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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JULY 25, 2000.
REGISTRATION NO. 333-96239
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
AMENDMENT NO. 3
TO
FORM S-4
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933
TENASKA GEORGIA PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
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DELAWARE 221100 47-0812088
(STATE OR OTHER JURISDICTION (PRIMARY STANDARD (I.R.S. EMPLOYER
OF INDUSTRIAL IDENTIFICATION NUMBER)
INCORPORATION OR ORGANIZATION) CLASSIFICATION CODE NUMBER)
</TABLE>
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1044 N. 115 STREET, SUITE 400 MICHAEL F. LAWLER
OMAHA, NEBRASKA 68154-4446 VICE PRESIDENT OF FINANCE AND TREASURER
(402) 691-9500 TENASKA GEORGIA PARTNERS, L.P.
(ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE 1044 N. 115 STREET, SUITE 400
NUMBER, INCLUDING AREA CODE, OF REGISTRANT'S OMAHA, NEBRASKA 68154-4446
PRINCIPAL EXECUTIVE OFFICES) (402) 691-9500
(NAME, ADDRESS, INCLUDING ZIP CODE, AND
TELEPHONE NUMBER, INCLUDING AREA CODE, OF
AGENT FOR SERVICE OF PROCESS)
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with a copy to:
TODD W. ECKLAND, ESQ.
WINTHROP, STIMSON, PUTNAM & ROBERTS
ONE BATTERY PARK PLAZA
NEW YORK, NEW YORK 10004
(212) 858-1000
------------------------
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE OF THE SECURITIES TO THE
PUBLIC: As soon as practicable after this Registration Statement becomes
effective.
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. / /
------------------------
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES
AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
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--------------------------------------------------------------------------------
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SUBJECT TO COMPLETION, DATED JULY 25, 2000
PROSPECTUS
THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY
NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER
TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE
SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
OFFER TO EXCHANGE OUR
9.50% SENIOR SECURED BONDS DUE 2030 THAT HAVE BEEN REGISTERED
UNDER THE SECURITIES ACT OF 1933
FOR ANY AND ALL OUTSTANDING
9.50% SENIOR SECURED BONDS DUE 2030
The Exchange Offer
- We will exchange all old bonds that are validly tendered and not validly
withdrawn for an equal principal amount of new bonds.
- We are relying on the position of the SEC staff in certain interpretive
letters to third parties providing that the new bonds will be freely
tradeable.
- You may withdraw tenders of old bonds at any time prior to the expiration
of the exchange offer.
- The exchange offer expires at 5:00 p.m., New York City time, on
, 2000, unless we extend the offer.
- An exchange of old bonds for new bonds will not constitute a taxable event
for U.S. federal income tax purposes.
The New Bonds
- The terms of the new bonds to be issued in the exchange offer are
substantially identical to the old bonds issued on November 10, 1999,
except that the new bonds will not contain terms with respect to transfer
restrictions or an increase in interest rate.
- No public market currently exists for the old bonds. We do not intend to
list the new bonds on any securities exchange and, therefore, no active
public market is anticipated.
YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE 31 OF THIS
PROSPECTUS BEFORE PARTICIPATING IN THE EXCHANGE OFFER.
---------------------
NEITHER THE SEC NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR
DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ADEQUACY OR ACCURACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
The date of this prospectus is , 2000.
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TABLE OF CONTENTS
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PAGE
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Important Notice About Information Presented in this
Prospectus................................................ ii
Prospectus Summary.......................................... 1
Risk Factors................................................ 31
Where You Can Find More Information......................... 39
Forward-Looking Statements.................................. 39
The Exchange Offer.......................................... 40
Use of Proceeds............................................. 50
Estimated Sources and Uses of Funds......................... 50
Selected Financial Information.............................. 51
Ratio of Earnings to Fixed Charges.......................... 52
Management of the Partnership............................... 52
Management of Tenaska Georgia, Inc.......................... 52
Affiliate Transactions...................................... 53
Management's Discussion and Analysis of Financial
Condition................................................. 54
Business and Regulatory Environment......................... 55
Energy Regulation........................................... 55
Description of the New Bonds................................ 58
Summary Description of Principal Financing Documents........ 64
Summary of Principal Project Documents...................... 102
Material United States Federal Income Tax Consequences...... 150
Plan of Distribution........................................ 154
ERISA Considerations........................................ 154
Litigation.................................................. 155
Legal Matters............................................... 155
Experts..................................................... 155
Miscellaneous............................................... 155
Index to Financial Statements............................... F-1
Report of Independent Public Accountants.................... F-2
Appendix A: Defined Terms................................... A-1
Appendix B: Independent Engineer's Report................... B-1
Appendix C: Independent Market Consultant's Report.......... C-1
</TABLE>
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IMPORTANT NOTICE ABOUT INFORMATION PRESENTED IN THIS PROSPECTUS
We have not authorized anyone to give you any information or to make any
representations about us or the transactions we discuss in this prospectus other
than those contained in this prospectus. If you are given any information or
representations about these matters that is not discussed in this prospectus,
you must not rely on that information. This prospectus is not an offer to sell
or a solicitation of an offer to buy securities anywhere or to anyone where or
to whom we are not permitted to offer or sell securities under applicable law.
The delivery of this prospectus does not, under any circumstances, mean that our
affairs have not changed since the date of this prospectus. It also does not
mean that the information in this prospectus is correct after this date.
We include cross-references in this prospectus to captions where you can
find further related discussions. The preceding Table of Contents provides the
pages on which these captions are located. For your convenience, a glossary of
technical terms used in this prospectus appears in Appendix A at the end of this
prospectus.
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PROSPECTUS SUMMARY
THIS SUMMARY CONTAINS BASIC INFORMATION ABOUT US AND ABOUT THE EXCHANGE
OFFER. IT DOES NOT CONTAIN ALL THE INFORMATION THAT IS IMPORTANT TO YOU. FOR A
MORE COMPLETE UNDERSTANDING OF OUR BUSINESS AND FINANCIAL STATUS AND THE
EXCHANGE OFFER, YOU SHOULD READ CAREFULLY THIS ENTIRE PROSPECTUS AND THE OTHER
DOCUMENTS THAT WE REFER YOU TO. INVESTORS SHOULD CONSIDER THE INFORMATION SET
FORTH UNDER "RISK FACTORS" PRIOR TO PARTICIPATING IN THE EXCHANGE OFFER.
FOR YOUR CONVENIENCE, A GLOSSARY OF THE TECHNICAL TERMS USED IN THIS
PROSPECTUS APPEARS IN APPENDIX A AT THE END OF THIS PROSPECTUS.
THE EXCHANGE OFFER
On November 10, 1999, we completed the private offering of our 9.50% Senior
Secured Bonds due 2030. We entered into an exchange and registration rights
agreement with Goldman, Sachs & Co., and TD Securities (USA) Inc. in the private
placement in which we agreed to deliver to you this prospectus and to complete
the exchange offer within 315 days after the date of original issuance of the
old bonds. You are entitled to exchange in the exchange offer your old bonds for
new bonds that are identical in all material respects to the old bonds except
that:
- the new bonds will be registered under the Securities Act of 1933;
- the new bonds will not be entitled to rights that are applicable to the
old bonds under the exchange and registration rights agreement; and
- the new bonds will not contain terms with respect to an increase in
interest rate.
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The Exchange Offer........................ We are offering to exchange up to $275.0 million
aggregate principal amount of 9.50% Senior Secured Bonds
due 2030 that have been registered under the Securities
Act of 1933 for up to $275.0 million aggregate principal
amount of 9.50% Senior Secured Bonds due 2030 that were
issued on November 10, 1999 in the private offering. Old
bonds may be exchanged in denominations of $100,000 and
integral multiples of $1,000 in excess thereof. We will
issue the new bonds promptly after the expiration of the
exchange offer.
Resales................................... Based on an interpretation by the SEC staff set forth in
no-action letters issued to third parties, we believe
that the new bonds issued under the exchange offer in
exchange for old bonds may be offered for resale, resold
and otherwise transferred by you (unless you are our
"affiliate" within the meaning of Rule 405 under the
Securities Act of 1933), without compliance with the
registration and prospectus delivery provisions of the
Securities Act of 1933, provided that you are not our
affiliate, that you are acquiring the new bonds in the
ordinary course of your business and that you have not
engaged in, do not intend to engage in, and have no
arrangement or understanding with any person to
participate in, a distribution of the new bonds.
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1
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All participating broker-dealers that receive new bonds
for their own accounts under the exchange offer in
exchange for old bonds that were acquired as a result of
market-making or other trading activity must acknowledge
that they will deliver a prospectus in connection with
any resale of the new bonds. See "PLAN OF DISTRIBUTION."
Any holder of old bonds who:
- is our affiliate,
- does not acquire new bonds in the ordinary course of
its business or
- tenders in the exchange offer with the intention to
participate, or for the purpose of participating, in a
distribution of new bonds,
cannot rely on the position of the SEC staff enunciated
in EXXON CAPITAL HOLDINGS CORPORATION, MORGAN STANLEY &
CO. INCORPORATED or similar no-action letters and, in
the absence of an exemption, must comply with the
registration and prospectus delivery requirements of the
Securities Act of 1933 in connection with the resale of
the new bonds.
Expiration Date; Withdrawal of Tenders.... The exchange offer will expire at 5:00 p.m., New York
City time, on , 2000, unless we decide to
extend it. We do not currently intend to extend the
expiration date, although we reserve the right to do so,
and we have agreed to use our reasonable best efforts to
commence and complete the exchange offer promptly but no
later than , 2000. A tender of old bonds under
the exchange offer may be withdrawn at any time prior to
the expiration date as provided in "THE EXCHANGE
OFFER--Withdrawal of Tenders." Any old bonds not
accepted for exchange for any reason will be returned
without expense to the tendering holder promptly after
the expiration or termination of the exchange offer.
Conditions to the Exchange Offer.......... The exchange offer is subject to customary conditions,
any of which we may waive, including if the exchange
offer would violate applicable law or any applicable
interpretation of the SEC staff or any action or
proceeding has been instituted or threatened with
respect to the exchange offer that 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 old bonds of any holder that has
not made the representations described under
"--Procedures for Tendering Old Bonds" below. The
exchange offer is not conditioned upon any minimum
aggregate principal amount of old bonds being tendered
for exchange. See "THE EXCHANGE OFFER--Conditions to the
Exchange Offer."
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2
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Procedures for Tendering Old Bonds........ If you wish to accept the exchange offer, you must
complete, sign and date the accompanying letter of
transmittal, or a copy of the letter of transmittal,
according to the instructions contained in this
prospectus and the letter of transmittal. You must also
mail or otherwise deliver the letter of transmittal, or
the copy, together with the old bonds and any other
required documents, to the exchange agent at the address
set forth on the cover of the letter of transmittal on
or prior to the expiration date. If you hold old bonds
through The Depository Trust Company and wish to
participate in the exchange offer, you must comply with
the Automated Tender Offer Program procedures of DTC, by
which you will agree to be bound by the letter of
transmittal. By signing or agreeing to be bound by the
letter of transmittal, you will represent to us that,
among other things:
- any new bonds that you receive will be acquired in the
ordinary course of your business;
- you have no arrangement or understanding with any
person or entity to participate in the distribution of
the new bonds;
- if you are a broker-dealer that will receive new bonds
for your own account in exchange for old bonds that were
acquired as a result of market-making activities, you
will deliver a prospectus, as required by law, in
connection with any resale of the new bonds; and
- you are not our "affiliate" as defined in Rule 405
under the Securities Act of 1933, or, if you are an
affiliate, you will comply with any applicable
registration and prospectus delivery requirements of
the Securities Act of 1933.
Delivery of New Bonds..................... In all cases, we will issue new bonds for old bonds that
we have accepted for exchange under the exchange offer
only after the exchange agent timely receives:
- old bonds or a timely book-entry confirmation of those
old bonds into the exchange agent's account at DTC; and
- a properly completed and duly executed letter of
transmittal and all other required documents or a
properly transmitted agent's message.
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3
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Special Procedures for Beneficial
Owners.................................. If you are a beneficial owner of old bonds that are
registered in the name of a broker, dealer, commercial
bank, trust company or other nominee and you wish to
tender those old bonds for exchange, you should contact
the registered holder promptly and instruct it to tender
those old bonds on your behalf. If you wish to tender
those old bonds yourself, you must either make
appropriate arrangements to re-register ownership of
those old bonds in your own name or obtain a properly
completed bond power from the registered holder. The
transfer of registered ownership to your own name may
take considerable time and you may not be able to
complete the transfer prior to the expiration date.
Guaranteed Delivery Procedures............ If you wish to tender your old bonds and your old bonds
are not immediately available or you cannot deliver your
old bonds, the letter of transmittal or any other
documents required by the letter of transmittal or
comply with the applicable procedures under DTC's
Automated Tender Offer Program on or prior to the
expiration date, you must tender your old bonds
according to the guaranteed delivery procedures set
forth in this prospectus under "THE EXCHANGE
OFFER--Guaranteed Delivery Procedures."
Effect on Holders of Old Bonds............ As a result of the making of, and upon acceptance for
exchange of all validly tendered old bonds under the
terms of, the exchange offer, we will have fulfilled a
covenant contained in the exchange and registration
rights agreement and, accordingly, we will not be
obligated to pay an increased interest rate as described
in the exchange and registration rights agreement. If
you are a holder of old bonds and do not tender your old
bonds in the exchange offer, you will continue to hold
the old bonds and you will be entitled to all the rights
and limitations applicable to the old bonds in the
indenture, except for any rights under the exchange and
registration rights agreement that by their terms
terminate upon the consummation of the exchange offer.
Consequences of Failure to Exchange....... All untendered old bonds will continue to be subject to
the restrictions on transfer provided for in the old
bonds and in the indenture. In general, the old bonds
may not be offered or sold unless registered under the
Securities Act of 1933, except under an exemption from,
or in a transaction not subject to, the Securities Act
of 1933 and applicable state securities laws. Other than
in connection with the exchange offer, we do not
currently anticipate that we will register the old bonds
under the Securities Act of 1933.
Material U.S. Federal Income Tax
Consequences............................ An exchange of old bonds for new bonds under the
exchange offer will not constitute a taxable event for
U.S. federal income tax purposes. See "MATERIAL UNITED
STATES FEDERAL INCOME TAX CONSEQUENCES."
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Use of Proceeds........................... We will not receive any proceeds from the issuance of
the new bonds in the exchange offer.
Exchange Agent............................ The Chase Manhattan Bank is the exchange agent for the
exchange offer. The address and telephone number of the
exchange agent are set forth in this prospectus under
"THE EXCHANGE OFFER--Exchange Agent."
</TABLE>
THE PARTNERSHIP
We were formed in April 1998 to develop, finance, construct, own or lease,
operate and maintain an electric generating plant in Heard County, Georgia that
will include six gas turbine-generators. This facility, together with all its
associated contracts and infrastructure that we may own and lease, is our
project. We do not engage and do not intend to engage in any business activities
other than those related to our project.
We are owned by Tenaska Georgia, Inc., our managing general partner, Diamond
Georgia, LLC, our general partner, and Tenaska Georgia I, L.P., our limited
partner. Our managing general partner owns 0.7% of our partnership interests,
our general partner owns 0.3% of our partnership interests, and our limited
partner owns the remaining 99%. Tenaska Energy, Inc., which is owned by
individual shareholders, owns all of the stock of our managing general partner.
Our managing general partner is also the managing general partner of, and owns a
1% general partner interest in, our limited partner. The remaining 99% of our
limited partner is owned by Tenaska Diamond, L.P., which is in turn owned by
Tenaska Energy, Inc., with a 35.20049% tracking interest in Tenaska Diamond's
share of our income and profits, Tenaska Georgia II, L.P., with a 34.49648%
tracking interest in Tenaska Diamond's share of our income and profits, and
Diamond Heard, L.P., with a 30.30303% tracking interest in Tenaska Diamond's
share of our income and profits.
None of our partners will have any obligation to pay the principal of or
premium, if any, or interest on the bonds. Our obligations to pay the principal
of and premium, if any, and interest on the bonds are obligations solely of the
partnership and are nonrecourse to the Development Authority of Heard County, to
any of our partners or affiliates or to any shareholder, partner, officer,
employee or director of the partnership, our partners or affiliates. Recourse on
the bonds is limited to the partnership and the collateral.
Tenaska, Inc., whose stock is also owned by Tenaska Energy, Inc., is an
energy project development and management services company specializing in
long-term ownership and operation of independent power generation, electricity
and natural gas marketing and natural gas supply and transportation systems.
Tenaska, Inc.'s affiliates are the majority owners and the managing general
partners of approximately 1,700 MW of energy related projects in active
development throughout the United States and internationally. Principals and
employees of Tenaska, Inc. have extensive career experience in the energy
industry, including the management and development of approximately 3,200 MW of
gas-fired electric generating plants and financing for $2.8 billion of energy
related projects. Tenaska, Inc.'s affiliates are the majority owners and the
managing general partners of five electrical generation facilities in the U.S.:
- an 830 MW, gas-fired, independent electrical generation facility under
construction in Grimes County, Texas;
- an 845 MW gas-fired independent electrical generation facility under
construction in Rusk County, Texas;
- a 245 MW gas-fired, combined-cycle cogeneration facility in Ferndale,
Washington;
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- a 223 MW, gas-fired combined-cycle cogeneration plant in Paris, Texas; and
- a 263 MW gas-fired combined-cycle cogeneration plant in Cleburne, Texas.
Other affiliates of Tenaska, Inc. are the lead developers and managers of a
gas-fired independent electrical generation facility with stated capacity of 586
MW under construction in Pakistan and an 83 MW hydro-electric facility under
construction in Bolivia. Tenaska, Inc.'s headquarters are located in Omaha,
Nebraska, with regional offices in Arlington, Texas and Calgary, Alberta.
Tenaska, Inc. has approximately 170 employees and consultants dedicated to
domestic and international power project development, ownership and operation,
fuel management, asset management and acquisitions.
We have been designated by the Federal Energy Regulatory Commission to be an
exempt wholesale generator under the Public Utility Holding Company Act of 1935.
As an exempt wholesale generator, we must be engaged exclusively in the business
of owning or operating an eligible facility and selling electricity at
wholesale. As an exempt wholesale generator, we are subject to the Federal Power
Act and to the jurisdiction of the Federal Energy Regulatory Commission with
respect to wholesale electric rates and other matters.
The bonds are not guaranteed by and are not obligations of our partners,
Tenaska Energy, Inc., Tenaska, Inc., or any other affiliate of our partners. You
may demand payment on the bonds only from us and your recourse for non-payment
is limited to the amount of the collateral.
THE DEVELOPMENT AUTHORITY OF HEARD COUNTY
The Development Authority of Heard County was created by the Board of
Commissioners of Heard County on January 3, 1972 under an activating resolution
authorized by an Act of the General Assembly of the State of Georgia for the
purpose of encouraging and promoting the expansion and development of industrial
and commercial facilities in Heard County, Georgia. The Development Authority
has issued, and we have purchased, the Development Authority's Taxable
Industrial Development Revenue Bonds (Tenaska Georgia Partners, L.P. Project),
Series 1999 on the same date and in the same principal amount as the old bonds,
to finance the development and construction of our project and other costs
described in this prospectus.
6
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MAJOR CONTRACTUAL RELATIONSHIPS
[CHART SHOWING CONTRACTUAL RELATIONSHIPS OMITTED]
7
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KEY PROJECT PARTICIPANTS
The table below indicates some of the principal participants in our project
and the partnership.
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Development Authority......... Development Authority of Heard County, which owns the
facility, the facility site and some related infrastructure
facilities and easements, and has leased them to us.
Zachry Construction........... Zachry Construction Corporation, the construction contractor
for the facility and its related electric interconnection
facilities.
PECO.......................... PECO Energy Company, our long-term power purchaser.
General Electric.............. General Electric Company, which will provide the six General
Electric PG7241 (FA) heavy-duty single shaft gas turbine-
generators that will be used to produce the electric energy
at the facility.
Operator...................... Tenaska Operations, Inc., a wholly owned subsidiary of
Tenaska, Inc. and the operator of our project.
Transco....................... Transcontinental Gas Pipe Line Corporation, which will
provide gas interconnection and metering facilities for our
project's gas pipeline.
Water Authority............... The Heard County Water Authority, the water supplier for the
facility.
Georgia Power................. Georgia Power Company, the owner and operator of the
electric interconnection facilities that will allow the
facility to be connected to the Georgia Integrated
Transmission System at 500 kV.
Willbros Engineers............ Willbros Engineers, Inc., the construction contractor for an
approximately one-mile pipeline to deliver natural gas from
the Transco interconnection to the facility site.
</TABLE>
Some of the parties described above (including PECO) or their affiliates,
including publicly held affiliates, file reports, proxy statements and other
information with the SEC. You may read and copy such reports, proxy statements
and other information at the SEC's public reference room in Washington, D.C.
Please call the SEC at 1-800-SEC-0330 for further information on the operation
of the public reference rooms. Such material may also be accessed electronically
at the SEC's web site on the Internet at http://www.sec.gov.
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THE PROJECT
OVERVIEW. The facility is expected to be an electric generating plant with
a stated summer rating of 936 MW. It will be located on a site near Georgia
State Highway 34 in Heard County, Georgia, approximately 40 miles southwest of
Atlanta. The facility will use natural gas to produce electric energy and will
use fuel oil as a back-up fuel. We expect the facility to serve as a peaking
facility, operating primarily during the summer months with very low capacity
factors during the remainder of the year.
Under our 29-year power purchase agreement, we will sell all of the
facility's net capacity and electrical output to PECO Energy Company and PECO
will provide us with natural gas and fuel oil. Under an Engineering, Procurement
and Construction Contract, or the EPC contract, Zachry Construction Corporation
will provide engineering, procurement and construction services with respect to
the facility and its related electric interconnection facilities. Under a
Contract for Purchase, or turbine contract, General Electric Company will
provide six General Electric PG7241 (FA) heavy-duty single shaft gas
turbine-generators that will be used to produce the electric energy at the
facility. On the date of issuance of the old bonds, the right to acquire the
turbine-generators under the turbine contract was assigned to Zachry
Construction, who acquired the turbine-generators as a part of its obligations
under our EPC contract. Other operations and maintenance services for our
project will be provided by Tenaska Operations, Inc. under an Operations and
Maintenance, or O&M, Agreement.
FACILITY LOCATION. The facility site lies in the middle of the Southern
Company transmission system, which extends from Mississippi to South Carolina
and from Tennessee to Florida. According to an analysis of the Southeast U.S.
power market prepared for us by Resource Data International, Inc. and included
in this prospectus as Appendix C, our project has many strong competitive
advantages and represents a low cost, highly competitive and much needed peaking
resource for the growing Southeastern power market.
Tenaska, Inc., the previous owner of the 101-acre facility site, conveyed it
to us concurrent with the issuance of the old bonds, and we transferred it,
together with related easements held by us, to the Development Authority.
EMCON, our environmental consultant, conducted a Phase I Environmental Site
Assessment of the facility site. EMCON found the facility site to be undeveloped
with no evidence of recognized adverse environmental conditions.
THE FACILITY. The facility, when completed, will include six
turbine-generators. Each turbine-generator contains an enclosed inlet air
filter, evaporative cooler, air compressor, dual fuel combustion system, power
turbine, 3,600 rpm 60 Hz generator and auxiliary systems. In each of the
turbine-generators, atmospheric air and water are delivered into the turbine
combustion chamber for NO(x) control when firing fuel oil. Fuel oil operation is
limited by the air permit to 57 million gallons in any consecutive 12 month
period and is expected to occur only when natural gas is not available. The
turbine-generators can be fueled by either natural gas or fuel oil, and will be
capable of switching fuels while operating at reduced capacity.
POWER PURCHASE AGREEMENT. Our power purchase agreement with PECO provides
for completion of the facility in two stages of three turbine-generators each.
Our power purchase agreement is initially set to expire 29 years after the first
three turbine-generators are operational. The first three turbine-generators are
scheduled to be operational on June 1, 2001. The second three turbine-generators
are scheduled to be operational on June 1, 2002. These dates are subject to
adjustment to a limited extent in the case of a FORCE MAJEURE event. PECO is
responsible for supplying all the natural gas and fuel oil necessary to fulfill
our obligations under the power purchase agreement. PECO will have the ability
to dispatch any turbine-generator upon the turbine-generator achieving
operational status, as defined in our power purchase agreement.
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All of the capacity and energy produced by the facility is committed to be
sold to PECO, except for electricity that is used for the facility's own energy
needs. The power purchase agreement provides for some fixed payments, subject to
off-setting payments by us to PECO for reduced availability, an availability
incentive bonus and other variable payments. We expect that the fixed payments,
which are payable whether or not PECO chooses to dispatch any of the
turbine-generators, will be adequate to cover our debt service and our fixed
operating and maintenance costs and to provide us with a return on equity.
PECO is one of the largest retail utilities in the United States with
1,500,000 retail electric and more than 400,000 retail natural gas customers in
southeastern Pennsylvania. It is a leading nationwide wholesale marketer of
energy. On September 23, 1999, Unicom Corporation and PECO issued a joint press
release announcing that they, along with a wholly owned subsidiary of PECO, had
entered into an Agreement and Plan of Exchange and Merger, dated as of
September 22, 1999. Unicom is engaged predominantly in the business of electric
energy generation, transmission and distribution, through Commonwealth Edison
Company, one of its subsidiaries. The consummation of the proposed merger
between PECO and Unicom, in the manner currently reported to be effected, would
not affect the contractual rights and obligations of the material participants
in the financing, development, construction or operation of the partnership's
project.
The PECO Energy Power Team, a unit of PECO's Generation Division, was formed
in 1994 to market power across the United States. The PECO Energy Power Team
will be responsible for marketing the capacity and energy purchased from our
project.
EPC CONTRACT. Under our EPC contract, we are obligated to pay a fixed price
of $229,064,832, including the cost of the turbine-generators under the turbine
contract, to Zachry Construction for the construction of the facility and its
related electric interconnection facilities, subject to increase for scope
changes. More than 70% of the value of our EPC contract is represented by the
cost of turbine-generators purchased under the turbine contract. Construction of
the facility began in March 2000. Our EPC contract contains liquidated damages
provisions for late completion and for failure to meet various performance
guarantees. Zachry Construction's aggregate liability for liquidated damages for
such late completion and for failure to meet the performance guarantees is
limited to 30% of the fixed price of $229,064,832. On September 10, 1999, we
delivered to Zachry Construction a limited notice to proceed which authorized
the commencement of geotechnical investigations and engineering and procurement
activities by Zachry Construction. We delivered to Zachry Construction full
notice to proceed on the date of issuance of the old bonds. Zachry
Construction's obligations under our EPC contract are guaranteed by its parent
company, H.B. Zachry Company. Zachry Construction has provided a payment and
performance bond in the amount of $229,064,832 issued by United States Fidelity
and Guaranty Company.
Zachry Construction is a wholly owned subsidiary of H.B. Zachry Company. As
of December 31, 1998, H.B. Zachry Company had annual revenues, total assets and
stockholders' equity of approximately $670 million, $150 million and
$100 million, respectively. H.B. Zachry Company and its affiliates have
constructed over 29,000 MW of power plants both domestically and
internationally, including 8,000 MW of combustion turbines and 1,130 MW of
combustion turbines.
TURBINE CONTRACT. Our limited partner had previously acquired rights to
purchase the turbine-generators from General Electric. The turbine contract was
assigned to Zachry Construction at cost, resulting in approximately
$33.6 million in savings over recent market prices. As assignee of the turbine
contract, Zachry Construction acquired the turbine-generators. The turbine
contract requires the turbine-generators to be delivered in installments
beginning September 30, 2000 and continuing through December 15, 2001. General
Electric is obligated to pay damages to Zachry Construction for unexcused late
delivery of the turbine-generators and if the performance of the
turbine-generators is not as
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required under the turbine contract. General Electric will also issue various
warranties in connection with the performance of the turbine-generators.
OPERATIONS AND MAINTENANCE AGREEMENT. We entered into the O&M agreement
with Tenaska Operations, Inc. on September 10, 1999 for the operation and
maintenance of our project. The O&M agreement has a term of 29 years from the
date of commercial operation of the first three turbine-generators. Tenaska
Operations is obligated to provide all services necessary for the safe and
reliable start-up, commissioning, operation and maintenance of our project.
Tenaska Operations will be compensated with a fixed management fee and an
incentive fee, with an availability adjustment based on performance.
Tenaska Operations is a wholly-owned subsidiary of Tenaska, Inc. Tenaska
Operations was formed to provide operations and maintenance services to electric
generating facilities in which affiliates of Tenaska, Inc. have an interest.
Under the O&M agreement, the Tenaska Operations is obligated to provide initial
start-up support for our project prior to the date of commercial operation of
the first three turbine-generators, operate and maintain the first three
turbine-generators once they achieve commercial operation and operate and
maintain our completed project. Tenaska Operations is obligated to provide
skilled personnel, procedures, training, administrative, management, and
professional and technical services necessary for the safe and reliable
start-up, commissioning, operation and maintenance of our project.
Tenaska Operations currently manages and administers operating and
maintenance contracts for a 223 MW plant in Paris, Texas; a 245 MW plant in
Ferndale, Washington; and a 263 MW plant in Cleburne, Texas. In addition to our
project, Tenaska Operations also has contracts to operate two additional
facilities currently under construction in Texas that will have a combined
capacity of 1,675 MW. All of the above-mentioned plants are facilities fueled by
natural gas.
FUEL ARRANGEMENTS. PECO is obligated to supply us with all the fuel
necessary to produce electric energy for PECO. We entered into the Interconnect,
Reimbursement and Operating Agreement with Transcontinental Gas Pipe Line
Corporation. Under this agreement, Transco will install and own metering
facilities for an interconnection between Transco's pipeline and a lateral gas
pipeline to be constructed to deliver natural gas from this interconnection
point to the facility site. The gas pipeline will be part of the property owned
by the Development Authority and leased to us and will be designed, constructed
and installed under a Fixed Price Engineering, Procurement and Construction
Contract between us and Willbros Engineers, Inc.
Fuel oil will be delivered to the facility site by truck and stored in a
165,000 barrel storage tank. We expect this quantity to be sufficient to operate
all six turbine-generators for over 80 hours at full capacity. Four fuel oil
unloading stations will be constructed to enable the facility to operate on fuel
oil for extended periods of time, should the need arise, subject to air permit
restrictions.
ELECTRIC INTERCONNECTION ARRANGEMENTS. The facility will be interconnected
to the Georgia Integrated Transmission System under our interconnection
agreement with Georgia Power Company. The interconnection facilities are being
designed, procured and constructed under our EPC contract. It will consist of
equipment operating at 500 kV at the high-side of the step-up transformers, and
will include a new 500 kV substation and modification of the Wansley to Fortson
500 kV transmission line. The Georgia Integrated Transmission System consists of
the aggregate of the Georgia transmission assets of Georgia Power, Georgia
Transmission Corporation and two other participants, and was created through
bilateral contracts between Georgia Power on the one hand, and each of the other
three participants on the other hand. The point of interconnection of the
facility is on a portion of the transmission system owned and maintained by
Georgia Transmission Corporation.
WATER AND WASTEWATER ARRANGEMENTS. The facility will require water to
operate the evaporative coolers of the turbine-generators and to operate the
turbine-generators on fuel oil. We will purchase
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our water from the Heard County Water Authority, a public body corporate and
politic formed under Georgia law in 1984, under a water purchase agreement. The
water agreement has a term of 30 years. We expect that the water in the storage
tanks combined with the 350 gallons per minute of water supplied by the Heard
County Water Authority under the water agreement will provide sufficient water
to operate the turbine-generators on fuel oil for approximately 160 hours over a
two-week period. A small amount of wastewater will be produced when the
evaporative coolers are used or when fuel oil is fired. This wastewater will be
discharged into Hilly Mill Creek under the partnership's wastewater discharge
permit.
LEASE AGREEMENT. Simultaneously with the issuance of the old bonds, we
entered into a lease agreement with the Development Authority of Heard County.
Under the lease agreement, the Development Authority has agreed to lease the
facility, the facility site and some related infrastructure facilities and
easements to us and we have agreed to make rent payments sufficient to pay, when
due, the principal of and interest on the revenue bonds issued by the
Development Authority together with other payments that may be retained by the
Development Authority or paid by the Development Authority to Heard County. In
addition, we have agreed to guarantee the payment obligations of the Development
Authority on its revenue bonds.
AD VALOREM TAX AGREEMENT. In order to obtain various benefits primarily
related to local property taxation, we have entered into the Ad Valorem Taxation
Agreement with the Board of Commissioners of Heard County and the Board of Tax
Assessors of Heard County. While the tax agreement is in effect, the facility,
the facility site and some related infrastructure facilities and easements will
not be subject to ad valorem taxation because they will be owned by the
Development Authority. However, our leasehold interest will be subject to ad
valorem taxes. The tax agreement sets forth how our interest under the lease
agreement will be valued before the completion of construction, and for the
20-year period following the year in which the facility is completed.
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THE NEW BONDS
The following summary contains basic information about the new bonds. It
does not contain all the information that may be important to you. For a more
complete description of the new bonds, please refer to the section of this
prospectus entitled "DESCRIPTION OF THE NEW BONDS."
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The Issuer................................ Tenaska Georgia Partners, L.P.
The Bonds................................. $275,000,000 aggregate principal amount of 9.50% Senior
Secured Bonds due 2030.
Conduit Financing......................... To obtain benefits primarily related to local property
taxation, the Development Authority of Heard County, a
public corporation created and existing under the laws
of the State of Georgia, owns the facility, the facility
site and some related facilities and easements. The
Development Authority issued, and we have purchased with
the proceeds of the old bonds, revenue bonds issued by
the Development Authority.
These revenue bonds are secured by a mortgage on the
facility, the facility site and some related facilities
and easements and by the Development Authority's rights
in the lease agreement and the Guaranty, described
above. These revenue bonds have been issued in the same
principal amount as, and bear interest at the same rate
as, the bonds, and are redeemable at our option as their
holder. We have agreed to redeem these revenue bonds in
a principal amount equal to any principal amount of the
bonds redeemed. We delivered these revenue bonds and
related security to The Chase Manhattan Bank, as
collateral agent, as security for the bonds and other
senior debt, and the Development Authority transferred
the proceeds of these revenue bonds to The Chase
Manhattan Bank, as collateral agent, for deposit in a
special construction fund, as described below in this
prospectus. Payments made by us in respect of principal
and interest on the bonds will be deemed to be a payment
of, and will also reduce a like amount of, principal and
interest due on these revenue bonds and corresponding
amounts due under the lease agreement.
Senior Financing
Arrangements............................ On the date of the original issuance of the old bonds,
we incurred obligations with respect to the old bonds
and we issued or otherwise incurred other senior debt.
Ranking of the Bonds...................... The bonds rank:
- equally in right of payment, and entitled to the
benefit of the liens on the collateral, with present and
future senior debt, except in some circumstances as
described in this prospectus and
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- senior in right of payment to all subordinated debt.
Repayment of drawings under the debt service reserve
letter of credit and the power purchase agreement
letter of credit constitute senior debt and are
secured on a parity basis by the collateral, but
unless a trigger event has occurred, or some other
events have occurred, as described in this prospectus,
principal payments of reimbursement obligations in
respect of these drawings will be made at a lower
order of priority than payments of principal of other
senior debt, including the bonds.
Under some circumstances involving various delays in
repayment of the principal amount of these drawings, or
in the case of a trigger event, the reimbursement may be
made at the same level of priority as payments of
principal of the bonds. In addition, under some
circumstances involving non-renewal, failure to replace
or a rating downgrade of the debt service reserve letter
of credit provider, or non-renewal or failure to replace
of the power purchase agreement letter of credit, the
letter of credit may be drawn upon up to the full
available amount, and the principal repayments of these
drawings would be made at the same level of priority as
payments of principal of the bonds.
Principal amounts of debt service reserve letter of
credit drawings that have the same priority as the
principal of the bonds are referred to as debt service
reserve bonds if they have that priority because of
delays in making a reimbursement to the debt service
reserve letter of credit provider, and are referred to
as debt service reserve term loans if they have that
priority because they result from a drawing upon
non-renewal, failure to replace or a rating downgrade of
the debt service reserve letter of credit provider.
Principal amounts of power purchase agreement letter of
credit drawings that have the same priority as the
principal of the bonds are referred to as power purchase
agreement term loans. Principal amounts of drawings
under the debt service reserve letter of credit, other
than debt service reserve bonds or debt service reserve
term loans, are referred to as debt service reserve
letter of credit loans, and principal amounts of
drawings under the power purchase agreement letter of
credit, other than power purchase agreement term loans,
are referred to as power purchase agreement letter of
credit loans.
In this prospectus, debt service reserve letter of
credit loans, debt service reserve term loans and debt
service reserve bonds are referred to individually or
collectively as debt service reserve loans, and power
purchase agreement letter of credit loans and power
purchase agreement term loans are referred to
individually and collectively as power purchase
agreement loans.
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Collateral................................ The bonds and the other senior debt are senior secured
debt obligations of ours secured on a rated basis by a
lien on and security interest in:
- our interest in all real property leased to and
easements held by us,
- all personal property owned by or leased to us,
equipment, various insurance policies and other tangible
and intangible assets,
- all of our right, title and interest in and to all
project documents,
- all of our revenues,
- all funds and sub-accounts established by us under the
collateral agency agreement,
- an assignment of all proceeds in respect of any
property insurance policy covering the partnership or
our project or all proceeds in respect of any action
to condemn, seize or appropriate all or any part of
our project, other than with respect to third party
liability insurance and worker's compensation,
- the revenue bonds issued by the Development Authority
of Heard County and all related security granted to The
Chase Manhattan Bank, as trustee under the related
indenture to secure these revenue bonds, including the
mortgage on the Development Authority's interest in
the facility, the facility site and some related
infrastructure facilities and easements, the
Development Authority's rights under our lease
agreement and the related rents, but not including
various payments to be retained by the Development
Authority or to be paid to Heard County, and the
Development Authority's rights to enforce various
covenants, and the partnership's guaranty of the
revenue bonds,
- all of our rights to receive equity contributions
including our rights in any guarantees or other security
for those equity contributions,
- all permits and other governmental approvals to the
extent permitted by law, and
- the equity interests of our partners in the
partnership.
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In addition, the bonds are secured by an exclusive lien
on and security interest in the funds and accounts
established under the Indenture, the debt service
reserve account and the debt service reserve letter of
credit, other than to the extent of the debt service
reserve letter of credit provider's right to various
proceeds thereunder.
Non-Recourse Obligations.................. Our obligations to pay the principal of and premium, if
any, and interest on the bonds are obligations solely of
the partnership and are nonrecourse to the Development
Authority of Heard County, to any of our partners or
affiliates or to any shareholder, partner, officer,
employee or director of the partnership, our partners or
affiliates. Recourse on the bonds is limited to the
partnership and the collateral.
Ratings................................... "BBB" by Standard & Poor's Ratings Group, or S&P, and
"Baa3" by Moody's Investors Service, Inc., or Moody's.
Interest Payment Dates.................... Semi-annually in arrears on each February 1 and August
1, commencing August 1, 2000, and at earlier redemption.
Denominations............................. We will issue the new bonds in denominations of $100,000
and integral multiples of $1,000 in excess thereof.
Use of Proceeds........................... We will not receive any cash proceeds from the issuance
of the new bonds. In consideration for issuing the new
bonds as contemplated in this prospectus, we will
receive in exchange old bonds in like principal amount,
which will be cancelled and as these will not result in
any increase in our indebtedness.
Average Life.............................. At the time the old bonds were originally issued, the
average life of the bonds was initially approximately
22.8 years.
Equity Commitment......................... The partners have committed to fund up to $35.5 million,
to be funded when and as required to pay project costs
upon and after the earlier to occur of:
- the expenditure of all proceeds of the revenue bonds
issued by the Development Authority of Heard County and
all other amounts available in the special
construction fund, as described below in this
prospectus and
- the occurrence and continuation of a defaulting event
under the collateral agency agreement prior to the date
of commercial operation of the three final three
turbine-generators which will not be earlier than June
1, 2002.
The obligation of partners contributing equity to the
partnership are supported by a letter of credit from a
bank or financial institution rated at least "A" by S&P
and "A2" by Moody's or by a corporate guarantee,
provided the guarantor is rated at least investment
grade by S&P and Moody's and has a minimum net worth of
$100,000,000.
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Scheduled Principal Payments.............. The principal of the bonds is payable in semi-annual
installments commencing February 1, 2006, on each
February 1 and August 1 to the registered owners on the
immediately preceding record date as set forth under
"DESCRIPTION OF THE BONDS--General" and "--Scheduled
Principal Payments."
Optional Redemption....................... We may redeem any of the bonds at any time at a
redemption price equal to the sum of:
- 100% of the principal amount of the bonds redeemed,
- accrued and unpaid interest on the bonds redeemed and
- a premium based on rates of comparable treasury
securities, plus 50 basis points.
Mandatory Redemptions..................... EVENTS OF LOSS. Notwithstanding the priorities of
payment set forth in "--Flow of Funds" below, upon an
event of loss, damage, destruction, condemnation,
seizure or appropriation of our project, we will,
subject to some exceptions and conditions, use insurance
or condemnation proceeds actually received by us that
are not used to repair or replace our project, on a
ratable basis, to redeem bonds in whole or in part at a
redemption price equal to 100% of the principal amount
of the bonds redeemed, plus accrued and unpaid interest
on the bonds redeemed, and to prepay all or a portion of
our other senior debt.
