--------------------------------------------------------------------
PARAMETER TREATMENT
--------------------------------------------------------------------
<S> <C>
Capacity(1) (MW) 832
--------------------------------------------------------------------
Heat Rate (Btu/kWh)(2) 6,700
--------------------------------------------------------------------
Fuel Natural Gas
--------------------------------------------------------------------
Delivered Fuel Price (1998$/MMBtu)
2002 2.55
2005 2.66
2010 2.78
2015 2.92
2020 3.03
2025 3.03
2030 3.03
--------------------------------------------------------------------
Availability (%) 95
--------------------------------------------------------------------
Variable O&M (1998$/MWh)(3) 0.8 - 4.3
--------------------------------------------------------------------
Minimum Turndown (%) 25
--------------------------------------------------------------------
NO(x) Rate (lbs/MMBtu) 0.02
--------------------------------------------------------------------
</TABLE>
(1) ISO undegraded.
(2) HHV, expected (vs. guaranteed).
(3) Inversely correlated with capacity factor.
Red Oak is very competitive due to its low heat rate of 6,700 Btu/kWh as
compared with the PJM current system average of approximately 10,500 Btu/kWh. It
is even competitive with many coal plants, particularly in the summer and
shoulder seasons when gas prices are discounted, and in the later years when
environmental costs become more burdensome for coal plants. Its dispatch remains
above 80 percent through 2014, and then declines gradually thereafter to
approximately 61 percent in 2030. The decline in dispatch is generally
attributable to the addition of newer, more efficient combined cycle units to
the system to meet growing demand requirements. These units displace Red Oak
somewhat, particularly during off-peak hours. Consequently, in the outer years,
Red Oak's dispatch is largely concentrated during peak and intermediate load
hours and the realized price is thus higher than the simple all-hours annual
average price.
EXHIBIT 5-7
RED OAK DISPATCH - BASE CASE
<TABLE>
<CAPTION>
---------------------------------------------------------------
YEAR REALIZED ENERGY PRICE
AVAILABLE TIME -----------------------------
DISPATCHED (%) 1998$/MWH
---------------------------------------------------------------
<S> <C> <C>
2002 84.2 25.0
---------------------------------------------------------------
2005 85.1 24.8
---------------------------------------------------------------
2010 83.3 25.2
---------------------------------------------------------------
2015 78.1 25.7
---------------------------------------------------------------
2020 70.5 25.7
---------------------------------------------------------------
2025 63.8 25.3
---------------------------------------------------------------
2030 61.3 24.8
---------------------------------------------------------------
</TABLE>
The PJM supply curves for the years 2002 and 2020 winter and summer periods
are shown in Exhibits 5-8 and 5-9. Throughout the forecast horizon, the Red Oak
Facility is very competitively positioned vis~a~vis coal plants, particularly in
the summer months. It is also
106
<PAGE>
considerably more competitive than the large amount of existing oil/gas steam
plants, and existing and new turbines.
EXHIBIT 5-8
PJM ILLUSTRATIVE PEAK HOUR SUPPLY CURVES - 2002 - BASE CASE
[GRAPH]
A LINE GRAPH SHOWING PEAK HOUR SUPPLY BY MW IN 2020
EXHIBIT 5-9
PJM ILLUSTRATIVE PEAK HOUR SUPPLY CURVES - 2020 - BASE CASE
[GRAPH]
A LINE GRAPH SHOWING PEAK HOUR SUPPLY BY MW IN 2020
107
<PAGE>
SUMMARY OF LOW GAS PRICE CASE FORECASTS
FIRM PRICE FORECAST(10) - LOW GAS PRICE CASE
On average, around-the-clock firm prices are approximately 10 percent lower
in the Low Gas Case compared to the Base Case. Most of the reduction is
associated with lower market energy prices as is discussed further in this
section. The forecast of firm market prices is graphically shown in Exhibit 5-10
in real. Actual data points for individual years are shown in Exhibit 5-11.
EXHIBIT 5-10
SUMMARY OF FIRM(1) PRICE FORECAST - LOW GAS PRICE CASE
[GRAPH]
A LINE GRAPH SHOWING FORECAST LOW PRICES BY YEAR FOR THE YEARS 2002-2027
EXHIBIT 5-11
SUMMARY OF FIRM(1) ALL-IN PRICE FORECAST ($/MWh) - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
-----------------------------------------------------
ANNUAL AVERAGE FIRM
YEAR PRICE FOR ENERGY
(1998 $)
-----------------------------------------------------
<S> <C>
2002 26.7 (-3.2)
-----------------------------------------------------
2005 27.2 (-3.3)
-----------------------------------------------------
2010 27.2 (-3.2)
-----------------------------------------------------
2015 27.2 (-3.2)
-----------------------------------------------------
2020 26.6 (-3.2)
-----------------------------------------------------
2025 26.0 (-3.1)
-----------------------------------------------------
2030 25.6 (-3.0)
-----------------------------------------------------
</TABLE>
(1)Firm Price = Sum of Energy Price and Capacity
Price at 100 percent load factor.
( ) shows change from Base Case.
----------------------
(10) This price is for all hours supply and it is firm unit contingent i.e. it
is backed by a specific unit.
108
<PAGE>
PJM EAST ENERGY PRICE FORECAST - LOW GAS PRICE CASE
Our near-term forecast, i.e., in 2002, in this case shows an annual average
electrical energy price of approximately $21.3/MWh (1998$) as shown in Exhibit
5-12. This price is $2.7/MWh lower than in the Base Case and is reflective of a
gas price $0.50/MMBtu lower than in the Base Case. In certain hours when coal is
on the margin, the lower gas price has almost no effect on the market-clearing
price. In hours when gas is on the margin, the lower gas price has a greater
effect the higher the marginal unit heat rate. In certain seasons where oil/gas
steam units burning oil are on the margin in the Base Case these units switch to
burning gas in the Low Gas Case. In this event, the fuel price decreases may be
less than $0.50/MMBtu.
EXHIBIT 5-12
PJM EAST ELECTRICAL ENERGY PRICE FORECAST ($/MWh) - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
----------------------------------------------------
YEAR ANNUAL AVERAGE - ALL HOURS
--------------------------------
(1998$)
----------------------------------------------------
<S> <C>
2002 21.3 (-2.7)
----------------------------------------------------
2005 20.9 (-3.2)
----------------------------------------------------
2010 21.0 (-3.5)
----------------------------------------------------
2015 21.3 (-3.4)
----------------------------------------------------
2020 21.1 (-3.3)
----------------------------------------------------
2025 20.5 (-3.2)
----------------------------------------------------
2030 20.1 (-3.1)
----------------------------------------------------
</TABLE>
( ) shows change from Base Case.
The energy price differential remains on average approximately $3 to
$3.5/MWh (1998$) relative to the Base Case. While gas prices increasingly
influence the marginal unit, the marginal unit heat rate generally improves over
time, thereby reducing the gas price effect.