EPC BUY-DOWN. Notwithstanding the priorities of payment
set forth in "--Flow of Funds" below, upon the receipt
by the partnership of proceeds of liquidated damages for
performance failures under our EPC contract, and subject
to some exceptions and conditions, we will use proceeds
actually received by us that are not used to repair,
modify or replace our project, on a ratable basis, to
redeem bonds in whole or in part at a redemption price
equal to 100% of the principal amount of the bonds
redeemed, plus accrued and unpaid interest on the bonds
redeemed, and to prepay all or a portion of our other
senior debt.
ENERGY CONTRACT BUY-OUTS. Notwithstanding the priorities
of payment set forth in "--Flow of Funds" below, upon
receipt of the proceeds of a buyout of our power
purchase agreement or another contract for the sale of
power from the facility, we will apply those proceeds as
follows:
- in the case of proceeds received by us upon the
exercise by PECO of its option to terminate our power
purchase agreement effective on the 20th anniversary
of the commencement of the operating term of our power
purchase agreement,
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first, to redeem bonds in whole or in part at a
redemption price equal to the principal amount of the
bonds redeemed, plus accrued and unpaid interest on
the bonds redeemed and
second, subject to some exceptions and conditions, to
prepay all or a portion of our other senior debt; and
- in the case of proceeds of any involuntary buyout of
our power purchase agreement or any other contract for
the sale of power from the facility and subject to
some exceptions and conditions, on a ratable basis, to
redeem bonds in whole or in part at a redemption price
equal to the principal amount of the bonds redeemed,
plus accrued interest on the bonds redeemed, and to
prepay all or a portion of our other senior debt.
BLOCKED PARTNER DISTRIBUTIONS. Notwithstanding the
priorities of payment set forth in "--Flow of Funds"
below, if amounts have been on deposit in the
distribution suspense account,"as described in this
prospectus below, for eighteen months after a default or
an event of default under our financing documents or a
failure by us to satisfy the debt service coverage
ratios required to distribute profits to our partners,
we will, under certain conditions, use these monies, on
a ratable basis, to redeem bonds in whole or in part at
a redemption price equal to the principal amount of the
bonds redeemed, plus accrued and unpaid interest on the
bonds redeemed, and to prepay our other senior debt.
This redemption and prepayment will occur only if the
required senior parties, which generally means the
affirmative vote of 51% of the aggregate principal
amount of our senior debt, elect to have these amounts
so applied following our request that the required
senior parties determine whether these funds will be
used to redeem bonds and to prepay our other senior debt
or will be released for distribution to the partners.
Permitted Indebtedness.................... In addition to the issuance of the bonds, the common
agreement permits us to incur:
- indebtedness in respect of the bonds issued by the
Development Authority, the lease agreement and the
guaranty,
- reimbursement obligations in respect of the debt
service reserve letter of credit,
- reimbursement obligations in respect of the power
purchase agreement letter of credit,
- up to $10 million for working capital in connection
with our project,
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- indebtedness to make capital improvements to our
project to maintain compliance with applicable law or
our project documents if:
--an independent engineer certifies that the proposed
improvements are reasonably expected to enable our
project to comply with applicable laws and, after the
financing, the projected debt service coverage ratio
will not be less than 1.10 to 1.00 or
--we receive a confirmation of the then current ratings
of the bonds;
- up to $15 million for discretionary capital
improvements to our project, provided that after giving
effect to the incurrence of this indebtedness, there
is no current event of default, under the common
agreement, and we receive a confirmation of the then
current ratings of the bonds;
- up to $100,000 in respect of reimbursement obligations
under a letter of credit securing our obligations
under the Georgia Power interconnection agreement;
- up to $10 million of other indebtedness to pay for
project costs, operating and maintenance expenses or
capital expenditures for our project; and
- up to $20 million of indebtedness of the partnership
subordinated to the bonds and the other senior debt.
The provisions of the common agreement restrict the
terms on which we may incur obligations in respect of
subordinated debt, which will consist solely of
unsecured loans, from either our affiliates or third
parties, fully subordinated to the bonds and our other
senior debt as to payment and exercise of remedies under
the collateral agency agreement.
The indebtedness identified above is referred to as
permitted indebtedness and all permitted indebtedness
other than the reimbursement obligations under the
letter of credit described above securing our
obligations under the Georgia Power interconnection
agreement and the subordinated debt described above is
referred to as senior debt.
Principal Covenants....................... Subject to some exceptions, we have agreed to, among
other things:
- construct, operate and maintain our project in
compliance with our project documents;
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- obtain and maintain in full force and effect all
necessary government approvals and maintain the
partnership as an exempt wholesale generator under
Public Utility Holding Company Act of 1935;
- comply with applicable laws;
- obtain and maintain customary insurance; and
- pay and discharge all taxes, assessments, charges and
claims;
Subject to some exceptions, we have agreed not to, among
other things:
- make any distributions other than as permitted under
the collateral agency agreement;
- make any investments other than permitted investments;
- sell our assets;
- terminate, amend, modify or otherwise take or fail to
take certain actions with respect to our project
documents relating to our project;
- enter into non-arm's length transactions with our
affiliates;
- create any lien on our properties other than permitted
liens; or
- engage in activities other than those contemplated by
our project and financing documents.
Change in Control......................... An event of default under the common agreement will
occur if our partners cease collectively to maintain
control of the partnership unless we receive a
confirmation of the then current ratings of the bonds.
Control means the possession, directly or indirectly, of
the economic interest in or power to direct or cause the
direction of the management and policies of a person
through ownership of equity interests.
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Debt Service
Reserve Account......................... We are required to maintain a debt service reserve
account for the benefit of the holders of the bonds. On
or before June 1, 2002, this account will be funded by
cash and/or a letter of credit in an amount sufficient
to pay principal and interest on the bonds on the next
semi-annual payment date for the bonds initially to be
approximately $13.1 million, plus, if a debt service
reserve letter of credit is in effect, six months of
interest on the maximum amount of the debt service
reserve letter of credit. In this prospectus, we refer
to the amount of the required funding of the debt
service reserve account as the debt service reserve
required balance and to the issuer of the debt service
reserve letter of credit as the debt service reserve
letter of credit issuer.
We may use the amount in this account to satisfy our
payment obligations due with respect to the bonds in the
event of a shortfall in other available funds. The use
of the debt service reserve account to satisfy these
obligations will not, by itself, constitute an event of
default under the Indenture or the common agreement. The
debt service reserve letter of credit issuer will be a
commercial bank or other financial institution with a
long-term unsecured debt rating of at least "A-" from
S&P and "A3" from Moody's.
Reimbursement obligations incurred under the debt
service reserve letter of credit will constitute senior
debt and be secured on a parity basis with the bonds by
the collateral. However, unless a trigger event has
occurred and except to the extent the reimbursement
obligations consist of debt service reserve bonds or
debt service reserve term loans, payments in respect of
the principal amount of the reimbursement obligations
will be made in a lower order of priority than payments
of principal on other senior debt.
Partnership Distribution Conditions....... Except as stated below, and in certain other
circumstances as described in this prospectus, we may
make distributions to our partners from the partnership
distribution fund created under the collateral agency
agreement on any semi-annual payment date for the bonds
at least six months after the date of commercial
operation of the final three turbine-generators only if:
- there has been no default or event of default;
- the debt service coverage ratio for the historical two
semi-annual periods taken as one period, and the
projected debt service coverage ratio for the bonds
for the subsequent two semi-annual periods, taken as
one period, each equals or exceeds 1.2 to 1.0 for
ordinary distributions, or 1.15 to 1.0 in the case of
distributions in amounts equal to partner tax
liability in respect of partnership income;
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- the balance in the debt service reserve account,
including the amount available under any debt service
reserve letter of credit, is at least equal to the
debt service reserve required balance, and
- our partnership is not insolvent and would not be
rendered insolvent by the distribution.
With respect to any semi-annual payment date for the
bonds occurring prior to the first anniversary of the
date of commercial operation of the final three
turbine-generators, which will not be earlier than June
1, 2002, the debt service coverage ratio for the two
historical semi-annual periods will be the debt service
coverage ratio achieved for the period since the date of
commercial operation, not earlier than June 1, 2002, of
the final three turbine- generators, even though that
period may not include any complete semi-annual period.
If any of the conditions set forth above are not
satisfied, then the amounts on deposit in the
partnership distribution fund, created under the
collateral agency agreement, will be transferred to the
distribution suspense account instead of being
distributed to our partners.
Distributions may be made to our partners on any monthly
funding date after the date of commercial operation of
the final three turbine-generators if the partnership
certifies that each of the conditions set forth above is
satisfied and:
- the debt service coverage ratio for the historical two
semi-annual periods, taken as one period, and the
projected debt service coverage ratios for the
subsequent two semi-annual periods, taken as one
period, using the expired portion of the semi-annual
period in which the funding date occurs as the first
subsequent semi-annual period for the calculation,
equal or exceed 1.4 to 1.0 and
- sufficient cash will be available on the next
succeeding payment date for the bonds to make required
debt service payments on the bonds without giving
effect to, or drawing on, any funds available in the
debt service reserve account, the distribution
suspense account, the partnership distribution fund,
the unrestricted account, the subordinated debt
account or any working capital facility.
Funds held in the distribution suspense account will be
available to pay debt service on the bonds, or other
senior debt, and/or to fund required balances with
respect to any of our project funds.
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Amounts that have been on deposit in the distribution
suspense account for more than 18 months after a default
or event of default has occurred or is continuing, or if
the partnership has not met the required debt service
coverage ratios, may be paid out to the partnership if
the required senior parties, upon the request of the
partnership, have not elected that these amounts be
applied to the redemption of the bonds, without premium,
and ratable retirement of other senior debt.
Form of Bonds............................. New bonds will be represented by one or more global
securities in fully registered form, without coupons,
which will be deposited with a custodian for, and
registered in the name of, DTC, or its nominee.
Beneficial interests in these global securities will be
shown on, and transfers of these interests will be
effected only through, the book-entry records maintained
by DTC and its direct and indirect participants.
Risk Factors.............................. Investment in the bonds involves certain risks. There
are certain factors that you should carefully consider.
Before participating in the exchange offer, see "RISK
FACTORS."
Flow of Funds............................. In most circumstances, following the date of commercial
operation of the final three turbine-generators, which
will not be earlier than June 1, 2002, under the
collateral agency agreement, the partnership will cause
the direct payment to the revenue fund created under the
collateral agency agreement, of all revenues or other
proceeds received by the partnership. In most
circumstances, monies on deposit in the revenue fund
will be deposited into the other accounts for the
following uses, in order of priority:
- operating and maintenance expenses, including major
maintenance expenses;
- payment of principal, interest or fees and other
charges relating to, any working capital facility;
- payment of administrative fees, expenses, costs,
liabilities and indemnities of the trustee under our
indenture and other agents related to senior debt;
- payment of interest on the bonds and on any other
senior debt and interest on any debt service reserve
loans and power purchase agreement loans and letter of
credit fees on the debt service reserve letter of
credit and the power purchase agreement letter of
credit;
</TABLE>
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<TABLE>
<S> <C>
- payment of principal and premium, if any, due on the
bonds, any debt service reserve bonds, debt service
reserve term loans or power purchase agreement term
loans and any other senior debt, other than debt
service reserve letter of credit loans and power
purchase agreement letter of credit loans;
- payment of any other amount, other than as otherwise
provided for in this flow of funds, due or becoming
due on the bonds, on any debt service reserve letter
of credit loans, on any power purchase agreement
letter of credit loans and on any other senior debt;
- payment of principal of any debt service reserve
letter of credit loans and replenishment of the debt
service reserve account;
- payment of principal of any power purchase agreement
letter of credit loans;
- upon the occurrence of certain events, the prepayment
of debt service reserve loans and power purchase
agreement loansv other than debt service reserve
letter of credit loans and power purchase agreement
letter of credit loans;
- payments with respect to any third-party subordinated
debt; and
- upon satisfaction of certain conditions, permitted
distributions to, or upon the direction of, our
partners.
In connection with an exercise by PECO of its option to
terminate our power purchase agreement effective on the
20thanniversary of the commencement of the operating
term of our power purchase agreement, any cash
collateral held by PECO as security for our obligations
under the power purchase agreement and released upon
termination of our power purchase agreement, will be
applied first to the payment of power purchase agreement
loans and then to other obligations as provided in the
collateral agency agreement.
Trustee................................... The Chase Manhattan Bank.
Collateral Agent.......................... The Chase Manhattan Bank.
Collateral Agency Agreement............... The collateral agency agreement designates The Chase
Manhattan Bank as the collateral agent for each of the
senior parties and describes, among other things:
- the preservation and administration of the collateral,
- the establishment of the accounts in our project
funds,
</TABLE>
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<TABLE>
<S> <C>
- the disposition of our project revenues among the
senior parties and us,
- the exercise of certain rights, remedies and options
by the senior parties and
- disposition of liquidated damages, loss proceeds and
energy contract buy-out proceeds.
Under the collateral agency agreement, the affirmative
vote of the required senior parties is required to
direct certain actions of The Chase Manhattan Bank, as
collateral agent, including the exercise of remedies
following a trigger event.
</TABLE>
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INDEPENDENT CONSULTANTS' REPORTS
This prospectus contains reports by R. W. Beck, Inc. and Resource Data as
independent consultants. In their preparation of these reports and projections,
the independent consultants have relied on assumptions regarding circumstances
beyond the control of the partnership, the independent consultants or any other
person. By their nature, these assumptions are subject to significant
uncertainties and actual results will differ, perhaps materially, from those
projected. The persons responsible for these projections or the assumptions
cannot give any assurance that these assumptions are correct or that these
projections will reflect actual results of operations. Accordingly, these
projections are not intended to be an illustration or prediction as to the
likelihood of future results. If the actual results of our project are
materially less favorable than those shown, or if the assumptions used in the
projections prove to be incorrect, the partnership's ability to make payments of
principal of and interest on the bonds may be adversely affected. For certain
additional information relating to the projections included in the independent
consultants' reports, see "RISK FACTORS--Financing Risks."
INDEPENDENT ENGINEER'S REPORT
R. W. Beck has prepared a report that analyzes certain technical,
environmental and economic aspects of our project. This report includes, among
other things, projections of revenues, expenses and debt service coverage and a
technical review of our project and the documents and agreements relating to our
project. The report also contains a projection of the cash flow to be used to
pay principal and interest on the bonds. A copy of the report is attached as
Appendix B to this prospectus and should be read in its entirety. R. W. Beck is
a leading consulting and engineering firm that devotes a substantial portion of
its resources to providing services related to the technical, environmental and
economic aspects of power projects and other industrial facilities.
Below is a summary of the conclusions expressed by R. W. Beck in its report.
This is merely a summary and is subject to the information contained, and the
assumptions made, in the report. The report should be read in its entirety in
order for the reader to completely understand the basis of the conclusions and
the assumptions upon which they are based. Certain terms used in the summary
below are defined in the report. On the basis of its studies, analyses and
investigations of the facility and the assumptions set forth in its report, R.
W. Beck is of the opinion that:
1. Zachry Construction and the Tenaska Operations have previously
demonstrated the capability to perform their responsibilities under our EPC
contract and our O&M agreement, respectively.
2. Provided that, as required by our EPC contract, Zachry Construction takes
into account the recommendations in the subsurface report and in our EPC
contract design criteria regarding:
- site development,
- subsurface conditions, and
- foundations
during design and construction of the facility, then the facility site is
suitable for construction and operation of the facility.
3. Based upon R.W. Beck's review of the environmental site assessments
conducted by EMCON for the facility site and the construction lay-down area:
- the investigations appear to have been conducted in a manner consistent
with industry standards, using comparable industry protocols for similar
studies with which R. W. Beck is familiar; and
- although R. W. Beck has not conducted an independent assessment of the
facility site, the conclusions reached by EMCON appear to be supported by
the data R.W. Beck has reviewed.
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4. The technology proposed for the facility is a sound and proven method of
electric generation.
5. If operated and maintained consistent with generally accepted industry
practices, the facility should be capable of:
- passing the acceptance tests under our EPC contract and
- meeting the requirements of the power purchase agreement and the current
environmental permits.
6. The facility has adequately provided for all off-site requirements,
including
- fuel supply and transportation,
- water supply,
- wastewater disposal, and
- electrical interconnection.
7. The proposed method of design, construction and operation of the facility
- has been developed under generally accepted industry practices and
- has taken into consideration the current environmental, license and permit
requirements that the facility must meet.
8. If designed, constructed, operated and maintained as currently proposed,
the facility should be capable of:
- operating during periods of peak electric customer demand,
- achieving an average annual output of 908 MW, and
- achieving an average annual net plant heat rate of 11,088 Btu/kWh (HHV).
The average annual output of 908 MW is within the range where neither party
shall owe a penalty or adjustment under our power purchase agreement. The
average annual net plant heat rate of 11,088 Btu/kWh (HHV) is within the range
where neither party shall owe a fuel adjustment payment under our power purchase
agreement.
9. Based on the projected level of dispatch, the facility should be capable
of achieving:
- a summer availability percentage of 98 percent and
- an annual availability percentage of 97 percent,
both as defined in our power purchase agreement. The annual availability
percentage of 97 percent is the level required to avoid reductions in the
reservation payments under our power purchase agreement.
10. The facility should have a useful life extending beyond the term of the
bonds.
11. Based on a limited notice-to-proceed of September 10, 1999, and
assuming:
- the absence of events such as delivery delays,
- labor difficulties,
- unusually adverse weather conditions,
- force majeure events,
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- the discovery of underground obstructions or hazardous materials or wastes
not previously known, or
- other abnormal events that are prejudicial to normal construction or
installation,
then the scheduled commercial operation dates of June 1, 2001 for the initial
three turbine-generators and June 1, 2002 for the final three turbine-generators
are achievable using generally accepted project and construction management
practices.
12. Given:
- the range of operating hours projected by Resource Data, which is typical
of plants serving electric load during peak demand hours, and
- the requirements of our power purchase agreement,
the acceptance tests and guarantees included in our EPC contract are adequate to
estimate the future performance of the facility.
13. The partnership has received the key environmental permits and approvals
required from the various federal, state, and local agencies, that are currently
necessary to construct the facility. While not all the required permits and
approvals have been issued, including some which cannot be obtained until the
facility is ready to operate, R. W. Beck is not aware of any technical
circumstances that would prevent the issuance of the remaining permits.
14. The estimates which serve as the basis for our EPC contract price and
the total construction cost were prepared under generally accepted engineering
and estimating practices and methods. The EPC contract price and the total
construction cost, including project contingency, are comparable to the costs of
simple cycle projects at similar stages of development utilizing similar
technologies with which R. W. Beck is familiar.
15. Based upon:
- the interest and reinvestment rates as estimated by the initial purchasers
of the old bonds and
- the total uses of funds as estimated by the partnership, then the
principal amount of the bonds, when combined with:
- the equity from the partnership,
- power purchase agreement revenue during the construction period from the
initial three turbine-generators and
- interest income during the construction period,
should be sufficient to fund the total construction cost and interest on the
bonds through May 31, 2002.
16. The methodology used by the partnership in preparing the operation and
maintenance cost estimate for the facility, including the provision for major
maintenance, is reasonable.
17. For the base case projected operating results for the facility, the
projected revenues under our power purchase agreement are adequate to:
- pay annual operating and maintenance expenses, including provisions for
major maintenance, and other operating expenses; and
- provide an annual debt service coverage ratio of at least 1.30 times the
annual debt service requirement on the bonds and a weighted average debt
service coverage ratio of 1.49 times the annual debt service requirement
over the term of the bonds.
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18. If Zachry Construction pays the partnership liquidated damages due to a
failure to achieve:
- the guaranteed net electrical output and
- guaranteed net heat rate,
then, for deficiencies equivalent to the performance minimums under our EPC
contract, the weighted average debt service coverage ratio over the term of the
bonds is projected to remain generally at the same level as in the base case
projected operating results.
INDEPENDENT MARKET CONSULTANT'S REPORT
Resource Data International has prepared a report that analyzes the
Southeast United States electricity market and the economic competitiveness of
our project within that market. The report provides an assessment of the
long-term market opportunities, including capacity and energy prices expected to
be received by generators, in the region for the years 2000 through 2030. A copy
of the report is attached as Appendix C to this prospectus and should be read in
its entirety. Although the revenue received from PECO is not materially affected
by the market price of electricity, we retained Resource Data to provide an
indication of the economic impact of our power purchase agreement on PECO.
Below is a summary of the conclusions expressed by Resource Data in its
report. This is merely a summary and is subject to the information contained,
and the assumptions made, in the report. The report should be read in its
entirety in order for the reader to completely understand the basis of the
conclusions and the assumptions upon which they are based. Certain terms used in
the summary below are defined in the report. On the basis of its studies,
analyses, and investigations of the facility and the assumptions set forth in
its report, Resource Data is of the opinion that:
1. Our project represents a low cost, highly competitive and much needed
peaking resource for the growing Southeastern power market. The total capacity
of our project is equal to only 1% of the capacity required in the Southeastern
power market by the year 2020.
2. Our project has many strong competitive advantages such as:
- Direct access to additional power markets beyond Georgia via relatively
strong transmission links into the Tennessee Valley Authority,
Virginia/Carolina, and Southwest Power Pool markets.
- State of the art generation technology which is ideal for serving peak
electricity loads.
- Ready access to competitively priced gas supply from a diversified range
of sources through an extensive interstate gas pipeline transmission
system.
3. As noted above, PECO has entered into a long term mutually acceptably
priced power purchase agreement with our project. PECO is very active in U.S.
wholesale power markets nationally and also in the Southeast U.S.
- Due to recent price spikes and the curtailment of firm contract
deliveries, control or ownership of a physical asset in the Southeast has
become a source of strategic advantage to marketers such as PECO. Such an
asset allows the marketer to ensure delivery of firm power. This provides
both an advantage in marketing the power(, as the purchaser is less likely
to enter into a contract with a seller that does not have control of
physical assets), and in avoiding liquidated damage payments in the event
of a transmission curtailment or other loss of power supplies.
- The optionality embedded in peaking power plants plays an integral role in
the portfolio of marketers such as PECO.
4. It is expected that PECO will operate our project only during summer peak
hours when electricity prices are highest. It is expected that our project will
achieve monthly summer capacity
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factors of 7% to 18%, averaging approximately 4% on an annual basis during the
20 year forecast period. Based on Resource Data's assumptions regarding price
and electricity demand growth for the period 2020-2030, Resource Data expects
that our project's utilization will continue to trend down slightly throughout
that period.
5. The technical capability of our project to start up and shut down quickly
should allow PECO to select operating hours in which revenues and profitability
can be maximized.
6. The cost of capacity and energy to PECO under our power purchase
agreement remains below the market price forecast under both Resource Data's
base and downside cases, confirming the economic attractiveness of the power
purchase agreement to PECO.
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RISK FACTORS
PROSPECTIVE INVESTORS SHOULD CAREFULLY CONSIDER THE RISKS DESCRIBED BELOW IN
ADDITION TO THE OTHER INFORMATION CONTAINED IN THIS PROSPECTUS BEFORE
PARTICIPATING IN THE EXCHANGE OFFER.
CONSTRUCTION RISK
WE MAY NOT BE ABLE TO COMPLETE THE CONSTRUCTION OF OUR PROJECT ON TIME FOR
REASONS BEYOND OUR CONTROL OR OUR CONTRACTORS' CONTROL.
The construction and timely completion of our project may be adversely
affected by factors commonly associated with any major construction effort,
including:
(a) shortages of materials and labor,
(b) work stoppages,
(c) labor disputes,
(d) weather interferences,
(e) unforeseen engineering, environmental or geological problems, and
(f) unanticipated cost increases.
If any of these events occur, the construction of our project may be
delayed, our project may cost us more to complete than we have currently
budgeted or our project may not perform as well as we expect it to. In turn, our
ability to pay amounts due on the bonds would be impaired.
WE MAY INCUR ADDITIONAL COSTS OR A REDUCTION IN REVENUE UNDER OUR POWER
PURCHASE AGREEMENT IF EACH TURBINE-GENERATOR IS NOT OPERATING BY THE DATE ON
WHICH OUR DELIVERY OBLIGATIONS UNDER OUR POWER PURCHASE AGREEMENT BEGIN WITH
RESPECT TO SUCH TURBINE-GENERATOR.
Our power purchase agreement obligates us to pay liquidated damages to PECO
if certain delays cause any turbine-generator to become operational later than
scheduled. We will not be obligated to pay liquidated damages until after twelve
months of delay if the delay is by reason of a FORCE MAJEURE event under the
power purchase agreement against which business interruption insurance is not
available or an act or omission of PECO. The aggregate amount of liquidated
damages payable by the partnership to PECO for delay will not exceed
(a) $8 million for each turbine-generator and (b) $25 million in the aggregate.
The present construction schedule for our project does not anticipate the
payment of any liquidated damages to PECO, but there can be no assurance that
this schedule will be met. If the initial three turbine-generators have not all
achieved operational status by June 1, 2002, subject to adjustment to a limited
extent for FORCE MAJEURE events which occur prior to June 1, 2001, PECO has the
right to terminate our power purchase agreement in respect of the initial three
turbine-generators. If the final three turbine-generators have not all achieved
operational status by June 1, 2003, subject to adjustment to a limited extent
for FORCE MAJEURE events, PECO has the right to terminate our power purchase
agreement in respect of the final three turbine-generators.
THE LIQUIDATED DAMAGES THAT WE MAY RECEIVE UNDER OUR EPC CONTRACT MAY NOT
FULLY COMPENSATE US FOR OUR LOSSES IF THERE IS A DELAY IN CONSTRUCTION OR IF THE
COMPLETED FACILITY DOES NOT SATISFY ITS PERFORMANCE REQUIREMENTS.
We are entitled to receive liquidated damages from the Zachry Construction
upon the occurrence of certain delays. We are not entitled to receive these
liquidated damages if the delay is caused by a FORCE MAJEURE event under our EPC
contract or certain acts or omissions by us, including the exercise by us of
certain of our rights under or with respect to the turbine contract. If one or
more turbine-generators do not achieve operational status by their scheduled
dates under our EPC contract, Zachry Construction could be obligated to pay us
liquidated damages at the rates determined under our EPC
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contract. If and to the extent that a delay is caused by an unexcused failure by
General Electric to perform under the turbine contract, the liquidated damages
payable by the Zachry Construction under our EPC contract may be in a lower
amount. The total amount of these liquidated damages payable because of delay in
achieving operational status, in the aggregate for all turbine-generators, is
22.5% of the guaranteed lump sum of $229,064,832 payable to Zachry Construction
for its performance under our EPC contract. We are also entitled to receive
performance liquidated damages of up to 22.5% of the $229,064,832 in the
aggregate for all turbine-generators from Zachry Construction if one or more
turbine-generators cannot satisfy tests that measure their net power output and
net heat rate, among other things, against the guaranteed standards included in
our EPC contract. The EPC contract limits the aggregate amount of delay and
performance liquidated damages for all turbine-generators to 30% of the
$229,064,832. Certain liquidated damages are offset by any net revenue received
by us from a turbine-generator's operation prior to entering commercial
operation. There can be no assurance that any liquidated damage payments would
be sufficient to pay for any increased costs to pay interest during construction
on the bonds, to replace lost revenues or to pay liquidated damages to PECO if
the completion of our project is delayed or if our project does not operate as
designed. Further, if Zachry Construction is required to pay liquidated damages
as discussed above, there can be no assurance that Zachry Construction, its
guarantor or the provider of Zachry Construction's payment and performance bond
will have the financial resources available to do so. See "SUMMARY OF PRINCIPAL
PROJECT DOCUMENTS--EPC Contract--Commercial Operation Liquidated Damages"
and--"Performance "Liquidated Damages."
THE AMOUNT THAT WE HAVE BUDGETED TO COVER INCREASED COSTS, THE AMOUNT OF OUR
INSURANCE COVERAGE AND OUR OTHER RESOURCES MAY BE INSUFFICIENT TO COVER
UNANTICIPATED COST OVERRUNS OR DELAYS IN ACHIEVING COMMERCIAL OPERATION.
We have included a contingency of approximately $12 million in our
construction budget to cover FORCE MAJEURE and other events that may give rise
to delays or cost overruns. The Independent Engineer has concluded that, based
on its experience, the amount of this contingency is comparable to the
contingencies of simple cycle projects at similar stages of development using
similar technologies with which it is familiar. There can be no assurance,
however, that the amount of the contingency and the proceeds of any delayed
opening insurance will be sufficient to pay for increased costs to pay interest
during construction on the bonds, or to replace lost revenues or to pay
liquidated damages to PECO resulting from any such events. In particular, we are
required to pay principal and interest due on the bonds without regard to any
FORCE MAJEURE events under our EPC contract. Although R.W. Beck has assessed the
construction schedule and the capabilities of Zachry Construction, there can be
no assurance that the schedule for completion of the turbine-generators will be
met. See "APPENDIX B--Independent Engineer's Report."
The facility is currently scheduled to be completed on June 1, 2002, with
the first three turbine-generators scheduled to be operational on June 1, 2001.
While we anticipate receiving revenues from operation of the first three
turbine-generators, and have included the amount of these anticipated revenues
among our sources for payment of costs of our project, including interest on our
outstanding bonds, until the anticipated date of commercial operation of the
entire project, we cannot assure you that any or all of the turbine-generators
will be successfully and timely constructed, or that the amount of revenues that
we will receive from operation will be as projected. If the revenues are less
than we have projected, we would be required to use contingency funds and the
proceeds of any delayed opening insurance, if available, and there is no
assurance that the amount of these contingency funds and insurance proceeds
would be sufficient to make up the shortfall.
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Prior to all turbine-generators becoming operational, the only sources
available to us to make payment on the bonds are the following:
- a portion of net proceeds from the issuance of the revenue bonds issued by
the Development Authority of Heard County which were purchased with the
proceeds of the bonds,
- any investment earnings on these proceeds,
- revenues, if any, from the operation of the first three
turbine-generators,
- budgeted contingency funds,
- insurance proceeds, if any, and
- certain liquidated damages, if any such damages become payable under our
EPC contract.
On the date of issuance of the bonds, the construction interest account
created under the Indenture was funded with $37,499,000. This amount, together
with interest anticipated to be earned thereon and on invested construction fund
proceeds and $15,258,000 of the amounts anticipated to be derived from our
operating revenues from the first three turbine-generators, is expected to be
sufficient to pay the interest on the bonds through May 31, 2002. If the date of
commercial operation of the first three turbine-generators were delayed, or if
by reason of operational problems or otherwise the revenues from these
turbine-generators were less than projected, these sources might not be
sufficient to pay amounts due on the bonds through May 31, 2002. While the
construction budget includes a contingency amount, and while under certain
circumstances there may be liquidated damages or insurance proceeds available to
fund this shortfall, there is no assurance that these amounts would be available
or sufficient to permit the partnership to pay amounts due on the bonds.
Moreover, the achievement of operational status of the first three
turbine-generators does not guarantee that the final three turbine-generators
will achieve operational status on time, if at all. Until the final three
turbine-generators are operational, payment of interest on the bonds will remain
dependent on the funds available from the sources listed above. See
"--Construction Risk" above.
DEPENDENCE ON OTHER THIRD PARTIES; CONTRACT RISKS
WE DEPEND ON ONE ENTITY TO PURCHASE ALL OF THE OPERATING OUTPUT OF THE
FACILITY.
Payments by PECO under our power purchase agreement represent our sole
source of revenue. Accordingly, our ability to pay amounts due on the bonds will
be significantly impaired if PECO stops making payments under our power purchase
agreement for any reason.
PECO is our sole customer, the sole recipient of the capacity and energy
output of the facility and the sole provider of natural gas and fuel oil
necessary to operate the facility. The viability of our project is subject to
the continued creditworthiness of PECO and its continued performance under our
power purchase agreement. Payments made by PECO will provide us with all of our
revenues during the term of our power purchase agreement. If PECO were to cease
fulfilling its obligations under our power purchase agreement, it is uncertain
whether we would be able to find another purchaser of the facility's output or
supplier of the facility's natural gas and fuel oil requirements. If another
purchaser were found, we cannot assure you that the price paid by that purchaser
and the cost of alternate fuel arrangements, if required, would enable us to pay
amounts due on the bonds. Because the facility is designed to operate as a
peaking facility, we will have higher total fuel costs than combined cycle
plants against which we may be competing in the event that our power purchase
agreement is terminated and the facility operates as a merchant plant or
otherwise. If PECO failed to make capacity, energy and the other payments
required under our power purchase agreement, PECO would be in default of our
power purchase agreement and our revenues would be adversely affected. In turn,
our ability to pay amounts due on the bonds would also be adversely affected.
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The ability of PECO to meet its obligations under the power purchase
agreement will be dependent on PECO's financial condition generally. In the
event that PECO sells or otherwise transfers its power marketing business, PECO
may assign our power purchase agreement without our consent to the buyer or
transferee of that business if (a) the buyer or transferee has a senior
unsecured public debt rating by Moody's or S&P that is not lower than PECO's
comparable unsecured senior debt rating at the time of that transfer and (b)
we receive confirmation of the rating of that buyer or transferee after giving
effect to that buyer's or transferee's assumption of the power purchase
agreement. For a summary of the events of default under our power purchase
agreement, see "SUMMARY OF PRINCIPAL PROJECT DOCUMENTS--Power Purchase
Agreement--TERMINATION, CURE AND EVENTS OF DEFAULT."
WE DEPEND UPON GEORGIA POWER FOR ELECTRIC INTERCONNECTION SERVICE.
We are relying on Georgia Power to interconnect the facility to the Georgia
Integrated Transmission System, and Georgia Power in turn is relying on its
rights under its bilateral contract with Georgia Transmission Corporation in
order to perform this service. This contract terminates at the election of
either party in 2012 or earlier upon the dissolution, liquidation or bankruptcy
of either party. If Georgia Power's participation in the Georgia Integrated
Transmission System should terminate during the life of our project, we would
attempt, if necessary, to negotiate terms with Georgia Transmission under which
the facility would remain interconnected with Georgia Transmission's
transmission system. If Georgia Power fails to timely perform its obligations
under the Georgia Power interconnection agreement, either because of disputes or
defaults under this contract or otherwise, this could delay or impair the
commercial operation of the facility. Such a delay or impairment would result in
an increase in costs and a loss of revenue, which could impair our ability to
pay amounts due on the bonds.
WE DEPEND ON A NUMBER OF OTHER ENTITIES TO CONSTRUCT, OPERATE AND MAINTAIN
OUR PROJECT.
We are highly dependent on many entities to, among other things:
- provide goods and services necessary for the facility to generate such
capacity and electric energy; and
- construct, operate and maintain our project.
If any entity upon whom we depend for the construction and operation of our
project were to breach its obligations to us, our ability to construct and
operate our project or to sell capacity and electric energy would be impaired.
This, in turn, could adversely affect our ability to pay amounts due on the
bonds. The other parties to our project documents have the right to terminate or
withhold payment or performance under these documents upon the occurrence of
certain events specified therein. In addition, if a party to a project document
were declared bankrupt or insolvent, this could impair that party's ability to
fulfill its obligations to us. This could adversely affect our ability to pay
amounts due on the bonds. See "SUMMARY OF PRINCIPAL PROJECT DOCUMENTS."
OPERATING RISK
THE OPERATION OF OUR PROJECT INVOLVES MANY RISKS--OPERATING RISK,
AVAILABILITY RISK, TECHNOLOGY RISK AND THE RISK OF EVENTS BEYOND OUR CONTROL.
The operation of power generation facilities like our project involves many
risks, including:
- the possibility of performing below expected levels of output or
efficiency,
- power shutdowns due to the breakdown or failure of equipment or processes,
- labor disputes,
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- under-performance during facility testing,
- failure to operate the facility optimally and reliably and
- catastrophic events such as fires, earthquakes, lightning, explosions,
floods or other similar occurrences affecting our project.
The failure of any one of the six turbine-generators could significantly
reduce revenues generated by the facility. This failure could also significantly
increase the operating expenses of the facility. This, in turn, would impair our
ability to pay amounts due on the bonds. If we are unable to meet our
availability and efficiency targets to PECO, we will be required to pay
penalties, which will reduce our revenues, and could impact the amounts
available to pay amounts due on the bonds. Under the formulas for availability
in the power purchase agreement, higher rates for dispatch could make it more
difficult for the partnership to achieve its availability targets. In the summer
months in particular, the availability target for the facility is high, and if
we failed to meet it we would be required to pay penalties in significant
amounts which could impact our ability to pay amounts due on the bonds. See
"SUMMARY OF PRINCIPAL PROJECT DOCUMENTS."
THE INSURANCE WE HAVE OBTAINED MAY BE INADEQUATE.
Although we maintain insurance consistent with industry standards to protect
against certain operating risks and other risks, not all risks are insured or
insurable. There can be no assurance that this insurance coverage will be
available in the future on commercially reasonable terms or at commercially
reasonable rates. If certain operating risks occur, or, if there is a total or
partial loss of our project, there can be no assurance that the proceeds of the
applicable insurance policies will be adequate to cover our lost revenues or
increased expenses. See "SUMMARY DESCRIPTION OF PRINCIPAL FINANCING
DOCUMENTS--Common Agreement--Certain Covenants--INSURANCE."
REGULATORY RISKS
OUR BUSINESS IS SUBJECT TO SUBSTANTIAL REGULATIONS AND PERMITTING
REQUIREMENTS AND MAY BE ADVERSELY AFFECTED BY CHANGES IN THESE REGULATIONS OR
REQUIREMENTS.
There are many federal, state and local laws pertaining to power generation
designed to protect human health and the environment or to serve other aspects
of public policy. These laws impose numerous requirements on the construction,
ownership and operation of our project. If we fail to comply with these
requirements, we could be prevented from completing or operating our project.
Moreover, modifications to the facility to comply with these requirements could
involve a material expenditure of funds or an incurrence of additional
indebtedness to bring our project into compliance. Our business could also be
materially adversely affected by changes in existing law or the interpretation
of those laws. These changes can impose more restrictive requirements on our
project in a way that could cause us to be unable to pay amounts due on the
bonds. Among these laws is the federal Clean Air Act, which requires the State
of Georgia and the federal government to take regulatory actions that may affect
our business. There can be no assurance that we will or can satisfy all
requirements that may result from actions taken in response to the federal Clean
Air Act.
Certain substances are regulated by the Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA"). If any of these regulated
substances were discovered in the soil or groundwater of the facility site, we
could be responsible for the investigation and removal of these substances
regardless of the source of these hazardous substances.
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WE CANNOT ASSURE YOU THAT ALL PERMITS AND APPROVALS WILL BE OBTAINED WHEN
NEEDED.
We are responsible for obtaining and maintaining various permits and other
regulatory approvals required for the operation of our project. Most material
permits and other regulatory approvals currently required to construct our
project have been obtained and we expect to obtain all the material permits in
connection with the operation of any turbine-generator prior to the
turbine-generator reaching operational status, except where a later time is
prescribed by law. However, there can be no assurance that all these permits and
approvals will be obtained prior to the date they are needed. Any delay or
failure to obtain these permits and approvals could delay construction or
operation of our project or result in additional costs. The renewal, extension
or obtaining of permits and approvals for our project are subject to contest or
appeal under federal or state law. Our failure to comply with these permits and
approvals, or delay in obtaining or maintaining in full force and effect any
such permits and approvals, could prevent or impair our ability to pay amounts
due on the bonds. See "ENERGY REGULATION--Permit Status."
FINANCING RISKS
IF WE DEFAULT ON THE BONDS, YOUR RIGHT TO PAYMENT, OR RECOURSE, WILL BE
LIMITED TO THE ASSETS AND CASH FLOWS OF THE FACILITY.
We are solely responsible for paying amounts due on the bonds. We were
formed for the sole purpose of designing, financing, constructing, procuring,
owning, leasing and operating our project. We conduct no other business and own
no other significant assets except our interests in our project, our project
documents and other assets related to the leasing or operation of our project.
Other than the equity contribution of up to $35.5 million, our partners and
their affiliates have no obligation to contribute additional equity to us.
Our ability to pay amounts due on the bonds will be entirely dependent on
our ability to construct our project and to perform under our power purchase
agreement at levels which provide sufficient revenues, after the payment of our
operations and maintenance costs and repayments under any working capital
facility, to pay amounts due on the bonds and our other debt when due. The bonds
and permitted senior debt will be paid out of the same funds without any
precedence over each other. However, payments in respect of the principal amount
of reimbursement obligations under the debt service reserve letter of credit and
the power purchase agreement letter of credit, prior to a trigger event or the
conversion of these obligations into debt service reserve term loans, debt
service reserve bonds or power purchase agreement term loans, will be made in a
lower order of priority than payments of principal of the bonds and other senior
debt. The bonds and permitted senior debt is entitled to the benefit of the
liens on the collateral securing their repayment. Operating and maintenance
expenses of the facility and repayments under any working capital facility are
generally payable before debt service with respect to the bonds.
The bonds and our other senior debt are secured only by (1) our rights in
our project, (2) a lien on the partnership interests in the partnership and
(3) the revenue bonds issued by the Development Authority and the related lien
on our project assets owned by the Development Authority of Heard County and
securing its revenue bonds. In certain circumstances, the ability of the
collateral agent to foreclose on the collateral upon the occurrence of a trigger
event or otherwise under the financing documents will be subject to perfection
and priority issues and to practical problems associated with realization of the
security interest. These types of issues and problems are associated with, among
other things, the effect a bankruptcy of the partnership would have on the
rights and remedies of its creditors (including the collateral agent), the
possible unenforceability of any assignment of rents prior to taking possession
of the mortgaged property, of allowing the conducting of more than one sale of
the project's real property or of waivers or advance consents that have the
effect of marshalling of assets and the possible lack of assignability of
licenses, permits and the like, as well as general principles of equity
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governing the availability of certain remedies and waivers. As a general matter,
all of the project's collateral could be affected by these issues and problems.
We cannot assure you that, if we default on the payments due on the bonds
and you foreclose on and sell our project, you will receive sufficient proceeds
to pay all amounts that we owe you on the bonds. In addition, there are certain
assets comprising our project, such as permits, that you may not be able to
effectively foreclose upon without the consent of a third party, such as a
governmental authority. We cannot assure you that if you try to foreclose on our
assets, you will get all of the third party approvals necessary to operate our
project.
WE MAY INCUR ADDITIONAL DEBT, OR BE REQUIRED TO MAKE PAYMENTS TO REIMBURSE
DRAWS UNDER LETTERS OF CREDIT, THAT COULD ADVERSELY AFFECT YOU.
We are permitted to incur additional indebtedness under the common
agreement, including additional series of bonds, to pay for certain capital
improvements and expansions of the facility and for other purposes. Certain
types of this permitted indebtedness may rank equally in payment with the bonds
and could result in lower debt service coverage ratios and cash available to pay
amounts due on the bonds. In addition, this indebtedness would share in the
collateral that secures the bonds. This may reduce the benefits of the
collateral to you and your ability to control certain actions taken with respect
to the collateral.
We have arranged for a debt service reserve letter of credit to fund the
debt service reserve account. In addition, in order to secure our obligations
under the power purchase agreement, we have provided the power purchase
agreement letter of credit to PECO. If either letter of credit is drawn upon, we
will be required to reimburse the banks that provided it. The payment of
interest in respect of drawings on both the power purchase agreement letter of
credit and the debt service reserve letter of credit will be made at the same
level of priority as payments of interest in respect of the bonds. In certain
circumstances, payments of the principal amount of drawings under the debt
service reserve letter of credit and the power purchase agreement letter of
credit will be made at the same level of priority as payments on the principal
amount of the bonds. There can be no assurance that the revenues of our project
or otherwise would be sufficient to cover these increases in debt service
payments. The banks providing the debt service reserve letter of credit and the
power purchase agreement letter of credit are secured on an equal basis with the
bonds by a lien on and security interest in the collateral.
WE ARE RELYING ON PROJECTIONS OF THE FUTURE PERFORMANCE OF THE FACILITY, AND
THESE PROJECTIONS MAY NOT PROVE TO BE ACCURATE.
The report by R. W. Beck contains projections of our operating results based
on assumptions and forecasts of our ability to generate revenue and of our
expected costs. The assumptions made with respect to fuel cost, which are
relevant to us under our power purchase agreement if the facility is less
efficient than expected, and dispatch are based upon a market analysis prepared
by Resource Data. We have reviewed and accepted these projections on the basis
of present knowledge and assumptions that we believe to be reasonable. The
financing of our project has been structured on the basis of these assumptions
and projections. These assumptions and projections relate to our project's
expected revenues and expenses over the term of the bonds. R.W. Beck has
formulated the assumptions used in its report after performing its technical,
environmental and economic evaluation of our project. The report also contains
other assumptions of business and economic conditions generally. The report sets
forth a discussion of the many assumptions utilized in formulating the
projections.
Arthur Andersen LLP, our independent auditors, have not reviewed R.W. Beck's
Report and, accordingly, do not express an opinion or any other form of
assurance on it. Except to the extent required under U.S. securities laws, we
will not provide you with revised projections or any summary of
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the differences between the projections and actual events. We expressly disclaim
any duty to update R.W. Beck's report under any circumstances.
For purposes of preparing these projections, certain assumptions, in
addition to those mentioned above, were made with respect to material
contingencies and other matters that are not within our control. Accordingly, we
cannot accurately predict the outcome of these projections. 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 an
indication of our current value or future performance. Therefore, we cannot
guarantee their accuracy or the accuracy of Resource Data's market analysis. 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.
Investors are cautioned not to place undue reliance on the projections. If
actual results are less favorable than those shown in the projections or if the
assumptions used in formulating these projections prove to be incorrect, our
ability to pay amounts due on the bonds may be materially adversely affected.
See "APPENDIX B--Independent Engineer's Report" and "APPENDIX C--Independent
Market Consultant's Report."
IF YOU DO NOT PROPERLY TENDER YOUR OLD BONDS, YOU WILL CONTINUE TO HOLD
UNREGISTERED OLD BONDS AND YOUR ABILITY TO TRANSFER OLD BONDS WILL BE ADVERSELY
AFFECTED
We will only issue new bonds in exchange for old bonds that are timely
received by the exchange agent together with all required documents, including a
properly completed and signed letter of transmittal, as described in this
prospectus. Therefore, you should allow sufficient time to ensure timely
delivery of the old bonds and you should carefully follow the instructions on
how to tender your old bonds. Neither we nor the exchange agent are required to
tell you of any defects or irregularities with respect to your tender of the old
bonds. If you do not tender your old bonds or if we do not accept your old bonds
because you did not tender your old bonds properly, then, after we consummate
the exchange offer, you will continue to hold old bonds that are subject to the
existing transfer restrictions and, except in certain limited circumstances, you
will no longer have any registration rights with respect to or be entitled to an
increased interest rate on the old bonds. In addition:
- if you tender your old bonds for the purpose of participating in a
distribution of the new bonds, you will be required to comply with the
registration and prospectus delivery requirements of the Securities Act of
1933 in connection with any resale of the new bonds; and
- if you are a broker-dealer that receives new bonds for your own account in
exchange for old bonds that you acquired as a result of market-making
activities or any other trading activities, you will be required to
acknowledge that you will deliver a prospectus in connection with any
resale of those new bonds.
We have agreed that, for a period of not less than 180 days after the
exchange offer is consummated, we will make a prospectus available to any
broker-dealer for use in connection with any such resale.
After the exchange offer is consummated, if you continue to hold any old
bonds, you may have difficulty selling them because there will be less old bonds
outstanding. In addition, if a large amount of old bonds are not tendered or are
tendered improperly, the limited amount of new bonds that would be issued and
outstanding after we consummate the exchange offer could lower the market price
of the new bonds.
THERE IS NO EXISTING MARKET FOR THE NEW BONDS, AND WE CANNOT ASSURE YOU THAT
AN ACTIVE TRADING MARKET WILL DEVELOP.
The new bonds are a new issue of securities with no established trading
market. We do not intend to apply for listing of the new bonds on any national
securities exchange or for quotation of the new
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bonds on any automated dealer quotation system. The liquidity of the trading
market in the new bonds, and the market price quoted for the new bonds, may be
adversely affected by changes in the overall market for these securities and by
changes in our financial performance or prospects or in the prospects for
companies in our industry generally. As a result, you cannot be sure that an
active trading market will develop for the new bonds. Moreover, even if a market
for the new bonds does develop, the new bonds could trade at a discount from
their face amount. If a market for the new bonds does not develop, you may be
unable to sell your new bonds for an extended period of time, if at all.
Consequently, you may not be able to liquidate your investment readily, and your
lenders may not readily accept the new bonds as collateral for loans.
WHERE YOU CAN FIND MORE INFORMATION
We are filing a registration statement on Form S-4 to register with the SEC
the new bonds to be issued in exchange for the old bonds. This prospectus is
part of that registration statement. As allowed by the SEC's rules, this
prospectus does not contain all of the information you can find in the
registration statement and the exhibits to the registration statement.
Upon effectiveness of the registration statement, we will file annual and
quarterly reports and other information with the SEC. You may read and copy any
reports, documents and other information we file at the SEC's public reference
rooms in Washington, D.C., New York, New York, and Chicago, Illinois. Please
call 1-800-SEC-0330 for further information on the public reference rooms. Our
filings will also be available to the public from commercial document retrieval
services and at the web site maintained by the SEC at http://www.sec.gov.
Our obligations to file reports with the SEC will be suspended if the new
bonds are held of record by fewer than 300 holders as of the beginning of any
fiscal year, and may cease filing reports with the SEC in respect of such fiscal
year, other than the fiscal year in which this registration statement is
declared effective.
FORWARD-LOOKING STATEMENTS
Various statements contained in this prospectus are forward-looking
statements. Such forward-looking statements can be identified by the use of
forward-looking terminology such as "believes," "expects," "may," "intends,"
"will," "should" or "anticipates," or by the negative thereof or other
variations thereon or comparable terminology, or by discussions of strategy.
Although these statements are based upon assumptions the partnership believes
are reasonable, no assurance can be given that the future results covered by the
forward-looking statements will be achieved. Such statements are subject to
risks, uncertainties and other factors which could cause actual results to
differ materially from future results expressed or implied by such
forward-looking statements. The most significant of such risks, uncertainties
and other factors are discussed above in this prospectus under "RISK FACTORS,"
and you are urged to consider these factors carefully. Except to the extent
required under U.S. securities laws, we do not intend to provide bondholders
with any revised or updated financial projections or analysis of the difference
between the financial projections and actual operating results.
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THE EXCHANGE OFFER
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
We have entered into an exchange and registration rights agreement with the
initial purchasers of the old bonds in which we agreed, under certain
circumstances, to file a registration statement relating to an offer to exchange
the old bonds for the new bonds. The registration statement of which this
prospectus forms a part was filed in compliance with this obligation. We also
agreed to use our reasonable best efforts to cause the exchange offer to be
consummated within 315 days following the original issuance of the old bonds.
The new bonds will have terms substantially identical to the old bonds except
that the new bonds will not contain terms with respect to transfer restrictions,
registration rights or an increased interest rate for failure to observe certain
obligations in the exchange and registration rights agreement. The old bonds
were issued on November 10, 1999.
Under the circumstances set forth below, we will use our reasonable best
efforts to cause the SEC to declare effective a shelf registration statement
with respect to the resale of the old bonds and keep the shelf registration
statement effective for up to two years after the effective date of the shelf
registration statement. These circumstances include:
- if pursuant to any changes in law, SEC rules or regulations or applicable
interpretations by the SEC staff do not permit us to effect the exchange
offer as contemplated by the exchange and registration rights agreement;
- if any old bonds validly tendered in the exchange offer are not exchanged
for new bonds within 315 days after the original issue of the old bonds;
or
- if the exchange offer is not available to any holder of the old bonds.
Each holder of old bonds that wishes to exchange old bonds for transferable
new bonds in the exchange offer will be required to make the following
representations:
- any new bonds will be acquired in the ordinary course of its business;
- it has no arrangement or understanding with any person to participate in
the distribution(, within the meaning of the Securities Act of 1933) of
the new bonds; and
- it is not our "affiliate," as defined in Rule 405 of the Securities Act of
1933, or, if it is an affiliate, it will comply with the applicable
registration and prospectus delivery requirements of the Securities Act of
1933.
RESALE OF NEW BONDS
Based on interpretations of the SEC staff set forth in no-action letters
issued to unrelated third parties, we believe that new bonds issued in the
exchange offer in exchange for old bonds may be offered for resale, resold and
otherwise transferred by any new bondholder without compliance with the
registration and prospectus delivery provisions of the Securities Act of 1933,
if:
- that holder is not an "affiliate" of ours within the meaning of Rule 405
under the Securities Act of 1933;
- that new bonds are acquired in the ordinary course of the holder's
business; and
- the holder does not intend to participate in the distribution of those new
bonds.
Any holder who tenders in the exchange offer with the intention of
participating in any manner in a distribution of the new bonds:
- cannot rely on the position of the SEC staff enunciated in EXXON CAPITAL
HOLDINGS CORPORATION, MORGAN STANLEY & CO. INCORPORATED or similar
no-action letters; and
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- must comply with the registration and prospectus delivery requirements of
the Securities Act of 1933 in connection with a secondary resale
transaction of the new bonds.
This prospectus may be used for an offer to resell, for the resale or for
other re-transfer of new bonds only as specifically set forth in this
prospectus. With regard to broker-dealers, only broker-dealers that acquired the
old bonds as a result of market-making activities or other trading activities
may participate in the exchange offer. Each broker-dealer that receives new
bonds for its own account in exchange for old bonds, where those old bonds were
acquired by that broker-dealer as a result of market-making activities or other
trading activities, must acknowledge that it will deliver a prospectus in
connection with any resale of the new bonds. This prospectus may be used by
these broker-dealers for this purpose. Please read the "PLAN OF DISTRIBUTION"
section for more details regarding the transfer of new bonds.
TERMS OF THE EXCHANGE OFFER
Upon the terms and subject to the conditions set forth in this prospectus
and in the letter of transmittal, we will accept for exchange any old bonds
properly tendered and not properly withdrawn on or prior to the expiration date.
Old bonds may be tendered only in denominations of $100,000 and integral
multiples of $1,000 in excess thereof. We will issue $1,000 principal amount of
new bonds in exchange for each $1,000 principal amount of old bonds surrendered
under the exchange offer.
The form and terms of the new bonds will be substantially identical to the
form and terms of the old bonds except the new bonds will be registered under
the Securities Act of 1933, will not bear legends restricting their transfer and
will not provide for any increase in interest rate upon failure of the issuer to
fulfill its obligations under the exchange and registration rights agreement to
file, and cause to be effective, a registration statement. The new bonds will
evidence the same debt as the old bonds. The new bonds will be issued under and
entitled to the benefits of the same indenture that authorized the issuance of
the old bonds. Consequently, both series will be treated as a single class of
debt securities under that indenture.
As of the date of this prospectus, $275.0 million aggregate principal amount
of the old bonds are outstanding. This prospectus and the letter of transmittal
are being sent to all registered holders of old bonds. There will be no fixed
record date for determining registered holders of old bonds entitled to
participate in the exchange offer.
We intend to conduct the exchange offer under the provisions of the exchange
and registration rights agreement, the applicable requirements of the Securities
Act of 1933 and the Securities Exchange Act of 1934, and the rules and
regulations of the SEC. Old bonds that are not tendered for exchange in the
exchange offer will remain outstanding and continue to accrue interest and will
be entitled to the rights and benefits those holders have under the indenture.
We will be deemed to have accepted for exchange properly tendered old bonds
when we have given oral or written notice of the acceptance to the exchange
agent. The exchange agent will act as agent for the tendering holders for the
purposes of receiving the new bonds from the partnership and delivering new
bonds to those holders. Subject to the terms of the exchange and registration
rights agreement, we expressly reserve the right to amend or terminate the
exchange offer, and not to accept for exchange any old bonds not previously
accepted for exchange, upon the occurrence of any of the conditions specified
below under the caption "--Conditions to the Exchange Offer."
Holders who tender old bonds in the exchange offer 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 old bonds. We
will pay all charges and expenses, other than certain applicable taxes described
below, in connection with the exchange offer. It is important that you read
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the "--Fees and Expenses" section below for more details regarding fees and
expenses incurred in the exchange offer.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
The exchange offer will expire at 5:00 p.m., New York City time on
, 2000, unless we extend it in our sole discretion. We do not
currently intend to extend the expiration date, although we reserve the right to
do so, and we have agreed to use our reasonable best efforts to commence and
complete the exchange offer promptly but no later than , 2000.
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
old 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.
We reserve the right, in our sole discretion:
- to delay accepting for exchange any old bonds or to extend the exchange
offer or to terminate the exchange offer and to refuse to accept old bonds
not previously accepted if any of the conditions set forth under
"--Conditions to the Exchange Offer" below have not been satisfied, by
giving oral or written notice of the delay, extension or termination to
the exchange agent; or
- subject to the terms of the exchange and registration rights agreement, to
amend the terms of the exchange offer in any manner.
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 old bonds. If we amend the exchange offer in a manner that we
determine to constitute a material change, we will promptly disclose that
amendment in a manner reasonably calculated to inform the holders of old bonds
of the amendment. During any of these extensions, all old bonds previously
tendered will remain subject to the exchange offer, and we may accept them for
exchange unless they have been previously withdrawn. We will return any old
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.
Without limiting the manner in which we may choose to make public
announcements of any delay in acceptance, extension, termination or amendment of
the exchange offer, we will have no obligation to publish, advertise or
otherwise communicate any such public announcement, other than by making a
timely release to a financial news service.
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 new bonds for, any old bonds, and we may
terminate the exchange offer as provided in this prospectus before accepting any
old bonds for exchange if in our reasonable judgment:
- the new bonds to be received will not be tradeable by the holder without
restriction under the Securities Act of 1933 or the Securities Exchange
Act of 1934 and without material restrictions under the blue sky or
securities laws of substantially all of the states of the United States;
- the exchange offer, or the making of any exchange by a holder of old
bonds, would violate applicable law or any applicable interpretation of
the SEC staff; or
- any action or proceeding has been instituted or threatened in any court or
by or before any governmental agency with respect to the exchange offer
that, in our judgment, would reasonably be expected to impair our ability
to proceed with the exchange offer.
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In addition, we will not be obligated to accept for exchange the old bonds
of any holder that has not made:
- the representations described under "--Purpose and Effect of the Exchange
Offer" or "--Procedures for Tendering" below and "PLAN OF DISTRIBUTION"
and
- other representations that may be reasonably necessary under applicable
SEC rules, regulations or interpretations to make available to us an
appropriate form for registration of the new bonds under the Securities
Act of 1933.
The exchange offer is not conditioned upon any minimum aggregate principal
amount of old bonds being tendered for exchange.
These conditions are for our sole benefit and we may assert them regardless
of the circumstances that may give rise to them or waive them in whole or in
part at any or at various times in our sole discretion. If we fail at any time
to exercise any of the foregoing rights, that failure will not constitute a
waiver of that right. Each such right will be deemed an ongoing right that we
may assert at any time or at various times.
In addition, we will not accept for exchange any old bonds tendered, and
will not issue new bonds in exchange for any of those old bonds, if at that time
any stop order is threatened or in effect with respect to the registration
statement of which this prospectus constitutes a part or the qualification of
the indenture under the Trust Indenture Act of 1939.
PROCEDURES FOR TENDERING
Only a holder of old bonds may tender those old bonds in the exchange offer.
To tender in the exchange offer, a holder must:
- complete, sign and date the letter of transmittal, or a facsimile of the
letter of transmittal; have the signature on the letter of transmittal
guaranteed if the letter of transmittal so requires; and mail or deliver
the letter of transmittal or facsimile to the exchange agent on or prior
to the expiration date (or, if the holder complies with the guaranteed
delivery procedures described below, within three New York Stock Exchange
trading days thereafter); or
- comply with DTC's Automated Tender Offer Program procedures described
below.
In addition, either:
- the exchange agent must receive old bonds along with the letter of
transmittal; or
- the exchange agent must receive, on or prior to the expiration date, a
timely confirmation of book-entry transfer of those old bonds into the
exchange agent's account at DTC according to the procedures for book-entry
transfer described below or a properly transmitted agent's message; or
- the holder must comply with the guaranteed delivery procedures described
below.
To be tendered effectively, the exchange agent must receive any physical
delivery of the letter of transmittal and other required documents at the
address set forth below under "--Exchange Agent" on or prior to the expiration
date.
The tender by a holder that is not withdrawn on or prior to the expiration
date will constitute an agreement between that holder and us under the terms and
subject to the conditions set forth in this prospectus and in the letter of
transmittal.
The method of delivery of old bonds, the letter of transmittal and all other
required documents to the exchange agent is at the holder's election and risk.
Rather than mail these items, we recommend
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that holders use an overnight or hand delivery service. In all cases, holders
should allow sufficient time to assure delivery to the exchange agent on or
prior to the expiration date. Holders should not send the letter of transmittal
or old bonds to us. Holders may request their respective brokers, dealers,
commercial banks, trust companies or other nominees to effect the above
transactions for them.
Any beneficial owner whose old bonds are registered in the name of a broker,
dealer, commercial bank, trust company or other nominee and who wishes to tender
should contact the registered holder promptly and instruct it to tender on the
owner's behalf. If that beneficial owner wishes to tender on its own behalf, it
must, prior to completing and executing the letter of transmittal and delivering
its old bonds, either:
- make appropriate arrangements to register ownership of the old bonds in
that owner's name; or
- obtain a properly completed bond power from the registered holder of old
bonds.
The transfer of registered ownership may take considerable time and may not
be completed prior to the expiration date.
Signatures on a letter of transmittal or a notice of withdrawal described
below must be 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 another "eligible institution" within the meaning of Rule 17Ad-15
under the Securities Exchange Act of 1934, unless the old bonds tendered
pursuant thereto are tendered:
- by a registered holder who has not completed the box entitled "Special
Issuance Instructions" or "Special Delivery Instructions" on the letter of
transmittal; or
- for the account of an eligible institution.
If the letter of transmittal is signed by a person other than the registered
holder of any old bonds listed on the old bonds, those old bonds must be
endorsed or accompanied by a properly completed bond power. The bond power must
be signed by the registered holder as the registered holder's name appears on
the old bonds and an eligible institution must guarantee the signature on the
bond power.
If the letter of transmittal or any old 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, they should also
submit evidence satisfactory to us of their authority to deliver the letter of
transmittal.
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 DTC program may, instead of physically
completing and signing the letter of transmittal and delivering it to the
exchange agent, transmit their acceptance of the exchange offer electronically.
They may do so by causing DTC to transfer the old bonds to the exchange agent
under 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 a book-entry confirmation, to
the effect that:
- DTC has received an express acknowledgment from a participant in its
Automated Tender Offer Program that is tendering old bonds that are the
subject of this book-entry confirmation;
- the participant has received and agrees to be bound by the terms of the
letter of transmittal (or, in the case of an agent's message relating to
guaranteed delivery, that the participant has received and agrees to be
bound by the applicable notice of guaranteed delivery); and
- the agreement may be enforced against that participant.
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We will determine in our sole discretion all questions as to the validity,
form, eligibility (including time of receipt), acceptance of tendered old bonds
and withdrawal of tendered old bonds. Our determination will be final and
binding. We reserve the absolute right to reject any old bonds not properly
tendered or any old bonds the acceptance of which would, in the opinion of our
counsel, be unlawful. We also reserve the right to waive any defects,
irregularities or conditions of tender as to particular old 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, any defects or irregularities in connection with tenders
of old bonds must be cured within the time as we shall determine. Although we
intend to notify holders of defects or irregularities with respect to tenders of
old bonds, neither we, the exchange agent nor any other person will incur any
liability for failure to give that notification. Tenders of old bonds will not
be deemed made until those defects or irregularities have been cured or waived.
Any old 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 will be
returned to the exchange agent without cost to the tendering holder, unless
otherwise provided in the letter of transmittal, as soon as practicable
following the expiration date.
In all cases, we will issue new bonds for old bonds that we have accepted
for exchange under the exchange offer only after the exchange agent timely
receives:
- old bonds or a timely book-entry confirmation of those old bonds into the
exchange agent's account at DTC; and
- a properly completed and duly executed letter of transmittal and all other
required documents or a properly transmitted agent's message.
By signing the letter of transmittal or transmitting an acceptance of the
exchange offer through DTC, each tendering holder of old bonds will represent to
us that, among other things:
- any new bonds that the holder receives will be acquired in the ordinary
course of its business;
- the holder has no arrangement or understanding with any person or entity
to participate in the distribution of the new bonds;
- if the holder is not a broker-dealer, it is not engaged in and does not
intend to engage in the distribution of the new bonds;
- if the holder is a broker-dealer that will receive new bonds for its own
account in exchange for old bonds that were acquired as a result of
market-making activities, it will deliver a prospectus, as required by
law, in connection with any resale of those new bonds; and
- the holder is not our "affiliate," as defined in Rule 405 of the
Securities Act of 1933, or, if the holder is our affiliate, it will comply
with any applicable registration and prospectus delivery requirements of
the Securities Act of 1933.
BOOK-ENTRY TRANSFER
The exchange agent will establish an account with respect to the old bonds
at DTC for purposes of the exchange offer promptly after the date of this
prospectus. Any financial institution participant in DTC's system may make
book-entry delivery of old bonds by causing DTC to transfer those old bonds into
the exchange agent's account at DTC under DTC's procedures for transfer. Holders
of old bonds who are unable to deliver confirmation of the book-entry tender of
their old bonds into the exchange agent's account at DTC or all other documents
of transmittal to the exchange agent on or prior to the expiration date must
tender their old bonds according to the guaranteed delivery procedures described
below.
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GUARANTEED DELIVERY PROCEDURES
Holders wishing to tender their old bonds but whose old bonds are not
immediately available or who cannot deliver their old bonds, 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 on or prior
to the expiration date may tender if:
- the tender is made through an eligible institution;
- on or prior to the expiration date, the exchange agent receives from the
eligible institution 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:
-- setting forth the name and address of the holder, any registered
number(s) of those old bonds and the principal amount of old bonds
tendered;
-- stating that the tender is being made thereby; and
-- guaranteeing that, within three New York Stock Exchange trading days
after the expiration date, the letter of transmittal (or facsimile
thereof) together with the old bonds or a book-entry confirmation, and
any other documents required by the letter of transmittal, will be
deposited by the eligible institution with the exchange agent; and
- the exchange agent receives the properly completed and executed letter of
transmittal (or facsimile thereof), as well as all tendered old bonds in
proper form for transfer or 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 to holders who wish to tender their old bonds according to the guaranteed
delivery procedures set forth above.
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, holders of old bonds may
withdraw their tenders at any time on or prior to the expiration date.
For your withdrawal to be effective:
- the exchange agent must receive a written notice (which may be by
telegram, telex, facsimile transmission or letter) of withdrawal at one of
the addresses set forth below under "--Exchange Agent" or
- holders must comply with the appropriate procedures of DTC's Automated
Tender Offer Program.
Any notice of withdrawal must:
- specify the name of the person who tendered the old bonds to be withdrawn;
- identify the old bonds to be withdrawn (including the principal amount of
those old bonds); and
- where certificates for old bonds have been transmitted, specify the name
in which those old bonds were registered, if different from that of the
withdrawing holder.
If certificates for old bonds have been delivered or otherwise identified to
the exchange agent, then, prior to the release of those certificates, the
withdrawing holder must also submit:
- the serial numbers of the particular certificates to be withdrawn; and
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- a signed notice of withdrawal with signatures guaranteed by an eligible
institution unless the holder is an eligible institution.
If old bonds have been tendered pursuant to 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 old bonds and
otherwise comply with DTC's procedures. We will determine all questions as to
the validity, form and eligibility (including time of receipt) of those notices,
and our determination will be final and binding on all parties. We will deem any
old bonds so withdrawn not to have been validly tendered for exchange for
purposes of the exchange offer. Any old bonds that have been tendered for
exchange but that are not exchanged for any reason will be returned to their
holder without cost to the holder (or, in the case of old bonds tendered by
book-entry transfer into the exchange agent's account at DTC according to the
procedures described above, those old bonds will be credited to an account
maintained with DTC for old bonds) as soon as practicable after withdrawal,
rejection of tender or termination of the exchange offer. Properly withdrawn old
bonds may be re-tendered 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 Chase Manhattan Bank has been appointed as exchange agent for the
exchange offer. You should direct questions and requests for assistance,
requests for additional copies of this prospectus or of the letter of
transmittal and requests for the notice of guaranteed delivery to the exchange
agent addressed as follows:
For Overnight Delivery, Delivery by Hand or Delivery by Registered or
Certified Mail:
The Chase Manhattan Bank
270 Park Avenue
New York, New York 10017
Attn: William H. McDavid, General Counsel
By Facsimile Transmission (for eligible institutions only):
(212) 270-4288
Confirm facsimile by telephone only:
(212) 270-2611
DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH
ABOVE OR TRANSMISSION VIA FACSIMILE OTHER THAN AS SET FORTH ABOVE DOES NOT
CONSTITUTE A VALID DELIVERY OF THE LETTER OF TRANSMITTAL.
FEES AND EXPENSES
We will bear the expenses of soliciting tenders. The principal solicitation
is being made by mail; however, we may make additional solicitations 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 others 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.
Our expenses in connection with the exchange offer include:
- SEC registration fees;
- fees and expenses of the exchange agent and the trustee;
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- accounting and legal fees and printing costs; and
- related fees and expenses.
TRANSFER TAXES
We will pay all transfer taxes, if any, applicable to the exchange of old
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:
- certificates representing old 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 old bonds
tendered;
- tendered old bonds are registered in the name of any person other than the
person signing the letter of transmittal; or
- a transfer tax is imposed for any reason other than the exchange of old
bonds under the exchange offer.
If satisfactory evidence of payment of those taxes is not submitted with the
letter of transmittal, the amount of those transfer taxes will be billed to that
tendering holder.
Holders who tender their old bonds for exchange will not be required to pay
any transfer taxes. However, holders who instruct us to register new bonds in
the name of, or request that old bonds not tendered or not accepted in the
exchange offer be returned to, a person other than the registered tendering
holder will be required to pay any applicable transfer tax.
CONSEQUENCES OF FAILURE TO EXCHANGE
Holders of old bonds who do not exchange their old bonds for new bonds under
the exchange offer will remain subject to the restrictions on transfer
applicable to the old bonds:
- as set forth in the legend printed on the old bonds as a consequence of
the issuance of the old bonds pursuant to the exemptions from, or in
transactions not subject to, the registration requirements of the
Securities Act of 1933 and applicable state securities laws; and
- otherwise as set forth in the offering memorandum distributed in
connection with the private offering of the old bonds.
In general, you may not offer or sell the old bonds unless they are
registered under the Securities Act of 1933, or if the offer or sale is exempt
from registration under, or not subject to, the Securities Act of 1933 and
applicable state securities laws. Except as required by the exchange and
registration rights agreement, we do not intend to register resales of the old
bonds under the Securities Act of 1933. Based on interpretations of the SEC
staff, new bonds issued pursuant to the exchange offer may be offered for
resale, resold or otherwise transferred by their holders (other than any such
holder that is our "affiliate" within the meaning of Rule 405 under the
Securities Act of 1933) without compliance with the registration and prospectus
delivery provisions of the Securities Act of 1933, provided that the holders
acquired the new bonds in the ordinary course of the holders' business and the
holders have no arrangement or understanding with respect to the distribution of
the new bonds to be acquired in the exchange offer. Any holder who tenders in
the exchange offer for the purpose of participating in a distribution of the new
bonds:
- could not rely on the applicable interpretations of the SEC; and
- must comply with the registration and prospectus delivery requirements of
the Securities Act of 1933 in connection with any secondary resale
transaction of the new bonds.
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After the exchange offer is consummated, if you continue to hold any old
bonds, you may have difficulty selling them because there will be less old bonds
outstanding. In addition, if a large amount of old bonds are not tendered or are
tendered improperly, the limited amount of new bonds that would be issued and
outstanding after we consummate the exchange offer could lower the market price
of the new bonds.
ACCOUNTING TREATMENT
We will record the new bonds in our accounting records at the same carrying
value as the old 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. We will record the expenses of
the exchange offer as incurred.
OTHER
Participation in the exchange offer is voluntary, and you should carefully
consider whether to accept. You are urged to consult your financial and tax
advisors in making your own decision on what action to take.
We may in the future seek to acquire untendered old bonds in open market or
privately negotiated transactions, through subsequent exchange offers or
otherwise. We have no present plans to acquire any old bonds that are not
tendered in the exchange offer or to file a registration statement to permit
resales of any untendered old bonds.
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USE OF PROCEEDS
We will not receive any proceeds from the issuance of the new bonds. In
consideration for issuing the new bonds as contemplated in this prospectus, we
will receive in exchange old bonds in like principal amount, which will be
cancelled and as such will not result in any increase in our indebtedness.
The proceeds of the old bonds were used to purchase the $275,000,000
principal amount of Taxable Industrial Development Revenue Bonds issued by the
Development Authority of Heard County, Georgia. The proceeds of these revenue
bonds will fund the design, procurement, construction, testing, commissioning
and initial operation of our project and were used to pay certain fees and
expenses in connection with the offering of the old bonds.
ESTIMATED SOURCES AND USES OF FUNDS
We estimate the total cost of designing, financing, engineering, procuring,
constructing, testing and start-up of our project to be approximately
$330.6 million. The following table sets forth the estimated sources and uses of
funds in connection with the construction, financing and commencement of
commercial operation of our project, including the issuance of the bonds.
<TABLE>
<S> <C>
SOURCES OF FUNDS(1)
Principal amount of the old bonds........................... $275,000,000
Equity Contribution(2)...................................... 35,500,000
Revenues from operation of the Initial Units(3)............. 20,089,000
------------
TOTAL SOURCES OF FUNDS................................ $330,589,000
============
USES OF PROCEEDS
EPC Contract................................................ $229,065,000
Electric Interconnection Facilities......................... 1,000,000
Gas Supply Facilities....................................... 3,123,000
Spare Parts................................................. 3,649,000
Development Cost............................................ 7,000,000
Initial Working Capital..................................... 258,000
Project Management.......................................... 4,643,000
Legal & Financing........................................... 5,114,000
Net Interest During Construction(4)......................... 52,757,000
Expenses of operation of the Initial Units.................. 4,831,000
Contingencies............................................... 11,962,000
Other....................................................... 7,187,000
------------
TOTAL PROJECT COSTS................................... $330,589,000
============
</TABLE>
------------------------
(1) This table does not include the provision of the debt service reserve letter
of credit or the power purchase agreement letter of credit.
(2) See "SUMMARY DESCRIPTION OF THE PRINCIPAL FINANCING DOCUMENTS--Equity
Contribution Agreement."
(3) Assumes occurrence of the date of commercial operation of the Initial Units
on June 1, 2001. A delay in the occurrence of this date would reduce this
amount. See "RISK FACTORS--Construction Risk."
(4) Interest during construction is $67,487,000 against which there has been
netted out $14,730,000 of projected interest income on unspent bond
proceeds. Reflects an interest rate of 9.50% on the bonds and that unspent
bond proceeds earn interest at an assumed 5% annual rate.
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SELECTED FINANCIAL INFORMATION
The selected financial information of the partnership set forth below has
been derived from, should be read in conjunction with, and is qualified in its
entirety by reference to, the financial statements of the partnership, including
the notes thereto, included elsewhere in this prospectus, which have been
audited by Arthur Andersen LLP, independent public accountants, as indicated in
their report thereon included elsewhere in this prospectus. These financial
statements have been prepared under generally accepted accounting principles
("GAAP"). The partnership has been in the development stage since its formation.
TENASKA GEORGIA PARTNERS, L.P.
SELECTED FINANCIAL INFORMATION
THE PARTNERSHIP
AS OF MARCH 31, 2000
<TABLE>
<S> <C> <C> <C>
ASSETS LIABILITIES AND PARTNERS' DEFICIT
Current Assets.......................... $231,740,581 Current Liabilities.................... $ 12,914,577
Development Work in Progress............ 38,008,696 Long Term Debt......................... 275,000,000
Land.................................... 602,529 Other Liabilities...................... 216,622
Other Assets............................ 7,602,906 Partners' Deficit
Tenaska Georgia, Inc................. (101,765)
Tenaska Georgia I, L.P............... (10,074,722)
------------
Total Partners' Deficit................ (10,176,487)
------------ ------------
Total Assets............................ $277,954,712 Total Liabilities and partners'
deficit................................ $277,954,712
============ ============
Net loss to partners accumulated during the development stage for the three months ended
March 31, 2000................................................................................ $ (2,397,688)
============
</TABLE>
AS OF DECEMBER 31, 1999
<TABLE>
<S> <C> <C> <C>
ASSETS LIABILITIES AND PARTNERS' DEFICIT
Current Assets.......................... $244,170,316 Current Liabilities.................... $ 3,946,876
Development Work in Progress............ 20,056,087 Long Term Debt......................... 275,000,000
Land.................................... 602,529 Other Liabilities...................... 86,501
Other Assets............................ 6,425,646 Partners' Deficit
Tenaska Georgia, Inc................. (77,788)
Tenaska Georgia I, L.P............... (7,701,011)
------------
Total Partners' Deficit................ (7,778,799)
------------ ------------
Total Assets............................ $271,254,578 Total Liabilities and partners'
deficit................................ $271,254,578
============ ============
Net loss to partners accumulated during the development stage for the twelve months ended
December 31, 1999............................................................................. $ (7,778,799)
============
</TABLE>
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RATIO OF EARNINGS TO FIXED CHARGES
Because we have not begun operations, we cannot calculate a ratio of
earnings to fixed charges.
MANAGEMENT OF THE PARTNERSHIP
Under our amended and restated partnership agreement (the "Partnership
Agreement"), Tenaska Georgia, Inc., our managing general partner, has the
exclusive power and authority to direct and manage our affairs and is
responsible for our day-to-day management, which includes administration of our
project. Tenaska Georgia I, L.P., is the limited partner under the Partnership
Agreement.
Certain actions by the partnership may be taken with a simple majority of
the general partners, based on their respective ownership interests. Examples of
these types of actions include:
- approving budgets, and
- entering into, amending or terminating material project contracts.
Dissolution of the partnership requires unanimous approval of the general
partners, based on their respective ownership interests. Removal of the managing
general partner requires unanimous approval of all partners, excluding the vote
of the managing general partner to be removed. Also, mergers, reorganizations
and the incurrence of debt require unanimous approval of the general partners.
MANAGEMENT OF TENASKA GEORGIA, INC.
The following are officers of TGI: Tenaska Georgia, Inc., our managing
general partner:
HOWARD L. HAWKS, Chairman and Chief Executive Officer of Tenaska, Inc. has
served as Chairman, CEO and President of our managing general partner since its
formation in 1998. Prior to forming Tenaska, Inc. in 1987, Mr. Hawks served in
various management positions at Enron Corp., formerly known as InterNorth Inc.,
for 21 years. He served as president of three of its subsidiary groups, Northern
Natural Resources and Enron Development, Northern Liquid Fuels Group, and
Northern Plains Natural Gas Company. Mr. Hawks also serves on the board of the
North American Electric Reliability Council (NERC). He is a graduate of the
University of Nebraska, where he earned a Bachelor of Science degree in
accounting and a Master of Business Administration degree.
THOMAS E. HENDRICKS, Vice President of Business Development of
Tenaska, Inc., has served as Vice President of our managing general partner
since its formation. Prior to co-founding Tenaska, Inc., Mr. Hendricks was an
executive with Enron Corp. and the Nebraska Public Power District. He served as
general manager of Northern Natural Resources and Enron Development, a
subsidiary of Enron Corp. Mr. Hendricks also serves on the Board of Trustees of
the Western Systems Coordinating Council. He graduated from the University of
Nebraska-Lincoln with a Bachelor of Science degree in chemical engineering.
RONALD N. QUINN, Vice President, Chief Financial Officer and Secretary of
Tenaska, Inc., is Vice President, CFO and Secretary of our managing general
partner. Prior to joining Tenaska, Inc. in 1988, Mr. Quinn was employed by
American Express Company as Vice President of Business Development in the
Information Services Division. Mr. Quinn has also held various executive
positions at Enron Corp. and at Norwest Bank. Mr. Quinn earned a Bachelor of
Science degree in business administration and a Master of Business
Administration degree from Creighton University.
MICHAEL F. LAWLER, Vice President of Finance and Treasurer of
Tenaska, Inc., is Vice President and Treasurer of our managing general partner.
Prior to joining Tenaska, Inc. in 1991, Mr. Lawler held positions as Senior Vice
President, Finance/Information Systems of Mercy Midlands; Owner and President of
Missouri Valley Natural Gas; Assistant Treasurer for InterNorth Inc., and as
Controller for Northern Propane Gas. Mr. Lawler earned a Bachelor of Science
degree in business administration from Creighton University and a Master of
Business Administration degree from the University of Iowa.
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<PAGE>
LARRY V. PEARSON, Vice President of Fuel Supply and Transportation for
Tenaska, Inc., serves as Vice President for our managing general partner. Prior
to joining Tenaska, Inc. in 1988, Mr. Pearson was an executive at Enron Corp.
for 15 years, where he held various positions, including Senior Vice President,
Enron Gas Supply; Vice President, Gas Supply, Northern Natural Gas Company; and
Vice President, Regulatory Affairs, Northern Natural Gas Company. Mr. Pearson
earned a Bachelor of Science degree in mechanical engineering from the South
Dakota School of Mines and Technology and a Master of Business Administration
degree from Creighton University.
MICHAEL C. LEBENS, Vice President of Engineering for Tenaska, Inc., serves
as Vice President of our managing general partner. Before joining Tenaska, Inc.
in 1987, Mr. Lebens was Director of Engineering for Enron Cogeneration Co. and
Northern Natural Resources, subsidiaries of Enron Corp. Mr. Lebens has also held
positions at Gibbs & Hill where he was Senior Mechanical Engineer and at
Burns & McDonnell, where he was responsible for mechanical design,
specifications and engineering estimates. Mr. Lebens earned his Bachelor of
Science degree and a Master of Science degree in mechanical engineering from the
University of Nebraska-Lincoln.
AFFILIATE TRANSACTIONS
OPERATING & MAINTENANCE AGREEMENT
Certain operation and maintenance services for our project are provided by
the Operator, which is a wholly owned subsidiary of Tenaska, Inc. Pursuant to
the O&M Agreement, we will pay the Operator for approved expenses. Tenaska
Operations will receive a fixed fee of $75,000 for the Pre-Commercial Operating
Period and a potential incentive fee of not more than $75,000 during or prior to
the Pre-Commercial Operating Period. During the Commercial Operating Period
(except for the year 2003), the Operator will receive a monthly fixed fee of
$18,750, escalated annually, an annual availability bonus of not more than
$75,000, escalated annually, and a potential annual incentive fee of not more
than $100,000, escalated annually. Tenaska Operations is liable to pay us a
negative annual availability percentage fee of not more than $75,000, escalated
annually, in the event of substandard performance. For further description of
the O&M Agreement, see "SUMMARY OF PRINCIPAL PROJECT DOCUMENTS--O&M Agreement."