Through 2015, annual average energy prices remain relatively constant in
real terms, with very minor fluctuations due to offsetting effects associated
with a number of factors similar to those in the Base Case. Exerting upward
price pressure is the transition from coal to gas on the margin in increasing
hours, the reduction in PJM West imports due to increasing demand
requirements there and in other neighboring regions, increasing environmental
allowance prices for SO(2) and NO(x) emissions, and slightly increasing gas
prices. The addition of new, efficient, low-variable cost combined cycle
units to the system exerts offsetting downward pressure on prices. Together,
these effects keep the energy prices from fluctuating any more than $0.40/MWh
(1998$) through 2020.
After 2020, Henry Hub gas prices are forecasted to no longer increase in
real terms, eliminating the upward pressure of increasing gas prices on energy
prices. The absence of this upward pressure causes prices to decrease slightly
from 2020 through 2030.
PJM CAPACITY PRICE FORECAST - LOW GAS PRICE CASE
The forecast for capacity prices in the PJM region in this case is shown in
Exhibit 5-13 and is very similar to the Base Case. While energy prices are lower
than in the Base Case, variable costs for new marginal gas-fired units are also
lower due to the lower gas prices. Consequently, new units are largely hedged to
moderate changes in the gas price, and capacity prices are also largely
unaffected.
109
<PAGE>
EXHIBIT 5-13
PJM ANNUAL CAPACITY PRICE FORECAST ($/kW-YR) - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
----------------------------------------------------
YEAR PURE CAPACITY PRICE
-----------------------------
(1998$)
----------------------------------------------------
<S> <C>
2002 47.0 (-5.0)
----------------------------------------------------
2005 55.0 (-1.0)
----------------------------------------------------
2010 54.0 (+2.0)
----------------------------------------------------
2015 52.0 (+2.0)
----------------------------------------------------
2020 48.0 (+1.0)
----------------------------------------------------
2025 48.0 (+1.0)
----------------------------------------------------
2030 48.0 (+1.0)
----------------------------------------------------
</TABLE>
( ) shows change from Base Case
The build mix in the Low Gas Price Case is very similar to that of the Base
Case. In total over the forecast horizon, approximately 2,700 MW fewer combined
cycles are projected to come on-line and instead a larger number of combustion
turbine builds are projected.
EXHIBIT 5-14(1)
FORECASTED CAPACITY ADDITIONS IN PJM - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------
YEAR COMBINED CYCLES COMBUSTION TURBINES TOTAL
----------------------------------------------------------------
PLANNED UNPLANNED PLANNED UNPLANNED
-------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1999-2002 970 4,528 0 0 5,498
-------------------------------------------------------------------------------------------
2003-2005 0 3,489 0 1,673 5,162
-------------------------------------------------------------------------------------------
2006-2010 0 4,926 0 938 5,864
-------------------------------------------------------------------------------------------
2011-2015 0 8,204 0 2,683 10,887
-------------------------------------------------------------------------------------------
2016-2020 0 4,470 0 4,023 8,493
-------------------------------------------------------------------------------------------
2021-2025 0 8,987 0 2,023 11,010
-------------------------------------------------------------------------------------------
2026-2030 0 8,409 0 1,147 9,556
-------------------------------------------------------------------------------------------
Total 970 43,013 0 12,487 56,470
-------------------------------------------------------------------------------------------
</TABLE>
(1)Does not include104 MW expansion of Muddy Run pumped storage plant which ICF
treats as a firm build.
DISCUSSION OF FACILITY DISPATCH - LOW GAS PRICE CASE
Red Oak is even more competitive with respect to the overall merit order in
PJM in the Low Gas Price Case. Relative to other gas-fired units, its relative
position is unchanged. However, relative to coal-fired and oil-fired units, its
lower gas costs allow it to displace some of these units. On average, Red Oak is
projected to economically dispatch at an approximately 10 percent greater
capacity factor.
110
<PAGE>
EXHIBIT 5-15
RED OAK DISPATCH - LOW GAS PRICE CASE
<TABLE>
<CAPTION>
------------------------------------------------------------------------
YEAR(1) AVAILABLE TIME REALIZED ENERGY PRICE
DISPATCHED (%) ------------------------------
1998$/MWh
------------------------------------------------------------------------
<S> <C> <C>
2002 93.8 ( +9.6) 21.4
------------------------------------------------------------------------
2005 95.1 (+11.8) 20.9
------------------------------------------------------------------------
2010 92.7 ( +9.4) 21.1
------------------------------------------------------------------------
2015 92.0 (+13.9) 21.4
------------------------------------------------------------------------
2020 86.4 (+15.9) 21.5
------------------------------------------------------------------------
2025 80.4 (+16.6) 21.0
------------------------------------------------------------------------
2030 72.8 (+11.5) 20.8
------------------------------------------------------------------------
</TABLE>
( ) shows change from Base Case.
SUMMARY OF HIGH GAS PRICE CASE FORECASTS
FIRM PRICE FORECAST(11) - HIGH GAS PRICE CASE
Converse to the Low Case, around-the-clock firm prices are approximately 10
percent higher than in the Base Case. The forecast of firm market prices is
graphically shown in Exhibit 5-16 in real and nominal dollars. Actual data
points for individual years are shown in Exhibit 5-17.
EXHIBIT 5-16
SUMMARY OF FIRM(1) PRICE FORECAST - HIGH GAS PRICE CASE
[GRAPH]
A LINE GRAPH SHOWNING HIGH GAS PRICE FORECAST-BY YEAR FOR THE YEARS 2002-2027
-----------------------
(11) This price is for all hours supply and it is firm unit contingent i.e. it
is backed by a specific unit.
111
<PAGE>
EXHIBIT 5-17
SUMMARY OF FIRM "ALL-IN" (1) PRICE FORECAST ($/MWh) - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
-----------------------------------------------------
ANNUAL AVERAGE FIRM PRICE FOR
YEAR ENERGY
(1998 $)
-----------------------------------------------------
<S> <C>
2002 31.9 (+2.0)
-----------------------------------------------------
2005 33.5 (+3.0)
-----------------------------------------------------
2010 33.7 (+3.3)
-----------------------------------------------------
2015 33.7 (+3.3)
-----------------------------------------------------
2020 33.0 (+3.2)
-----------------------------------------------------
2025 32.2 (+3.1)
-----------------------------------------------------
2030 31.6 (+3.0)
-----------------------------------------------------
</TABLE>
(1)Firm Price = Sum of Energy Price and Capacity Price
at 100 percent load factor.
( ) shows change from Base Case.
PJM EAST ENERGY PRICE FORECAST - HIGH GAS PRICE CASE
The High Gas Price Case assumes higher gas prices of $0.50/MMBtu relative
to the Base Case. Our near-term forecast, i.e., in 2002, in this case shows an
annual average electrical energy price of approximately $26.0/MWh (1998$) as
shown in Exhibit 5-18. This price is $2/MWh higher than in the Base Case. The
Higher gas price has less of an impact than the same differential in the Low Gas
Case as oil/gas steam units on the margin burning gas in the Base Case are
protected from higher gas prices in certain seasons from an oil price ceiling,
as oil prices are unchanged in this scenario. No comparable ceiling is available
to single fuel steam units and a less binding ceiling is applicable for combined
cycle and combustion turbine units due to the considerably higher distillate
price.