LAND ARRANGEMENTS
Tenaska, Inc. has:
- sold to us by limited warranty deed its interest in 101.29 acres of land
located in Heard County, Georgia for a price of $616,100,
- leased 13.13 acres of land to us on a triple net basis for use as a
material and equipment laydown area, at a base rental rate of $1,094 per
month and for a term expiring on December 31, 2002,
- granted us a perpetual non-exclusive easement over an easement area of up
to eighty feet in width for utilities and access over Tenaska, Inc.'s
property and through the Georgia Transmission property, for purposes of
providing access to George Brown Road, in consideration for the payment of
$2,500 per acre of easement area, and
- granted us a publicly recorded option to acquire up to 8 acres of
Tenaska, Inc.'s land for use by us or our successors or assigns as an
electric substation site for a purchase price of $6,500 per acre, with an
option exercise and closing period expiring December 31, 2001.
Following the transfer of Tenaska, Inc.'s interest in the 101.29 acres of
land, we granted Tenaska, Inc. a perpetual non-exclusive gas pipeline easement
and temporary construction easement across the same property in consideration
for the payment of $2,500 per acre of easement area. Thereafter, we transferred
our interest in the same 101.29 acres of land, and some related easements, to
the Development Authority.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION
GENERAL
We were formed on April 16, 1998, to develop, finance, construct, own or
lease, operate and maintain our project. Prior to the sale of the old bonds, we
were in the development stage and had no operating revenues and expenses. We
estimate the total cost of designing, financing, engineering, procuring,
constructing and commissioning our project to be approximately $330.6 million.
See "ESTIMATED SOURCES AND USES OF FUNDS."
EQUITY CONTRIBUTION
Our partners are obligated to contribute up to $35.5 million to the
partnership to fund the costs of developing, financing, constructing, testing
and initially operating our project. Each of our partner's obligation is
supported by an acceptable letter of credit or other acceptable credit support.
LIQUIDITY AND CAPITAL RESOURCES
We believe that the net proceeds from the sale of the old bonds, interest
income on the unspent portion thereof during the construction period,
anticipated revenues from the operation of the Initial Units and proceeds of the
equity contributions will be sufficient to:
- fund the engineering, procurement, construction, testing and commissioning
of our project,
- pay certain fees and expenses in connection with the financing and
development of our project, and
- pay the costs of developing, financing and initially operating our
project, including interest on the bonds.
We are also required to pay a major maintenance expense (including payments
to General Electric International such as monthly fixed charges and availability
bonus or penalty payments) of approximately $1,038,000 in 2001 and approximately
$2,085,000 in 2002. As described in R.W. Beck's report, the amount of payments
after 2002 are assumed to escalate at 3 percent per year through January 31,
2011 and at the rate of general inflation thereafter.
In order to provide liquidity in the event of temporary cash flow
shortfalls, we are required to maintain an account that will contain an amount
equal to the principal and interest due on the bonds on the next scheduled
payment date. Our obligation to fund this account begins on June 1, 2002. The
maintenance of this balance will be done through cash funding, the issuance of a
letter of credit or a combination of both.
During the three months ended March 31, 2000, we incurred $17,952,609 of
project construction costs that were capitalized as Development Work in
Progress. As of March 31, 2000, construction of the project was on schedule and
within budget.
BUSINESS STRATEGY AND OUTLOOK
Our overall business strategy is to perform as agreed under our 29-year
Power Purchase Agreement with PECO and to maximize our revenues under the Power
Purchase Agreement by earning incentive payments available through achieving
certain availability and efficiency levels. We intend to cause our project to be
managed, operated and maintained in compliance with all applicable documents
relating to our project and all applicable legal requirements.
54
<PAGE>
BUSINESS AND REGULATORY ENVIRONMENT
INTRODUCTION
In recent years, federal and state initiatives have further promoted the
development of competition in the sale of electricity and gas. On the federal
level, the Federal Energy Regulatory Commission has adopted a rule that
facilitates access to the nationwide transmission grid by utility and
non-utility purchasers of electricity and allows utilities subject to Federal
Energy Regulatory Commission jurisdiction to recover stranded costs. In
addition, proposals have been introduced in Congress to repeal the Public
Utility Holding Company Act of 1935. If the repeal of the Public Utility Holding
Company Act of 1935 were to occur, competitive advantages that independent power
producers have over certain regulated utilities may be reduced or eliminated.
COMPETITION
Pursuant to the Power Purchase Agreement, PECO is required to purchase all
of the facility's capacity up to "Contract Capacity" and, pursuant to its
request, the facility's energy. The Power Purchase Agreement generally prohibits
us from selling capacity or energy to third parties. Therefore, during the term
of the Power Purchase Agreement, competition from other capacity and energy
providers will become an issue only if PECO breaches its agreement and ceases to
purchase the facility's capacity and energy or the Power Purchase Agreement is
otherwise terminated or not performed under its terms.
EMPLOYEES
We have no employees and do not anticipate having any employees in the
future. Pursuant to our O&M Agreement with Tenaska Operations, Inc., Tenaska
Operations, Inc. will operate and maintain the facility. The direct labor
personnel and the plant operations management will be employees of Tenaska
Operations, Inc. Management oversight of Tenaska Operations, Inc. will be
provided by Tenaska, Inc. pursuant to a service agreement between Tenaska
Operations, Inc. and Tenaska, Inc.
LEGAL PROCEEDINGS
The partnership is not party to any legal proceedings.
ENERGY REGULATION
EXEMPT WHOLESALE GENERATOR STATUS
We intend to operate as an "exempt wholesale generator" commencing on and
after the date the Initial Units are operational. On June 7, 1999, we submitted
a filing with the Federal Energy Regulatory Commission for an Order Accepting
Initial Rate Schedule for Filing, Waiving Regulations, and Granting Blanket
Approvals. Federal Energy Regulatory Commission has accepted the filing, which
includes waivers of various regulatory requirements that apply to traditional
electric utilities, on July 28, 1999. On July 9, 1999, Federal Energy Regulatory
Commission certified the partnership as an "exempt wholesale generator."
An exempt wholesale generator is a public utility under the Federal Power
Act, and the partnership, when operating solely as an exempt wholesale
generator, would be subject to the jurisdiction of the Federal Energy Regulatory
Commission with respect to its wholesale electric rates and other matters. An
exempt wholesale generator must be engaged exclusively in the business of owning
or operating an eligible facility and selling electricity at wholesale. An
eligible facility is a generating facility that is used solely to produce
electricity exclusively for sale at wholesale. An exempt wholesale generator is
exempt from the Public Utility Holding Company Act of 1935 and no company would
become a holding company under the Public Utility Holding Company Act of 1935
due to its
55
<PAGE>
holding 10% or more of the voting securities or partnership interests in the
partnership. There is no restriction on the proportion of equity interest in an
exempt wholesale generator that may be held by electric utilities and electric
utility holding companies. As an exempt wholesale generator, the partnership's
sale to PECO in the wholesale market will be exempt from rate regulation as an
electric utility under state law.
ENVIRONMENTAL REGULATION
We are required to comply with a number of statutes and regulations relating
to protection of the environment and the safety and health of the personnel
operating our project and the public during the operation of our project. Such
statutes and regulations include, among others, the regulation of air emissions,
water discharges, solid and hazardous waste disposal, hazardous materials
handling, petroleum storage, and safety and health standards, practices and
procedures applicable to the operation of the facility.
On September 24, 1998, the United States Environmental Protection Agency
(the "EPA") issued a final rule to address regional transport of ground-level
ozone in the eastern United States through reductions in nitrogen oxides
("NO(x)") in 23 jurisdictions in the east and midwest, including Georgia (the
EPA NO(x) Rule"). In 1999 in a separate action, the Georgia Environmental
Protection Division proposed certain modifications to its state implementation
plan to address the Atlanta ozone non-attainment area. Those proposed changes
include limitations on NO(x) emissions in a 34-county area, including Heard
County. This proposed change is currently under review by state and federal
officials. The EPA NOx Rule set forth an annual NO(x) emissions budget for each
affected jurisdiction and required each such jurisdiction to submit a state
implementation plan demonstrating how it would meet its budget. Depending upon
how the implementation plan for Georgia would allocate the burden of compliance
with the EPA NOx Rule as between existing generating stations and new generating
stations (such as the facility) and how Georgia modifies its implementation plan
to address the Atlanta ozone non-attainment area, the cost of operating the
facility could be materially adversely affected. The United States Court of
Appeals for the District of Columbia Circuit on May 25, 1999 stayed indefinitely
the deadline for jurisdictions to submit their implementation plans. We cannot
predict how the court challenge to the EPA NOx Rule will be resolved or whether
the EPA NOx Rule will be repromulgated in its original or in a modified form, or
if there will ultimately be any change to Georgia's regulations that adversely
affect our project. Comprehensive settlement discussions failed in August 1999,
and the continuing litigation may be protracted. We cannot predict the outcome
of other pending litigation concerning petitions by downwind states under
Section 126 of the Clean Air Act to mandate specific reductions at specific
facilities in upwind states or of other litigation about ozone standards which
might indirectly affect matters related to NO(x) implementation plan issues or
how Georgia or the EPA may ultimately resolve Atlanta's ozone non-attainment
issues.
CLEAN WATER ACT. We are subject to a variety of state and federal
regulations governing existing and potential water and wastewater discharges
from the facility. Generally, federal regulations promulgated pursuant to the
Clean Water Act govern overall water and wastewater discharges, through National
Pollutant Discharge Elimination System permits. Under current provisions of the
Clean Water Act, existing permits must be renewed every five years, at which
time permit limits are subject to extensive review and can be modified to
account for changes in regulations. In addition, the permits have re-opener
clauses that can be used to modify a permit at any time. Amendments to the Clean
Water Act could be adopted, which would require us to pay for additional
monitoring requirements and toxicity reduction evaluations. The impact of any
such amendments is not expected to significantly affect our project.
CERCLA. The facility site may be investigated for potential environmental
contamination. Investigation prior to the purchase of the facility site revealed
no evidence of the release of CERCLA-listed substances nor the presence of any
significant soil contamination. CERCLA requires the cleanup
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of sites from which there has been a release or threatened release of hazardous
substances. In the Phase I Environmental Site Assessment, the facility site was
found to be undeveloped with no evidence of recognized adverse environmental
conditions.
PERMIT STATUS
We have obtained all of the construction permits required to be obtained by
us to begin construction of the facility and expect to obtain all other
construction permits by the time required for timely completion of our project
on or before the date all six Units are scheduled to be operational. An Air
Quality Permit was granted by the Georgia Environmental Protection Division on
December 18, 1998 and amended on April 21, 1999. The Air Quality Permit obtained
by us included all state and federal new source review requirements (Prevention
of Significant Deterioration and Acid Rain Prevention Program permitting
requirements). The approval to operate will be incorporated in the Title V
permit when it is issued, as discussed below.
We have a permit from the United States Army Corps of Engineers, Nationwide
Permit ("NWP") No. 26, which permits a total of 2.08 acres of wetlands to be
filled at the facility site and the pipeline easement. Coverage under NWP
No. 26 places a 3-acre maximum wetland impact loss for the entire project,
including necessary fuel and electrical interconnections. A pre-construction
notification, including a wetlands mitigation plan was submitted to the US Army
Engineers in compliance with the requirements of NWP No. 26. Coverage under the
NWP was verified and the mitigation plan was approved by US Army Engineers on
April 21, 1999, subject to submission to and approval by the US Army Engineers
of a restrictive covenant consistent with the plan. The covenant was submitted
to US Army Engineers for approval and was recorded in accordance with under the
terms of the US Army Engineers authorization.
Based upon final grading and drainage plans, we will file an application for
a Disturbance Permit with Heard County. Currently, there is no general National
Pollutant Discharge Elimination System permit available for storm water
discharges associated with construction activity such as ours in the State of
Georgia and the Georgia Environmental Protection Division has informed us that
it will not issue individual permits for such activities. Should a general
National Pollutant Discharge Elimination System permit become available, we
intend to file a Notice of Intent to be covered by such permit and to comply
with all applicable terms of the permit. We will otherwise comply with all
applicable federal and state requirements for control of storm water during
construction.
We are required to operate in compliance with EPA requirements regarding the
storage and transfer of petroleum fuel oil. We have received a National
Pollutant Discharge Elimination System permit to discharge wastewater to Hilly
Mill Creek through an outfall which we will construct.
The facility is subject to permitting under Title V of the Clean Air Act
Amendments of 1990 and applicable state regulations. The Title V permit has not
yet been issued. We will file a permit application for a Title V Permit within
12 months after the initial operation of any particular Unit.
Georgia Power will be required to file the Georgia Power Interconnection
Agreement with the Federal Energy Regulatory Commission and will be subject to
acceptance or rejection within 60 days of filing. We regard this as a routine
filing and expect that Federal Energy Regulatory Commission will accept the
filing.
The renewal, extension or obtaining of permits and approvals for the
facility are and may be subject to contest or appeal under federal or state law.
See "RISK FACTORS--Regulatory Risks."
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DESCRIPTION OF THE NEW BONDS
GENERAL
The partnership issued the old bonds and will issue the new bonds pursuant
to the Indenture. The aggregate principal amount of the old bonds and new bonds
that may be outstanding at any one time will not exceed $275,000,000. The bonds
will mature on February 1, 2030 and will bear interest from their date of
issuance at 9.50% per annum. Except as described below, the new bonds will be
issued as fully registered bonds in authorized denominations of $100,000 and
integral multiples of $1,000 in excess thereof. Interest on the bonds will be
payable semi-annually in arrears on each February 1 and August 1, commencing
August 1, 2000 (each a "Scheduled Payment Date"), and at earlier redemption, to
the registered owners of the bonds (each a "Holder") as shown on the books for
the registration and transfer of the bonds kept at the designated corporate
trust office of The Chase Manhattan Bank, in its capacity as trustee under the
Indenture (the "Trustee"), at the close of business on the fifteenth day next
preceding such Scheduled Payment Date. Payment of principal on the bonds will
begin on February 1, 2006 and thereafter will be payable on each Scheduled
Payment Date. Interest on the bonds will be computed on the basis of a 360-day
year consisting of twelve 30-day months.
PAYMENT OF PRINCIPAL AND INTEREST
So long as DTC or its nominee, Cede & Co., is the registered owner of the
global bond issued to DTC or its nominee in registered form representing all or
a portion of the Bonds (the "Global Bonds"), payments of the principal of and
premium, if any, and interest thereon will be made directly to DTC or Cede &
Co., as nominee for DTC, under DTC's practices and procedures. Disbursements of
such payments to owners of beneficial interests in the Global Bonds are the
responsibility of the participants, as described below.
The principal of and premium, if any, and interest on each of the bonds
issued in certificate form to a Person other than DTC (the "Certificated Bonds")
will be payable by check mailed to the address of the Holder of such
Certificated Bond as such addresses appear in the books maintained by the
Trustee or, upon request by any Holder of $1 million or more in aggregate
principal amount of Certificated Bonds, by wire transfer to such Holder, except
for the payment of the final installment of principal payable with respect
thereto, which shall be made upon surrender of such bond at the principal
corporate trust office of the Trustee.
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SCHEDULED PRINCIPAL PAYMENTS
The principal of the bonds will be payable in semi-annual installments on
Scheduled Payment Dates commencing February 1, 2006 as follows:
<TABLE>
<CAPTION>
SCHEDULED PAYMENT DATE PAYMENT SCHEDULED PAYMENT DATE PAYMENT
---------------------- --------- ---------------------- ------------
<S> <C> <C> <C>
February 1, 2006 $ 344,000 February 1, 2018 $ 5,844,000
August 1, 2006 344,000 August 1, 2018 5,844,000
February 1, 2007 344,000 February 1, 2019 6,532,000
August 1, 2007 344,000 August 1, 2019 6,532,000
February 1, 2008 688,000 February 1, 2020 6,875,000
August 1, 2008 688,000 August 1, 2020 6,875,000
February 1, 2009 1,032,000 February 1, 2021 7,219,000
August 1, 2009 1,032,000 August 1, 2021 7,219,000
February 1, 2010 1,375,000 February 1, 2022 7,563,000
August 1, 2010 1,375,000 August 1, 2022 7,563,000
February 1, 2011 1,719,000 February 1, 2023 8,250,000
August 1, 2011 1,719,000 August 1, 2023 8,250,000
February 1, 2012 2,407,000 February 1, 2024 8,594,000
August 1, 2012 2,407,000 August 1, 2024 8,594,000
February 1, 2013 3,094,000 February 1, 2025 8,938,000
August 1, 2013 3,094,000 August 1, 2025 8,938,000
February 1, 2014 3,438,000 February 1, 2026 9,282,000
August 1, 2014 3,438,000 August 1, 2026 9,282,000
February 1, 2015 4,125,000 February 1, 2027 9,969,000
August 1, 2015 4,125,000 August 1, 2027 9,969,000
February 1, 2016 4,469,000 February 1, 2028 11,688,000
August 1, 2016 4,469,000 August 1, 2028 11,688,000
February 1, 2017 5,157,000 February 1, 2029 12,375,000
August 1, 2017 5,157,000 August 1, 2029 12,375,000
February 1, 2030 12,358,000
Total: $275,000,000
</TABLE>
BOOK-ENTRY, DELIVERY, FORM AND TRANSFER
GLOBAL BONDS
The new bonds will be initially issued in the form of one or more permanent
global bonds, which will be registered in the name of DTC or a nominee of DTC
and deposited on behalf of the purchasers of the old bonds represented thereby
with the Trustee as custodian for DTC.
The aggregate principal amount of the Global Bonds may from time to time be
increased or reduced by adjustments made in the records of the Trustee as
custodian for DTC.
Interests in the Global Bonds may be held in denominations of $100,000 and
integral multiples of $1,000 in excess thereof.
CERTIFICATED BONDS
Interests in the Global Bond will be exchangeable for bonds in certificated,
fully registered form without coupons in denominations of $100,000 and integral
multiples of $1,000 in excess thereof (1) (a) if DTC notifies the partnership
that it is unwilling or unable to continue as depository for such Global Bonds
or DTC ceases to be a "Clearing Agency" registered under the Securities Exchange
Act of 1934, and a successor depository is not appointed by the partnership
within 90 days, or (b) at the
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written request of a majority of holders of beneficial interests in a Global
Bond during an Event of Default and (2) if such exchange complies with the
Indenture and the rules and procedures of DTC and its nominee (the "Applicable
Procedures").
REPLACEMENT EXCHANGE AND TRANSFER
If any bond at any time is mutilated, defaced, destroyed, stolen or lost,
such bond may be replaced at the cost of the applicant (including the reasonable
and duly documented fees and expenses of the partnership and the Trustee) upon
provision of evidence satisfactory to the Trustee and the partnership that such
bond was destroyed, stolen or lost, together with such indemnity as the Trustee
and the partnership may require. Mutilated or defaced bonds must be surrendered
before replacements will be issued.
CERTAIN BOOK-ENTRY PROCEDURES FOR THE GLOBAL BONDS
The descriptions of the operations and procedures of DTC set forth below are
provided solely as a matter of convenience. These operations and procedures are
solely within the control of the respective settlement systems and are subject
to change by them from time to time. The partnership takes no responsibility for
these operations or procedures, and investors are urged to contact the relevant
system or its participants directly to discuss these matters. DTC has advised
the partnership that it is
- a limited purpose trust company organized under the laws of the State of
New York,
- a "banking organization" within the meaning of the New York Banking Law,
- a member of the Federal Reserve System,
- a "clearing corporation" within the meaning of the Uniform Commercial
Code, as amended and
- a "clearing agency" registered pursuant to Section 17A of the Securities
Exchange Act of 1934.
DTC was created to hold securities for its participants and facilitates the
clearance and settlement of securities transactions between participants through
electronic book-entry changes to the accounts of its participants, thereby
eliminating the need for physical transfer and delivery of certificates. DTC's
participants include securities brokers and dealers, banks and trust companies,
clearing corporations and certain other organizations. Indirect access to DTC's
system is also available to other entities such as banks, brokers, dealers and
trust companies (collectively, the "Indirect Participants") that clear through
or maintain a custodial relationship with a participant, either directly or
indirectly. Investors who are not participants may beneficially own securities
held by or on behalf of DTC only through participants or Indirect Participants.
The partnership expects that pursuant to procedures established by DTC
(a) DTC will credit the accounts of participants with an interest in the Global
Bond and (b) ownership of the bonds will be shown on, and the transfer of
ownership thereof will be effected only through, records maintained by DTC (with
respect to the interests of participants) and the records of participants and
the Indirect Participants (with respect to the interests of persons other than
participants). The laws of some jurisdictions may require that certain
purchasers of securities take physical delivery of such securities in definitive
form. Accordingly, the ability to transfer interests in the bonds represented by
the Global Bond to such persons may be limited. In addition, because DTC can act
only on behalf of its participants, who in turn act on behalf of persons who
hold interests through participants, the ability of a person having an interest
in bonds represented by the Global Bond to pledge or transfer such interest to
persons or entities that do not participate in DTC's system, or to otherwise
take actions in respect of such interest, may be affected by the lack of a
physical definitive security in respect of such interest. So long as DTC or its
nominee is the registered owner of the Global Bond, DTC or such nominee, as the
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case may be, will be considered the sole owner or holder of the bonds
represented by the Global Bond for all purposes under the Indenture.
Except as provided above, owners of beneficial interests in the Global Bond
will not be entitled to have bonds represented by the Global Bond registered in
their names, will not receive or be entitled to receive physical delivery of
Certificated Bonds, and will not be considered the owners or holders thereof
under the Indenture for any purpose, including with respect to the giving of any
direction, instruction or approval to the Trustee thereunder. Accordingly, each
holder owning a beneficial interest in the Global Bond must rely on the
procedures of DTC and, if such holder is not a participant or an Indirect
Participant, on the procedures of the participant through which such holder owns
its interest, to exercise any rights of a holder of bonds under the Indenture or
the Global Bond. The partnership understands that under existing industry
practice, in the event that the partnership requests any action of holders of
bonds, or a holder that is an owner of a beneficial interest in the Global Bond
desires to take any action that DTC, as the holder of the Global Bond, is
entitled to take, DTC would authorize the participants to take such action and
the participants would authorize holders owning through such participants to
take such action or would otherwise act upon the instruction of such holders.
Neither the partnership nor the Trustee will have any responsibility or
liability for any aspect of the records relating to or payments made on account
of bonds by DTC, or for maintaining, supervising or reviewing any records of DTC
relating to such bonds.
Payments with respect to the principal of, and premium, if any, and interest
on, any bonds represented by the Global Bond registered in the name of DTC or
its nominee on the applicable record date will be payable by the Trustee to or
at the direction of DTC or its nominee in its capacity as the registered holder
of the Global Bond representing such bonds under the Indenture. Under the terms
of the Indenture, the partnership and the Trustee may treat the persons in whose
names the bonds, including the Global Bond, are registered as the owners thereof
for the purpose of receiving payment thereon and for any and all other purposes
whatsoever. Accordingly, neither the partnership nor the Trustee has or will
have any responsibility or liability for the payment of such amounts to owners
of beneficial interests in the Global Bond (including principal, premium, if
any, and interest). Payments by the participants and the Indirect Participants
to the owners of beneficial interests in the Global Bond will be governed by
standing instructions and customary industry practice and will be the
responsibility of the participants or the Indirect Participants and DTC.
Transfers between participants in DTC will be effected under DTC's procedures,
and will be settled in same-day funds.
OPTIONAL REDEMPTIONS
REDEMPTION AT THE OPTION OF THE PARTNERSHIP
At the option of the partnership, the bonds are subject to redemption prior
to the Stated Maturity thereof, in whole or in part, on any business day, at a
price equal to the Redemption Price plus the Make-Whole Premium.
BLOCKED DISTRIBUTIONS
Subject to exceptions and conditions, the bonds shall be redeemed, in whole
or in part, at any time on any business day, at a price equal to the Redemption
Price with monies from the Distribution Suspense Account received by the Trustee
from the Collateral Agent, provided such receipt is under the Collateral Agency
Agreement. See "SUMMARY DESCRIPTION OF PRINCIPAL FINANCING DOCUMENTS--Collateral
Agency Agreement--PARTNERSHIP DISTRIBUTION FUND--Blocked Partner Distributions."
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MANDATORY REDEMPTIONS
EVENT OF LOSS
Subject to exceptions and conditions, the bonds shall be redeemed, in whole
or in part, at a price equal to the Redemption Price with certain monies from
the Loss Proceeds Account received by the Trustee from the collateral agent
designated by the Collateral Agency Agreement (the "Collateral Agent") in
connection with an Event of Loss or an Event of Eminent Domain that has been
determined under the Collateral Agency Agreement to render all or a portion of
the facility incapable of being rebuilt, repaired or restored to permit
operation of the facility or a portion thereof on a commercially feasible basis.
See "SUMMARY DESCRIPTION OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency
Agreement--LOSS PROCEEDS ACCOUNT."
EXCESS LOSS PROCEEDS
Subject to exceptions and conditions, the bonds shall be redeemed, in whole
or in part, at a price equal to the Redemption Price with monies from the Loss
Proceeds Account received by the Trustee from the Collateral Agent in the event
that Loss Proceeds in excess of $1,000,000 remain in the Loss Proceeds Account
following the repair or restoration in respect of which such Loss Proceeds were
received. See "SUMMARY DESCRIPTION OF PRINCIPAL FINANCING DOCUMENTS--Collateral
Agency Agreement--LOSS PROCEEDS ACCOUNT."
ENERGY CONTRACT BUY-OUT
The bonds shall be redeemed, in whole or in part, at a price equal to the
Redemption Price with monies received by the Trustee from the Collateral Agent
from the Energy Contract Buy-Out Proceeds Sub-account if the partnership
receives either:
(a) the required payment from PECO in connection with a termination by PECO
of the Power Purchase Agreement on the 20th anniversary of the date of
commencement of the operating term of the Power Purchase Agreement, or
(b) subject to exceptions and conditions, any cash payment from a purchaser
of capacity or energy (including under the Power Purchase Agreement,
other than as referred to in clause (a)), the effect of which is to
result in the termination or cancellation of, reduce future payments
under, or change the term of, the capacity or energy purchase contract
between such purchaser and the partnership; provided, however, that, in
the case of cash payments referred to in clause (b), this provision shall
be applicable only if the termination or cancellation of, reduction of
payments under, or change in term of, the related capacity or energy
purchase contract is certified by the partnership as not voluntarily
sought by the partnership, but into which the partnership is legally or
practically required to enter by force of law or regulation, or by an
actual or threatened condemnation, expropriation or other taking of our
project, or by an actual or threatened bankruptcy proceeding on the part
of the purchaser of the electricity or capacity under the subject
contract or by an actual or threatened termination of full performance on
the part of such purchaser; provided, further that, in the case of a
threatened
- condemnation, expropriation or other taking,
- bankruptcy proceeding or
- termination of full performance,
such threat shall be express and in writing, and the partnership shall have
certified that such threat has resulted in the bonds being placed on a negative
credit watch or in a Rating Downgrade by either Rating Agency, or, either Rating
Agency shall have indicated that any such threatened action should
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result in either the bonds being placed on a negative credit watch or in a
Rating Downgrade (each, an "Involuntary Buyout Event"). See "SUMMARY DESCRIPTION
OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency Agreement--LOSS PROCEEDS
ACCOUNT--ENERGY CONTRACT BUY-OUT."
EPC BUY-DOWN
Subject to exceptions and conditions, the bonds shall be redeemed, in whole
or in part, at a price equal to the Redemption Price with monies received by the
Trustee from the Collateral Agent from the EPC Buy-Down Proceeds Sub-account
under the Collateral Agency Agreement in connection with an EPC Buy-Down that
has been determined under the Collateral Agency Agreement to render the facility
incapable of being rebuilt, repaired or restored in order to remedy the
circumstances giving rise to the obligation of the EPC Contractor to pay to an
EPC Buy-Down. See "SUMMARY DESCRIPTION OF PRINCIPAL FINANCING
DOCUMENTS--Collateral Agency Agreement--LOSS PROCEEDS ACCOUNT--EPC BUY-DOWN."
SELECTION OF BONDS FOR REDEMPTION; EFFECT OF REDEMPTION
Bonds subject to redemption in part will be redeemed on a pro rata basis.
All bonds, or portions thereof, called for redemption will cease to bear
interest on the Redemption Date and will no longer be considered Outstanding,
provided that sufficient funds for their redemption are on deposit with the
Trustee on or prior to the Redemption Date.
RATINGS
Moody's and S&P have assigned the bonds the ratings set forth above under
"PROSPECTUS SUMMARY--The New Bonds--Ratings." There is no assurance that any
such ratings will remain in effect for any given period of time or that such
ratings will not be lowered, suspended or withdrawn entirely by the applicable
Rating Agency, if, in such Rating Agency's judgment, circumstances so warrant.
Any such lowering, suspension or withdrawal of any such ratings may have a
material adverse effect on the market price or marketability of the bonds.
SECURITY AND SOURCES OF PAYMENT FOR THE BONDS
The following description of the security and sources of payment for the
bonds constitutes a summary thereof and should not be considered to be a full
statement of the provisions thereof and is qualified in its entirety by
reference to all provisions of the Financing Documents and complete reference to
this prospectus in its entirety.
The bonds are obligations solely of the partnership payable solely from, and
secured by the pledge of, the Indenture Collateral, as set forth in the
Indenture, and by the Collateral, as set forth in the other Security Documents.
The Indenture Collateral consists of the funds and accounts established under
the Indenture, the Debt Service Reserve Account established under the Collateral
Agency Agreement and any Debt Service Reserve Letter of Credit (other than to
the extent of the Debt Service Reserve Letter of Credit provider's right to
amounts thereunder). The rights of Holders with respect to the Indenture
Collateral and the Collateral are governed by the provisions of the Indenture
and the Collateral Agency Agreement. For the rights of the parties to the
Collateral Agency Agreement, see "SUMMARY DESCRIPTION OF PRINCIPAL FINANCING
DOCUMENTS--Collateral Agency Agreement."
The partnership's obligations under the bonds are nonrecourse to any of the
partners or affiliates (other than the partnership) or any shareholder, partner,
officer, employee or director. Recourse on the bonds is limited to the
partnership, the Indenture Collateral and the Collateral.
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SUMMARY DESCRIPTION OF PRINCIPAL FINANCING DOCUMENTS
THE FOLLOWING ARE SUMMARIES OF THE MATERIAL TERMS OF PRINCIPAL FINANCING
DOCUMENTS RELATED TO OUR PROJECT AND SHOULD NOT BE CONSIDERED TO BE A FULL
STATEMENT OF THE TERMS AND PROVISIONS OF SUCH DOCUMENTS. ACCORDINGLY, THE
FOLLOWING SUMMARIES ARE QUALIFIED IN THEIR ENTIRETY BY REFERENCE TO EACH
DOCUMENT. COPIES OF EACH DOCUMENT ARE AVAILABLE FOR INSPECTION AS DESCRIBED
ABOVE UNDER "IMPORTANT NOTICE ABOUT INFORMATION PRESENTED IN THIS PROSPECTUS."
UNLESS OTHERWISE STATED, ANY REFERENCE IN THIS PROSPECTUS TO ANY DOCUMENT SHALL
MEAN SUCH DOCUMENT AND ALL SCHEDULES, EXHIBITS AND ATTACHMENTS THERETO AS
AMENDED, SUPPLEMENTED OR OTHERWISE MODIFIED AND IN EFFECT AS OF THE DATE HEREOF.
OVERVIEW OF THE PRINCIPAL FINANCING DOCUMENTS:
The principal financing documents that we entered into in connection with
the issuance and sale of the bonds, and the primary purposes of these documents,
are as follows:
- INDENTURE: We entered into the Indenture with the Trustee, as
representative of the holders of the bonds. The indenture includes, among
other things: (a) procedures for the issuance of the bonds and additional
bonds and their authentication by the Trustee; (b) provisions that permit,
or require, us to redeem the bonds before their maturity date;
(c) affirmative covenants that require us to take action while any bonds
are outstanding; (d) negative covenants that restrict our activities while
any bonds are outstanding; and (e) events of default that permit the
holders of the bonds to exercise remedies against us and the collateral.
- COMMON AGREEMENT: We entered into the Common Agreement with the Trustee,
the Debt Service Reserve Letter of Credit Agent, the Power Purchase
Agreement Letter of Credit Agent and the Collateral Agent. The Common
Agreement sets forth, among other things, the conditions precedent to the
issuance and delivery of the bonds, events of default, representations and
warranties of the partnership and various covenants of the partnership.
- COLLATERAL AGENCY AGREEMENT: We entered into this agreement with the
Collateral Agent, the Trustee, Development Authority Trustee, Debt Service
Reserve Letter of Credit Agent, the Power Purchase Agreement Letter of
Credit Agent and the Depositary Bank. The Collateral Agent obtains its
authority to act on behalf of the Secured Parties under the Collateral
Agency Agreement. The Collateral Agency Agreement also provides for the
sharing of collateral among the Secured Parties and the procedures for
voting by the Secured Parties on the exercise of remedies.
- DEBT SERVICE RESERVE LETTER OF CREDIT REIMBURSEMENT AGREEMENT: We entered
into this agreement with The Toronto-Dominion Bank to provide up to
$16 million to be held by the Collateral Agent to serve as a debt service
reserve facility for our project.
- POWER PURCHASE AGREEMENT LETTER OF CREDIT REIMBURSEMENT AGREEMENT: We
entered into this agreement with The Toronto-Dominion Bank which will
provide a Power Purchase Agreement letter of credit for use by the
partnership in connection with our project.
- EQUITY CONTRIBUTION AGREEMENT: We entered into this agreement with
Tenaska, Inc., our Contributing Partners and the Collateral Agent. Under
this agreement, if the amounts on deposit in the Construction Fund are
insufficient to make transfers required to pay our Project Costs, each
Contributing Partner will contribute equity to the partnership from time
to time during the construction period at the request of the Collateral
Agent.
- SECURITY AGREEMENT: We entered into this agreement with the Collateral
Agent for the benefit of the Senior Parties. Under this agreement, we have
granted a continuing lien on and a security interest in: (a) all of the
partnership's personal property interests, (b) all proceeds in respect of
any action to condemn, seize or appropriate all or any part of the
project, (c) all proceeds in
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respect of any property insurance policy (other than proceeds of business
interruption insurance or delayed opening insurance) covering the
partnership or the project, (d) amounts held in any account of the
partnership (excluding the Unrestricted Account), Governmental Approvals
(to the extent permitted by their terms and by applicable law), and
(e) general intangibles and all other personal property of the
partnership, including all products and proceeds thereof.
- OTHER AGREEMENTS: We also entered into the Deed to Secure Debt, Assignment
of Rents and Leases and Security Agreement with the Collateral Agent. In
connection with the collateral assignment of contract rights held by the
partnership, including rights under our Project Documents, the Collateral
Agent received an executed consent to assignment from some of the third
parties to our Project Documents. The Development Authority entered into
the Deed to Secure Debt, Security Agreement and Assignment of Rents and
Leases with the Development Authority Trustee, our managing general
partner entered into a General Partner Pledge and Security Agreement and
our limited partner entered into a Limited Partner Pledge and Security
Agreement in favor of the Collateral Agent.
INDENTURE
ACCOUNTS
The following accounts (the "Indenture Accounts") have been established by
the Trustee: the account so designated, established and created under the
Indenture (the "Bond Payment Account"), including the Interest Sub-Account and
the Principal Sub-Account, the Redemption Account and the Construction Interest
Account. All amounts from time to time held in each Indenture Account shall 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 PAYMENT ACCOUNT
On the Date of Commercial Operation of the final three Units scheduled to be
placed into Power Purchase Agreement Commercial Operation (the "Final Units"),
the Bond Payment Account will be funded from amounts transferred from the
Construction Interest Account pursuant to the Indenture, and from the
Construction Fund established pursuant to the Collateral Agency Agreement.
Following the Date of Commercial Operation of the Final Units, the Bond Payment
Account will be funded from amounts transferred from the Debt Service Fund and,
if required, the Debt Service Reserve Account pursuant to the Collateral Agency
Agreement. See "--Collateral Agency Agreement."
The Trustee shall deposit (1) all funds received by it for the payment of
interest on the bonds into the Interest Sub-Account for disbursement under the
Indenture and (2) all funds received by it for the payment of principal on the
bonds into the Principal Sub-Account for disbursement under the Indenture.
CONSTRUCTION INTEREST ACCOUNT
Prior to the Date of Commercial Operation of the Final Units, the Trustee
shall deposit all funds received by it for the payment of interest on the bonds
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 a Scheduled Payment Date or otherwise). On the Date of
Commercial Operation of the Final Units and upon the partnership's delivery to
the Collateral Agent and the Trustee of a Commercial Operation Certificate, the
Trustee shall transfer all funds remaining in the Construction Interest Account
to the Bond Payment Account for deposit in the Interest Sub-Account.
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INTEREST SUB-ACCOUNT AND PRINCIPAL SUB-ACCOUNT
- The Trustee is authorized and directed to disburse from the Interest
Sub-Account, the amount required to pay interest on the bonds when due
(whether on a Scheduled Payment Date or otherwise).
- The Trustee is authorized and directed to disburse from the Principal
Sub-Account, the amount required to pay principal on the bonds when due
(whether on a Scheduled Payment Date or otherwise).
REDEMPTION OF BONDS; NOTICE
NOTICE TO TRUSTEE
The election or requirement of the partnership to redeem any bonds, at any
time, will be evidenced by a written request of the partnership specifying the
principal amount of the bonds to be redeemed. If the partnership elects or is
required to redeem any bonds, the Trustee will determine the date on which such
redemption will occur (the "Redemption Date") which will be within 90 days of
its receipt of monies in respect of the event resulting in the partnership's
obligation or election to redeem the bonds.
NOTICE OF REDEMPTION
Notice of redemption will be given to the Holders of such series to be
redeemed at least 30 days but not more than 60 days prior to the Redemption
Date. All notices of redemption will state, among other things:
- the Redemption Date,
- the premium payable on redemption, if any,
- the portion of the principal amount of each bond to be redeemed,
- that on the Redemption Date interest on such bonds will cease to accrue on
and after said date,
- the place of payment where such bonds are to be surrendered for payment of
the amount in respect of such redemption,
- the record date and
- that the availability in the Redemption Account of an amount of
immediately available funds to pay such bonds in full is a condition
precedent to such redemption.
BONDS PAYABLE ON REDEMPTION DATE
The bonds or portions thereof to be redeemed will, on the Redemption Date,
become due and payable, and from and after such date such bonds or portions
thereof will cease to bear interest. Upon surrender of any such bond for
redemption, an amount in respect of such bond or portion thereof will be paid as
provided therein; PROVIDED, HOWEVER, that any payment of interest on any bond,
the Scheduled Payment Date of which is on or prior to the Redemption Date, will
be payable to the Holder of such bond registered as such at the close of
business on the record date according to the terms of such bond and the
Indenture.
Any notice of redemption shall be conclusively presumed to have been duly
given whether or not such notice is actually received by the Holder. No defect
in the notice with respect to any bond (whether in the form of notice or the
mailing thereof) shall affect the validity of the redemption proceedings for any
other bonds.
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REPRESENTATIONS AND WARRANTIES; PERFORMANCE OF COVENANTS
All representations and warranties by and all covenants of the partnership
set forth in the Common Agreement are incorporated by reference into the
Indenture as if set forth therein.
EVENTS OF DEFAULT; REMEDIES
CERTAIN EVENTS
The following events constitute "Events of Default" under the Indenture:
(a) failure in the payment of principal of, premium, if any, or interest on
any bond when the same becomes due and payable, whether by scheduled maturity or
required prepayment or redemption or by acceleration or otherwise, and such
failure continues for more than 5 days following the due date for payment in the
case of principal, and more than 15 days following the due date for payment in
the case of interest or premium; or
(b) an Event of Default shall have occurred and be continuing under the
Common Agreement.
ENFORCEMENT OF REMEDIEs
(a) Subject to subsections (c) and (d) below, if one or more Events of
Default has occurred and is continuing, then:
(1) in the case of an Event of Default described in clause (a) above,
the Trustee may, and at the direction of the Holders of not less than 25% in
aggregate principal amount of the Outstanding Bonds (the "One-Quarter
Holders") the Trustee shall, declare the entire principal amount of
Outstanding Bonds, all interest accrued and unpaid thereon, all premium (if
any) and other amounts payable in respect thereof, to be due and payable;
(2) in the case of all other Events of Default other than a bankruptcy
event with respect to the partnership, such action described in the above
paragraph may be taken by the Holders of greater than 50% in an aggregate
principal amount of the Outstanding Bonds (the "Majority Holders"), by
written notice to the Trustee and the partnership, and the Trustee, by
written notice to the partnership; or
(3) in the case of a bankruptcy event with respect to the partnership,
the entire principal amount of the Outstanding Bonds, all interest accrued
and unpaid thereon, all premium (if any) and other amounts payable in
respect thereof shall automatically become due and payable.
Within 30 days after the occurrence of an Event of Default which is known to
the Trustee, the Trustee will mail to each Holder notice of such Event of
Default. Except in the case of an Event of Default relating to failure to pay
principal of, premium, if any, or interest on any bond, the Trustee may withhold
such notice from the Holders if the Trustee in good faith determines that
withholding notice is in the interest of the Holders.
Notwithstanding the absence of direction from the Majority Holders directing
the Trustee to accelerate the maturity of the bonds, if one or more of the
Events of Default referred to in clause (a)(2) immediately above has occurred
and is continuing, the Trustee may declare the entire principal amount of the
Outstanding Bonds, all interest accrued and unpaid thereon, and all premium (if
any) and other amounts payable under the bonds and the Indenture, if any, to be
due and payable, unless the Majority Holders direct the Trustee not to
accelerate the maturity of the bonds, if in the good faith exercise of its
discretion the Trustee determines that such action is necessary to protect the
interests of the Holders.
(b) At any time after the principal of the bonds has become due and payable
upon a declared acceleration, and before any judgment or decree for the payment
of the money so due, or any portion
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thereof, has been entered, the Majority Holders, by written notice to the
partnership and the Trustee, may rescind and annul such declaration and its
consequences if:
(1) there has been paid to or deposited with the Trustee a sum
sufficient to pay:
- all overdue interest on the bonds;
- the principal of and premium (if any) on any bonds that have become
due (including overdue principal) other than by such declaration of
acceleration; and
- all sums paid or advanced by the Trustee and the reasonable
compensation, expenses, disbursements, and advances of the Trustee,
its agents and counsel; and
(2) all Events of Default, other than the nonpayment of the principal of
the bonds that has become due solely by such acceleration, have been
cured or waived under the Indenture and the Collateral Agency Agreement;
provided that no such rescission or annulment will affect or impair any
subsequent Default or Event of Default.
(c) If an Event of Default has occurred and is continuing and an
acceleration has occurred, subject to, among other things, the Collateral Agency
Agreement, the Trustee may sell the Indenture Collateral as the Majority Holders
shall request, or, in the absence of such request, as the Trustee in its
discretion shall deem expedient in the interest of the Holders, at public or
private sale.
(d) Subject to the Collateral Agency Agreement, if an Event of Default has
occurred and is continuing and an acceleration has occurred, the Trustee may (as
the Majority Holders request) direct the Collateral Agent to take possession of
all Collateral and, pursuant to the Collateral Agency Agreement, to sell such
Collateral, as and to the extent permitted under the Collateral Agency
Agreement.
(e) All rights and remedies available to the Holders, or to the Trustee with
respect to the Collateral, or otherwise pursuant to 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 interest
represented by the Outstanding Bonds.
APPLICATION OF MONIES COLLECTED BY TRUSTEE. Any money collected or to be
applied by the Trustee after an Event of Default in respect of the bonds will be
applied to amounts owed with respect to all bonds on a pro rata basis and will
be applied ratably to the Holders in the following order from time to time, on
the date or dates fixed by the Trustee: (a) FIRST, to the payment of all amounts
due to the Trustee or any predecessor Trustee under the Indenture; (b) SECOND,
- in case the unpaid principal amount of the bonds has not become due, to
the payment of any overdue interest, in the order of the maturity of the
payments thereof,
- in case the unpaid principal amount of a portion of the bonds has become
due, first to the payment of accrued interest on all bonds in the order of
the maturity of the payments thereof, and next to the payment of the
overdue principal of and premium, if any, on all bonds then due or
- in case the unpaid principal amount of all the bonds has become due, to
the payment of the whole amount then due and unpaid upon the bonds for
principal, premium, if any, and interest;
and (c) THIRD, in case the unpaid principal amount of all the bonds has become
due, and all of the outstanding principal, premium, if any, interest and other
amounts owed in connection with bonds have been fully paid, any surplus then
remaining will be paid to the partnership, or to whomsoever may be lawfully
entitled to receive the same, or as a court of competent jurisdiction may
direct.
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AMENDMENTS AND SUPPLEMENTS
The partnership and the Trustee may amend or supplement the Indenture
without the consent of the Holders
- to add additional covenants of the partnership, to surrender rights
conferred upon the partnership, or to confer additional benefits upon the
Holders,
- to increase the assets securing the partnership's obligations under the
Indenture,
- to provide for the issuance of additional bonds,
- for any purpose not inconsistent with the terms of the Indenture or to
cure any ambiguity, defect or inconsistency,
- to reflect any amendments required by a Rating Agency in circumstances
where confirmation of the ratings is required under the Indenture or
- to provide for the issuance of new bonds as contemplated by any agreement
entered into in connection with the issuance of additional bonds.
The Indenture may be otherwise amended or supplemented by the partnership
and the Trustee with the consent of the Majority Holders; PROVIDED, HOWEVER,
that no such amendment or supplement may, without the consent of Holders of all
then Outstanding Bonds, modify
- the principal, premium (if any) or interest payable upon any bonds,
- the dates on which interest on or principal of any bonds is paid,
- the dates of maturity of any bonds,
- the procedures for amendment by a supplemental indenture, or
- the grant of security interests for the benefit of the bonds.
SATISFACTION AND DISCHARGE OF THE INDENTURE; DEFEASANCE
The partnership may terminate the Indenture by delivering all Outstanding
Bonds to the Trustee for cancellation and by paying all other sums payable under
the Indenture.
Legal and covenant defeasance will be permitted upon terms and conditions
customary for transactions of this nature.
TRUSTEE
There will at all times be a Trustee under the Indenture, which must be a
corporation which
- has a combined capital and surplus of at least $50 million,
- is subject to supervision or examination by a federal or state or District
of Columbia authority and
- has a corporate trust office in New York, New York, each to the extent
there is such an institution eligible and willing to serve.
The partnership agrees to indemnify and hold harmless the Trustee in
connection with the performance of its duties under the Indenture, except for
liability which results from the gross negligence or bad faith of the Trustee.
The Trustee may resign at any time by giving written notice thereof to the
partnership. The Trustee may be removed at any time by act of the Majority
Holders, with notice thereof delivered to the Trustee and to the partnership.
The partnership will give notice of each resignation and removal of the Trustee
and each appointment of a successor Trustee to all Holders.
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COMMON AGREEMENT
The partnership entered into a Common Agreement (the "Common Agreement")
with the Trustee, the Debt Service Reserve Letter of Credit Agent, the Power
Purchase Agreement Letter of Credit Agent, and the Collateral Agent. The Common
Agreement sets forth, among other things, the conditions precedent to the date
of issuance and delivery of the bonds (the "Closing Date"), events of default,
representations and warranties of the partnership and various covenants of the
partnership.
CERTAIN COVENANTS
Set forth below are various affirmative and negative covenants of the
partnership contained in the Common Agreement.
USE OF PROCEEDS. The partnership used the proceeds from the sale of the
bonds to purchase the revenue bonds issued by the Development Authority of Heard
County, the proceeds of which will be used only to pay Project Costs.
REPORTING REQUIREMENTS. The partnership will provide to the Collateral
Agent, the Trustee, each Rating Agency and such other Senior Parties which so
request
- unaudited financial statements for each of the first three quarters of
each fiscal year (commencing with the quarter ending March 31, 2000) and
annual audited financial statements for each fiscal year (commencing with
the fiscal year ended December 31, 2000),
- all other information in respect of the partnership reasonably requested
by either Rating Agency,
- written notice of any Default or Event of Default or any notice of any
material litigation, claim or proceeding pending or to the best knowledge
of the partnership, threatened, involving or affecting the partnership or
our project,
- a copy of the annual operating budget for each calendar year after the
Date of Commercial Operation and
- quarterly signed and authorized officer's certificates from the
partnership certifying that, as of such date, no Default or Event of
Default has occurred and is continuing, or, if a Default or Event of
Default has occurred and is continuing, a statement as to the nature
thereof.
COMPLIANCE WITH LAWS. The partnership will comply with all applicable laws
and Governmental Approvals applicable to it, and all other acts, rules,
regulations, permits, orders and requirements, except where non-compliance would
not reasonably be expected to result in a Material Adverse Effect.
GOVERNMENTAL APPROVALS; TITLE. The partnership will at all times
(a) obtain and maintain in full force and effect and comply with all
Governmental Approvals and other consents and approvals required at any time in
connection with its business, except where failure to take such action would not
reasonably be expected to result in a Material Adverse Effect and (b) preserve
and maintain good and marketable title or valid leasehold rights to its
properties and assets (subject to no liens other than Permitted Liens).
PERFORMANCE OF OBLIGATIONS. The partnership will perform and observe in all
respects the terms and provisions of each Project Document to which it is a
party, unless failure to so perform and observe would not reasonably be expected
to result in a Material Adverse Effect.
EXEMPT WHOLESALE GENERATOR STATUS. The partnership will at all times
maintain its exempt wholesale generator status under the Public Utility Holding
Company Act of 1935, unless failure to maintain such status (a) would not cause
a breach under or forfeiture of the pricing or other material
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benefits of the Project Documents or (b) would not reasonably be expected to
result in a Material Adverse Effect.
NATURE OF BUSINESS. The partnership will not at any time conduct any
activities other than those contemplated by our project and Financing Documents
and all activities related thereto.
AMENDMENTS TO PROJECT DOCUMENTS. The partnership will not amend, modify,
cancel or terminate any Project Document (other than change orders under the EPC
Contract and the Pipeline EPC Contract) or the Tax Agreement unless the
partnership certifies that such amendment, modification, termination or
cancellation would not reasonably be expected to result in a Material Adverse
Effect; provided that in the case of an amendment, modification, termination or
cancellation of the Power Purchase Agreement, each Rating Agency then rating the
bonds confirms in writing that such amendment, modification, termination or
cancellation would not result in a Rating Downgrade.
ADDITIONAL PROJECT DOCUMENTS. The partnership will not enter into any
Additional Project Document unless the partnership certifies in writing that the
transactions contemplated by such Additional Project Document would not
reasonably be expected to result in a Material Adverse Effect and either
(a) such certification is concurred with by the Independent Engineer or
(b) each Rating Agency then rating the bonds confirms in writing that the entry
into the Additional Project Document would not result in a Rating Downgrade;
provided that, the foregoing prohibition shall not apply (1) if PECO is not
performing under the Power Purchase Agreement, to any Additional Project
Document providing for short term capacity and energy sales, spot gas and
related transportation or (2) if the transactions contemplated by the Additional
Project Document, when taken together with all other Additional Project
Documents which are in effect and have not been so certified, do not exceed
$1,500,000 in any one calendar year.
INSURANCE. The partnership will maintain, with responsible and financially
sound insurance carriers, customary insurance in such amounts and with terms and
conditions under standard industry practice. All physical damage and business
interruption insurance policies of the partnership shall name the Collateral
Agent as loss payee and as additional insured, provided that unless the
Collateral Agent is exercising remedies, the consent of the partnership will be
required prior to any final adjustment upon an event of loss under such
policies.
PROHIBITION ON FUNDAMENTAL CHANGES. The partnership will not enter into any
transaction of merger or consolidation, change its form of organization or its
business, liquidate, wind-up or dissolve itself (or suffer any liquidation or
dissolution). The partnership will not sell, transfer, assign, hypothecate,
pledge, lease, sublease or otherwise dispose of (in one transaction or in a
series of transactions) any of its assets except (a) in the ordinary course of
business or (b) if such asset is worn out, obsolete or no longer necessary or
useful in the operation of our project; provided, however, if the aggregate fair
market value of such worn out, obsolete, unnecessary or useless asset exceeds
$2,000,000, the partnership must certify in writing that such asset is worn out,
obsolete or no longer necessary or useful in the operation of our project;
provided further, this restriction does not apply to any property which is the
subject of the Georgia Power Interconnection Agreement and the land on which
such property is to be located and related easements.
RESTRICTED PAYMENTS. The partnership will not make any declaration or
payment of distributions, dividends or other payments to any Person or make any
payments of principal or interest on any Affiliate Subordinated Debt from funds
in the Distribution Suspense Account, except as permitted under the Collateral
Agency Agreement or as permitted under "ESTIMATED SOURCES AND USES OF FUNDS."
TRANSACTIONS WITH AFFILIATES. Except for transactions entered into pursuant
to our project and Financing Documents or the Partnership Agreement, the
partnership will not enter into any transaction
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or series of related transactions with any Person (including any Affiliate of
the partnership) on terms less favorable to the partnership than those in
comparable arms-length transactions.
LIMITATIONS ON DEBT. The partnership will not create or incur or suffer to
exist any Indebtedness except "Permitted Indebtedness," which is limited to the
following:
(a) the revenue bonds issued by the Development Authority of Heard County,
the Lease Agreement and the Guaranty;
(b) the bonds;
(c) Indebtedness incurred to finance in whole or in part the making of
capital improvements to our project required to maintain compliance with
applicable laws or our Project Documents; provided that, after giving
effect to the incurrence of such Indebtedness (A) an Authorized Officer
of the partnership certifies in writing and the Independent Engineer
confirms as reasonable (subject to customary assumptions and
qualifications) that (1) such capital improvements are reasonably
expected to enable the partnership to comply with such applicable laws or
Project Documents, as the case may be, and (2) the calculations of the
partnership that demonstrate that after giving effect to the incurrence
of such Indebtedness the minimum Projected Debt Service Coverage Ratio
for (x) the next two consecutive Semi-Annual Periods commencing with the
Semi-Annual Period in which such Indebtedness is incurred, taken as one
annual period, and (y) each pair of subsequent consecutive Semi-Annual
Periods taken as a single annual period through the Final Maturity Date,
will not be less than 1.1 to 1.0, or (B) each Rating Agency then rating
the bonds provides written confirmation that no Rating Downgrade will
result from the incurrence of such Indebtedness;
(d) Indebtedness in an aggregate principal amount not to exceed $15,000,000
incurred to finance in whole or in part the making of capital
improvements in respect of our project, other than those capital
improvements referenced in clause (iii) above; provided that, (A) no
Event of Default shall have occurred and be continuing and (B) each
Rating Agency then rating the bonds provides written confirmation that no
Rating Downgrade will result from such the incurrence of such
Indebtedness;
(e) Indebtedness incurred under the Debt Service Reserve Letter of Credit
Reimbursement Agreement, any Working Capital Facility and the Power
Purchase Agreement Letter of Credit Reimbursement Agreement;
(f) Indebtedness in an aggregate principal amount not to exceed $100,000
incurred in connection with the Georgia Power Interconnection Agreement;
(g) Subordinated Debt in an aggregate principal amount not to exceed
$20,000,000, under the requirements set forth herein; and
(h) Other Indebtedness relating to our project in an aggregate principal
amount not to exceed $10,000,000, which may be used for Project Costs,
Operating and Maintenance Expenses and capital expenditures with respect
to our project.
LIMITATIONS ON LIENS. The partnership will not create or suffer to exist or
permit any Liens upon or with respect to any of its properties except "Permitted
Liens," which are limited to the following:
- Liens specifically permitted or required by, or created by, any Security
Document;
- Liens to secure Permitted Indebtedness; provided that, the holder of such
Permitted Indebtedness, or a representative thereof, shall have entered
into the Collateral Agency Agreement; and provided, further that, in the
case of Liens to secure Permitted Indebtedness which constitutes
Subordinated Debt, the holders of Subordinated Debt shall not be permitted
to foreclose such Liens until all Senior Debt has been irrevocably paid in
full in cash;
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- Liens for taxes, assessments or governmental charges which are either not
yet due or which are being diligently contested in good faith by
appropriate proceedings and for which adequate reserves are established
under GAAP;
- Liens in connection with worker's compensation, unemployment insurance or
other social security or pension obligations;
- mechanic's, workmen's, materialmen's, supplier's, construction or other
similar Liens arising in the ordinary course of business or incident to
the development, construction, operation and maintenance of our project;
- servitudes, easements, rights-of-way, restrictions, minor defects or
irregularities in title and such other encumbrances or charges against
real property or interests therein as are of a nature generally existing
with respect to properties of a similar character and which do not in any
material way interfere with the use thereof or the business of the
partnership;
- capital leases entered into by the partnership to the extent not
prohibited by the Common Agreement; and
- other Liens incidental to the conduct of the partnership's business or the
ownership of properties and assets which were not incurred in connection
with the borrowing of money or the obtaining of advances or credit (other
than vendor's liens for accounts payable in the ordinary course of
business), and which do not in the aggregate materially impair the use
thereof in the operation of the partnership's business.
INSPECTION. The Senior Parties, the Independent Engineer and the Insurance
Consultant shall have the right to visit and inspect any of the properties of
the partnership, and to examine and make copies of the books of record and
accounts of the partnership and discuss the affairs, finances and accounts of
the partnership with, and be advised as to the same by, its officers, all at
such reasonable times and intervals, with reasonable notice prior to such
inspection, and to such reasonable extent as the Senior Parties may request.
CONSTRUCTION OF THE FACILITY. The partnership shall cause the construction
of the facility to be prosecuted and completed with diligence and continuity
(except for interruptions provided for in the EPC Contract or due to events of
FORCE MAJEURE, which events of FORCE MAJEURE the partnership shall use its
commercially reasonable efforts to mitigate), in a good and workmanlike manner
and under sound, generally accepted building and engineering practices, all
material applicable laws and Governmental Approvals and the EPC Contract. The
partnership shall at all times cause a complete set of the current and (when
available) as-built plans (and all supplements thereto) relating to the facility
to be maintained on the facility site or the EPC Contractor's offices and
available for inspection by the Independent Engineer and the Senior Parties.
CHANGE ORDERS. The partnership will not initiate or consent to any change
orders under the EPC Contract unless an Authorized Representative of the
partnership certifies that (a) such change order is reasonable and is consistent
with sound engineering practice, (b) such change order could not reasonably be
expected to materially adversely affect the operation or reliability of our
project, and (c) the implementation of such change order is not reasonably
expected to materially delay the Date of Commercial Operation of the Final
Units; PROVIDED that, unless the Independent Engineer has concurred in writing
with the certifications set forth in clauses (a), (b) and (c) above, such change
order shall not exceed $500,000 individually or, when aggregated with all other
change orders that have not been concurred with in writing or otherwise approved
or ratified by the Independent Engineer, $5,000,000.
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ADDITIONAL COVENANTS
In addition to the covenants described above, the Common Agreement also
contains covenants of the partnership regarding:
- maintenance of existence,
- payment of taxes,
- maintenance of books and records, and
- delivery to the Trustee of all other information required to be delivered
pursuant to Rule 144A(d)(4) under the Securities Act in order to permit
compliance by a Holder with Rule 144A in connection with a resale of the
bonds.
EVENTS OF DEFAULT; REMEDIES
The following events constitute "Events of Default" under the Common
Agreement:
(a) The occurrence of an event of default under the bonds, the Indenture,
the Power Purchase Agreement Letter of Credit Reimbursement Agreement, the Debt
Service Reserve Letter of Credit Reimbursement Agreement or a Working Capital
Facility;
(b) Any representation or warranty made by the partnership in the Common
Agreement, or any representation or warranty in any certificate or other
document furnished to the Senior Parties by or on behalf of the partnership
thereunder, proves to have been false or misleading in any material respect as
of the time made, confirmed or furnished and such fact, event or circumstance
that gave rise to such inaccuracy has resulted, or would reasonably be expected
to result, in a Material Adverse Effect and such fact, event or circumstance
continues to be uncured for 30 or more days from the date the partnership
obtains actual knowledge thereof; PROVIDED that, if the partnership commences
and diligently pursues efforts to cure such fact, event or circumstance within
such 30-day period and delivers written notice thereof to the Collateral Agent,
the partnership may continue to effect such cure and such misrepresentation will
not be deemed an Event of Default under the Common Agreement for an additional
60 days so long as the partnership is diligently pursuing such cure;
(c) The partnership fails to perform or observe any covenant or agreement
contained in the Common Agreement regarding maintenance of existence, insurance,
Governmental Approvals, restrictions on Indebtedness and Liens, Restricted
Payments, guarantees, disposition of assets, amendments to Project Documents,
entering into Additional Project Documents, fundamental changes or nature of
business, and such failure continues uncured for 30 or more days from the date
the partnership obtains actual knowledge thereof;
(d) The partnership fails to perform or observe any of its covenants
contained in the Common Agreement (other than those contained in (c) above) and
such failure continues uncured for 30 or more days from the date the partnership
obtains actual knowledge thereof; PROVIDED, HOWEVER, that if the partnership
commences and diligently pursues efforts to cure such default within such 30-day
period and delivers written notice thereof to the Collateral Agent, the
partnership may continue to effect such cure and such default will not be deemed
an Event of Default for an additional 60 days so long as the partnership is
diligently pursuing such cure;
(e) Various events occur involving the voluntary or involuntary bankruptcy,
insolvency, receivership or reorganization of the partnership;
(f) Any Security Document ceases to be in full force and effect or any Lien
purported to be granted thereby with respect to any material Collateral ceases
to be a valid and perfected Lien in favor of the Collateral Agent for the
benefit of the Senior Parties on the Collateral described therein with the
priority purported to be created thereby and such cessation has resulted in a
Material Adverse
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Effect; PROVIDED, that the partnership has 30 days from the date the partnership
obtains actual knowledge thereof to cure such cessation (if curable), or to
furnish to the Collateral Agent all documents or instruments required to cure
any such cessation, if curable;
(g) Any material Project Document ceases to be valid and binding and in full
force and effect, any third party thereto denies that it has any liability or
obligation under any material Project Document and such third party ceases
performance thereunder, or any third party is in default under such Project
Document (subject to any applicable grace period), and in each case such
cessation or default has resulted or would reasonably be expected to result in a
Material Adverse Effect; PROVIDED that, no such event will be an Event of
Default if within 180 days from the occurrence of such event, the partnership
(1) causes the third party to confirm its obligations under such Project
Document and/or resume performance thereunder (as the case may be) or
(2) enters into an alternate agreement which (A) contains substantially similar
terms and conditions or, if such terms and conditions are no longer available on
a commercially reasonable basis, the terms and conditions then available on a
commercially reasonable basis and (B) after giving effect to the agreement,
enables the partnership to maintain a minimum annual Projected Debt Service
Coverage Ratio equal to or greater than the lesser of (1) the minimum annual
Projected Debt Service Coverage Ratio which would have been in effect had
performance under the original Project Document continued and (2) 1.2 to 1.0;
PROVIDED, FURTHER that in the case of the Power Purchase Agreement, each Rating
Agency confirms that neither of such actions will result in a Rating Downgrade;
(h) The partners cease to collectively maintain Control of the partnership
unless each Rating Agency provides written confirmation that such cessation will
not result in a Rating Downgrade;
(i) The partnership fails to make any payment, or comply with any covenant,
in respect of any Indebtedness in an amount exceeding $10,000,000; PROVIDED that
such failure continues unwaived or uncured beyond any applicable grace period
and results in the acceleration of the maturity of such Indebtedness; and
(j) The entry of one or more final and non-appealable judgments for the
payment of money in excess of $10,000,000 against the partnership, which remain
unpaid or unstayed for 60 or more days.
COLLATERAL AGENCY AGREEMENT
The partnership entered into the Collateral Agency and Intercreditor
Agreement (the "Collateral Agency Agreement") with the Collateral Agent, the
Trustee, and the Trustee under the Indenture of Trust, dated as of November 1,
1999, between the Development Authority and The Chase Manhattan Bank, as trustee
(the "Development Authority Trustee"), Debt Service Reserve Letter of Credit
Agent, the Power Purchase Agreement Letter of Credit Agent and the Depositary
Bank. The Collateral Agency Agreement provides for, INTER ALIA, (a) the
preservation and administration of the Collateral, (b) the disposition of the
Collateral among the Senior Parties and (c) the exercise of various rights,
remedies and options by the Senior Parties. See "DESCRIPTION OF THE
BONDS--Security and Sources of Payment for the bonds." The Chase Manhattan Bank,
which acts as the Collateral Agent for the Senior Parties, also acts as
depositary bank with respect to accounts of the partnership in which the
Collateral Agent has been granted a security interest. The partnership has no
right of withdrawal under any Project Fund (as defined below) except under some
circumstances to be set forth in the Collateral Agency Agreement.
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THE PROJECT FUNDS
The following funds and sub-accounts (collectively, the "Project Funds")
have been established by the partnership with the Collateral Agent and pledged
as security for the benefit of the Collateral Agent acting on behalf of the
Senior Parties:
- Construction Fund;
- Revenue Fund with the Loss Proceeds Account sub-account (including the
Energy Contract Buy-Out Proceeds Sub-account and the EPC Buy-Down Proceeds
Sub-account thereof);
- Operating Fund (including the Major Maintenance Sub-account thereof);
- Debt Service Fund with the Debt Service Reserve Account and Subordinated
Debt Account sub-accounts; and
- Partnership Distribution Fund with the Distribution Suspense Account and
Unrestricted Account sub-accounts.
All amounts deposited in the Project Funds will, at the written request and
direction of the partnership, be invested by the Collateral Agent in Permitted
Investments, except for amounts deposited in the Unrestricted Account.
The partnership may also establish up to two checking accounts in the
locality of our project or the principal executive office of the managing
general partner of the partnership (the "Local Accounts") which will also be
pledged as security for the benefit of the Collateral Agent acting on behalf of
the Senior Parties.
CONSTRUCTION FUND. Prior to the Date of Commercial Operation of the Final
Units, all revenues of the partnership, the net proceeds of the revenue bonds
issued by the Development Authority of Heard County, all earnings on such
proceeds, all equity contributions of the partners of the partnership, all Loss
Proceeds, all business interruption and delayed opening insurance proceeds and
all EPC Contract delay damages and performance damages, will be deposited in the
Construction Fund, and may be used only for payment of Project Costs, upon
presentation to the Collateral Agent of a complete and properly executed
requisition (the "Requisition") signed by the partnership (various contents of
which shall be confirmed by the Independent Engineer). The Collateral Agent
shall apply the amounts in the Construction Fund to the payment, or
reimbursement, to the extent the same have been paid or satisfied by the
partnership, of Project Costs. Each Requisition shall be submitted to the
Collateral Agent no less than three business days in advance of the drawing date
and shall include the following:
(1) a certification that the proceeds will be used only for Project Costs;
(2) a certification that the work performed to date has been performed in a
good and workmanlike manner and under our Project Document under which
such work has been performed;
(3) a statement that the remaining funds in the Construction Fund, together
with the equity commitments and other available sources, are reasonably
expected to be sufficient to complete our project according to the EPC
Contract and the Pipeline EPC Contract on or prior to the Scheduled Date
of Commercial Operation for the Final Units;
(4) a statement that the partnership reasonably expects that the facility
will be completed when required in order to prevent a termination of the
Power Purchase Agreement due to such delay;
(5) a statement that no Default or Event of Default has occurred and is
continuing;
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(6) a statement that all proceeds of previous requisitions have been
properly applied and that the items for which amounts are being requested
have not been the subject of a previous requisition;
(7) a certification that the required insurance, material Governmental
Approvals and necessary Project Documents are in full force and effect;
(8) a certification that the representations in the Common Agreement
concerning organization and status of the partnership, no default under
our Project Documents and Financing Documents, violation of Governmental
Approvals or litigation that could reasonably be expected to result in a
Material Adverse Effect, continued exempt wholesale generator status and
maintenance of required insurance policies are true and correct in all
material respects;
(9) a statement that, to the best of the partnership's knowledge, the
partnership is and the facility site is, in compliance with all
environmental laws, noncompliance with which could reasonably be expected
to result in a Material Adverse Effect; and
(10) a statement that there has not been any sale, forfeiture or loss of any
material amount of the Collateral and that the Collateral is not subject
to any Liens other than Permitted Liens.
Notwithstanding the foregoing, delayed opening or business interruption
insurance proceeds and EPC Contract delay damages paid with respect to a delay
in achieving commercial operation of one or more Units shall be applied first to
interest accruing during the period of such delay on the bonds (through transfer
to the Debt Service Fund), then to pay PECO any amount due and owing as
liquidated damages as a result of such delay, then to reimburse the Power
Purchase Agreement Letter of Credit provider for any unreimbursed drawing on the
Power Purchase Agreement Letter of Credit for Power Purchase Agreement delay
liquidated damages accruing with respect to such delay, then to pay other
Project Costs.
If the partnership cannot satisfy item (1), (4) or (6) above, the Collateral
Agent will not be required to release the funds from the Construction Fund in
respect of such Requisition until such clauses are satisfied. If the partnership
can satisfy those three items, but cannot satisfy any other item, and the
Requisition, various contents of which are confirmed by the Independent
Engineer, (a) specifies and identifies the failure and the causes of the
failure, to satisfy the requirements of the requisition, and (b) certifies that
(1) there is no Bankruptcy Event with respect to the partnership and (2) each of
the EPC Contract, the Power Purchase Agreement, the required insurance policies
and material Governmental Approvals needed for construction of our project are
in full force and effect, then the Collateral Agent will be required to pay the
requisition; provided that within fifteen (15) days of receipt of such
requisition, the Collateral Agent shall give notice to the Senior Parties
describing such failure and specifying that, unless the Collateral Agent shall
have received, by the second business day prior to the time of payment of
further requisitions containing any such specified failures, notice of objection
from the Required Senior Parties, the Collateral Agent shall continue to make
payment of such requisitions from available funds in the Construction Fund.
PAYMENTS ON DATE OF COMMERCIAL OPERATION. Not later than 10 days after
receipt by the Collateral Agent of a certificate of the partnership (the
"Commercial Operation Certificate") (the contents of which shall be confirmed in
writing by the Independent Engineer) certifying, among other things:
- that all conditions precedent to Date of Commercial Operation of Final
Units pursuant to the EPC Contract have occurred,
- that, except as specified in such Commercial Operation Certificate, all
Project Costs have been paid, specifying the amount needed to pay such
remaining Project Costs,
- that all necessary approvals and permits have been obtained for initial
operation of our project,
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- the amounts to be transferred from the Construction Fund under the next
succeeding paragraph, and
- that no Default or Event of Default has occurred and is continuing,
the Collateral Agent shall, upon receipt of a certificate of the Independent
Engineer confirming the statements made by the partnership in the Commercial
Operation Certificate and after retaining in the Construction Fund the amount,
if any, specified by the partnership as necessary to pay Project Costs which are
not then due and payable, transfer all remaining funds in the Construction Fund
by wire transfer to the following accounts and recipients in the following order
of priority:
FIRST, to the Operating Fund, an amount to the extent available, as
specified by the partnership but in any event, no less than one-month's
projected Operating and Maintenance Expenses;
SECOND, to the Debt Service Fund, an amount, to the extent available, as
specified by the partnership for funding of Accrued Senior Debt;
THIRD, to the Debt Service Reserve Account, an amount as specified by the
partnership equal to the Debt Service Reserve Required Balance less (a) the
amount of monies already on deposit in the Debt Service Reserve Account and (b)
the amount available under of any Debt Service Reserve Letter of Credit; and
FOURTH, to the Unrestricted Account of the Partnership Distribution Fund for
distribution without regard to any Distribution Conditions.
REVENUE FUND.The partnership will arrange for the direct payment of all
Available Cash Flow into the Revenue Fund. Any excess funds in any of the
Project Funds will be transferred to the Revenue Fund on the next succeeding
Funding Date. In most circumstances, following the date of commercial operation
of the final three turbine-generators, which will not be earlier than June 1,
2002, under the collateral agency agreement, the partnership will cause the
direct payment to the revenue fund created under the collateral agency
agreement, of all revenues or other proceeds received by the partnership. In
most circumstances monies on deposit in the revenue fund will be deposited into
the other accounts for the following uses, in order of priority:
[FLOW CHART]
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OPERATING FUND AND LOCAL ACCOUNTS. The Operating Fund will be used to pay
Operating and Maintenance Expenses. The Local Accounts will also be used to pay
Operating and Maintenance Expenses.
Prior to any withdrawals from the Operating Fund and Local Accounts to pay
Operating and Maintenance Expenses, the partnership must certify that it does
not reasonably expect that the aggregate amount transferred with respect to
Operating and Maintenance Expenses in the applicable calendar year will exceed
125% of the amount budgeted therefor by the partnership unless the partnership
further certifies that such excess is necessary and reasonable. If monies in the
Operating Fund and the Local Accounts are insufficient on any day to make
payments with respect to Operating and Maintenance Expenses, then the Collateral
Agent will withdraw funds and pay such deficiency into the Operating Fund first
from the Revenue Fund, then from the Distribution Suspense Account, then from
the Partnership Distribution Fund, then from the Unrestricted Account and lastly
from the Subordinated Debt Account (to the extent funds are available in each
such Fund).
DEBT SERVICE FUND. Funds in the Debt Service Fund will be utilized to make
interest and principal payments on the bonds, Debt Service Reserve Bonds, Debt
Service Reserve Letter of Credit Loans, Debt Service Reserve Term Loans, Power
Purchase Agreement Letter of Credit Loans, Power Purchase Agreement Term Loans
and Other Senior Debt. If monies in the Debt Service Fund are insufficient on
any date to make payments due with respect to the
- bonds,
- the Debt Service Reserve Bonds,
- Debt Service Reserve Letter of Credit Loans,
- Debt Service Reserve Term Loans,
- Power Purchase Agreement Letter of Credit Loans,
- Power Purchase Agreement Term Loans or Other Senior Debt,
then the Collateral Agent will withdraw funds and pay such deficiency into the
Debt Service Fund first from the Distribution Suspense Account, then from the
Partnership Distribution Fund, then from the Unrestricted Account and then from
the Subordinated Debt Account. If an insufficient amount of monies remains on
deposit in the Debt Service Fund following the transfers in the preceding
sentence, then distribution of monies will be made ratably to the Persons
entitled thereto under paragraphs FOURTH, FIFTH and SIXTH under the heading
"Priority of Payments" set forth below.
SUBORDINATED DEBT ACCOUNT. Funds in the Subordinated Debt Account will be
utilized to pay principal, interest and other amounts (including fees) payable
on any Third Party Subordinated Debt.
DEBT SERVICE RESERVE ACCOUNT. Under the Collateral Agency Agreement, the
Debt Service Reserve Account was established for the benefit of the Holders. On
June 1, 2002, the partnership is required to initially fund the Debt Service
Reserve Account with cash and/or by providing the Collateral Agent with a Debt
Service Reserve Letter of Credit from one or more commercial banks or other
financial institutions whose long-term unsecured debt obligations are rated at
least "A-" by S&P and "A3" by Moody's. Any Debt Service Reserve Letter of Credit
will be issued pursuant to the Debt Service Reserve Letter of Credit
Reimbursement Agreement and will have terms substantially as described below.
See "--Debt Service Reserve Letter of Credit Reimbursement Agreement." On and
after June 1, 2002, the Debt Service Reserve Account may accumulate cash
deposits from (a) net interest
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earned on amounts deposited therein and (b) amounts transferred from the Revenue
Fund provided below under "--Priority of Payments."
The sum of amounts available to be drawn under the Debt Service Reserve
Letter of Credit and all cash and Permitted Investments deposited in or credited
to the Debt Service Reserve Account will be required to equal the amount of the
principal and interest payment on the bonds on the next Scheduled Payment Date
plus, if a Debt Service Reserve Letter of Credit is in effect, six months
interest on the maximum amount under the Debt Service Reserve Letter of Credit
(the "Debt Service Reserve Required Balance"). Amounts on deposit in or credited
to the Debt Service Reserve Account will be available in the event the amounts
due with respect to principal of and interest on the bonds or, if a Debt Service
Reserve Letter of Credit is in effect, up to six months' interest on the
outstanding Debt Service Reserve Loans have been requisitioned and the amounts
withdrawn from the Revenue Fund, the Debt Service Fund, the Local Accounts, the
Distribution Suspense Account, the Partnership Distribution Fund and the
Subordinated Debt Account (as applicable) allocated thereto are insufficient to
pay, in full, all amounts so requisitioned, in which event the Collateral Agent
shall (a) withdraw the monies on deposit in the Debt Service Reserve Account
and/or draw on the Debt Service Reserve Letter of Credit (as determined by the
partnership) in an amount equal to the lesser of (x) the amount necessary to
make up such deficiency and (y) the sum of the monies on deposit in the Debt
Service Reserve Account and the monies available to be drawn under such Debt
Service Reserve Letter of Credit and (b) apply such monies to the payment of
amounts due with respect to the bonds or to pay such interest on Debt Service
Reserve Loans.
PARTNERSHIP DISTRIBUTION FUND. The Partnership Distribution Fund will be
funded from monies transferred from the Revenue Fund after all other amounts
then required have been paid as provided below under "--Priority of Payments."
The partnership may make distributions to the partners from the Partnership
Distribution Fund on each Scheduled Payment Date occurring at least six months
after the Date of Commercial Operation of the Final Units upon satisfaction of
the following conditions (such conditions, the "Distribution Conditions"):
(a) (1) the amounts on deposit in the Debt Service Reserve Account equals or
exceeds the Debt Service Reserve Required Balance and (2) the amount deposited
in the Major Maintenance Sub-account of the Operating Fund on the Funding Date
on which such distribution is proposed to be made equals or exceeds the Major
Maintenance Required Amount required to be deposited therein on such Funding
Date;
(b) no Default or Event of Default under the Common Agreement has occurred
and is continuing;
(c) the Debt Service Coverage Ratio for the preceding two Semi-Annual
Periods measured as one period (or, with respect to any date prior to the Date
of Commercial Operation of the Final Units, for the period since the Date of
Commercial Operation of the Final Units notwithstanding that such period does
not include any complete Semi-Annual Periods), measured as one annual period,
was equal to or greater than 1.2 to 1.0 for ordinary distributions or 1.15 to
1.0 for distributions in amounts equal to the tax liability of partners in
respect of partnership income, as certified by an Authorized Officer of the
partnership;
(d) the Projected Debt Service Coverage Ratio for the succeeding two
Semi-Annual Periods, measured as one annual period, will be equal to or greater
than 1.2 to 1.0, or 1.15 to 1.0 for distribution amounts equal to the tax
liability of partners in respect of partnership income, in each case as
certified by an Authorized Officer of the partnership;
(e) the partnership is not insolvent and will not be rendered insolvent by
such distribution; and
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(f) the partnership has delivered a certificate to the Collateral Agent
(without written objection from it) certifying as to the satisfaction of each of
the Distribution Conditions required to be satisfied as of such date.
Payment of Affiliate Subordinated Debt, distributions to the Partners or to
the Unrestricted Account (as directed by the partnership) may be made on any
monthly Funding Date at least six months after the Date of Commercial Operation
of the Final Units on which the following conditions are satisfied in addition
to clauses (a), (b) and (e) above:
(a) the Debt Service Coverage Ratio for the preceding two Semi-Annual
Periods (or, with respect to any date prior to two complete Semi-Annual Periods
having occurred prior to the Date of Commercial Operation of the Final Units,
for the period since the Date of Commercial Operation of the Final Units
notwithstanding that such period does not include any complete Semi-Annual
Periods) measured as one annual period will be equal to or greater than 1.4 to
1.0 for ordinary distributions, as certified by an Authorized Officer of the
partnership;
(b) the Projected Debt Service Coverage Ratio for the succeeding two
Semi-Annual Periods (including the Semi-Annual Period containing the Funding
Date), measured as one annual period, will be equal to or greater than 1.4 to
1.0, as certified by an Authorized Officer of the partnership; and
(c) an Authorized Officer of the partnership certifies that sufficient cash
will be available for the next succeeding Scheduled Payment Date without drawing
on any funds available in the Debt Service Reserve Account, the Distribution
Suspense Account, the Partnership Distribution Fund, the Unrestricted Account,
the Subordinated Debt Account or any Working Capital Facility.
In the event that, on any Scheduled Payment Date, the Distribution
Conditions are not satisfied, monies in the Partnership Distribution Fund will
be transferred to the Distribution Suspense Account and will not be distributed
unless the situation set forth below applies or until the Distribution
Conditions are satisfied.
BLOCKED PARTNER DISTRIBUTIONS. If monies cannot be distributed on any
Scheduled Payment Date because a Default or Event of Default has occurred and is
continuing or if the partnership has not met the required Debt Service Coverage
Ratios set forth above, then such monies will be deposited into the Distribution
Suspense Account and if such monies have not been withdrawn and distributed
within eighteen months of such Default, Event of Default or failure to meet
required Debt Service Coverage Ratios, the partnership may request that the
Required Senior Parties elect whether or not to use such funds to retire Senior
Debt. If the Required Senior Parties do not elect to retire Senior Debt, then
such monies will be deposited in the Unrestricted Account. If, upon request of
the partnership, the Required Senior Parties do elect to retire Senior Debt,
such monies will be transferred to the Revenue Fund and applied as set forth
below under "--Rights of Senior Parties to Certain Proceeds."
LOSS PROCEEDS ACCOUNT
EVENTS OF LOSS. All Loss Proceeds will be paid directly into the Loss
Proceeds Account. If an Event of Loss occurs with respect to our project for
which the partnership receives Loss Proceeds less than or equal to $10,000,000,
the Collateral Agent will withdraw and transfer to the partnership the amount of
such Loss Proceeds requested by the partnership provided that the partnership
describes how such Loss Proceeds will be used and certifies that
- no Event of Default has occurred and is continuing,
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- our project can be rebuilt, repaired or restored to permit operation of
our project or a portion thereof on a commercially feasible basis, and
- the Loss Proceeds, together with any other amounts that are available to
the partnership for such rebuilding, repair or restoration are sufficient
to permit such rebuilding, repair or restoration of our project or a
portion thereof, including the making of all required payments of interest
and principal on the partnership's Indebtedness during such rebuilding,
repair or restoration.