EXHIBIT 5-18
PJM EAST ELECTRICAL ENERGY PRICE FORECAST ($/MWh) - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
---------------------------------------------------
YEAR ANNUAL AVERAGE - ALL HOURS
------------------------------
(1998$)
---------------------------------------------------
<S> <C>
2002 26.0 (+2.0)
---------------------------------------------------
2005 26.9 (+2.8)
---------------------------------------------------
2010 27.9 (+3.4)
---------------------------------------------------
2015 27.9 (+3.2)
---------------------------------------------------
2020 27.6 (+3.2)
---------------------------------------------------
2025 26.8 (+3.1)
---------------------------------------------------
2030 26.2 (+3.0)
---------------------------------------------------
( ) shows change from Base Case.
---------------------------------------------------
</TABLE>
Annual average energy prices initially increase in real-terms, from
approximately $26.0/MWh in 2002 to $27.9/MWh in 2015 before decreasing to
$26.2/MWh (1998$) in 2030. The energy price differential relative to the Base
Case remains in the $2.8 to $3.4/MWh range from 2005 to 2030.
PJM CAPACITY PRICE FORECAST - HIGH GAS PRICE CASE
The forecast for capacity prices in the PJM region in this case is shown in
Exhibit 5-19 is very similar to the Base Case, again due to the unchanged
capital and financing cost structure for new builds, and the relatively hedged
position of new units to changes in gas prices.
112
<PAGE>
EXHIBIT 5-19
PJM ANNUAL CAPACITY PRICE FORECAST ($/kW-YR) - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
-----------------------------------------------
YEAR PURE CAPACITY PRICE
--------------------------
(1998$)
-----------------------------------------------
<S> <C>
2002 52.0 ()
-----------------------------------------------
2005 58.0 (+2)
-----------------------------------------------
2010 51.0 (-1)
-----------------------------------------------
2015 51.0 (+1)
-----------------------------------------------
2020 47.0 ()
-----------------------------------------------
2025 47.0 ()
-----------------------------------------------
2030 47.0 ()
-----------------------------------------------
( ) shows change from Base Case.
-----------------------------------------------
</TABLE>
The build mix in the High Gas Price Case is also very similar to that of
the Base Case, the only net difference being approximately 1,000 MW fewer
combined cycles and greater combustion turbines over the entire forecast
horizon.
EXHIBIT 5-20
FORECASTED CAPACITY ADDITIONS IN PJM(1) - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
YEAR COMBINED CYCLES COMBUSTION TURBINES TOTAL
----------------------------------------------------------------------
PLANNED UNPLANNED PLANNED UNPLANNED
----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1999 - 2002 970 0 0 1,625 2,595
----------------------------------------------------------------------------------------------------------
2003 - 2005 0 2,985 0 2,177 5,162
----------------------------------------------------------------------------------------------------------
2006 - 2010 0 7,086 0 0 7,086
----------------------------------------------------------------------------------------------------------
2011 - 2015 0 9,222 0 1,133 10,355
----------------------------------------------------------------------------------------------------------
2016 - 2020 0 7,299 0 2,817 10,116
----------------------------------------------------------------------------------------------------------
2021 - 2025 0 10,314 0 1,285 11,599
----------------------------------------------------------------------------------------------------------
2026 - 2030 0 7,889 0 1,667 9,556
----------------------------------------------------------------------------------------------------------
Total 970 44,795 0 10,704 56,469
----------------------------------------------------------------------------------------------------------
</TABLE>
(1)Does not include104 MW expansion of Muddy Run pumped storage plant which ICF
treats as a firm build.
DISCUSSION OF FACILITY DISPATCH - HIGH GAS PRICE CASE
Red Oak is slightly less competitive with respect to the overall PJM merit
order in the High Gas Price Case due to its higher variable costs. Again, its
relative position is unchanged relative to other gas-fired units, but
potentially disadvantaged relative to coal- and oil-fired units. Capacity
factors are between 4 and 9 percent lower than in the Base Case, but are still
never below 55 percent.
113
<PAGE>
EXHIBIT 5-21
RED OAK DISPATCH - HIGH GAS PRICE CASE
<TABLE>
<CAPTION>
-----------------------------------------------------------------------
YEAR(1) AVAILABLE TIME REALIZED ENERGY PRICE
DISPATCHED (%) -----------------------------
1998$/MWh
-----------------------------------------------------------------------
<S> <C> <C>
2002 75.5 (-8.7) 28.0
-----------------------------------------------------------------------
2005 75.5 (-9.6) 28.9
-----------------------------------------------------------------------
2010 75.5 (-7.8) 29.5
-----------------------------------------------------------------------
2015 73.2 (-4.9) 29.4
-----------------------------------------------------------------------
2020 67.2 (-3.3) 29.3
-----------------------------------------------------------------------
2025 58.2 (-5.6) 28.9
-----------------------------------------------------------------------
2030 57.7 (-3.6) 28.2
-----------------------------------------------------------------------
</TABLE>
( ) shows change from Base Case.
SUMMARY OF OVERBUILD CASE FORECASTS
FIRM PRICE FORECAST(12) - OVERBUILD CASE
The Overbuild Case was structured with builds as necessary to meet peak
demand and reserve requirements of the Base Case through 2020, and an additional
unexpected infusion of builds on the order of 10 percent of aggregate peak
demand, above and beyond the additions included in the Base Case in 2020(13).
The forecast of firm market prices is graphically shown in Exhibit 5-22 in real
and nominal dollars. Actual data points for individual years are shown in
Exhibit 5-23.
---------------------
(12) This price is for all hours supply and it is firm unit contingent i.e. it
is backed by a specific unit.
(13) In the Base Case, PJM was building approximately 1,700 MW for export
purposes. In the Overbuild Case, we assumed a 10 percent overbuild of peak
relative to local demand requirements. Thus, approximately 7,500 MW of builds
above and beyond local requirements were infused, resulting in approximately
5,800 MW of additional builds relative to the Base Case.
114
<PAGE>
EXHIBIT 5-22
SUMMARY OF FIRM(1) PRICE FORECAST - OVERBUILD CASE
[GRAPH]
A LINE GRAPH SHOWING PRICE FORECAST FOR OVERBUILD BY YEAR FOR THE
YEARS 2002-2027
EXHIBIT 5-23
SUMMARY OF FIRM(1) PRICE FORECAST - OVERBUILD CASE
<TABLE>
<CAPTION>
------------------------------------------------------
ANNUAL AVERAGE FIRM PRICE FOR
YEAR ENERGY
(1998 $/MWh)
------------------------------------------------------
<S> <C>
2002 29.9 ()
------------------------------------------------------
2005 30.5 ()
------------------------------------------------------
2010 30.4 ()
------------------------------------------------------
2015 30.4 ()
------------------------------------------------------
2020 29.0 (-0.8)
------------------------------------------------------
2025 29.1 ()
------------------------------------------------------
2030 28.6 ()
------------------------------------------------------
</TABLE>
(1)Firm Price = Sum of Energy Price and Capacity Price
at 100 percent load factor.