If an Event of Loss occurs with respect to our project for which the
partnership receives Loss Proceeds in excess of $10,000,000, the Collateral
Agent will withdraw and transfer to the partnership the amount of such Loss
Proceeds requested by the partnership in a signed and authorized officer's
certificate of the partnership (the "Officer's Certificate"); provided that
(a) the Collateral Agent and the Independent Engineer have received a
certificate from the partnership
- describing in reasonable detail the nature of the repairs or restoration,
- stating the cost of such repairs or restoration and the specific amount
requested to be paid to the partnership (or as otherwise directed by the
partnership), the timing of such payments and that such amount is
requested to pay the cost thereof,
- certifying that our project can be rebuilt, repaired or restored to permit
operation of our project or a portion thereof on a commercially feasible
basis,
- certifying that the Loss Proceeds, together with any other amounts that
are available to the partnership for such rebuilding, repair or
restoration are sufficient to permit such rebuilding, repair or
restoration of the facility or a portion thereof, including the making of
all required payments of interest and principal on the partnership's
Indebtedness during such rebuilding, repair or restoration and
- certifying that the partnership will use its best efforts to cause any
repairs or restoration to be commenced and completed promptly and
diligently at its own cost and expense (including the use of funds on
deposit in the Loss Proceeds Account (other than any EPC Buy-Down proceeds
and Energy Contract Buy-Out proceeds)) and
(b) the Independent Engineer shall have provided the Collateral Agent a
written certificate stating that, based on a reasonable investigation, it
believes that the certifications made by the partnership are reasonable.
EXCESS LOSS PROCEEDS. If (1) the partnership determines that our project or
a portion thereof cannot be rebuilt, repaired or restored under the immediately
preceding paragraph or (ii)(2) Excess Loss Proceeds greater than $1,000,000
remain in the Loss Proceeds Account, then the Collateral Agent shall withdraw
such unused Loss Proceeds and transfer such amounts to the Revenue Fund for
distribution by the Collateral Agent under the terms of the Collateral Agency
Agreement. See "--Rights of Senior Parties to Certain Proceeds."
ENERGY CONTRACT BUY-OUT. All proceeds received by or on behalf of the
partnership in respect of an Energy Contract Buy-Out shall be deposited into the
Energy Contract Buy-Out Proceeds Sub-account. In the case of an Energy Contract
Buy-Out in connection with a termination by PECO of the Power Purchase Agreement
on the 20th anniversary of the date of commencement of the operating term of the
Power Purchase Agreement, the proceeds of such Energy Contract Buy-Out ("PECO
Buy-Out Proceeds") up to an amount equal to the full amount of the Redemption
Price of the Outstanding Bonds shall be transferred by the Collateral Agent to
the Trustee for deposit in the
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Redemption Account under the Indenture prior to any payment of such proceeds
being made to any other Person.
The Collateral Agency Agreement provides that notwithstanding any other
provisions regarding priorities of payment in the Financing Documents, any PECO
Buy-Out Proceeds shall be first applied to the Redemption Price of the
Outstanding Bonds and that no holder of Senior Debt (other than the bonds) shall
make any claim to or against such PECO Buy-Out Proceeds until the Trustee has
notified the Collateral Agent that the holders of the bonds have received the
Redemption Price. In the event that any PECO Buy-Out Proceeds remain following
such redemption and in the event of any other Energy Contract Buy-Out (including
any other Energy Contract Buy-Out affecting the Power Purchase Agreement), so
long as no Default or Event of Default shall have occurred and be continuing and
so long as the Rating Agencies confirm that the following transfer will not
result in a Rating Downgrade, only proceeds of such events in excess of
$10,000,000 shall be distributed by the Collateral Agent under the terms of the
Collateral Agency Agreement and such $10,000,000 shall be transferred to the
Partnership Distribution Fund for distribution under the Collateral Agency
Agreement; provided that if the minimum Projected Debt Service Coverage Ratio
for each pair of subsequent consecutive two Semi-Annual Periods, taken as a
whole annual period, through the final Maturity Date is less than 1.5 to 1.0,
then only that portion of such $10,000,000 that would remain after sufficient
proceeds are applied to retire Senior Debt in order to achieve a minimum
Projected Debt Service Coverage Ratio of 1.5 to 1.0 for each pair of subsequent
consecutive Semi-Annual Periods, taken as a whole annual period, through the
final Maturity Date, shall be transferred to the Partnership Distribution Fund,
for distribution by the Collateral Agent under the terms of the Collateral
Agency Agreement. See "--Rights of Senior Parties to Certain Proceeds."
EPC BUY-DOWN. All EPC Buy-Down amounts received by or on behalf of the
partnership shall be deposited into the EPC Buy-Down Proceeds Sub-account.
IF PROCEEDS ARE $10,000,000 OR LESS. If the partnership receives EPC
Buy-Down proceeds less than or equal to $10,000,000, the Collateral Agent shall
withdraw and transfer to the partnership (or as otherwise directed by the
partnership), the amount of such EPC Buy-Down proceeds requested by the
partnership in an Officer's Certificate of the partnership which shall also
describe how such EPC Buy-Down proceeds shall be used; provided that such
Officer's Certificate shall certify that:
- no Event of Default shall have occurred and be continuing,
- the facility can be rebuilt, repaired or restored in order to remedy the
circumstance giving rise to the obligation of the EPC Contractor under the
EPC Contract to pay such EPC Buy-Down amounts and
- the EPC Buy-Down proceeds, together with any other amounts that are
available to the partnership for such rebuilding, repair or restoration
are sufficient to permit such rebuilding, repair or restoration of the
facility or a portion thereof, including the making of all required
payments of interest and principal on the partnership's Indebtedness
during such rebuilding, repair or restoration.
If the facility cannot be rebuilt, repaired or restored or if the
partnership cannot certify as to the conditions set out above, such EPC Buy-Down
proceeds shall be transferred to the Revenue Fund and used under the terms of
the Collateral Agency Agreement.
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IF PROCEEDS EXCEED $10,000,000.
APPLICATION TO REBUILDING FACILITY. If the partnership receives EPC
Buy-Down proceeds in excess of $10,000,000, the Collateral Agent shall withdraw
and transfer to the partnership (or as otherwise directed by the partnership),
the amount of such EPC Buy-Down proceeds requested by the partnership in an
Officer's Certificate of the partnership; provided that (A) the Collateral Agent
and the Independent Engineer shall have received an Officer's Certificate of the
partnership and such Officer's Certificate shall:
- describe in reasonable detail the nature of the rebuilding, repairs or
restoration,
- state the cost of such rebuilding, repair or restoration and the specific
amount requested to be paid to the partnership (or as otherwise directed
by the partnership), the timing of such payments and that such amount is
requested to pay the cost thereof,
- certify that the facility can be rebuilt, repaired or restored in order to
remedy the circumstance giving rise to the obligation of the EPC
Contractor under the EPC Contract to pay such EPC Buy-Down amounts and
that the EPC Buy-Down proceeds, together with any other amounts that are
available to the partnership for such rebuilding, repair or restoration,
are sufficient to permit such rebuilding, repair or restoration of the
facility or a portion thereof, including the making of all required
payments of interest and principal on the partnership's Indebtedness
during such rebuilding, repair or restoration, and
- certify that the partnership shall use its best efforts to cause any
repairs or restoration to be commenced and completed promptly and
diligently at its own cost and expense (including the use of funds on
deposit in the EPC Buy-Down Proceeds Sub-account),
and (B) the Independent Engineer shall have provided to the Collateral Agent a
written certificate stating that, based on a reasonable investigation, it
believes that the certifications made by the partnership are reasonable.
DISTRIBUTION TO SENIOR PARTIES. If with respect to EPC Buy-Down proceeds
subject to the immediately preceding paragraph, the partnership determines that
the facility or a portion thereof cannot be rebuilt, repaired or restored under
the provisions of the Collateral Agency Agreement, or excess EPC Buy-Down
Proceeds greater than $1,000,000 remain in the EPC Buy-Down Proceeds Sub-account
following the repair, restoration or rebuilding of the facility, then, so long
as the Rating Agencies confirm that the following transfer will not result in a
Rating Downgrade, only proceeds of such event in excess of $10,000,000 shall be
distributed by the Collateral Agent under the terms of the Collateral Agency
Agreement and such $10,000,000 shall be transferred to the Partnership
Distribution Fund, for distribution by the Collateral Agent under the terms of
the Collateral Agency Agreement; provided that if the minimum Projected Debt
Service Coverage Ratio for each pair of subsequent consecutive two Semi-Annual
Periods, taken as a whole annual period, through the final Maturity Date is less
than 1.5 to 1.0, then only that portion of such $10,000,000 that would remain
after sufficient proceeds are applied to retire Senior Debt in order to achieve
a minimum Projected Debt Service Coverage Ratio of 1.5 to 1.0 for each pair of
subsequent consecutive Semi-Annual Periods, taken as a whole annual period,
through the Final Maturity Date, shall be transferred to the Partnership
Distribution Fund, for distribution by the Collateral Agent under the terms of
the Collateral Agency Agreement. See "--Rights of Senior Parties to Certain
Proceeds."
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PRIORITY OF PAYMENTS
After the transfer specified above under "--Construction Fund--PAYMENTS ON
DATE OF COMMERCIAL OPERATION", upon receipt of a certificate from the
partnership (or a duly Authorized Officer for such purposes) detailing the
amounts to be paid, monies in the Revenue Fund (other than monies constituting
proceeds of an Energy Contract Buy-Out or an EPC Buy-Down, and except after the
declaration of a Trigger Event) will be transferred monthly by the Collateral
Agent into the following accounts in the Project Funds and in the following
order of priority:
FIRST, to the Operating Fund, an amount that, together with amounts already
on deposit in such fund and in the Local Accounts, will be sufficient to pay
Operations and Maintenance Expenses certified by the partnership to be due and
payable, or, in respect of the Major Maintenance Required Amount, required to be
reserved, prior to the next succeeding monthly Funding Date; provided that
amounts due and payable with respect to Operations and Maintenance Expenses
during the Funding Period will be transferred to the Local Accounts upon the
request of the partnership if the partnership certifies that it does not
reasonably expect that the aggregate amount transferred with respect to
Operating and Maintenance Expenses in any fiscal year will exceed 125% of the
amount specified in the annual operating budget for such fiscal year unless the
partnership further certified that such excess is necessary and reasonable;
SECOND, to the Working Capital Facility provider, an amount equal to the
amount of principal, interest, fees or other amounts due with respect to any
Working Capital Facility (including optionally payable principal amounts) prior
to the next succeeding Funding Date less the aggregate of the amounts previously
transferred on any prior Funding Date which remain on deposit in the Operating
Fund;
THIRD,
- to the Trustee, the Depositary Agent, the Collateral Agent and the
Development Authority Trustee, for the payment of Trustee Claims,
Depositary Agent Claims, all obligations of the partnership, now or
hereafter existing, to pay fees, costs, expenses, liabilities and
indemnities to the Collateral Agent pursuant to the Financing Documents
(the "Collateral Agent Claims"), and all obligations of the partnership,
now or hereafter existing, to pay administrative fees, costs, expenses,
liabilities and indemnities under the Development Authority Indenture or
the Lease Agreement (the "Development Authority Trustee Claims"),
respectively,
- to the Debt Service Reserve Letter of Credit Agent for the payment of Debt
Service Reserve Letter of Credit Agent Claims,
- to the Power Purchase Agreement Letter of Credit Agent for the payment of
Power Purchase Agreement Letter of Credit Agent Claims and
- to the agents or representatives of Other Senior Debt for the payment of
Other Senior Debt Agent Claims;
provided that if funds in the Revenue Fund are insufficient to make the payments
specified in this paragraph THIRD, distribution of funds shall be made ratably
to the specified recipients;
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FOURTH, to the Debt Service Fund an amount that equals:
- one-sixth of the interest due or becoming due on the bonds on the next
succeeding Scheduled Payment Date,
- one-sixth of the interest due or becoming due on any Other Senior Debt on
the next succeeding Scheduled Payment Date,
- one-sixth of the interest and letter of credit fees due or becoming due on
any Debt Service Reserve Bond, Debt Service Reserve Letter of Credit Loan
and Debt Service Reserve Term Loan on the next succeeding Scheduled
Payment Date and
- one-sixth of the interest and letter of credit fees due or becoming due on
any Power Purchase Agreement Letter of Credit Loan and Power Purchase
Agreement Term Loan on the next succeeding Scheduled Payment Date;
provided that any transfers required pursuant to this priority FOURTH which were
not made on the prior Funding Date shall also be made as of the current Funding
Date;
FIFTH, to the Debt Service Fund an amount that equals:
- one-sixth of the principal and premium due or becoming due on the bonds on
the next succeeding Scheduled Payment Date,
- one-sixth of the principal due or becoming due on the Debt Service Reserve
Bonds and Debt Service Reserve Term Loans on the next succeeding Scheduled
Payment Date,
- one-sixth of the principal due or becoming due on the Power Purchase
Agreement Term Loans on the next succeeding Scheduled Payment Date and
- one-sixth of the principal due or becoming due on any Other Senior Debt on
the next succeeding Scheduled Payment Date;
provided that any transfers required pursuant to this priority FIFTH which were
not made on the prior Funding Date shall also be made as of the current Funding
Date;
SIXTH, to the Debt Service Fund an amount that equals:
- one-sixth of any other amount due or becoming due on the bonds on the next
succeeding Scheduled Payment Date,
- one-sixth of any other amount due or becoming due under the Debt Service
Reserve Letter of Credit Reimbursement Agreement on the next succeeding
Scheduled Payment Date,
- one-sixth of any other amount due or becoming due on any Other Senior Debt
on the next succeeding Scheduled Payment Date and
- one-sixth of any other amount due or becoming due under the Power Purchase
Agreement Letter of Credit Reimbursement Agreement on the next succeeding
Scheduled Payment Date (excluding the amount of principal due on such Debt
Service Reserve Letter of Credit Loans and Power Purchase Agreement Letter
of Credit Loans, which is provided for under priority SEVENTHand EIGHTH,
respectively, below and excluding amounts provided for under priorities
THIRD, FOURTH and FIFTH above);
provided that any transfers required pursuant to this priority SIXTH which were
not made on the prior Funding Date shall also be made as of the current Funding
Date;
SEVENTH, to the Debt Service Reserve Letter of Credit Agent, to the extent
of available cash, an amount equal to the outstanding principal amount of any
Debt Service Reserve Letter of Credit Loans that have not been converted into
Debt Service Reserve Bonds or Debt Service Reserve Term Loans, and then to the
Debt Service Reserve Account an amount such that the total amount available to
be
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drawn on the Debt Service Reserve Letter of Credit together with any cash or
permitted investments already deposited in or credited to the Debt Service
Reserve Account equals the Debt Service Reserve Required Balance;
EIGHTH, to the Power Purchase Agreement Letter of Credit Agent, to the
extent of available cash, an amount equal to the outstanding principal amount of
any Power Purchase Agreement Letter of Credit Loans that have not been converted
into Power Purchase Agreement Term Loans;
NINTH, during the Letter of Credit Sweep Period (as defined below), to the
Debt Service Reserve Letter of Credit Agent and the Power Purchase Agreement
Letter of Credit Agent, on a ratable basis, to the extent of available cash, an
amount equal to the outstanding Debt Service Reserve Bonds, Debt Service Reserve
Term Loans and Power Purchase Agreement Term Loans outstanding on such date;
TENTH, to the Subordinated Debt Account, an amount that will be sufficient
to pay principal, interest and other amounts (including fees) certified by the
partnership to be due and payable on any Third Party Subordinated Debt prior to
the next succeeding Funding Date; and
ELEVENTH, if and to the extent there are amounts remaining in the Revenue
Fund, to the Partnership Distribution Fund.
Monies will be transferred from the Debt Service Fund on each Funding Date
to pay amounts due on Permitted Indebtedness under priorities FOURTH, FIFTH and
SIXTH above. In the event that monies in the Debt Service Fund are insufficient
to make the transfers for each of the purposes set forth in priorities FOURTH,
FIFTH and SIXTH above, in the full amount required by such priorities, the
monies available shall be distributed ratably for each such purpose in such
order or based on the amounts due for each purpose in such order or priority.
APPLICATION OF AVAILABLE CASH TO PREPAY DEBT SERVICE RESERVE LOANS AND POWER
PURCHASE AGREEMENT LOANS; APPLICATION OF CASH COLLATERAL RELEASED BY PECO
The partnership, on any date after February 1, 2012, may furnish to the
Collateral Agent an Letter of Credit Sweep Notice, which shall be irrevocable if
and to the extent it so provides, and which shall authorize and direct the
Collateral Agent, on each Funding Date during a period (the "Letter of Credit
Sweep Period") commencing on the date specified in such Notice and continuing
until the Letter of Credit Sweep Termination Date, to pay to the Debt Service
Reserve Letter of Credit Agent or the Power Purchase Agreement Letter of Credit
Agent, as applicable, for application to the ratable prepayment of Debt Service
Reserve Bonds, Debt Service Reserve Term Loans and Power Purchase Agreement Term
Loans that may be outstanding on such Funding Date, all available cash up to the
outstanding amount of such Debt Service Reserve Bonds, Debt Service Reserve Term
Loans and Power Purchase Agreement Term Loans, after application of proceeds
from the Revenue Fund under paragraphs FIRSTthrough EIGHTH of the Flow of Funds
set forth above (and assuming the application of such proceeds to the payment of
Senior Debt (to the extent allocable thereto) and other amounts on the next
Scheduled Payment Date).
In the event of an Energy Contract Buy-Out resulting from a termination by
PECO of the Power Purchase Agreement on the 20thanniversary of the commencement
of the operating term of the Power Purchase Agreement, as provided in the Power
Purchase Agreement, after the receipt by the partnership and/or the Collateral
Agent of the PECO Buy-Out Proceeds, and the transfer thereof by the Collateral
Agent to the Trustee for deposit in the Redemption Fund of the amounts required
to be so transferred, any amount of cash collateral then held by PECO as a
result of a drawing under the Power Purchase Agreement Letter of Credit shall,
upon release by PECO, be transferred to the Power Purchase Agreement Letter of
Credit Agent for application to the prepayment of the Power Purchase Agreement
Term Loan made as a result of such drawing, notwithstanding any other provisions
regarding priorities of payment in the Financing Documents. Any excess amounts
after such application
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shall be transferred to the Collateral Agent for deposit into the Revenue Fund
for distribution pursuant to the Collateral Agency Agreement.
INVESTMENT OF MONIES
Amounts on deposit in the Project Funds (other than in the Unrestricted
Account) will, at the written request and direction of the partnership, be
invested by the Collateral Agent in Permitted Investments. Such investments will
generally mature in such amounts and not later than such times as may be
necessary to provide monies when needed to make payments as provided in the
Collateral Agency Agreement. Net interest or gain received from such investments
will be applied as provided in the Collateral Agency Agreement. So long as an
outstanding balance will remain in any of the accounts of the Project Funds, the
Collateral Agent will provide the partnership with monthly statements showing
the amount of all deposits made to, the net investment income or gain received
and collected for, all disbursements from and the amount then available in each
such account of the Project Funds.
EVENTS OF DEFAULT UNDER THE COLLATERAL AGENCY AGREEMENT
EVENTS OF DEFAULT; TRIGGER EVENTS. Each of the following constitutes an
event of default (a "Trigger Event") under the Collateral Agency Agreement:
(a) an Event of Default under the Indenture and an acceleration of all
indebtedness issued thereunder,
(b) an Event of Default under the Debt Service Reserve Letter of Credit
Reimbursement Agreement and an acceleration of all indebtedness incurred
thereunder,
(c) an Event of Default under the Power Purchase Agreement Letter of Credit
Reimbursement Agreement and an acceleration of all indebtedness incurred
thereunder,
(d) an event of default under a Working Capital Facility and an acceleration
of all indebtedness issued thereunder, or
(e) an event of default under any other Senior Debt instrument and an
acceleration of all of the Indebtedness issued thereunder provided such
Indebtedness is in an aggregate principal amount in excess of $10 million;
and, in each case, the Collateral Agent has, upon direction from the Required
Senior Parties, declared such event to be a Trigger Event.
Upon the occurrence and continuance of a Trigger Event, the Collateral Agent
will exercise, by the direction of the Required Senior Parties, such rights and
remedies with respect to the Collateral as are granted to it under the
Collateral Agency Agreement, the Security Documents and applicable law.
No Senior Party has any right to (a) take any action with respect to the
Collateral independent of the Collateral Agent or (b) direct the Collateral
Agent to take any action in respect of the Collateral other than under the
Collateral Agency Agreement.
EXERCISE OF REMEDIES AND APPLICATION OF PROCEEDS. Pursuant to the
Collateral Agency Agreement, the affirmative vote of 51% of the Combined
Exposure (in each case, the "Required Senior Parties") is sufficient to direct
various actions of the Collateral Agent, including the exercise of remedies
following a Trigger Event (as defined above); PROVIDED that, for purposes of
directing such actions, the Trustee will be entitled to vote on all matters
under the Collateral Agency Agreement according to the aggregate principal
amount of the Outstanding Bonds in respect of which it has received votes from
Holders subject, however, in all events, to the terms and provisions of the
Indenture.
If a Trigger Event has occurred and is continuing and upon a written request
of the Required Senior Parties, the Collateral Agent is authorized to take any
and all actions and to exercise any and all
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rights, remedies and options and which the Required Senior Parties direct it to
take, including realization and foreclosure on the Collateral.
Except with respect to PECO Buy-Out Proceeds, which shall be applied as
described in "--The Project Funds--LOSS PROCEEDS ACCOUNT--Energy Contract
Buy-Out," the non-cash proceeds of any sale, disposition or other realization or
foreclosure by the Collateral Agent upon the Collateral or any portion thereof
will be held by the Collateral Agent for the benefit of the Senior Parties until
sold or otherwise converted into cash. Cash proceeds will be transferred to the
Revenue Fund, and the Collateral Agent will distribute them in the order of
priority to:
(a) the Debt Service Fund for payment to the Collateral Agent, the
Development Authority Trustee, the Debt Service Reserve Letter of Credit Agent,
the Power Purchase Agreement Letter of Credit Agent, the Depositary Bank, the
Other Senior Debt Agent and the Trustee, ratably, an amount equal to all
Collateral Agent Claims, Development Authority Trustee Claims, Debt Service
Reserve Letter of Credit Agent Claims, Power Purchase Agreement Letter of Credit
Agent Claims, Depositary Agent Claims, Other Senior Debt Agent Claims and
Trustee Claims, respectively, due and owing to such parties under the Financing
Documents,
(b) the Debt Service Fund for payment to the Senior Parties, ratably, an
amount equal to the unpaid amount of all Senior Debt constituting principal,
interest and any fees due,
(c) the Debt Service Fund for payment to the Senior Parties, ratably, an
amount equal to all other unpaid amounts;
(d) to the Subordinated Debt Account for payment to the holders of Third
Party Subordinated Debt, ratably, an amount equal to the unpaid amount of all
Third Party Subordinated Debt due; and
(e) to the partnership or to whomever a court of competent jurisdiction may
direct any surplus.
At the time the Collateral Agent is to make a distribution pursuant to
clause (b) in the immediately preceding paragraph, the Collateral Agent will
deposit into a separate interest-bearing trust account an amount equal to the
then outstanding amount of the Debt Service Reserve Letter of Credit (which
outstanding amount of the Debt Service Reserve Letter of Credit will be
calculated after giving effect to the redemption of bonds from such distribution
made pursuant to clause (b) above). The Collateral Agent will hold the monies in
such account until receipt of a written notice or notices from the Debt Service
Reserve Letter of Credit Agent to the effect that either (x) the Collateral
Agent has made a drawing on the Debt Service Reserve Letter of Credit, which
notice will specify the amount or amounts of such drawings, or (y) the Debt
Service Reserve Letter of Credit has expired or terminated. Upon receipt of
notice as specified in (x) above, the Collateral Agent will distribute to the
Debt Service Reserve Letter of Credit Agent an amount equal to such drawing's
proportionate share of the Debt Service Reserve Letter of Credit collateralized
by such account specified in the notice. Upon receipt of notice as specified in
(y) above, the Collateral Agent will distribute from the relevant separate
account (under clauses (b), (c), (d) and (e) above and without regard to this
paragraph) to the appropriate Persons an amount equal to the balance in such
account.
At the time the Collateral Agent is to make a distribution pursuant to
clause (b) in the second preceding paragraph, the Collateral Agent will deposit
into a separate interest-bearing trust account an amount equal to the then
outstanding amount of the Power Purchase Agreement Letter of Credit (which
outstanding amount of the Power Purchase Agreement Letter of Credit will be
calculated after giving effect to the redemption of bonds from such distribution
made pursuant to clause (b) above). The Collateral Agent will hold the monies in
such account until receipt of a written notice or notices from the Power
Purchase Agreement Letter of Credit Agent to the effect that either (x) the
Collateral Agent has made a drawing on the Power Purchase Agreement Letter of
Credit, which notice will specify the amount or amounts of such drawings, or
(y) the Power Purchase Agreement Letter of Credit has expired or terminated.
Upon receipt of notice as specified in (x) above, the Collateral Agent will
distribute to the Power Purchase Agreement Letter of Credit Agent an amount
equal to such
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drawing's proportionate share of the Power Purchase Agreement Letter of Credit
collateralized by such account specified in the notice. Upon receipt of notice
as specified in (y) above, the Collateral Agent will distribute from the
relevant separate account (under clauses (b), (c), (d) and (e) above and without
regard to this paragraph) to the appropriate Persons an amount equal to the
balance in such account.
RIGHTS OF SENIOR PARTIES TO CERTAIN PROCEEDS
Except for the PECO Buy-Out Proceeds, cash proceeds deposited in the Revenue
Fund under "--The Project Funds--LOSS PROCEEDS ACCOUNT--Events of Loss," "--The
Project Funds--LOSS PROCEEDS ACCOUNT--EPC Buy-Down," "--The Project Funds--LOSS
PROCEEDS ACCOUNT--Energy Contract Buy-Out" and cash to be deposited in the
Revenue Fund under "--The Project Funds--PARTNER DISTRIBUTION FUND--Blocked
Partner Distributions" shall be used by the Collateral Agent for distribution in
the order of priority to:
(a) the Debt Service Fund for payment, ratably, to the Collateral Agent, the
Development Authority Trustee, the Debt Service Reserve Letter of Credit Agent,
the Power Purchase Agreement Letter of Credit Agent, the Depositary Bank, the
Other Senior Debt Agent and the Trustee, ratably, an amount equal to all
Collateral Agent Claims, Development Authority Trustee Claims, Debt Service
Reserve Letter of Credit Agent Claims, Power Purchase Agreement Letter of Credit
Agent Claims, Depositary Agent Claims, Other Senior Debt Agent Claims and
Trustee Claims, respectively, due and owing to such parties under the Financing
Documents;
(b) the Debt Service Fund for payment to the Senior Parties, ratably, an
amount equal to the unpaid amount of all Senior Debt constituting principal,
interest and any fees due;
(c) the Debt Service Fund for payment to the Senior Parties, ratably, an
amount equal to all other unpaid amounts;
(d) to the Subordinated Debt Account for payment to the holders of
Subordinated Debt, ratably, an amount equal to the unpaid amount of all
Subordinated Debt due; and
(e) to the partnership or to whomever a court of competent jurisdiction may
direct any surplus.
At the time the Collateral Agent is to make a distribution pursuant to
clause (b) in the immediately preceding paragraph, the Collateral Agent will
deposit into a separate interest-bearing trust account in an amount equal to the
then outstanding amount of the Debt Service Reserve Letter of Credit (which
outstanding amount of the Debt Service Reserve Letter of Credit will be
calculated after giving effect to the redemption of bonds from such distribution
made pursuant to clause (b) above). The Collateral Agent will hold the monies in
such account until receipt of a written notice or notices from the Debt Service
Reserve Letter of Credit Agent to the effect that either (x) the Collateral
Agent has made a drawing on the Debt Service Reserve Letter of Credit, which
notice will specify the amount or amounts of such drawings, or (y) the Debt
Service Reserve Letter of Credit has expired or terminated. Upon receipt of
notice as specified in (x) above, the Collateral Agent will distribute to the
Debt Service Reserve Letter of Credit Agent an amount equal to such drawing's
proportionate share of the Debt Service Reserve Letter of Credit collateralized
by such account specified in the notice. Upon receipt of notice as specified in
(y) above, the Collateral Agent will distribute from the relevant separate
account (under clauses (b), (c), (d) and (e) above and without regard to this
paragraph) to the appropriate Persons an amount equal to the balance in such
account.
At the time the Collateral Agent is to make a distribution pursuant to
clause (b) in the second preceding paragraph, the Collateral Agent will deposit
into a separate interest-bearing trust account an amount equal to the then
outstanding amount of the Power Purchase Agreement Letter of Credit (which
outstanding amount of the Power Purchase Agreement Letter of Credit will be
calculated after giving effect to the redemption of bonds from such distribution
made pursuant to such clause (b)). The Collateral Agent will hold the monies in
such account until receipt of a written notice or notices from the Power
Purchase Agreement Letter of Credit Agent to the effect that either (x) the
Collateral Agent
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has made a drawing on the Power Purchase Agreement Letter of Credit, which
notice will specify the amount or amounts of such drawings, or (y) the Power
Purchase Agreement Letter of Credit has expired or terminated. Upon receipt of
notice as specified in (x) above, the Collateral Agent will distribute to the
Power Purchase Agreement Letter of Credit Agent an amount equal to such
drawing's proportionate share of the Power Purchase Agreement Letter of Credit
collateralized by such account specified in the notice. Upon receipt of notice
as specified in (y) above, the Collateral Agent will distribute from the
relevant separate account (under clauses (b), (c), (d) and (e) above and without
regard to this paragraph) to the appropriate Persons an amount equal to the
balance in such account.
CERTAIN RIGHTS OF COLLATERAL AGENT
Neither the Collateral Agent nor any of its agents or affiliates will be
liable for action lawfully taken by in or in connection with the Collateral
Agency Agreement except for gross negligence or willful misconduct. The Senior
Parties agree to indemnify the Collateral Agent from and against any
liabilities, obligations, costs or expenses incurred by or asserted against the
Collateral Agent in its capacity arising out of the Collateral Agency Agreement.
The Collateral Agent may resign as Collateral Agent upon 30 days' notice to
the Senior Parties and may be removed at any time with or without cause by the
Required Senior Parties (as defined below), with any such resignation or removal
to become effective only upon the appointment of a successor Collateral Agent.
Whenever the Collateral Agent deems it necessary, the Collateral Agent may take
action to appoint another bank or trust company to act as an additional
collateral agent of all or any part of the Collateral.
Each Person replacing any of the Senior Parties and each Person (or trustee
or agent thereof) providing Senior Debt to the partnership will be required to
become a party to the Collateral Agency Agreement, which will be amended to the
extent necessary to accommodate the replacement or addition of such Persons.
AMENDMENTS AND WAIVERS
Any amendment, modification, supplement, consent or waiver of any provision
of the Collateral Agency Agreement, the Common Agreement or any Security
Document requires the written consent of the Collateral Agent, acting at the
direction of the Required Senior Parties. If any consent or direction of the
Required Secured Parties is necessary in order for the Collateral Agent to
exercise any rights or remedies under any of the Security Documents or the
Collateral Agency Agreement, or to amend, modify or supplement, give any consent
under, or waive any provision of, any of the Security Documents, the Common
Agreement or the Collateral Agency Agreement, and if any such exercise of rights
or remedies, or any such amendment, modification, supplement, consent or waiver
(either alone or together with each then effective amendment, modification,
supplement, consent or waiver not previously approved by the Power Purchase
Agreement Letter of Credit Agent or the Debt Service Reserve Letter of Credit
Agent, as the case may be) could reasonably be expected to have a material
adverse effect on the Power Purchase Agreement Letter of Credit Agent or the
Debt Service Reserve Letter of Credit Agent (which material adverse effect is
materially different from the effect with respect to other Senior Parties), the
Collateral Agent shall not accept such consent or direction from the Required
Senior Parties unless the Power Purchase Agreement Letter of Credit Agent or the
Debt Service Reserve Letter of Credit Agent, as the case may be, shall have
received written notice of such proposed consent or direction at least fifteen
days prior to the effectiveness thereof, and the Power Purchase Agreement Letter
of Credit Agent or the Debt Service Reserve Letter of Credit Agent, as the case
may be, shall have approved such amendment, modification or supplement, consent
or waiver (which approval shall not be unreasonably withheld).
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DEBT SERVICE RESERVE LETTER OF CREDIT REIMBURSEMENT AGREEMENT
The Toronto-Dominion Bank (the "Debt Service Reserve Letter of Credit
Issuer"), pursuant to a Debt Service Reserve Letter of Credit and Reimbursement
Agreement (the "Debt Service Reserve Letter of Credit Reimbursement Agreement"),
has agreed to provide the Debt Service Reserve Letter of Credit for the account
of the partnership in an amount up to $16 million to be held by the Collateral
Agent to serve as a debt service reserve facility for our project. The Financing
Documents require that the Debt Service Reserve Account be funded in an amount
equal to the Debt Service Reserve Required Balance on or before June 1, 2002.
The Collateral Agent shall have the right to make drawings on the Debt
Service Reserve Letter of Credit beginning on June 1, 2002. The Collateral Agent
may make drawings under the Debt Service Reserve Letter of Credit upon the
occurrence of the following events:
(1) 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);
(2) upon receipt of a notice from the partnership that the long-term debt
rating of such Debt Service Reserve Letter of Credit Issuer is less than
"A-" as determined by S&P or "A3" as determined by Moody's (collectively,
the "Required Rating") and the Debt Service Reserve Letter of Credit has
not been replaced within the time period specified therein;
(3) upon receipt of a notice from the Debt Service Reserve Letter of Credit
Agent 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;
(4) if, subsequent to June 1, 2002, moneys transferred to the Debt Service
Reserve Letter of Credit Agent from the Revenue Account are insufficient
to repay the interest on any Debt Service Reserve Letter of Credit Loans;
and
(5) a termination of the Debt Service Reserve Letter of Credit or the
occurrence of a Trigger Event.
The Collateral Agent will apply the proceeds of each such drawing: (a) in
the case of clauses (1) and (4) of the preceding sentence, to payment of the
relevant obligation and (b) in the case of clauses (2), (3) and (5) of the
preceding sentence, to the Debt Service Reserve Account until there shall be
deposited therein an aggregate amount equal to the Debt Service Reserve Required
Balance.
Subject to the conditions of drawing, the Debt Service Reserve Letter of
Credit will mature, expire, or terminate on the earlier to occur of (a) seven
years from the date of issuance of the Debt Service Reserve Letter of Credit and
(b) the occurrence of a Debt Service Reserve Letter of Credit Event of Default;
provided, however, that the Debt Service Reserve Letter of Credit shall 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 Agent first giving
the Collateral Agent and the Trustee written notice thereof at least 60 days
prior to such termination during which period the Collateral Agency shall be
entitled to draw on such Debt Service Reserve Letter of Credit as described
above under "Collateral Agency Agreement--The Project Funds--DEBT SERVICE
RESERVE ACCOUNT." The Debt Service Reserve Letter of Credit Agent shall also
provide a copy of such written notice to the partnership at the time such notice
is given to the Collateral Agent and the Trustee.
The partnership shall 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 Agent of notice from the Trustee consenting to such termination or
reduction.
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The amount available for the drawing under the Debt Service Reserve Letter
of Credit will be reduced upon (a) making draws thereunder, (b) the reduction of
the Debt Service Reserve Required Balance and (c) various deposits in cash in
the Debt Service Reserve Account.
DEBT SERVICE RESERVE LETTER OF CREDIT LOANS
Except as otherwise provided below, each Drawing on the Debt Service Reserve
Letter of Credit shall constitute the making by the Debt Service Reserve Letter
of Credit provider of a loan to the partnership (a "Debt Service Reserve Letter
of Credit Loan"). The partnership shall 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 set forth in the Debt Service
Reserve Letter of Credit Reimbursement Agreement.
The partnership shall 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 shall 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 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 (a "Debt Service Reserve Letter of
Credit Loan Maturity Date").
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 below in this summary, amounts available for drawing under
the Debt Service Reserve Letter of Credit shall 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 Term
Loans).
NON-REPLACEMENT OF DEBT SERVICE RESERVE LETTER OF CREDIT
If the Debt Service Reserve Letter of Credit is not replaced at least
45 days prior to its stated maturity date, or the credit rating of the Debt
Service Reserve Letter of Credit Issuer is less than the Required Rating and the
partnership does 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 (such drawing on the Debt Service Reserve Letter of Credit due
to non-replacement of the Debt Service Reserve Letter of Credit, a "Debt Service
Reserve Term Loan") in an amount equal to the lesser of (a) the amount available
to be drawn under such letter of credit and (b) the difference between (x) the
Debt Service Reserve Required Balance and (y) amounts then on deposit in the
Debt Service Reserve Account, and will deposit such drawing into the Debt
Service Reserve Account. A Debt Service Reserve Term Loan will amortize pursuant
to a "mortgage-style" amortization schedule and the maturity date of any Debt
Service Reserve Term Loan shall be 10 years after the date such loan is made.
Interest on and principal of any Debt Service Reserve 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, the partnership shall have failed to repay at least 50% of the
original amount of such Debt Service Reserve Letter of Credit Loan, or if by the
Debt Service Reserve Letter of Credit Loan Maturity Date of such Debt Service
Reserve Letter of Credit Loan the partnership shall 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
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Loan Provider, be converted into a new security (a "Debt Service Reserve Bond")
having a principal amount equal to the remaining principal amount of the Debt
Service Reserve Letter of Credit Loan so converted. Each Debt Service Reserve
Bond shall be amortized on the same amortization schedule as the bonds and
mature on the same maturity date as the 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
The covenants of the partnership contained in the Common Agreement shall be
incorporated by reference (with appropriate substitution of parties) in the Debt
Service Reserve Letter of Credit Reimbursement Agreement as if set forth in full
in the Debt Service Reserve Letter of Credit Reimbursement Agreement.
DEBT SERVICE RESERVE LETTER OF CREDIT EVENTS OF DEFAULT
Each of the following shall be an event of default (a "Debt Service Reserve
Letter of Credit Event of Default") under the Debt Service Reserve Letter of
Credit Reimbursement Agreement:
(a) any principal of any Debt Service Reserve Loan is not paid in full
within 5 days after the due date thereof;
(b) any other amount due under the Debt Service Reserve Letter of Credit
Reimbursement Agreement or any related promissory note is not paid in
full within 15 days after the due date thereof; or
(c) an Event of Default under the Common Agreement shall 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 2/3percent or more of the Debt Service Reserve Letter of Credit commitments
(the "Required Debt Service Reserve Letter of Credit Banks"), the Debt Service
Reserve Letter of Credit Provider may:
(1) after notice as required in the Financing Documents, terminate the Debt
Service Reserve Letter of Credit,
(2) declare all amounts owing under the Debt Service Reserve Letter of
Credit Reimbursement Agreement and any related promissory note to be
forthwith due and payable (including amounts not yet advanced under the
Debt Service Reserve Letter of Credit, which shall upon being so advanced
be and become immediately due and payable), whereupon such obligations
shall become and be due and payable, without presentment, demand or
protest;
(3) terminate the ability of the partnership to cause the reinstatement of
the stated amount of the Debt Service Reserve Letter of Credit through
the reimbursement of drawings; and
(4) terminate the ability of the partnership to continue any Debt Service
Reserve Loans as, or to convert Debt Service Reserve Loans to, Eurodollar
Rate Loans; provided, that the Debt Service Reserve Letter of Credit
Agent shall not have the right to exercise any other remedies except
under the provisions of the Collateral Agency Agreement.
POWER PURCHASE AGREEMENT LETTER OF CREDIT REIMBURSEMENT AGREEMENT
The Toronto-Dominion Bank (the "Power Purchase Agreement Letter of Credit
Issuer"), pursuant to a Power Purchase Agreement Letter of Credit and
Reimbursement Agreement (the "Power
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Purchase Agreement Letter of Credit Reimbursement Agreement"), has agreed
pursuant to the terms of the Power Purchase Agreement to provide the Power
Purchase Agreement Letter of Credit for use by the partnership in connection
with our project.
The Power Purchase Agreement Letter of Credit Issuer issued the Power
Purchase Agreement Letter of Credit on the date of issuance of the bonds, for
the account of the partnership in the amount of $15,000,000, which amount shall
be increased by $10,000,000 on April 1 of the Start Year for the Initial Units
and in favor of PECO. PECO may make drawings under the Power Purchase Agreement
Letter of Credit if (1) the partnership has failed to pay PECO certain various
liquidated damages payable under the Power Purchase Agreement, (2) the
partnership has failed to pay availability adjustments under the Power Purchase
Agreement, (3) the expiry date of the Power Purchase Agreement Letter of Credit
is to occur and it has not been renewed or replaced by an acceptable credit
support; or the Power Purchase Agreement Letter of Credit is terminated as
described below.
Subject to the conditions of drawing, the Power Purchase Agreement Letter of
Credit will mature, expire or terminate on the earlier to occur of (1) seven
years from the date of issuance of the Power Purchase Agreement Letter of
Credit; and (2) the occurrence of a Power Purchase Agreement Letter of Credit
Event of Default; provided, however, that the Power Purchase Agreement Letter of
Credit shall 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 Agent first giving the Collateral Agent and PECO written notice thereof
at least 60 days prior to such termination. The Power Purchase Agreement Letter
of Credit Agent shall also provide a copy of such written notice to the
partnership at the time such notice is given to the Collateral Agent and the
Power Purchaser.