( ) shows changes from Base Case.
PJM EAST ENERGY PRICE FORECAST - OVERBUILD CASE
Energy prices are unchanged until 2020. In this year, the additional builds
of approximately 5,800 MW in PJM are largely comprised of combined cycles, thus
making available an even greater amount of low cost energy to the system. Energy
prices thus decrease by $1.3/MWh (1998$) in this year.
115
<PAGE>
EXHIBIT 5-24
PJM EAST ELECTRICAL ENERGY PRICE FORECAST - ($/MWh)
<TABLE>
<CAPTION>
-----------------------------------------------------
YEAR ANNUAL AVERAGE - ALL HOURS
-------------------------------
(1998$)
-----------------------------------------------------
<S> <C>
2002 24.0 ()
-----------------------------------------------------
2005 24.1 ()
-----------------------------------------------------
2010 24.5 ()
-----------------------------------------------------
2015 24.7 ()
-----------------------------------------------------
2020 23.1 (-1.3)
-----------------------------------------------------
2025 23.6 (-0.1)
-----------------------------------------------------
2030 23.1 (-0.1)
-----------------------------------------------------
( ) shows changes from the Base Case.
-----------------------------------------------------
</TABLE>
By 2025, projected demand growth is sufficient to absorb the overbuild, and
energy prices are very similar to those in the Base Case.
PJM CAPACITY PRICE FORECAST - OVERBUILD CASE
Capacity prices are also unchanged until 2020. In 2020, PJM has more
capacity than required to meet local requirements. However, the excess can be
absorbed by neighboring regions, and thus capacity still has considerable
(although lesser) value and is derived as the price of capacity in the export
region net firm transmission costs. Thus, the 2020 capacity price is
approximately 15 percent lower than in the Base Case. By 2025, demand growth
absorbs the excess, and once again, new builds are required for the system. The
forecast for capacity prices in the PJM region in this case is shown in Exhibit
5-25.
EXHIBIT 5-25
PJM ANNUAL CAPACITY PRICE FORECAST ($/kW-YR) - OVERBUILD CASE
<TABLE>
<CAPTION>
-------------------------------------------------
YEAR PURE CAPACITY PRICE
----------------------------
(1998$)
-------------------------------------------------
<S> <C>
2002 52.0 ()
-------------------------------------------------
2005 56.0 ()
-------------------------------------------------
2010 52.0 ()
-------------------------------------------------
2015 50.0 ()
-------------------------------------------------
2020 41 (-6)
-------------------------------------------------
2025 48 (+1)
-------------------------------------------------
2030 48 (+1)
-------------------------------------------------
( ) shows change from Base Case.
-------------------------------------------------
</TABLE>
116
<PAGE>
EXHIBIT 5-26
FORECASTED CAPACITY ADDITIONS IN PJM(1) - OVERBUILD CASE
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
YEAR COMBINED CYCLES COMBUSTION TURBINES TOTAL
------------------------------------------------------------------------
PLANNED UNPLANNED PLANNED UNPLANNED
-------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1999-2002 970 1,290 0 1,026 3,286
-------------------------------------------------------------------------------------------------------------
2003-2005 0 3,899 0 1,262 5,161
-------------------------------------------------------------------------------------------------------------
2006-2010 0 5,864 0 0 5,864
-------------------------------------------------------------------------------------------------------------
2011-2015 0 9,500 0 1,418 10,918
-------------------------------------------------------------------------------------------------------------
2016-2020 4,045 6,770 1,774 2,970 15,559
-------------------------------------------------------------------------------------------------------------
2021-2025 0 5,963 0 1,105 7,068
-------------------------------------------------------------------------------------------------------------
2026-2030 0 8,409 0 1,148 9,557
-------------------------------------------------------------------------------------------------------------
Total 5,015 41,695 1,774 8,929 57,413
-------------------------------------------------------------------------------------------------------------
</TABLE>
(1)Does not include104 MW expansion of pumped storage plant which ICF treats as
a firm build.
DISCUSSION OF FACILITY DISPATCH - OVERBUILD CASE
In 2020, there is a larger number of more efficient combined cycle units in
the system relative to Red Oak, as compared to the Base Case. Thus, in certain
marginal hours in 2020, Red Oak is displaced and its overall capacity factor is
approximately 6 percent lower than in the Base Case.
EXHIBIT 5-27
RED OAK DISPATCH - OVERBUILD CASE
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------
YEAR AVAILABLE TIME REALIZED ENERGY PRICE
DISPATCHED (%) -------------------------------
1998$/MWh
----------------------------------------------------------------------------------
<S> <C> <C>
2002 84.2 () 25.0
----------------------------------------------------------------------------------
2005 85.1 () 24.8
----------------------------------------------------------------------------------
2010 83.3 () 25.2
----------------------------------------------------------------------------------
2015 78.1 () 25.7
----------------------------------------------------------------------------------
2020 64.7 (-5.8) 24.2
----------------------------------------------------------------------------------
2025 64.6 (+0.8) 25.2
----------------------------------------------------------------------------------
2030 61.3 () 24.7
----------------------------------------------------------------------------------
</TABLE>
( ) shows changes from the Base Case.
117
<PAGE>
APPENDIX A
ANNUAL PRICE RESULTS
-------------------------------------------------------------------------------
BASE CASE ANNUAL PRICE RESULTS
<TABLE>
<CAPTION>
Year Red Oak Realized All-Hour Energy PJM Capacity Price (98$/kW/yr) Red Oak Firm Price (98$/MWh)
Price (98$/MWh)
<S> <C> <C> <C>
2002 24.99 52.0 32.0
2003 24.92 53.3 32.1
2004 24.86 54.6 32.2
2005 24.79 56.0 32.3
2006 24.88 55.2 32.3
2007 24.97 54.4 32.3
2008 25.06 53.6 32.3
2009 25.15 52.8 32.4
2010 25.25 52.0 32.4
2011 25.33 51.6 32.5
2012 25.42 51.2 32.6
2013 25.51 50.8 32.7
2014 25.60 50.4 32.9
2015 25.69 50.0 33.0
2016 25.68 49.4 33.0
2017 25.68 48.8 33.1
2018 25.67 48.2 33.2
2019 25.67 47.6 33.2
2020 25.66 47.0 33.3
2021 25.59 47.0 33.4
2022 25.52 47.0 33.4
2023 25.45 47.0 33.5
2024 25.38 47.0 33.6
2025 25.31 47.0 33.7
2026 25.21 47.0 33.7
2027 25.11 47.0 33.7
2028 25.01 47.0 33.6
2029 24.91 47.0 33.6
2030 24.82 47.0 33.6
</TABLE>
(1) Energy price realized during hours of dispatch, i.e., expressed at Red Oak
capacity factor.
(2) Sum of realized energy price and capacity price at Red Oak
capacity factor.
A-1
<PAGE>
HIGH GAS CASE ANNUAL PRICE RESULTS
<TABLE>
<CAPTION>
Year Red Oak Realized All-Hour Energy PJM Capacity Price (98$/kW/yr) Red Oak Firm Price(2)(98$/MWh)
Price(1)(98$/MWh)
<S> <C> <C> <C>
2002 27.98 52.0 35.8
2003 28.28 53.9 36.4
2004 28.59 55.9 37.0
2005 28.90 58.0 37.7
2006 29.03 56.5 37.6
2007 29.16 55.1 37.5
2008 29.28 53.7 37.4
2009 29.41 52.3 37.3
2010 29.54 51.0 37.3
2011 29.51 51.0 37.3
2012 29.48 51.0 37.3
2013 29.45 51.0 37.3
2014 29.41 51.0 37.3
2015 29.38 51.0 37.3
2016 29.37 50.2 37.3
2017 29.36 49.4 37.3
2018 29.34 48.6 37.3
2019 29.33 47.8 37.3
2020 29.32 47.0 37.3
2021 29.24 47.0 37.5
2022 29.17 47.0 37.6
2023 29.09 47.0 37.8
2024 29.02 47.0 38.0
2025 28.94 47.0 38.2
2026 28.78 47.0 38.0
2027 28.63 47.0 37.9
2028 28.47 47.0 37.7
2029 28.32 47.0 37.6
2030 28.16 47.0 37.5
</TABLE>
(1) Energy price realized during hours of dispatch, i.e., expressed at Red Oak
capacity factor.
(2) Sum of realized energy price and capacity price at Red Oak
capacity factor.
A-2
<PAGE>
LOW GAS CASE ANNUAL PRICE RESULTS
<TABLE>
<CAPTION>
Year Red Oak Realized All-Hour Energy PJM Capacity Price (98$/kW/yr) Red Oak Firm Price(2)(98$/MWh)
Price(1)(98$/MWh)
<S> <C> <C> <C>
2002 27.98 52.0 35.8
2003 28.28 53.9 36.4
2004 28.59 55.9 37.0
2005 28.90 58.0 37.7
2006 29.03 56.5 37.6
2007 29.16 55.1 37.5
2008 29.28 53.7 37.4
2009 29.41 52.3 37.3
2010 29.54 51.0 37.3
2011 29.51 51.0 37.3
2012 29.48 51.0 37.3
2013 29.45 51.0 37.3
2014 29.41 51.0 37.3
2015 29.38 51.0 37.3
2016 29.37 50.2 37.3
2017 29.36 49.4 37.3
2018 29.34 48.6 37.3
2019 29.33 47.8 37.3
2020 29.32 47.0 37.3
2021 29.24 47.0 37.5
2022 29.17 47.0 37.6
2023 29.09 47.0 37.8
2024 29.02 47.0 38.0
2025 28.94 47.0 38.2
2026 28.78 47.0 38.0
2027 28.63 47.0 37.9
2028 28.47 47.0 37.7
2029 28.32 47.0 37.6
2030 28.16 47.0 37.5
</TABLE>
(1) Energy price realized during hours of dispatch, i.e., expressed at Red Oak
capacity factor.
(2) Sum of realized energy price and capacity price at Red Oak
capacity factor.
A-3
<PAGE>
OVERBUILD CASE ANNUAL PRICE RESULTS
<TABLE>
<CAPTION>
Year Red Oak Realized All-Hour Energy PJM Capacity Price (98$/kW/yr) Red Oak Firm Price(2)(98$/MWh)
Price(1)(98$/MWh)
<S> <C> <C> <C>
2002 21.39 47.0 27.1
2003 21.23 49.5 27.2
2004 21.07 52.2 27.4
2005 20.92 55.0 27.5
2006 20.96 54.8 27.6
2007 21.01 54.6 27.6
2008 21.05 54.4 27.7
2009 21.10 54.2 27.7
2010 21.15 54.0 27.8
2011 21.20 53.6 27.8
2012 21.25 53.2 27.8
2013 21.30 52.8 27.8
2014 21.35 52.4 27.8
2015 21.40 52.0 27.8
2016 21.41 51.2 27.8
2017 21.42 50.4 27.8
2018 21.44 49.6 27.8
2019 21.45 48.8 27.8
2020 21.46 48.0 27.8
2021 21.36 48.0 27.8
2022 21.27 48.0 27.8
2023 21.17 48.0 27.8
2024 21.08 48.0 27.8
2025 20.98 48.0 27.8
2026 20.95 48.0 27.9
2027 20.92 48.0 28.0
2028 20.89 48.0 28.1
2029 20.86 48.0 28.2
2030 20.83 48.0 28.4
</TABLE>
(1) Energy prices realized during hours of dispatch, i.e., expressed at Red Oak
capacity factor.
(2) Sum of realized energy price and capacity price at Red Oak
capacity factor.
A-4
<PAGE>
GAS PRICE COMPARISON (98$/MMBtu)
<TABLE>
<CAPTION>
Year Base Case High Gas Case Low Gas Case Overbuild Case
<S> <C> <C> <C> <C>
2002 2.59 3.10 2.10 2.59
2003 2.61 3.12 2.12 2.61
2004 2.64 3.14 2.14 2.64
2005 2.66 3.17 2.16 2.66
2006 2.68 3.19 2.19 2.68
2007 2.70 3.22 2.21 2.70
2008 2.73 3.24 2.24 2.73
2009 2.75 3.27 2.26 2.75
2010 2.78 3.29 2.29 2.78
2011 2.81 3.32 2.31 2.81
2012 2.83 3.34 2.34 2.83
2013 2.86 3.37 2.37 2.86
2014 2.89 3.40 2.40 2.89
2015 2.93 3.43 2.42 2.93
2016 2.95 3.45 2.45 2.95
2017 2.97 3.47 2.47 2.97
2018 2.99 3.50 2.49 2.99
2019 3.01 3.52 2.52 3.01
2020 3.03 3.55 2.54 3.02
2021 3.03 3.55 2.54 3.02
2022 3.04 3.55 2.54 3.02
2023 3.04 3.55 2.54 3.03
2024 3.04 3.55 2.53 3.03
2025 3.04 3.55 2.53 3.03
2026 3.04 3.55 2.53 3.03
2027 3.04 3.55 2.53 3.03
2028 3.04 3.55 2.53 3.03
2029 3.03 3.55 2.53 3.03
2030 3.03 3.54 2.53 3.03
</TABLE>
A-5
<PAGE>
APPENDIX B
DEREGULATION OF THE ELECTRIC UTILITY INDUSTRY
STRUCTURE OF THE COMPETITIVE MARKET
The premise of this study is that all the facilities will primarily
function in a competitive, deregulated, commodity-oriented, wholesale power
business. This represents a change relative to most previous power projects in
the United States that were built under different, much more regulated
circumstances. The goal of this chapter is to describe the changes in the
business environment facing the facilities and future power plants making at
least some merchant sales, especially the change in the commercial risk. Later
chapters will describe the economics of the new business and the computer-based
market modeling performed as part of our analysis of the wholesale power market.