The partnership shall have the right to terminate or reduce the Power
Purchase Agreement Letter of Credit upon the receipt by the Power Purchase
Agreement Letter of Credit Agent of notice from PECO consenting to such
termination or reduction.
POWER PURCHASE AGREEMENT LETTER OF CREDIT LOANS
Except as otherwise provided herein, each Drawing on the Power Purchase
Agreement Letter of Credit shall constitute the making by the Power Purchase
Agreement Letter of Credit provider of a loan (a "Power Purchase Agreement
Letter of Credit Loan"). The partnership shall 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 rates established in the
Power Purchase Agreement Letter of Credit Reimbursement Agreement. The
partnership shall pay the interest on any Power Purchase Agreement 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 shall repay the principal
amount of any Power Purchase Agreement Letter of Credit Loans out of cash
available in the Revenue Account after payment of debt service on all Senior
Debt and principal of Power Purchase Agreement Letter of Credit Loans. Each
Power Purchase Agreement Letter of Credit Loan will mature five years after the
date such Power Purchase Agreement Letter of Credit Loan is made (the "Power
Purchase Agreement Letter of Credit Loan Maturity Date").
CONVERSION INTO POWER PURCHASE AGREEMENT TERM LOANS
If by the date 30 months after the making of a Power Purchase Agreement
Letter of Credit Loan, the partnership shall have failed to repay the amount of
such Power Purchase Agreement Letter of Credit Loan, then from and after the
applicable date, such Power Purchase Agreement Letter of Credit Loan may, at the
option of the Power Purchase Agreement Letter of Credit Agent, be converted into
a new security (a "Power Purchase Agreement Term Loan") having a principal
amount equal to the remaining principal amount of the Power Purchase Agreement
Letter of Credit Loan so converted.
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Each Power Purchase Agreement Term Loan shall be amortized over a period of five
years from the date of such conversion to a Power Purchase Agreement Term Loan
and shall be amortized based on mortgage-style amortization payments of
principal and interest. Interest on and principal of any Power Purchase
Agreement Term Loan will be paid, respectively, at the same levels as interest
on and principal of the bonds.
NON-REPLACEMENT OF POWER PURCHASE AGREEMENT LETTER OF CREDIT
If the Power Purchase Agreement Letter of Credit is not extended or replaced
at least 10 days prior to its termination date, PECO is permitted to draw on the
Power Purchase Agreement Letter of Credit in amount equal to the amount
available to be drawn under such letter of credit. Such drawing shall be funded
as a Power Purchase Agreement Term Loan, which will amortize pursuant to a
"mortgage-style" amortization schedule. The maturity date of any Power Purchase
Agreement Term Loan shall be 5 years after the date such loan is made. Interest
on and principal of any Power Purchase Agreement Term Loan will be paid,
respectively, at the same levels as interest on and principal of the bonds.
COVENANTS
The covenants of the partnership contained in the Common Agreement shall be
incorporated by reference (with appropriate substitution of parties) in the
Power Purchase Agreement Letter of Credit Reimbursement Agreement as if set
forth 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 shall be an event of default (a "Power Purchase
Agreement Letter of Credit Event of Default") under the Power Purchase Agreement
Letter of Credit Reimbursement Agreement:
(1) any principal of any Power Purchase Agreement Loans is not paid in full
within 5 days after the due date thereof;
(2) any amount due under the Power Purchase Agreement Letter of Credit
Reimbursement Agreement or any related promissory note is not paid in
full within 15 days after the due date thereof; and
(3) an "Event of Default" under the Common Agreement shall occur and be
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 Power Purchase Agreement Letter of Credit
commitments (the "Required Power Purchase Agreement Letter of Credit Banks"),
the Power Purchase Agreement Letter of Credit Agent may:
(1) terminate the Power Purchase Agreement Letter of Credit,
(2) declare all amounts owing under the Power Purchase Agreement Letter of
Credit Reimbursement Agreement and any related promissory note to be
forthwith due and payable (including amounts not yet advanced under the
Power Purchase Agreement Letter of Credit, which shall upon being so
advanced be and become immediately due and payable), whereupon such
obligations shall become and be due and payable, without presentment,
demand or protest;
(3) terminate any ability of the partnership to cause the reinstatement of
the stated amount of the Power Purchase Agreement Letter of Credit
through the reimbursement of drawings; and
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(4) terminate the ability of the partnership to continue Power Purchase
Agreement Loans as or to convert Power Purchase Agreement Loans to
Eurodollar Rate loans; provided, that the Power Purchase Agreement Letter
of Credit Agent shall not have the right to exercise any other remedies
except under the provisions of the Collateral Agency Agreement.
EQUITY CONTRIBUTION AGREEMENT
Pursuant to an Equity Contribution Agreement entered into by and among our
Contributing Partners, the partnership, and the Collateral Agent, each
Contributing Partner will contribute equity to the partnership from time to time
during the construction period (each an "Equity Contribution") at the request of
the Collateral Agent, if the amounts then on deposit in the Construction Fund
are insufficient to make the transfers required to pay our Project Costs as
specified in the Collateral Agency Agreement. The obligation of each
Contributing Partner to make its Equity Contributions is supported by a
Contributing Partner Support Instrument or Support Instruments in the aggregate
amount of such Contributing Partner's Equity Contribution Commitment. The
obligation of each Contributing Partner to make Equity Contributions will not at
any time cause (1) the total amount of Equity Contributions made by such
Contributing Partner to exceed such Contributing Partner's Equity Contribution
Commitment, and (2) the aggregate amount of the Contributing Partners' Equity
Contributions to exceed $35,500,000. All Equity Contributions will be deposited
in the Construction Fund and applied to pay or reimburse the partnership for the
payment of our Project Costs, whether matured or unmatured, under the Financing
Documents.
The Equity Contribution Agreement also provides that if either (1) an Event
of Default under the Common Agreement or (2) any Contributing Partner Event of
Default, has occurred and is continuing on or prior to the Date of Commercial
Operation of the Final Units, the Collateral Agent is authorized to make a
drawing under such Contributing Partner's Support Instrument or Support
Instruments, in an amount equal to such Contributing Partner's Equity
Contribution Commitment less its Equity Contribution made up to such date. Any
such Equity Contribution following the occurrence and continuation of an Event
of Default or any Contributing Partner Event of Default will be deposited in the
Construction Fund and will be applied under the Collateral Agency Agreement.
Pursuant to the Equity Contribution Agreement, on the Date of Commercial
Operation of the Final Units, the Collateral Agent shall draw under each
Contributing Partner's Support Instrument or Support Instruments an amount equal
to each Contributing Partner's percentage of the Remaining Required Equity
Contribution and the remaining "excess" equity committed but unfunded will be
canceled; PROVIDED that, the partnership delivers an Officer's Certificate to
the Collateral Agent on such date certifying that:
(a) the Date of Commercial Operation of the Final Units has occurred;
(b) all other amounts due and payable under the Equity Contribution
Agreement have been paid or escrowed or otherwise provided for as of such date;
(c) no Default or Event of Default under the Common Agreement or any other
Financing Document has occurred and is continuing on and as of such date; and
(d) the Debt Service Reserve Account is fully funded on and as of such date
to the extent required under the Collateral Agency Agreement.
CONSENTS TO ASSIGNMENTS
In connection with the collateral assignment of contract rights held by the
partnership, including rights under our Project Documents, the Collateral Agent
received an executed consent to assignment
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from some of the third parties party to such Project Documents. In each such
consent, the applicable third party has, in respect of our Project Documents to
which it is a party, among other matters:
(a) consented to the collateral assignment thereof to the Collateral Agent
on behalf of the Senior Parties,
(b) agreed to pay all amounts, if any, receivable by the partnership
thereunder directly into the Revenue Fund created under the Collateral Agency
Agreement,
(c) agreed to various matters concerning the exercise of remedies by the
Collateral Agent upon an Event of Default under the Collateral Agency Agreement,
and
(d) agreed to the exercise by the Senior Parties of various cure rights with
respect to our Project Documents.
DEVELOPMENT AUTHORITY DEED TO SECURE DEBT
The Development Authority entered into the Deed to Secure Debt, Security
Agreement and Assignment of Rents and Leases with the Development Authority
Trustee and granted a security interest to the Development Authority Trustee in
all of the Development Authority's right, title and interest in and to all of
the real property interests (including fee interests, easement interests and
leasehold interests, if any) of the Development Authority to the Leased
Property, together with, but not limited to, leases and licenses of the
premises, improvements, renewals and replacements of, and additions to the
Leased Property and modifications, extensions and renewals of the Lease
Agreement. The rents, issues and profits of the premises, together with all
leases and other documents evidencing such rents, issues and profits, now or
hereafter in effect, were assigned by the Development Authority to the
Development Authority Trustee, but such Security Deed and said assignment shall
be subject and subordinate to the Lease so long as there shall not exist a
default under the Lease or the Indenture of Trust, dated as of November 1, 1999,
between the Development Authority and The Chase Manhattan Bank, as trustee
thereunder (the "Development Authority Indenture").
SECURITY AGREEMENT
The partnership entered into the Assignment and Security Agreement (the
"Security Agreement") with the Collateral Agent for the benefit of the Senior
Parties granting a continuing Lien on and a security interest in all of the
partnership's personal property interests including, but not limited to, all
receivables, equipment, contracts, contract rights, all proceeds in respect of
any action to condemn, seize or appropriate all or any part of the project (the
"Eminent Domain Proceeds"), all proceeds in respect of any property insurance
policy (other than proceeds of business interruption insurance or delayed
opening insurance) covering the partnership or the project (the "Insurance
Proceeds"), amounts held in any account of the partnership (excluding the
Unrestricted Account), Governmental Approvals (to the extent permitted by their
terms and by applicable law), general intangibles and all other personal
property of the partnership, including all products and proceeds thereof.
Pursuant to the terms of the Security Agreement, upon the occurrence and
during the continuance of a Trigger Event, the Collateral Agent may, subject to
the terms of the Collateral Agency Agreement, take possession of the Collateral
or any portion thereof covered by the Security Agreement.
Net Proceeds from any collection, recovery, receipt, appropriation,
realization or sale with respect to the Collateral shall be applied under the
Collateral Agency Agreement.
PLEDGE AGREEMENTS
Pursuant to the General Partner Pledge and Security Agreement and the
Limited Partner Pledge and Security Agreement entered into by our managing
general partner and our limited partner,
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respectively, in favor of the Collateral Agent, each of our managing general
partner and our limited partner pledged to the Collateral Agent, for its benefit
and the benefit of the Senior Parties, a security interest in (1) all of its
general or limited, as the case may be, partnership interests in the
partnership, whether now owned or hereafter acquired, (2) the right to receive
all monies and property representing a distribution in respect of the property
described in the preceding clause (1), whether now owned or hereafter acquired,
and (3) all proceeds, products and accessions of and to any of the property
described in the preceding clauses (1) and (2), whether now owned or hereafter
acquired.
PARTNERSHIP DEED TO SECURE DEBT
The partnership entered into the Deed to Secure Debt, Assignment of Rents
and Leases and Security Agreement with the Collateral Agent and granted a
security interest to the Collateral Agent for the benefit of the Senior Parties
in all of the partnership's right, title and interest in and to all of the real
property interests (including fee interests, easement interests and leasehold
interests, if any) of the partnership under the Lease and the other related real
property rights and interests. All of the partnership's right, title and
interest in and to all Real Property Leases and Income were assigned by the
partnership to the Collateral Agent.
ROLE OF THE INDEPENDENT ENGINEER
R. W. Beck, Inc. currently serves as the Independent Engineer under the
Common Agreement.
Pursuant to a professional services agreement (the "Independent Engineer
Agreement") with the partnership, the Independent Engineer's responsibilities
include, but are not limited to, (1) providing an independent assessment, during
the start-up and performance testing phase of our project, of the initial
operation of our project and the completion of the EPC Contract, and
(2) monitoring and confirming the successful completion of our project.
Under the Common Agreement and the Collateral Agency Agreement, the
Independent Engineer is responsible for confirming the reasonableness of various
statements and projections required to be provided by various parties,
including, but not limited to:
- the cost of and the feasibility of rebuilding, repairing or restoring the
facility following an Event of Loss,
- under some circumstances, the calculation of Projected Debt Service
Coverage Ratios, and
- the base case projections for our project.
The Collateral Agent shall, at the request of the Required Senior Parties,
remove the Independent Engineer if at any time the existing 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
shall take charge or control of, the Independent Engineer or its property or its
affairs for the purpose of rehabilitation, conservation or liquidation, and
shall appoint a successor Independent Engineer from those engineers then listed
on a schedule to the Common Agreement. Within thirty days of receipt by the
Collateral Agent of a written notification from the partnership to the effect
that the Independent Engineer has failed to carry out its obligations in a
timely manner, the Collateral Agent shall, unless directed by the Required
Senior Parties not to do so, remove the Independent Engineer and appoint a
successor Independent Engineer from those engineers then listed on a schedule to
the Common Agreement; PROVIDED, however, that in the event that a Third Party
Engineer (as defined below) determines that the failure of the existing
Independent Engineer to carry out its obligations in a timely manner has
resulted or could reasonably be expected to result in a Material Adverse Effect,
the partnership shall have the unilateral right to remove the Independent
Engineer and appoint a successor Independent Engineer from those successor
engineers then listed on a schedule to the Common Agreement; and PROVIDED,
further, that the Independent Engineer so appointed shall not be such Third
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Party Engineer. The partnership shall pay for all services performed by the
Independent Engineer and its reasonable and documented costs and expenses
related thereto.
THIRD PARTY ENGINEER DISPUTE RESOLUTION
If the partnership and the Independent Engineer are in dispute in respect of
a notice, plan, report, certificate or budget and they are unable to resolve the
dispute within seven days of the Independent Engineer expressing its
disagreement with, or failing when requested by the partnership to approve,
confirm, concur in or consent to, such notice, plan, report, certificate or
budget, a single independent engineer (the "Third Party Engineer") shall be
designated to consider and decide the issues raised by such dispute. The
selection of such Third Party Engineer shall be made from the list of engineers
described below. The partnership shall designate the Third Party Engineer from
such list not later than the third day following the expiration of the seven day
period described above and such designation, subject to acceptance thereof by
the Third Party Engineer so designated, shall become effective ten business days
after notice is given by the partnership to the Collateral Agent of the
selection of a Third Party Engineer unless the Collateral Agent, acting at the
direction of the Required Senior Parties, gives notice of their disagreement
with such designation within such ten business day period, in which event the
partnership shall select another Third Party Engineer pursuant to the foregoing
procedure. In the event the designated Third Party Engineer shall decline the
assignment, the foregoing procedure shall apply to designation of an alternative
Third Party Engineer. Within three days of the acceptance of a Third Party
Engineer, each of the partnership and the Independent Engineer shall submit to
the Third Party Engineer a notice setting forth in detail such Person's position
in respect of the issues in dispute. Such notice shall include supporting
documentation, if appropriate.
The Third Party Engineer shall complete all proceedings and issue his
decision with regard to the issues in dispute as promptly as reasonably
possible, but in any event within ten 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 such case the Third Party Engineer shall state in writing his
reasons for believing that additional time is needed and shall specify the
additional period required, which period shall not exceed ten days without the
partnership's agreement.
If the Third Party Engineer determines that the concerns set forth in the
Independent Engineer's notice are valid, he shall so state and shall state the
corrective actions to be taken by the partnership. In such case, the partnership
shall promptly take such actions. The partnership shall thereafter bear all
costs which may arise from actions taken pursuant to the Third Party Engineer's
decision. If the Third Party Engineer determines that the concerns set forth in
the Independent Engineer's notice are not valid, he shall so state and shall
state the appropriate actions, if any, to be taken by the partnership. In such
case, the partnership shall take such actions, if any, and for purposes of the
Common Agreement, the Independent Engineer shall 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 shall be final and
non-appealable. The partnership shall bear all reasonable and documented costs
incurred by the Third Party Engineer in connection with this dispute resolution
mechanism.
The Third Party Engineer shall be chosen from the list of qualified
engineers set forth in a schedule to the Common Agreement. At any time either
the partnership or the Collateral Agent, acting at the direction of the Required
Senior Parties, may remove a particular engineer from the list by obtaining the
other's consent to such removal (such consent not to be unreasonably withheld,
conditioned or delayed). However, no name or names may be removed from the list
if such removal would leave the list without at least two names, unless,
concurrently therewith, the parties agree to the addition of one or more names
to such list (such agreement not to be unreasonably withheld, conditioned or
delayed).
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During January of each year, each of the partnership and the Collateral
Agent shall review the current list of Third Party Engineers and the partnership
shall give notice to the Collateral Agent and the Collateral Agent, acting at
the direction of the Required Senior Parties, shall give notice to the
partnership of any proposed additions to the list and any intended deletions.
Intended deletions shall automatically become effective thirty days after notice
is received by the other unless written objection is made by such other person
within thirty days and provided that such deletions do not leave the list
without at least two names. Proposed additions to the list shall automatically
become effective thirty days after notice is received by the other person unless
written objection is made by such other person within thirty days. By mutual
agreement between the partnership and the Collateral Agent, acting at the
direction of five percent (5%) of the Combined Exposure, a new name or names may
be added to the list of Third Party Engineers at any time.
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SUMMARY OF PRINCIPAL PROJECT DOCUMENTS
THE FOLLOWING ARE SUMMARIES OF THE MATERIAL TERMS OF THE PRINCIPAL
AGREEMENTS RELATED TO OUR PROJECT AND SHOULD NOT BE CONSIDERED TO BE A FULL
STATEMENT OF THE TERMS AND PROVISIONS OF SUCH AGREEMENTS. ACCORDINGLY, THE
FOLLOWING SUMMARIES ARE QUALIFIED IN THEIR ENTIRETY BY REFERENCE TO EACH
AGREEMENT. COPIES OF EACH AGREEMENT ARE AVAILABLE FOR INSPECTION AS DESCRIBED
ABOVE UNDER "IMPORTANT NOTICE ABOUT INFORMATION PRESENTED IN THIS PROSPECTUS."
UNLESS OTHERWISE STATED, ANY REFERENCE IN THIS PROSPECTUS TO ANY AGREEMENT SHALL
MEAN SUCH AGREEMENT AND ALL SCHEDULES, EXHIBITS AND ATTACHMENTS THERETO AS
AMENDED, SUPPLEMENTED OR OTHERWISE MODIFIED AND IN EFFECT AS OF THE DATE HEREOF.
OVERVIEW OF THE PRINCIPAL PROJECT DOCUMENTS:
The principal project documents that we entered into, and the primary
purposes of these documents, are as follows:
- POWER PURCHASE AGREEMENT. We have entered into this agreement with PECO
whereby PECO will purchase all of the electric energy and capacity
produced by the facility, up to Contract Capacity, and all ancillary
products or services available from the facility, with the exception of
any ancillary services required to be furnished as a requirement of the
Georgia Power Interconnection Agreement or by order of a regulatory body.
PECO will pay for these products and services according to a structure of
payments based upon various formulae set out in the agreement. The
agreement contemplates adjustments in price and penalties for the
inability of the facility to meet various targets, such as the
Availability Percentages.
- POWER PURCHASE AGREEMENT DISPUTED PAYMENTS AGREEMENT. We have agreed to
enter into this agreement with PECO and the Collateral Agent in the event
of a dispute regarding the Power Purchase Agreement. Funds will be set
aside in the event of a dispute and controlled by the Collateral Agent,
and will be paid out by the Collateral Agent upon receipt of a withdrawl
certificate stating that either (a) a satisfactory resolution of the
dispute has been reached or (b) an arbitration award or court award has
been issued with respect to the Power Purchase Agreement Disputed
Payments.
- EPC CONTRACT. We have entered into an Engineering, Procurement and
Construction Agreement on a fixed-price basis with the EPC Contractor who
will perform services in connection with the design, engineering,
procurement, site preparation, civil works, construction, start-up,
training and testing, and to provide all materials, equipment (excluding
operational spare parts), machinery, tools, construction fuels, utilities,
labor, transportation, administration and other services and items for the
facility. Under the term of the contract, the EPC Contractor must
demonstrate that the requirements of various testing and acceptance stages
as outlined in the agreement have been met by specified dates. Failure to
satisfy these conditions may result in a payment adjustment, a penalty
(i.e., in the form of liquidated damages) against the EPC Contractor, or
both.
- O&M AGREEMENT. We have entered into the O&M Agreement with the Operator.
This agreement provides for initial startup support during turnover,
testing, operation, maintenance and management of the facility and the
performance of other defined services by the Operator. The partnership has
agreed to pay the Operator a possible incentive fee, a fixed management
fee and an availability adjustment fee.
- GEORGIA POWER INTERCONNECTION AGREEMENT. We have entered into the Georgia
Power Interconnection Agreement with Georgia Power. This agreement
provides for the direct interconnection of the partnership's electric
generation facilities with the Georgia Integrated Transmission System. The
Georgia Integrated Transmission System is a contractual joint use
arrangement applicable to the transmission systems owned by Georgia Power,
Georgia
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Transmission Corp. and two other owners of electric transmission systems
in Georgia. The term of Georgia Power's participation in Georgia
Integrated Transmission System will end in 2012 if either Georgia Power or
Georgia Transmission Corp. gives notice of termination, and such term can
end prior to or after such date upon the occurrence of an insolvency of,
or default by, either Georgia Power or Georgia Transmission Corp. The
point of interconnection on the Georgia Integrated Transmission System is
on a part of the Georgia Integrated Transmission System that is owned by
Georgia Transmission Corp.
- PIPELINE EPC CONTRACT. We entered into this agreement with the Pipeline
Contractor on a turnkey basis providing for the Pipeline Contractor to
perform services in connection with the design, engineering, equipment and
materials procurement, construction, start-up, training and testing of the
pipeline. The Pipeline Contractor shall pay to us liquidated damages in
the amount of $5,000 for each full day or part thereof that Substantial
Completion is not achieved after the liquidated damages date, with a
maximum cap of 40 days.
- THE GAS INTERCONNECT AGREEMENT. We entered into this agreement with
Transco providing for Transco to construct and operate a natural gas
delivery point to the partnership and associated meter station on
Transco's mainline in Heard County, Georgia. In order to establish the
interconnection between the natural gas facilities of Transco and the
partnership, each of Transco and the partnership shall design, construct,
own, operate and maintain various facilities. Upon termination of the Gas
Interconnect Agreement, Transco shall have the right to abandon all or a
portion of the Tenaska Meter Station in place. Transco shall use all
reasonable efforts to salvage any equipment reimbursed by the partnership
and refund the recovered amount to the partnership.
- WATER AGREEMENT. We entered into the Water Agreement with the Heard County
Water Authority. This agreement provides for the partnership to receive
potable water at the 350 gallons per minute (504,000 gallons per day).
- LEASE AGREEMENT. We entered into the Lease Agreement with the Development
Authority. Under this agreement, the Development Authority leases to us,
subject to Permitted Liens, the facility, the facility site, some related
infrastructure facilities and related easements and those items of
machinery, equipment and related property required under the Lease to be
acquired or installed in the facility or on the facility site or
easements.
- AD VALOREM TAXATION AGREEMENT. We are a party to the Ad Valorem Taxation
Agreement along with the Board of Commissioners of Heard County and the
Board of Tax Assessors of Heard County. The parties agree that the
facility will not be subject to ad valorem taxation because it will be
owned by the Development Authority, but that the partnership's leasehold
interest will be subject to ad valorem taxes. This agreement sets forth
how the partnership's interest under the Lease Agreement will be valued
before the completion of construction, and for the 20 year period
following the year in which the facility is completed.
POWER PURCHASE AGREEMENT
The partnership and PECO have entered into the Power Purchase Agreement for
the sale to PECO of all the electric energy and capacity (up to Contract
Capacity) produced by the facility and all ancillary products or services
available from the facility (except for any ancillary services that are required
to be furnished as a requirement of the Georgia Power Interconnection Agreement
or by order of a regulatory body).
COMMERCIAL OPERATION. The Initial Units are scheduled to achieve Power
Purchase Agreement Commercial Operation on June 1, 2001 and the Final Units are
scheduled to achieve Commercial Operation on June 1, 2002.
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For each Unit that is not in Power Purchase Agreement Commercial Operation
by the scheduled date, the partnership is required to pay PECO liquidated
damages as its exclusive remedy. The partnership shall be required to pay
$25,000 for each day of delay for each Unit for the first 15 days, $50,000 for
each day after 15 days through to 30 days; and $66,667 for each day thereafter
up to an aggregate amount of $8,000,000 per Unit and $25,000,000 in the
aggregate. The partnership may be excused from paying liquidated damages for up
to twelve months for delays, against which, at that time, business interruption
insurance is not customarily obtained by independent power companies with gas
fired power production facilities in the U.S.
OPERATING TERM AND TERMINATION OPTIONS. The operating term commences on the
Date of Commercial Operation of the Initial Units and ends on the 29th
anniversary thereof (the "Operating Term"). PECO may terminate the Power
Purchase Agreement on the 20th anniversary of the Date of Commercial Operation
by giving one year's prior notice of such termination and paying the partnership
$175,000,000.
If all the Initial Units or all the Final Units are not in Power Purchase
Agreement Commercial Operation by the 365th day following the applicable
scheduled Commercial Operation date for such Units ("Delay Termination Date"),
PECO may, at any time until all such Units are in Power Purchase Agreement
Commercial Operation, terminate the Power Purchase Agreement with respect to all
such Units. If PECO terminates its obligations with respect to the Initial Units
before the Final Units have achieved Power Purchase Agreement Commercial
Operation, the partnership has the right to terminate the Power Purchase
Agreement at any time prior to the Final Units achieving Power Purchase
Agreement Commercial Operation.
The Delay Termination Dates for the Initial Units and the Final Units are
subject to adjustment for events of force majeure (up to twelve months unless at
the end of such period two-thirds of the Units required to achieve Power
Purchase Agreement Commercial Operation at the end of such period are in Power
Purchase Agreement Commercial Operation, then an additional six months
adjustment is available). However, no adjustment will be made to the Delay
Termination Date for the Initial Units if the event of force majeure commences
after the scheduled Date of Commercial Operation for such Units.
Following the Date of Commercial Operation, PECO may terminate the Power
Purchase Agreement, if the Summer Availability Percentage (see Availability
Calculation below) is less than 67% for two consecutive Contract Years and the
capacity test conducted during such second Contract Year is less than 550 MW. In
such event, PECO's only entitlement to damages will be to recover any accrued
amounts owed to PECO as of the date of such termination including, but not
limited to, any Availability Adjustment payable.
PAYMENTS. For each month of the Operating Term, PECO shall pay the
following amounts:
- Reservation Payments being the product of (1) the number of Units that
have achieved Power Purchase Agreement Commercial Operation, (2) Unit
Capacity, (3) the reservation rate for such Contract Year as set forth in
the Power Purchase Agreement, and (4) 1000.
- Energy Payments being the sum of (1) the product of the total amount of
Delivered Energy received by PECO during that month to the extent that
such energy was generated by Units fired by fuel oil and the fuel oil
energy rate applicable for that Contract Year (as set forth in the Power
Purchase Agreement), (2) the product of the total amount of Delivered
Energy received by PECO during that month to the extent that energy was
generated by Units fired by natural gas and the gas energy rate applicable
for that Contract Year (as set forth in the Power Purchase Agreement), and
(3) sum of (x) any Replacement Energy Payments (see below).
- Excess Run Time Payment being a payment in respect of each Unit which
(1) delivers energy fired on gas for longer than 16 consecutive hours
equal to the sum of the product of the
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Delivered Energy produced during such period and $2.00/MWh, or
(2) delivers energy fired on fuel oil for longer than 13 consecutive hours
equal to the product of Delivered Energy produced during such period and
$3.00/MWh.
- Start Charges at a rate of $11,000 (to escalate by 3% each year) for each
firing of a Unit in response to a request for energy by PECO (a "Start").
- Standby Mode Charge of $10 for each hour or part thereof for each Unit in
standby mode during Non- Summer Months.
- Fuel Tax Payments being a payment by one party to the other with respect
to taxes imposed by the State of Georgia on fuel delivered to the
facility. If the partnership is responsible for filing and paying taxes on
fuel delivered to the facility, PECO shall pay to the partnership PECO's
Fuel Tax Obligation (see below). However, if PECO is responsible for the
filing and payment of such taxes the partnership shall reimburse PECO for
the positive difference (if any) between the total amount of such taxes
shown due on the tax return and PECO's Fuel Tax Obligation but if such
difference is negative, PECO shall make a payment to the partnership equal
to such negative difference. PECO's Fuel Tax Obligation shall equal the
sum of the products of (a) the sum of (i) 6% and (ii) one-half the
difference between (1) the tax rate applicable to sales and/or use tax on
fuel in Heard County and (2) 6%, (but if fuel becomes exempt from the
sales tax, the rate shall be 3%) and (b) the sum of (i) the volume of
natural gas delivered to the facility times (ii) the Daily Index Citation,
or such other price accepted for the purpose and (A) the volume of fuel
oil as delivered to the facility times (B) the value of such fuel oil as
determined under Georgia tax law or such other price for such fuel oil
accepted for the purpose.
- Replacement Energy Payments being the sum, for all days of the month, of
(1) the product of (a) the total amount of replacement energy delivered
per day and (b) the sum of (A) the gas energy rate (as set forth in the
Power Purchase Agreement) and (B) the product of the index-based gas price
for such day and $0.03 per MMMBtu and 11.1 MMBTU/MWh, and (2) any Start
Charges that PECO would have incurred had the replacement energy been
delivered from the facility, less (3) any unmitigated damages incurred by
PECO to any fuel supplier as a result of the partnership's failure to
fulfill an energy request from the facility.
- Availability Adjustments (see below).
Other payments detailed in the Power Purchase Agreement are:
(a) Reimbursement by the partnership to PECO for any payments made to third
parties for power to start-up a single Unit in excess of the cost of procuring
10 MW of capacity and 2 MWh of energy or a total of 30 MW of capacity and 6 MWh
of energy to start-up three Units simultaneously.
(b) The Fuel Adjustment Payment is a payment to be made for each Contract
Year in which the facility is operated during the months of June, July, August
and September (the "Summer Months") at Base Unit Output for at least 2000 Unit
hours. The Summer Months Base Heat Rate is the quotient of (1) the total amount
of natural gas consumed by the facility during the Base Unit Output Hours
divided by (2) the total amount of Delivered Energy during such hours. If the
Summer Months Base Heat Rate is greater than 10.8 MMBTU/MWh and less than 11.3
MMBTU/MWh, neither party shall owe the other party a Fuel Adjustment Payment. If
the Summer Months Base Heat Rate is greater than 11.3 MMBTU/MWh, the partnership
shall make a Fuel Adjustment Payment to PECO equal to the sum of the products
for each day of (A) the Daily Index Citation times (B) the positive difference
between the Summer Months Base Heat Rate and 11.3 MMBTU/MWh times (C) the
Delivered Energy during such day. If the Summer Months Base Heat Rate is less
than 10.8 MMBTU/MWh, PECO shall make a Fuel Adjustment Payment to the
partnership equal to the sum of the products for each day of (A) the Daily Index
Citation, times (B) the positive difference between 10.8 MMBTU/MWh and the
Summer Months Base Heat Rate, times (C) the Delivered Energy during such day.
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AVAILABILITY ADJUSTMENTS. The partnership is to endeavor in good faith to
cause the facility to achieve a Summer Availability Percentage of at least 97%
during the Summer Months and an Annual Availability Percentage of at least 97%.
(a) AVAILABILITY PENALTIES. The Summer Availability Percentage is calculated
at the end of the Summer Months and equals the quotient of Summer Output divided
by Summer Potential where Summer Output equals the sum of Hourly Output for all
Summer Peak Hours and Summer Potential equals the sum of Hourly Potential for
all Summer Peak Hours. If the Summer Availability Percentage is less than 87.0%,
the partnership shall pay to PECO a Summer Availability Adjustment equal to the
product of (1) the positive difference between 97% and the Summer Availability
Percentage and (2) 3.34% of the Reservation Payments for that Contract Year. The
partnership shall make payment by offsetting all amounts payable by PECO to the
partnership during subsequent months until the amount is offset.
The Annual Availability Percentage is calculated at the end of each Contract
Year and equals the quotient of Annual Output divided by Annual Potential where
Annual Output equals the sum of Summer Output and Non-Summer Output. Non-Summer
Output equals the sum of Hourly Output for all Non-Summer Peak Hours and Annual
Potential equals the sum of Summer Potential and Non-Summer Potential.
Non-Summer Potential equals the sum of Hourly Potential for all Non-Summer Peak
Hours.
For each hour of each year, Hourly Output and Hourly Potential are
determined by categorizing such hour into one of the following categories:
(1) If (A) Delivered Energy during such hour varies above or below the
energy request by more than the specified tolerance and (B) the facility
delivers 0 MWh during the immediately preceding hour, Hourly Output shall
equal Delivered Energy and Hourly Potential shall equal the energy request.
(2) If (A) Delivered Energy for such hour varies above or below the
energy request by an amount equal to or less than the specified tolerance
and (B) the facility produced 0 MWh during the immediately preceding hour,
Hourly Output and Hourly Potential shall both equal the "Required
Potential," being either the contract capacity for each Summer Peak Hour or
the product of Unit capacity and the number of Units on the Unit Call
Schedule for each Non Summer Peak Hour.
(3) If (A) Delivered Energy for such hour varies above or below the
energy request by more than the specified tolerance and (B) the facility is
reduced to 0 MW during such hour pursuant to an energy request, Hourly
Output shall equal Delivered Energy and Hourly Potential shall equal the
energy request for such hour.
(4) If (A) Delivered Energy for such hour varies above or below the
energy request by less than the specified tolerance and (B) the facility is
reduced to 0 MW during such hour pursuant to an energy request, Hourly
Output and Hourly Potential shall both equal the energy request for such
hour.
(5) If (A) Delivered Energy for such hour varies above or below the
energy request by more than the specified tolerance and (B) the facility
produced more than 0 MWh during the immediately preceding hour, Hourly
Output shall equal Delivered Energy and Hourly Potential shall equal
Required Potential.
(6) If (A) Delivered Energy for such hour varies above or below the
energy request by an amount equal to or less than the specified tolerance,
and (B) the facility produced more than 0 MWh during the immediately
preceding hour, Hourly Output and Hourly Potential shall equal Required
Potential.
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(7) If (A) the energy request for an hour is 0 MW but (B) Delivered
Energy is equal to or greater than 1 MWh, Hourly Output shall be 0 MWh and
Hourly Potential shall equal Required Potential.
(8) If (A) the energy request for an hour is 0 MW and (B) Delivered
Energy is 0 MWh, Hourly Output and Hourly Potential shall equal Required
Potential.
(9) If (A) the energy request for an hour is greater than 0 MWh but
(B) the ability to deliver or consume fuel to or at the facility is
prohibited due to a state or federal prohibition on fuel delivery or
consumption, Hourly Output and Hourly Potential shall equal Delivered
Energy. If 0 MWh of energy can be delivered due to such prohibition, the
hour will not be included in calculating Availability Percentages.
(10) If PECO elects Peak Availability Option #1 and then requests less
than the number of Unit hours of energy that it is entitled to request from
Units required to be on the Unit Call Schedule during the Non- Summer Months
of such year ("Maximum Available Energy Hours"), the difference between the
Maximum Available Energy Hours and the number of actual MWhs requested by
PECO in such Non-Summer Peak Hours of the Non- Summer Months shall be
credited to the partnership at full contract capacity for the purpose of
calculating the Annual Availability Adjustment.
If the Annual Availability Percentage is less than 97.0% but greater than
76.9%, the partnership shall owe PECO an Annual Availability Adjustment equal to
the product of (1) the positive difference between 97.0% and the Annual
Availability Percentage and (2) 3.34% of the Reservation Payments for that
Contract Year. But if the Annual Availability Percentage is less than or equal
to 76.9%, the partnership shall owe PECO an Annual Availability Adjustment equal
to the sum of (A) 66.8% of the Reservation Payments for that Contract Year and
(B) the product of (a) the positive difference between 76.9% and Annual
Availability and (b) 0.432% of the Reservation Payments for that Contract Year.
However, the Annual Availability Adjustment for any Contract Year is capped at
the Reservation Payments for that Contract Year.
At the end of the Summer Months of each Contract Year, PECO shall calculate
the "Accrued Availability Adjustment," which shall be the Summer Availability
Adjustment for the first Contract Year, and the sum of Annual Availability
Adjustments which have not been fully rebated to PECO and any Summer
Availability Adjustment owed to PECO for all other Contract Years. At such time
the partnership shall make Availability Adjustment payments to PECO as follows:
if the Accrued Availability Adjustment is less than the available amount of the
Acceptable Credit Support provided by the partnership, the amounts payable shall
be offset against payments from PECO; and if the Accrued Availability Adjustment
exceeds the available amount of the Acceptable Credit Support, the partnership
shall pay to PECO an amount equal to such excess over the available amount of
the Acceptable Credit Support and payment of the remaining Accrued Availability
Adjustment will be made by offsetting all amounts payable by PECO to the
partnership during subsequent months, until the amount of payments and offsets
by the partnership equals the Accrued Availability Adjustment.
At the end of each Contract Year, the parties will make Availability
Adjustment payments to each other as follows: if the amount of the Summer
Availability Adjustment that has been paid exceeds the Annual Availability
Adjustment which has not been rebated or otherwise paid to PECO, PECO shall make
payment of such difference to the partnership; and if the Annual Availability
Adjustment exceeds the amount of the Summer Availability Adjustment that has
been paid, the partnership shall make payment to PECO of such difference by
offsetting all amounts against amounts payable by PECO, provided that if there
is any Accrued Availability Adjustment for the preceding Contract Years which
has not been rebated to PECO, PECO shall offset its payment obligation against
such Accrued Availability Adjustment. Any Availability Adjustment payable to
PECO at the end of the Operating Term shall be paid by wire transfer.
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(B) AVAILABILITY INCENTIVE. At the end of the Summer Months, if the Summer
Availability Percentage exceeds 97%, PECO will pay to the partnership the
"Availability Incentive Payment" calculated as follows. If the Summer
Availability Percentage exceeds 97% but the Peak Days Availability is less than
99%, the Availability Incentive Payment shall equal the product of (A) the
positive difference between the Summer Availability Percentage and 97%,
(B) 100, and (C) $150,000. If the Summer Availability Percentage exceeds 97% and
the Peak Days Availability is 99% or greater, the Availability Incentive Payment
shall equal the product (A) the positive difference between the Summer
Availability Percentage and 97%, (B) 100, and (C) $500,000. The "Peak Days
Availability" is calculated in respect of the availability of the facility in
the five days during the Summer Months with the highest On-Peak Energy Prices
for such period. The availability is calculated as the sum of all Hourly Output
results for the Summer Peak Hours during those five days divided by the sum of
all Hourly Potential such hours during such days.
METERING FACILITIES. PECO shall pay to the partnership 56% of the total
amount that the partnership is required to pay Transco with respect to the
installation of the natural gas metering facilities, capped at $784,000.
TESTING CONTRACT CAPACITY. The partnership shall provide PECO with its
declaration of capacity for the first Contract Year no later than the scheduled
date of Power Purchase Agreement Commercial Operation for the Initial Units.
Each subsequent Contract Year (except for last) the partnership shall conduct a
capacity test of Units in commercial operation, after which the partnership
shall declare capacity for the immediately following Contract Year. If the
declared level exceeds the most recent capacity test result, PECO may request a
capacity test during the following May and if such test is less than that
declared, the capacity for the immediately following Contract Year shall equal
the most recent capacity test result.
The partnership's declared capacity for the first Contract Year must not be
less than the product of 150 MW and the number of Units that are in commercial
operation. For the second Contract Year, capacity declared by the partnership
shall be not less than 875 MW and not more than 950 MW (with such amounts
reduced pro rata if less than six Units are in commercial operation). Capacity
declared by the partnership for Contract Years after the second Contract Year
must be not less than 875 MW and within 50 MW of the then current capacity based
on six Units being in commercial operation, with minimum and maximum Contract
Capacity adjusted for the number of Units actually in commercial operation.
EXCLUSIVITY. The partnership shall sell all of the capacity and all of the
energy generated by the facility during the Operating Term, net of that required
for operation, to PECO at the point of delivery. PECO will purchase such energy
and capacity provided it is delivered pursuant to an energy request and in
amounts, with respect to an hour, within the greater of 1% of such energy
request and 2MWhs ("Energy Delivery Tolerance"). However, at any time when an
event of default by PECO is continuing, the partnership may enter into
agreements with terms of up to thirty days to sell capacity and/or energy to
other parties. The net revenue from such sales will be credited against amounts
payable by PECO to the partnership.
MAINTENANCE. The partnership shall cause the completion of all scheduled
maintenance for each major item of equipment between March 15th and May 15th or
between October 1st and November 30th each year. However, twice during the
Operating Term, the partnership may, following one years' advance notice, extend
these periods to March 1st to May 31st and October 1st to November 30th.
On or before April 1st of each year, the partnership is to provide PECO with
a plan for scheduled outages for the next five years. The scheduled outages for
the immediately following year shall be binding on the partnership but merely
estimates for the other years. The start date or end date of a
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scheduled outage may be shifted up to seven days following notice to PECO
provided that the end date of such scheduled outage does not occur after the
specific periods permitted for such outages.