REGULATORY SETTING PRIOR TO EPACT (1992)
Prior to the start of deregulation, regulation was primarily conducted by
individual states. Most power was produced by vertically integrated,
investor-owned utilities. Regulators mandated cost-plus pricing of electricity
to retail customers who were only permitted to purchase power from the
state-franchised utility. Under cost-plus pricing, utilities were allowed to
charge prices sufficient to recover all prudently incurred costs of producing
electricity, including an allowed rate of return on equity capital in the firm.
Prices, or retail tariffs, were established through periodic rate case
proceedings, and remained fixed until the next proceeding. Throughout most of
the history of this system, cost-plus facilitated low cost corporate financing
of even very large power plants and other capital investments.
The regulatory lag between proceedings gave the utility some incentive to
maintain efficient operations. In addition, regulators attempted to mandate
utility action to decrease costs. However, by the late 1970s, policy-makers
became dissatisfied in part due to rising electricity prices and two other key
issues: (i) that cost-plus pricing failed to accommodate rapid technological
change, and (ii) it failed to penalize utilities for poor investment decisions.
The first major step towards deregulating electric utilities occurred with
the passage on the federal level of the Public Utilities Regulatory Policies Act
(PURPA). Secondarily, there also was the passage of the Power plant and
Industrial Fuel Use Act; both laws were passed in 1978. The key element of PURPA
was the requirement that utilities connect qualifying facilities (QFs), a
category including coal and renewable-fuel based generation facilities, to the
transmission grid and to purchase the power at or below the utilities' avoided
cost (e.g., the variable and/or fixed costs the utility would have incurred to
build and/or operate their own power plants). Utilities were also required to
offer stand-by power to QFs at non-discriminatory rates.
B-1
<PAGE>
The Power Plant and Industrial Fuel Use Act barred the use of fuel oil and
natural gas in new utility power plant facilities, forcing utilities to look to
QFs and Independent Power Producers (IPPs) for supplemental peak-load
requirements. Indeed, this entire move to keep utilities from gas eventually
coincided with two key developments: (i) advances in small, easy to operate jet
engine-based power-plants; and (ii) falling natural gas prices. Ultimately, the
fuel use act was repealed but not before the momentum of power plant
construction had shifted away from regulated utilities.
Qualifying facilities proliferated in several states at the urging of local
regulators which allowed them to enter into long-term contracts at prices equal
to the avoided cost determined by state regulators. The use of long-term
contracts allowed both QF and IPP projects to be heavily levered (most projects
were financed at debt/equity ratios of four) and obtain low cost non-recourse
project financing. By the early 1990s, as electricity demand growth continued,
most new construction was being met by non-utility projects.
The level of avoided costs, determined ex ante by regulators, was often
very high relative to actual market rates, providing limited benefits or often
excessive costs to ratepayers. This was in spite of low financing costs. As a
result, many states and FERC established competitive bidding systems to achieve
lower contract prices. Problems notwithstanding, PURPA demonstrated that
utilities could integrate non-utility generating sources (NUGs) into their
supply decisions as a reliable source of power and the financing could be made
available. Further, it clearly raised the prospect that generation was not a
natural monopoly and hence could be a deregulated competitive industry.
THE ROAD TO REGULATION
Wisconsin and New York were among the first states to start regulating electric
utilities in 1907. With the Public Utilities Holding Company Act of 1935,
multi-state holding companies were required to adopt simple corporate structures
which became subject primarily to state regulation. Asset acquisition was
confined to geographically defined areas and limited to utility-related
functions, and regulatory oversight was established to monitor transactions
among holding company affiliates. The Federal Water Power Act of 1920 and the
Federal Power Act of 1935 provided for the creation of the Federal Power
Commission (renamed the Federal Energy Regulatory Commission (FERC) in 1977)
whose purpose was to regulate transactions involving the interstate transmission
of electricity (among other duties). This practically restricted FERC to
regulating transactions between utilities. The FPC also had the power to order
interconnection among utilities. By the Post-World War II period, the country
had in place the mixed state-federal system described in this chapter.
COMPETITION AFTER EPACT
The Energy Policy Act (EPAct), enacted in 1992, addressed several key
barriers to competition. Prior to EPAct, the non-utility generator was
prohibited from using transmission to reach other buyers, and hence faced only
one buyer - i.e., transmission was not subject to common carrier status. EPAct
required transmission-owning utilities to deliver power from generators to other
utilities and electric wholesale customers at reasonable, non-discriminatory,
cost-based rates. The Act also provided for Exempt Wholesale Generators (EWGs),
which are exempt from PURPA requirements on both fuel use and the corporate
structure required under PUHCA, and were allowed to sell their power at
market-determined prices. They essentially provided access to transmission for
practically any new power plant. FERC Orders 888 and 889 were issued to
implement the provisions of EPAct and required utilities to file their
transmission
B-2
<PAGE>
tariffs with the FERC. Also, a separate decision by FERC opened power trading to
non-utilities creating the wholesale power marketing industry. FERC's swift
issuance of rather complex orders was facilitated by its prior deregulation of
the natural gas transmission industry. Overall, EPAct and FERC action laid the
foundations required for the creation of deregulated wholesale power markets.
During this period FERC did not attempt to change end-user regulations, in
deference to the authority of state regulators. However, aggressive FERC action
set off a major change in state regulation, promising to further change the
generation business. Today many state utility commissions and legislatures are
in various stages of advancing their own deregulation plans. Most restructuring
efforts allow limited or full access to end user consumers, with transmission
and distribution systems regulated as common carriers. Under this arrangement,
so-called "aggregators" or "marketers" act as intermediaries between generators
and customers by aggregating customer loads and arranging with generators to
meet the aggregate demand. This further supports new power plant construction
since the buy side is thus opened.
In order to achieve a level playing field, many states are also trying to
require the establishment of an Independent System Operator (ISO) responsible
for the unbiased dispatch of power, and/or a Power Exchange (PX) in which prices
and quantities of power are determined.
IMPACT OF STRANDED COSTS
Under cost-plus pricing, utilities were allowed to depreciate their assets
and earn returns without regard to changes in the actual market value.
Deregulation could change this. Under deregulation and current market
conditions, many of the generation plants currently insulated by cost-plus
pricing to franchised end use customers would show negative cash flows based on
the remaining, undepreciated asset balances. The undepreciated assets that would
not likely be recovered in a competitive environment are called "stranded
assets." In addition, as mentioned, a large number of the contracts with both
QFs and IPPs were priced prior to the deflation of energy prices after 1986, or
used a level of avoided cost well above current market prices. If utilities
holding such contracts were opened to competition, they would be forced to
purchase power at above-market prices. Utilities may also be required to incur
costs associated with specific environmental and social obligations mandated by
the state that would not be recoverable in a competitive environment.
The above market costs which result from deregulation are generally
referred to as "stranded costs." Some state deregulation plans allow for partial
or full recovery of stranded costs through non-bypassable competitive transition
or societal benefits charges levied by the distribution company. The charges may
continue until either all of the stranded costs have been recovered, or, in the
case of charges to cover environmental and social programs, until regulators
deem fit. Alternatively, regulators have set a transition period in which
utilities can ameliorate their stranded cost problem through continuing
depreciation and sales to end users at fixed above-market rates.
The recovery of stranded costs does not directly affect our analysis.
Competitive market prices and conditions reflect cash going forward, marginal
costs, not the resolution of sunk stranded costs. However, there are indirect
impacts of stranded cost recovery. For example, it has implications for retail
prices and the market demand for electricity. For example, with only
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partial stranded cost recovery, lower retail prices may result which, in turn,
may result in increased demand. The likely result of higher demand is
accommodated in ICF's analysis, which has often rejected utility growth
projections as being too low for this and other reasons.
Additionally, resolution of stranded cost recovery is associated with other
aspects of deregulation of the industry. These include rationalization of
generation; notably the shutdown of uneconomic plants whose cash costs cannot be
recovered but which are now insulated by cost plus regulation. This potentially
includes some nuclear units as well as some conventional steam fossil units. On
the other hand, full exposure to market incentives may result in modest upgrades
of plant availabilities and capacities and some tapping of underutilized coal
and repowering opportunities. On net, we have modeled some moderate changes or
potential for changes; see later discussion.
We do not believe, contrary to some public views, that treatment of
stranded cost will result in widespread bankruptcy. However, even if it did, the
operational and price effects should still be limited.
Another related issue is divestiture of generation. In order to value
assets and stranded costs, states are encouraging sales of generation assets.
This also decreases market power. This analysis assumes a competitive market and
to the extent this is not true, long-run prices and plant revenues could be
higher.
SELECT ADDITIONAL DEREGULATION ISSUES
FERC is also considering additional issues related to transmission. Chief
among these relates to the treatment of congestion. This study anticipates
congestion to a large degree by incorporating transmission constraints between
regions. Also, FERC is considering additional aggregation of regions into
regional ISOs. This is also anticipated in our analysis, which assumes regional
consolidation of tariffs.
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PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Section 18-108 of the Delaware Limited Liability Company Act provides
that subject to the standards and restrictions, if any, as are described in its
limited liability company agreement, a limited liability company may, and will
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.
Section 4.2 of our Limited Liability Company Agreement provides that we
will indemnify to the fullest extent permitted by the laws of the State of
Delaware, as from time to time in effect, the Directors and Officers of our
company.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Exhibit
NUMBER DESCRIPTION
3 Amended and Restated Limited Liability Company Agreement, dated as
of November 23, 1999 by AES Red Oak, L.L.C.
4.1(a) Trust Indenture, dated as of March 1, 2000, by and among AES
Red Oak, L.L.C., the Trustee and the Depositary Bank.
4.1(b) First Supplemental Indenture, dated as of March 1, 2000, by and
among AES Red Oak, L.L.C., the Trustee and the Depositary Bank.
4.2 Collateral Agency and Intercreditor Agreement, dated as of March 1,
2000, by and among AES Red Oak, L.L.C., the Trustee, the Collateral
Agent, the Debt Service Reserve Letter of Credit Provider, the Power
Purchase Agreement Letter of Credit Provider, the Working Capital
Provider and the Depositary Bank.
4.3 Debt Service Reserve Letter of Credit and Reimbursement Agreement,
dated as of March 1, 2000, by and among AES Red Oak, L.L.C., the
Debt Service Reserve Letter of Credit Provider and the Banks named
therein.
4.4 Power Purchase Agreement Letter of Credit and Reimbursement
Agreement, dated as of March 1, 2000, by and among AES Red Oak,
L.L.C., the Power Purchase Agreement Letter of Credit Provider and
the Banks named therein.
4.5 Global Bond, dated March 15, 2000, evidencing 8.54% Senior Secured
Bonds of AES Red Oak, L.L.C., Series A due 2019 in the principal
amount of $224,000,000.
4.6 Global Bond, dated March 15, 2000, evidencing 9.20% Senior Secured
Bonds of AES Red Oak, L.L.C., Series B due 2029 in the principal
amount of $160,000,000.
4.7 Equity Subscription Agreement, dated as of March 1, 2000, by and
among AES Red Oak, L.L.C., AES Red Oak, Inc. and the Collateral
Agent.
4.8 Working Capital Agreement, dated as of March 1, 2000, by and among
AES Red Oak, L.L.C., Working Capital Provider, and the Banks named
therein.
4.9 Security Agreement, dated as of March 1, 2000, by and between AES
Red Oak, L.L.C. and the Collateral Agent.
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4.10 Pledge and Security Agreement, dated as of March 1, 2000, by and
between AES Red Oak, Inc. and the Collateral Agent.
4.11 Pledge and Security Agreement, dated as of March 1, 2000, by and
between AES Red Oak, L.L.C. and the Collateral Agent.
4.12 Consent to Assignment, dated as of March 1, 2000, by and between
Williams Energy Marketing & Trading Company and the Collateral
Agent, and consented to by AES Red Oak, L.L.C. (with respect to the
Power Purchase Agreement).
4.13 Consent to Assignment, dated as of March 1, 2000, by and between The
Williams Companies, Inc. and the Collateral Agent, and consented to
by AES Red Oak, L.L.C. (with respect to the PPA Guaranty)
4.14 Consent to Assignment, dated as of March 1, 2000, by and between
Raytheon Engineers & Constructors, Inc. and the Collateral Agent,
and consented to by AES Red Oak, L.L.C. (with respect to the EPC
Contract).
4.15 Consent to Assignment, dated as of March 1, 2000, by and between
Raytheon Company and the Collateral Agent, and consented to by AES
Red Oak, L.L.C. (with respect to the EPC Guaranty).
4.16 Consent to Assignment, dated as of March 1, 2000, by and between
Siemens Westinghouse Power Corporation and the Collateral Agent, and
consented to by AES Red Oak, L.L.C. (with respect to the Maintenance
Services Agreement).
4.17 Consent to Assignment, dated as of March 1, 2000, by and between AES
Sayreville, L.L.C. and the Collateral Agent, and consented to by AES
Red Oak, L.L.C. (with respect to the Development and Operations
Services Agreement).
4.18 Consent to Assignment, dated as of March 1, 2000, by and between
Jersey Central Power and Light Company d/b/a/ GPU Energy and the
Collateral Agent, and consented to by AES Red Oak, L.L.C. (with
respect to the Interconnection Agreement).
4.19 Consent to Assignment, dated as of March 1, 2000, by and between the
Borough of Sayreville and the Collateral Agent, and consented to by
AES Red Oak, L.L.C. (with respect to the Water Supply Agreement).
5 Opinion of Hunton & Williams regarding Legality.
10.1* Fuel Conversion Services, Capacity and Ancillary Services Purchase
Agreement, dated as of September 17, 1999, and Amendment No. 1 to
Fuel Conversion Services, Capacity and Ancillary Services Purchase
Agreement, dated as of February 21, 2000, by and between AES Red
Oak, L.L.C. and Williams Energy Marketing & Trading Company.
10.2* Agreement for Engineering, Procurement and Construction Services,
dated as of October 15, 1999, and Amendment No. 1 to Agreement for
Engineering, Procurement and Construction Services, dated as of
February 23, 2000 by and between AES Red Oak, L.L.C. and Raytheon
Engineers & Constructors, Inc.
10.3* Guaranty, dated as of October 15, 1999, by Raytheon Company in favor
of AES Red Oak, L.L.C. (included as appendix L to Exhibit 10.2)
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10.4* Maintenance Program Parts, Shop Repairs and Scheduled Outage TFA
Services Contract, dated as of December 8, 1999, and amendment
No. 1, dated February 15, 2000, by and between AES Red Oak, L.L.C.
and Siemens Westinghouse Power Corporation.
10.5* Development and Operations Services Agreement, dated as of March 1,
2000, by and between AES Sayreville, L.L.C. and AES Red Oak, L.L.C.
10.7 Water Supply Agreement, dated as of December 22, 1999, by and
between AES Red Oak, L.L.C. and the Borough of Sayreville.
10.8* Generation Facility Transmission Interconnection Agreement, dated as
of April 27, 1999, by and between Jersey Central Power & Light
Company d/b/a GPU Energy and AES Red Oak, L.L.C.
10.9 Mortgage, Security Agreement and Assignment of Leases and Income,
dated as of March 1, 2000, by and between AES Red Oak, L.L.C. and
the Mortgagee.
10.10 Assignment of Leases and Income, dated as of March 1, 2000, by and
between AES Red Oak, L.L.C. and the Collateral Agent.
10.11 Financial Agreement, dated as of December 3, 1999, by and between
AES Red Oak Urban Renewal Corporation and the Borough of Sayreville.
10.12 Promissory Note, dated as of March 15, 2000, of AES Red Oak Urban
Renewal Corporation to AES Red Oak, L.L.C.
10.13 Ground Lease Agreement, dated as of March 1, 2000, by and between
AES Red Oak, L.L.C. and AES Red Oak Urban Renewal Corporation.
10.14 Sublease Agreement, dated as of March 1, 2000, by and between AES
Red Oak Urban Renewal Corporation and AES Red Oak, L.L.C.
10.15 Memorandum of Ground Lease, dated as of March 1, 2000, by and
between AES Red Oak, L.L.C. and AES Red Oak Urban Renewal
Corporation.
10.16 Memorandum of Sublease, dated as of March 1, 2000, by and between
AES Red Oak Urban Renewal Corporation and AES Red Oak, L.L.C.
10.17 Construction Agency Agreement, dated as of March 1, 2000, by and
between AES Red Oak Urban Renewal Corporation and AES Red Oak,
L.L.C.
10.18 Leasehold Mortgage, Security Agreement and Assignment of Leases and
Income, dated as of March 1, 2000, by and between AES Red Oak Urban
Renewal Corporation and AES Red Oak, L.L.C.
10.19 Assignment of Mortgage, dated as of March 1, 2000, by AES Red Oak,
L.L.C. in favor of the Collateral Agent.
10.20 URC Security Agreement, dated as of March 1, 2000, by and between
AES Red Oak Urban Renewal Corporation and AES Red Oak, L.L.C.
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10.21 Assignment of Leases and Income, dated as of March 1, 2000, by and
between AES Red Oak Urban Renewal Corporation and AES Red Oak,
L.L.C.
10.22 Assignment of Assignment of Leases and Income, dated as of March 1,
2000, by AES Red Oak, L.L.C. in favor of the Collateral Agent.
10.23* Guaranty, dated as of March 1, 2000, by The Williams Companies,
Inc. in favor of AES Red Oak, L.L.C. (PPA Guaranty).
23.1 Consent of Stone & Webster.
23.2 Consent of ICF Resources Incorporated.
23.3 Consent of Hunton & Williams (contained in Exhibit 5).
23.4 Consent of Deloitte & Touche LLP.
24 Power of Attorney (included on the signature page of this
registration statement).
25 Statement of Eligibility and Qualification on Form T-1 of The Bank
of New York, as Trustee under the Indenture.
27 Financial Data Schedule.
99.1 Form of Letter of Transmittal.
99.2 Form of Letter to Clients.
99.3 Form of Letter to Registered Holders and DTC Participants.
99.4 Form of Notice of Guaranteed Delivery.
---------------------
* To be filed by amendment.
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 registration statement:
(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 described in the registration
statement. Notwithstanding the foregoing, any increase or
decrease in the volume of securities offered (if the total
dollar value of the securities offered 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 a 20% change in the maximum
aggregate offering price described in the "Calculation of
Registration Fee" table in the
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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 the
information in this Registration Statement.
2. That, for the purpose of determining any liability under the
Securities Act of 1933, each the post-effective amendment will be
deemed to be a new Registration Statement relating to the
securities offered therein, and the offering of the securities at
that time will 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. 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.
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 the
request, and to send the incorporated documents by first class mail or other
equally prompt means. This includes information contained in the documents filed
subsequent to the effective date of the registration statement through the date
of responding to the request.
D. 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 the indemnification is against public policy as expressed in the Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against the liabilities (other than the payment by the registrant of expenses
incurred or paid by a director, officer or controlling person of the registrant
in the successful defense of any action, suit or proceeding) is asserted by the
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 the indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
the issue.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as
amended, the registrant has duly caused this registration statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the
County of Arlington, and Commonwealth of Virginia, on June 29, 2000.
AES RED OAK, L.L.C.
By: /S/ JOHN RUGGIRELLO
------------------------------
John Ruggirello
POWER OF ATTORNEY
Each director and/or officer of the issuer whose signature appears
below hereby appoints John Ruggirello and Barry Sharp, and each of them
severally, as his attorney-in-fact to sign in his name and behalf, in any and
all capacities stated below, and to file with the SEC, any and all amendments,
including post-effective amendments, to this registration statement.
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed below by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
/S/ JOHN RUGGIRELLO President and Director June 29, 2000
-----------------------------------------------------
John Ruggirello
/S/ BARRY SHARP Director and Chief Financial June 29, 2000
----------------------------------------------------- Officer (and principal
Barry Sharp accounting officer)
Director June _____, 2000
-----------------------------------------------------
Roger Naill
</TABLE>