If a scheduled outage extends beyond the specific period permitted for such
outage, such outage will be deemed a Forced Outage when calculating the
Availability Percentages unless PECO states in response to a written request by
the partnership for such a statement that it would not have dispatched such
Units during the extension. The partnership shall not be entitled to require any
supporting documentation from PECO if PECO is unwilling to provide such a
statement. If the facility cannot fulfill an energy request due to a forced
outage, the partnership shall have the right, with at least 6 hours prior
notice, to request PECO to accept and purchase replacement energy.
OPERATION. On or before April 15 of the first year of operation for the
Initial Units, and each year during the Operating Term, PECO shall elect Peak
Availability Option #1 whereby PECO shall be entitled to request energy for
16 hours of each day of the Summer Months or Peak Availability Option #2 whereby
PECO shall be entitled to request energy (A) for 20 hours on each Monday through
Friday, and (B) for 16 hours on each Saturday and Sunday. If PECO elects Peak
Availability Option # 1, PECO shall be required to place Units on the Unit Call
Schedule from the facility during the Non- Summer Months for a minimum of the
lesser of 2091 Unit hours, or the number of hours allowed by the air permit.
During the Summer Peak Hours and the Non-Summer Peak Hours of December,
January and February, the partnership shall make all Units in commercial
operation available for dispatch by PECO. The partnership shall make 4 Units
available for dispatch by PECO during the Non-Summer Peak Hours in the months of
October, November, March, April and May (the "Shoulder Months"), unless only the
Initial Units or Final Units have reached commercial operation, in which case
the partnership shall make 2 Units available. The partnership shall provide PECO
with an Availability Schedule.
PECO shall provide the partnership with a Unit Call Schedule for each Unit
for each day. PECO must place all Units in commercial operation on the Unit Call
Schedule for each Summer Peak Hour but is not required to place all Units in
commercial operation on the Unit Call Schedule during each day of December,
January and February. PECO may place up to four Units in commercial operation on
the Unit Call Schedule during each day of the Shoulder Months. PECO may
designate the number of Units to be in standby mode during each day of the Non-
Summer Months.
FUEL. PECO is solely responsible for procuring and transporting the fuel.
PECO shall maintain all fuel oil delivery permits. The partnership takes title
to all fuel at the delivery point.
BILLING. Each day during the Operating Term, PECO will give to the
partnership a daily confirmation letter confirming all the information needed to
calculate the Annual Output and Annual Potential for each hour of such day. The
partnership countersigns the letter but if there is a dispute the parties are to
use good faith effort to resolve the dispute within 5 days. An escrow account
shall be established and the disputed amount shall be paid into said account if
either party disputes a statement. Amounts expected to exceed $7,500,000 shall
not be subject to arbitration. Interest shall be paid upon amounts not paid when
due. See "Power Purchase Agreement Disputed Payments Agreement" below.
After the end of each month, the partnership shall deliver to PECO a monthly
statement detailing the information from the daily confirmation letter and all
other information necessary to calculate the payment. At the end of the Summer
Months and the Contract Year, PECO shall give to the partnership a statement
showing the Availability Adjustment and any Availability Incentive Payment.
TERMINATION, CURE AND EVENTS OF DEFAULT. If any event of default is not
cured within the relevant cure period or if any party wrongfully repudiates the
Power Purchase Agreement and fails to withdraw such repudiation, then the other
party may immediately terminate the Power Purchase Agreement. However, PECO
agrees not to terminate the Power Purchase Agreement pursuant to a default by
the
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partnership until it first provides written notice of such default to the
financial institutions and affords the financial institutions an opportunity to
cure.
The partnership's events of default include the following: abandonment of
the construction of the facility for any period in excess of 60 consecutive
days, abandonment of the operation of the facility for any period in excess of
10 consecutive days; a material breach of the partnership's representations,
warranties or covenants; various bankruptcy related events; or any other
material breach by the partnership of any material provision. However, the
failure of the partnership to deliver the amount of energy requested or to have
the number of Units available on the Availability Schedule under the Power
Purchase Agreement or of the facility to achieve an expected heat rate, do not
constitute events of default.
PECO's events of default include the following: failure to make any payment
to the partnership when due, provided, however, that the failure by PECO to make
payments due to the partnership up to an aggregate limit of $7,500,000 do not
constitute an event of default if such amount is disputed in good faith and is
deposited by PECO into an escrow account; a material breach of any of PECO's
representations or warranties; various bankruptcy related events; or any other
material breach by PECO of any material provision. See "Power Purchase Agreement
Disputed Payments Agreement" below.
For the partnership abandonment defaults, the partnership has fifteen days
from the receipt of such notice to cure. For all other partnership and PECO
defaults (except for a payment default by PECO), the defaulting party has sixty
days from the receipt of such notice to cure such default, provided that if the
default cannot be cured within the said sixty days, the defaulting party may
provide the non-defaulting party with a plan for the appropriate actions which
the defaulting party must diligently pursue.
The financial institutions are permitted to cure non-monetary defaults by
the partnership within 75 days and monetary defaults within 30 days in each case
after receipt of such notice or of the termination of the partnership's right to
cure, whichever is later. In addition, the financial institutions may cure by
assuming, or causing the assumption of the partnership's rights and obligations
under the Power Purchase Agreement, however, no transfer of rights can take
place if such entity, in PECO's reasonable judgment, (1) does not possess a
satisfactory level of experience in electric power facility operations or
(2) is one of three parties which PECO is permitted to name as a competitor. The
party assuming the Power Purchase Agreement has forty-five days from the
effective date of such assumption to cure the material breach or default or if
the default is a non-monetary default or such longer period as is required so
long as the party who assumes the Power Purchase Agreement has commenced and is
diligently pursuing appropriate action to cure such default.
However, the above cure periods are limited to twelve months if the default
is a non-monetary default (except that the partnership or the financial
institutions may extend cure rights beyond twelve months by posting an
additional $10,000,000 in credit support), or four months if the default is a
monetary default, from the date of written notice of the default to the
financial institutions.
PECO shall not be entitled to assert any termination rights in respect of a
failure to have Units on the Availability Schedule, failure to achieve the
expected heat rate or failure to comply with an energy request. In such event,
PECO's exclusive remedy is to recover Availability Adjustments and Fuel
Adjustment Payments. This limitation on damages only applies to failures that
cause the partnership to be unable to deliver amounts of energy that are or may
be requested by PECO and not to any other material breach of any material
provision independent of shortages in the amount of energy delivered or
available for delivery.
ASSIGNMENT. Neither party may assign the Power Purchase Agreement without
the prior written consent of the other but if PECO sells or otherwise transfers
its power marketing business, PECO may
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assign the Power Purchase Agreement without the partnership's consent if
(1) the buyer or transferee has a senior unsecured public debt rating by Moody's
or S&P or a successor thereof that is not lower than PECO's comparable unsecured
Senior Debt rating at the time of such transfer and (2) such rating organization
shall have confirmed that such rating shall remain in effect following the
buyer's or transferee's assumption of the Power Purchase Agreement. The Power
Purchase Agreement may not be transferred to any purchaser of the facility upon
foreclosure by, any party which is (1) a Competitor or (2) in PECO's reasonable
judgment does not possess a satisfactory level of experience in electric power
facility operations.
LIMITATIONS OF LIABILITY AND INDEMNIFICATION. Neither party shall hold the
other liable for any claims and expenses on account of bodily injury to the
personnel of or damage to property, occurring in connection with a party's
performance under the Power Purchase Agreement except for any liability or loss
because of bodily injury or property damage arising out of or in connection with
PECO's or the partnership's, respective performance of the Power Purchase
Agreement; except that neither shall be obligated to indemnify the other for
injury or damage caused by the negligence or willful misconduct of the other
party.
The partnership releases PECO, its successors and assigns from all claims
from any force majeure (but not from damages otherwise recoverable under the
Power Purchase Agreement), operation of the facility in parallel with local
utility's electrical systems, transfer, transmission, use or disposition of
energy delivered prior to its delivery to PECO at the applicable delivery point,
transportation, handling, use, or disposition of all fuel to be fired at the
facility after it is delivered to the partnership at the delivery point. PECO
releases the partnership and its successors from all claims resulting from any
force majeure (but not from damages otherwise recoverable under the Power
Purchase Agreement), operation of the facility in parallel with the local
utility's electric systems, transfer, transmission, use or disposition of energy
after it is delivered to PECO at the applicable delivery point; interruption,
suspension or curtailment of delivery of power to the local utility' electric
systems caused by the local utility' electric systems; or transportation,
handling, use, or disposition of all fuel to be fired at the facility prior to
it being delivered to the partnership.
DISPUTE RESOLUTION. In the case of a dispute between parties as to the
selection of an alternative publication or index as a basis for the Daily Gas
Price, capacity and tests or the monthly statement, a single arbitrator will
resolve the dispute. The arbitrator will be chosen jointly by the parties and,
after each of the parties independently presents a "final offer" with supporting
rationale, the arbitrator will select either the position of the partnership or
PECO. If the parties fail to choose an arbitrator one will be chosen by the AAA
under the Commercial Arbitration Rules of the AAA. Arbitration proceedings will
be resolved within 30 days after the appointment of the arbitrator. If, after
30 days, a decision has not been made either party can void the appointment of
the arbitrator and elect to have a new arbitrator appointed.
COVENANTS. The partnership covenants to: comply with all material
applicable laws; use prudent utility practice to maximize satisfaction of energy
requests and to end any forced outage; promptly comply with procedures to obtain
access to insurance proceeds if there is a casualty; ensure that the O&M
contractor is not when the contract is entered into, a Competitor and that the
O&M contract contains a covenant that the O&M contractor shall not undertake the
sale, brokering or marketing of electrical energy or capacity and any affiliate
of the O&M Contractor (that is not an affiliate of the partnership) shall not
conduct business in the ordinary course from the same offices used by an
affiliate of the O&M contractor that is engaging in the sale, brokering or
marketing of electrical energy or capacity; use commercially reasonable efforts
to maintain the air permit without any adverse modification; and at no cost, act
in good faith to assist PECO with the maintenance of permits regarding fuel oil
delivery and to notify PECO of any proposal to modify such permits. The
partnership also covenants: not to consent to modifications to the air permit
that adversely affect various rights of
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the partnership, unless the failure to so agree, would result in adverse effects
at least as severe as those resulting from the modification; and until
termination and except as specifically provided with respect to replacement
energy, not to negotiate with any other party with respect to the purchase of
any fuel for the facility or the sale of any capacity and energy or ancillary
products to be produced by the facility.
PECO covenants to: enter into a consent to assignment to the financing
institutions and to provide an opinion of counsel, request energy in good faith
and to cooperate with the partnership to limit dispatch of the facility at
levels that are not economically efficient, provided that PECO shall not be
required to incur any economic loss or cost in avoiding dispatch at uneconomic
levels. PECO at the partnership's sole cost, will cooperate with its efforts to
claim and benefit from any pollution allowances or credits related to the
facility.
The parties covenant to: cooperate in good faith in all reasonable respects
in matters involving the construction of the facility, the interconnection
facilities, and the metering equipment, and in the operation of thereof; act, in
all reasonable respects, in good faith toward the other and when dealing with
governmental regulatory bodies.
SECURITY. The partnership shall maintain acceptable credit support or cash
collateral of $15,000,000 to be delivered on the earlier to occur of financial
closing or January 1, 2000 and an additional $10,000,000 to be delivered on
April 1, 2001. Up to the full $25,000,000 of total acceptable credit support may
be drawn upon by PECO if the partnership has failed to pay amounts due under the
Power Purchase Agreement.
FORCE MAJEURE. "Force Majeure," as used in the Power Purchase Agreement,
includes, but is not restricted to, failure or threat of failure of facilities
(excluding such causes by the partnership or the EPC Contractor's failure to
comply with Prudent Utility Practice), flood, earthquake, storm, fire,
lightning, Acts of God, explosions etc. A party is not required to settle any
strike, lockout, workout stoppage, etc. Force majeure shall not include changes
in market conditions, lack of finances, or an inability to accept power due to
transmission constraints. Each party releases the other from any and all claims,
loses, harm resulting from any force majeure. Dates established under the Power
Purchase Agreement will be adjusted, within specific limits, due to the extent a
party is not able to meet such date due to a force majeure.
CHOICE OF LAW. The Power Purchase Agreement is governed by and construed
under the laws of the State of Georgia, regardless of the conflicts of laws
provisions of such laws.
CONFIDENTIALITY. The parties agree to keep all information relating to the
Power Purchase Agreement confidential except for disclosure to certain parties
after receipt of a confidentiality agreement, and except for disclosures as
required by any law. The partnership shall keep confidential notices of energy
requests and any intra-day adjustments of energy to be delivered from the power
marketing groups of (a) Tenaska, Inc. (b) any affiliate of Tenaska, Inc. or
(c) any partners. However, the partnership may, after the bill for such month
has been issued, provide to the partners information on the aggregate amount of
energy delivered to each delivery point.
POWER PURCHASE AGREEMENT DISPUTED PAYMENTS AGREEMENT
The partnership and PECO have agreed to the form of the Power Purchase
Agreement Disputed Payments Agreement which would be entered into among the
partnership, PECO and the Collateral Agent in the event of a Power Purchase
Agreement dispute. The following is a summary of the terms provided in this
form.
ESTABLISHMENT OF THE ACCOUNT. The Collateral Agent agrees to accept all
amounts and Permitted Investments received or held by the Collateral Agent
pursuant to the Disputed Payments Agreement
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and to promptly deposit into the Power Purchase Agreement Disputed Payments
Account. The Power Purchase Agreement Disputed Payments Account is in the name
of the Collateral Agent for the benefit of the Senior Parties and all amounts in
the account, and the Permitted Investments, registered in the name of the
Collateral Agent or credited to another account maintained by and in the name of
the Collateral Agent. Unless specially endorsed to the Collateral Agent, no
amounts or other property credited to the Power Purchase Agreement Disputed
Payments Account will be registered in the name of or payable to the partnership
or PECO. All of the partnership's rights, title and interest, in and to such
amounts and Permitted Investments held in or credited to the Power Purchase
Agreement Disputed Payments Account constitute a part of the Collateral and not
part of the Indebtedness.
SECURITY INTEREST. As collateral security for the prompt payment and
performance of the partnership's obligations owing to any of the Senior Parties
under the Financing Documents, the partnership transfers and grants to the
Collateral Agent a lien on and security interest in and to all of the
partnership's rights under the Power Purchase Agreement Disputed Payments
Account and all investments, Permitted Investments, all security entitlements
and any other property at any time deposited in or credited to the Power
Purchase Agreement Disputed Payments Account.
The Collateral Agent has the right to debit the Power Purchase Agreement
Disputed Payments Account to the extent of any and all fees owing to the
Collateral Agent directly related to the Collateral or the Collateral Agent's
duties. If the Collateral Agent obtains a security interest in the Collateral or
any security entitlement credited thereto, the Collateral Agent such security
interest subordinated to the security interest of the Senior Parties.
The Collateral Agent's powers are not affected by the bankruptcy of the
partnership or PECO or the lapse of time. The obligations of the Collateral
Agent continue until the termination of the Financing Documents.
DOMINION AND CONTROL OF THE ACCOUNT, FUNDS, AND PERMITTED INVESTMENTS. The
Collateral Agent has exclusive possession of and sole control and dominion over
the Power Purchase Agreement Disputed Payments Account. The partnership and PECO
have no right to withdrawal amounts from the Power Purchase Agreement Disputed
Payments Account, but merely to direct and authorize the Collateral Agent to
deposit and withdraw funds from the Power Purchase Agreement Disputed Payments
Account.
Pending disbursement of funds held in the Power Purchase Agreement Disputed
Payments Account such funds are to be invested and reinvested in Permitted
Investments at the risk and expense of the partnership and PECO. The Collateral
Agent will follow the instructions of authorized officers of the partnership and
PECO, but shall not be liable for any loss resulting from investments made under
instructions from the partnership or PECO. If the Collateral Agent is not so
instructed, amounts on deposit in the Power Purchase Agreement Disputed Payments
Account will be invested and reinvested in Permitted Investments and then
liquidated at the risk of the partnership and PECO. Interest paid or other
earnings made on Permitted Investments are to be credited to the Power Purchase
Agreement Disputed Payments Account. The Collateral Agent is not liable for any
loss, except if such loss is the result of gross negligence or willful
misconduct or for special, indirect or consequential loss or damage of any kind
whatsoever.
If cash is required to be disbursed, and no cash is available in the Power
Purchase Agreement Disputed Payments Account, the Collateral Agent is authorized
to cause Permitted Investments to be liquidated into cash in such manner the
Collateral Agent deems reasonable.
DISTRIBUTION FROM THE ACCOUNT. Upon receipt of a withdrawal certificate
stating that (a) PECO and the partnership have reached a satisfactory resolution
of their dispute with respect to the Power Purchase Agreement Disputed Payments,
or (b) an arbitration award or court order has been issued with respect to the
Power Purchase Agreement Disputed Payments, the Collateral Agent shall transfer
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the relevant amount of the Power Purchase Agreement Disputed Payment, together
with any interest on or earnings from Permitted investments, to the Revenue
Account if for the account of the partnership or to such accounts as designated
by PECO if for the account of PECO. PECO shall promptly deposit all Power
Purchase Agreement Disputed Payments into the Power Purchase Agreement Disputed
Payments Account at the time it disputes any amount.
EXPENSES; INDEMNIFICATION; FEES. The partnership agrees to pay all of the
Collateral Agent's out-of-pocket expenses, and agrees to indemnify the
Collateral Agent from and against all claims, losses, liabilities and expenses
resulting from the Power Purchase Agreement Disputed Payments Agreement.
GOVERNING LAW. The Power Purchase Agreement Disputed Payments Account is
governed by and construed under the laws of the State of New York, regardless of
the conflicts of laws provisions of such laws.
EPC CONTRACT
The partnership and the EPC Contractor are parties to an Engineering,
Procurement and Construction Agreement on a fixed-price basis, which provides
for the EPC Contractor to perform services in connection with the design,
engineering, procurement, site preparation, civil works, construction, start-up,
training and testing, and to provide all materials, equipment (excluding
operational spare parts), machinery, tools, construction fuels, utilities,
labor, transportation, administration and other services and items
(collectively, the "Work") for the facility.
SCOPE OF WORK. The EPC Contractor shall furnish the design and engineering
for the facility and the facility site, including the preparation of all
technical and design drawings and plans, with design and engineering that meet
the requirements of the EPC Contract and are prepared and implemented under
applicable laws, Applicable Insurance Policies and Good Utility Practice. In
addition, the EPC Contractor shall:
- furnish all labor, supervision, construction utilities, and tools
necessary to procure for, construct, direct and support start-up of the
facility;
- correct all Work that fails to conform to the requirements of the EPC
Contract and any Defects relating to the facility or the Work under the
EPC Contract;
- be solely responsible for dealing with, coordinating and handling all
communications, negotiations and resolutions of disputes concerning all
Equipment or other matters related to the Work with all Subcontractors and
Lower-tier Subcontractors and bear full responsibility for any part of the
Work accomplished by Subcontractors and Lower-tier Subcontractors and for
the acts and omissions of Subcontractors and Lower-tier Subcontractors;
- replace or repair any inadequate, nonconforming, damaged or defective
Equipment or Work during construction;
- supervise and direct the Work;
- bear responsibility for keeping the Work on schedule;
- make timely status reports to the partnership;
- pay Subcontractor in a timely manner;
- bear sole responsibility for and have control over Subcontractors, labor,
construction means, materials, material suppliers, methods, techniques,
sequences, and procedures as well as supervising and directing all
portions of the Work;
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- bear responsibility for carrying out its obligations so that each of the
Units and the facility operate safely and in compliance with all
applicable laws and in full satisfaction of all operating requirements set
forth in the EPC Contract;
- procure all Equipment, and provide the partnership with a list of spare
parts for such Equipment, whereupon the partnership shall purchase all
such spare parts prior to Commercial Operation of the Final Units (risk of
loss will remain with the EPC Contractor for spare parts until they are
delivered to the Operator at or before the Commercial Operation date of
the final Unit);
- as part of the Guaranteed Lump Sum Price, secure and pay for all necessary
permits, except for any Department of Energy permits, zoning, subdivisions
or similar permits, and those environmental permits described in the EPC
Contract;
- complete the Work in a good and workmanlike manner under the construction
practices used by a prudent construction contractor, so to enable the
partnership, without modification of the Work, to meet its Power Purchase
Agreement obligations;
- provide engineers to support the partnership's operator training program;
and
- bear responsibility for all site preparation for the facility site.
Notwithstanding the preceding two sentences, the EPC Contractor shall have
no greater responsibility to the partnership for compliance with applicable laws
with respect to Equipment supplied or services performed pursuant to the Turbine
Contract, than General Electric has to the EPC Contractor, as assignee of the
Turbine Contract, for such Equipment supplied and service performed pursuant to
the Turbine Contract.
GUARANTEED LUMP SUM PRICE AND PAYMENT. The partnership shall pay the EPC
Contractor for its performance of the EPC Contract a Guaranteed Lump Sum Price,
which includes payments made under the Turbine Contract and the EPC Contractor's
Fixed Price, subject to adjustment under the EPC Contract. The EPC Contractor
shall use reasonable efforts to consume not more than a set specified amount of
fuel during the performance of the Work through the date of Commercial Operation
of the last Unit to achieve Commercial Operation. The EPC Contractor is
responsible for the payment of all sales and use taxes with respect to any
purchases made by the EPC Contractor in order to perform the Work, except as
otherwise provided in the EPC Contract.
The Guaranteed Lump Sum Price shall be invoiced and paid on a monthly basis.
The EPC Contractor shall submit to the partnership a report of the progress and
status of the Work on a monthly basis. The partnership will pay General
Electric, either directly or jointly with the EPC Contractor, the amount due
under the Turbine Contract. All amounts paid to General Electric by the
partnership shall be credited against the Turbine Contract portion of the
Guaranteed Lump Sum Price. The partnership will also pay the respective vendors
of the Designated Equipment, either directly or jointly with the EPC Contractor,
the amount due under the Designated Contracts.
The partnership will have twenty-five days to approve each invoice and pay
the EPC Contractor a progress payment, not including any amounts due pursuant to
the Turbine Contract or Designated Contracts, of ninety-five percent (95%) of
the amount specified in such invoice to be due to the EPC Contractor, not
including any amounts due pursuant to the Turbine Contract or the Designated
Contracts, the remaining five percent (5%) of such amount to be Retainage.
Additionally, the partnership has the right to withhold 150% of the amount of
any lien filed against the facility or the facility site from the monthly
progress payments, until such lien is removed. All progress payments are subject
to deductions by the partnership for:
- overpayments;
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- liquidated damages due the partnership under the EPC Contract;
- such amount as the partnership reasonably determines to be the cost of
remedying any defective, nonconforming or nonperformed Work;
- amounts subject to good faith disputes;
- the cost of any loss or damage to the partnership caused by the EPC
Contractor; and
- any amounts due to the partnership or other indemnified parties pursuant
to the EPC Contract indemnification provisions. In the event of a dispute,
the parties shall continue to perform under the EPC Contract, and shall
resolve such dispute in good faith under the provisions set forth in the
EPC Contract.
CHANGE ORDERS. After receipt of notice from the EPC Contractor of an
Unforeseen Condition which will increase or decrease the cost of the Work or the
facility by more than $40,000 or cause a delay in the Scheduled Date of
Commercial Operation, the partnership shall issue a change order adjusting the
Guaranteed Lump Sum Price or extending the Scheduled Date of Commercial
Operation, as appropriate. The total dollar amount for all Change Orders due to
Unforeseen Conditions shall not exceed $1,500,000. In addition, if a change in
the law or in any applicable insurance policy materially changes the Work and
materially increases or decreases the EPC Contractor's cost of performance under
the EPC Contract, a change in the Work or Scheduled Date of Commercial Operation
of a Unit may be approved by the partnership.
There shall be no extension of the Scheduled Date of Commercial Operation of
a Unit except as a result of partnership Caused Delay, a Force Majeure event, or
a Change Order where the EPC Contractor:
(1) demonstrates that such delay, event or order will proximately cause the
EPC Contractor to fail to achieve Commercial Operation by the Scheduled
Date of Commercial Operation and specifies the number of days of expected
delay;
(2) demonstrates that it will use all reasonable efforts to maintain the
Scheduled Date of Commercial Operation; and
(3) explains the specific actions it will take to work around or mitigate
the impact of the delay, event or order on the Scheduled Date of
Commercial Operation.
Unless otherwise agreed, in the event of a partnership Caused Delay, a Force
Majeure event or Change Order, the Scheduled Date of Commercial Operation shall
be extended by the number of days specified by the EPC Contractor as set forth
in clause (1).
If the partnership fails to obtain permits or licenses identified in the EPC
Contract when required, or fails to maintain such permits or licenses in force
(unless such failure is caused by the EPC Contractor), the partnership shall
have ten days in which to cure such failure, and if the partnership does not
cure such failure, the EPC Contractor shall be entitled to a Change Order to the
extent that such failure materially increases the EPC Contractor's cost of
performance, or entitles the EPC Contractor to an extension of the Scheduled
Date of Commercial Operation. To the extent any Change Order affects the
Equipment or services furnished under the Turbine Contract, General Electric
must approve such Change Order.
PARTNERSHIP'S RESPONSIBILITY. The partnership shall, at its own expense:
- provide, "as is," the facility site described in the EPC Contract;
- apply for and obtain the permits and licenses necessary in the prosecution
of the Work or the operation of the facility as listed in the EPC
Contract;
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- pay all taxes associated with income or earned surplus generated by the
facility or facility site, as well as all real property taxes or personal
property taxes levied on the Equipment, facility, facility site and all
components thereof;
- be responsible for the portion of sales and use taxes as provided in the
EPC Contract;
- provide access to the facility site so as to allow Contractor to perform
the Work;
- furnish qualified operating and maintenance personnel to operate and
maintain the facility;
- provide start-up and operating fuels, turbine lube oil for flushing and
initial fill, bulk CO(2)and hydrogen for generator purge and cooling, bulk
CO(2)and FM 200 for the turbine fire protection systems, and bulk water
treatment chemicals;
- pay for any start-up power off the permanent auxiliary transformer for the
permanent Equipment;
- make available spare parts under the EPC Contract;
- provide and pay for tools, materials and supplies for normal maintenance
of the System after the partnership issues a Certificate of Mechanical
Completion for such System;
- provide sufficient water (excluding water used for construction) and
access to wastewater disposal to permit normal and continuous operation of
the facility;
- supply tools, backfeed power, water supply, and natural gas supply;
- provide for acceptance of electric power when necessarily requested by the
EPC Contractor; and
- use reasonable efforts to operate the facility after the Date of
Commercial Operation so as to permit the EPC Contractor to expeditiously
complete the Work.
PARTNERSHIP'S REVIEW. The partnership has the right throughout the term of
the EPC Contract to review and to designate others (including the Independent
Engineer) to review all Drawings and to inspect Work at all stages at the
facility site, the EPC Contractor's premises and the Subcontractors' premises.
The EPC Contractor shall afford reasonable access to the facility site to the
Independent Engineer, and to others designated by the partnership, for the
necessary servicing, maintaining, modifying, or upgrading of the land or
facilities located thereon.
DESIGN AND OPERATING REQUIREMENT. The EPC Contractor shall meet all the
requirements and specifications applicable to the Work under the Power Purchase
Agreement and the Interconnection Agreements, and the facility shall be designed
and constructed so as to meet or exceed the PECO Test requirements.
WARRANTIES.
ENGINEERING, DESIGN AND PERFORMANCE WARRANTIES. The EPC Contractor warrants
to the partnership that:
- the Work, the facility and the engineering and design of the facility will
meet the requirements of the EPC Contract and be under applicable laws,
Applicable Insurance Policies and Good Utility Practice;
- it will use best efforts to obtain Subcontractor warranties of twenty-four
months running in favor of the partnership, and in no event will
Subcontractor warranties for engineered Equipment be for less than a
period of the greater of twelve months after the date of commercial
operation or eighteen months after the Scheduled Date of Commercial
Operation (as originally determined without any extentions otherwise
applicable to such date);
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- the performance of various Equipment will meet or exceed the performance
requirements set forth in the EPC Contract;
- the Systems will be designed and constructed so as not to interfere with
or limit the performance of the Equipment to meet the requirements set
forth in the EPC Contract; and
- the Units and the facility will meet the EPC Contract's specified
performance warranties.
EQUIPMENT WARRANTIES. The EPC Contractor warrants to the partnership that:
- all Equipment will be new, in strict accordance with specifications,
applicable laws and Good Utility Practice, free of Defects in material and
workmanship, be Year 2000 compliant and suitable for use under the
climatic and range of operating conditions as set forth in the EPC
Contract;
- the facility will be fit for the intended purposes as described in the EPC
Contract;
- it will execute, submit and otherwise fulfill all obligations connected
with Subcontractor warranty documents; and
- for the length of the warranty period set forth in the EPC Contract,
administer, litigate and process any disputes, disagreements or claims
with the person issuing such warranty concerning the breach thereof;
cooperating with and allowing the partnership to participate in all
decisions which materially affect the partnership or the operation of the
facility. The warranties of the EPC Contractor with respect to Work or
Equipment supplied pursuant to the Turbine Contract will be the same as
the warranties provided pursuant to the Turbine Contract, including the
warranty limitation set forth in the Turbine Contract concerning
"collateral damage" as defined therein, provided that if the EPC
Contractor recovers all or part of the costs of such "collateral damage"
from General Electric under any other provision of the Turbine Contract,
the EPC Contractor shall, to the extent of such recovery, be responsible
for correcting such "collateral damage."
OTHER WARRANTIES. The EPC Contractor warrants:
- during all Acceptance Testing, (A) that when operating the combustion
turbines under manufacturers' requirements, that the hourly average air
emissions for each Unit and the facility as a whole will not exceed the
values set forth in the permits attached to the EPC Contract, (B) the
facility's water discharge during operation will meet the requirements of
the EPC Contract, and (C) the operation of the Units and the facility will
meet the applicable noise emission requirements set forth in the EPC
Contract;
- the facility will be designed and completed in a manner such that
operation of the facility will not result in a revocation or suspension of
its status as an Exempt Wholesale Generator; and
- upon transfer of title, the partnership will have title to all Work free
and clear of claims and liens of all Persons (other than the interest of
the Development Authority pursuant to the offering of the bonds).
Except as otherwise provided in the EPC Contract, the EPC Contractor is
obligated for all warranties described above for each Unit for periods specified
in the EPC Contract. The warranties of General Electric under the Turbine
Contract apply to defects that appear prior to Substantial Completion and during
certain set periods specified in the Turbine Contract. Where any item of
Equipment supplied by General Electric is used with more than one Unit, the
warranty on such item is for the same period as the warranty on the Unit with
which it is first used. Subject to some overall limitations (as described below
in LIMITATION OF LIABILITIES), the Warranty Period for a Unit will be extended
on a day-for-day basis for any period of time in excess of ten days that a Unit
is not capable of operating due solely to a warranty claim attributable to
General Electric. The number of days of
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Warranty Period extension will be counted as those days in excess of ten between
(1) the date the Unit is removed from service, or unable to return to service,
solely due to a warranty nonconformity for which General Electric is
responsible; and (2) the date the corrective work is complete and the EPC
Contractor advises General Electric that the Unit is available for return to
service.
The EPC Contractor is obligated for the warranty period from the date of
Commercial Operation of the last Unit on some equipment which enters service
with the Initial Units. All partnership warranties under the Turbine Contract
will be assigned to the partnership immediately following Commercial Operation.
The warranties and remedies for each warranted item described above will be
inoperative with respect to a Defect in such warranted item if:
- such Defect in such warranted item is caused by the partnership's failure
to operate and maintain the warranted item in conformance with applicable
operating and maintenance instructions or under generally accepted
operating practices of the electric power producing industry;
- the warranted item is materially altered without the written consent of
the EPC Contractor and the alteration causes such Defect in such warranted
item; or
- the EPC Contractor requests operating and maintenance data from the
partnership with respect to a defective warranted item and the partnership
fails to provide the EPC Contractor with reasonable access to it.
The EPC Contractor shall have no warranty responsibility for:
- any repairs, adjustments, alterations, replacement or maintenance that may
be required resulting from normal corrosion, erosion or wear and tear; or
(ii)
- any Defect in a computer program or portion thereof, which has been
modified (excluding revisions typically allowed by the manufacturer)
without the written consent of the EPC Contractor.
The limitations set forth above shall not limit or modify the warranties set
forth in the Turbine Contract. With respect to all warranties and rewarranties
made by General Electric pursuant to the Turbine Contract, all of which are
incorporated by reference into the EPC Contract, the EPC Contractor has the
primary, separate and direct obligation to the partnership for such warranties
and rewarranties; provided, however, that as between the partnership and the EPC
Contractor, the EPC Contractor does not have the benefit of any conditions,
exclusions or exceptions to such warranties and rewarranties under the Turbine
Contract or the EPC Contract which arise as a result of the actions or failures
to act of the EPC Contractor (including actions or failures to act of
Subcontractors other than General Electric and Lower-tier Subcontractors),
including any breach by the EPC Contractor of the standards of performance set
forth for Buyer in the Turbine Contract or for the EPC Contractor in the EPC
Contract.
PARTNERSHIP'S RIGHT TO CURE WORK AND SET OFF. If the EPC Contractor fails,
refuses or neglects to make any required payment related to the Work or perform
any of its obligations and fails to commence in good faith and with due
diligence to remedy any such non-payment or non-performance within 72 hours
after notification, the partnership may make such payment or perform such act at
the expense of the EPC Contractor. The partnership has the right to set off any
claim of the partnership for liability of the EPC Contractor arising under the
EPC Contract against any debt or obligation of the partnership to the EPC
Contractor arising under the EPC Contract.
MECHANICAL COMPLETION; FUNCTIONAL TESTING. Mechanical Completion shall be
achieved when the EPC Contractor determines that a particular System, Unit or
Phase:
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- has been assembled, constructed or completed under the Drawings;
- has successfully passed checkout and System Testing for Mechanical
Completion (including functional testing of all components of the System)
and necessary non-performance testing;
- is sufficiently identified, including all records or other documents
pertaining to the assembly or construction of the System; and
- is ready for Functional Testing.
After the EPC Contractor notifies the partnership in writing that the
System, Unit or Phase is mechanically complete ("Notice of Mechanical
Completion"), the partnership shall set forth either (1) an indication that the
particular System, Unit or Phase appears to be mechanically complete, except for
Punch List items ("Mechanical Completion"); or (2) rejection of the particular
System, Unit or Phase as mechanically complete. Upon receipt by the EPC
Contractor of the partnership's rejection, it shall take immediate action and
proceed with due diligence and in good faith to remedy the conditions described
in such rejection. Such procedure shall be repeated until Mechanical Completion
of the facility has been achieved.
Functional Testing of a Unit or a critical System may proceed upon Notice of
Mechanical Completion of such Unit or System and verification by the partnership
that Functional Testing may proceed, provided that such critical System shall
have its control systems tested for efficient operation prior to the
commencement of such Functional Testing. Prior to the commencement of Functional
Testing, the EPC Contractor shall complete and the partnership shall approve all
written operating procedures, maintenance manuals and operator training as set
forth in the EPC Contract.
Notwithstanding the issuance of a Certificate of Mechanical Completion by
the partnership with respect to a System or a Unit, prior to Commercial
Operation, the operation and maintenance of the System or Unit shall be under
the direction and control of the EPC Contractor through the its start-up
manager. On the date on which Commercial Operation of a Unit occurs, control of
the operation and maintenance of the Unit and risk of loss to such Unit shall
transfer from the EPC Contractor to the partnership.
ACCEPTANCE TESTING. The EPC Contractor will develop specific test
procedures and submit them at least 90 days prior to the start of Acceptance
Testing to the partnership and the Independent Engineer for review and, if
necessary, revision. Before Acceptance Testing begins, each of the Unit's
systems must have achieved Mechanical Completion (with the exception of Punch
List items), and all Functional Testing must have been performed. The Unit must
also be available for normal and continuous operation, all necessary permits
must have been obtained, and each Unit's CEMS instrumentation must have been
calibrated. The partnership, the Construction Lender, the Independent Engineer,
PECO and others will be notified before Acceptance Testing begins and given the
opportunity to witness the tests.
The Acceptance Testing will entail testing by the partnership to confirm
that each Unit and the facility meet its requirements under the EPC Contract, as
well as PECO Tests to confirm that the partnership's obligations under the Power
Purchase Agreement can be met. The net power output and the net heat rate will
be measured for the entire facility, as well as for each Unit. Emissions tests
will be performed to determine whether each Unit complies with air permit
requirements.
The EPC Contractor remains liable for liquidated damages for each Unit until
that Unit passes each of the previously mentioned tests and is ready for
Commercial Operation. However, the EPC
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Contractor will not be liable for additional schedule liquidated damages for a
Unit, provided the following are satisfied:
- the EPC Contractor notifies the partnership that although the Unit has not
met the net power output and net heat rate guarantees, it passed each of
the other tests and has achieved the Interim Performance Requirements for
net power output and net heat rate;
- corrective actions and retesting of the Unit will not interfere with the
normal and continuous operation of the Unit during the 180 days after
notice; and
- the EPC Contractor immediately pays liquidated damages for any delay up to
the date of notice plus liquidated damages for performance based on the
results of the most recent tests, subject to deferral of some or all of
the performance liquidated damages to the extent that there is a deferral
of performance liquidated damages under the Turbine Contract.
Upon satisfaction of the foregoing conditions the EPC Contractor will use
all reasonable efforts to ensure that the Unit will achieve the Unit Output
Requirement and the Unit Heat Rate Requirements, while satisfying the CEMS
Requirements (1) until the Unit Output Requirement and the Unit Heat Rate
Requirements have been achieved while satisfying the CEMS Requirements and/or
(2) until the later of (a) the 181st day after notice was given and (b) the end
of the first two consecutive non-peak months after the date notice was given,
whichever occurs first (the "Retest Period"). If, by the end of the Retest
Period, the Unit satisfies the CEMS Requirements, and improvement in the net
power output and net heat rate for such Unit is achieved, the partnership is
required to refund any liquidated damages paid relating to that improvement. If,
by the 181st day, CEMS Requirements are met but the Unit Output Requirement and
Unit Heat Rate Requirements for such Unit are not, the partnership may terminate
retesting, and liquidated damages will be determined based on the most recent
test results.
The EPC Contractor is required to pay modified liquidated damages if, due to
the EPC Contractor's changes, adjustments, or retesting, a Unit is not available
to the partnership for normal and continuous operation during the Retest or any
Extension Period, except during off peak months, when the EPC Contractor will
not be required to pay such damages.
The partnership may direct the EPC Contractor to require General Electric to
continue remediation and testing activities under the Turbine Contract until the
earlier of (a) the EPC Contractor's achievement of the Unit Output Requirement
and the Unit Heat Rate Requirements and (b) the expiration of the retesting
period.
COMMERCIAL OPERATION. A Unit will not be deemed ready for Commercial
Operation unless it has satisfied the requirements of (a):
- the Unit Output Requirement and Unit Heat Rate Requirement;
- the Unit Availability Test;
- the Demonstration Tests; and
- air permit compliance requirements, as measured by CEMS instrumentation
during Acceptance Testing, and
(b) is available for normal and continuous operation and capable of delivering
the electric output of the Unit at the Interconnection Points for electric power
transmission. After a Unit achieves Commercial Operation, the partnership will
issue the EPC Contractor a certificate of Commercial Operation for that Unit.
FINAL ACCEPTANCE. Before Final Acceptance of the facility, the EPC
Contractor must demonstrate that each of the Units satisfies the Emissions Tests
and any Demonstration Tests. If any Unit fails such
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tests, the EPC Contractor will make adjustments until the partnership is
satisfied. The partnership will issue a Certificate of Final Acceptance
evidencing that all Work has been completed except for the Combustion Turbine
Evaporative Cooler Test or any Punch List items (with a total estimated cost of
less than $150,000) after:
- each Unit has achieved Commercial Operation;
- all retesting for any Unit, if applicable, is terminated;
- all requirements for all Units have been achieved; and
- the Work is complete.
COMMERCIAL OPERATION LIQUIDATED DAMAGES. The EPC Contractor is required to
pay liquidated damages ("Commercial Operation Liquidated Damages") of
(a) $40,000 per Unit, per day for the first 14 days elapsing after the Scheduled
Date of Commercial Operation for that Unit until the Unit achieves Commercial
Operation; (ii)(b) $65,000 per Unit, per day for days 15-30 after the Scheduled
Date of Commercial Operation for that Unit until the Unit achieves Commercial
Operation; and (c) $82,000 per Unit, per day for the 31st day after the
Scheduled Date of Commercial Operation for that Unit until either Commercial
Operation for the Unit is achieved. The aggregate liability of the EPC
Contractor for liquidated damages for Commercial Operation Liquidated Damages
shall not exceed 22.5% of the Guaranteed Lump Sum Price. Liquidated damages will
be offset by any net revenue received by the partnership from the applicable
Unit's operation prior to the Commercial Operation of that Unit.
The amount of Commercial Operation Liquidated Damages payable by the EPC
Contractor may be reduced if and to the extent that the delays are due to
failure by General Electric to perform under the Turbine Contact. The
methodology for computing these reductions, and the amounts of liquidated
damages provided for under the Turbine Contract that would be taken into account
in computing such reductions, are as follows:
(i)(a) The total Commercial Operation Liquidated Damages accrued by the EPC
Contractor, prior to any reduction, shall be multiplied by a fraction, the
numerator of which is the number of days of delay in which the Units do not
achieve Commercial Operation by the Scheduled Dates of Commercial Operation and
for which the performance of General Electric under the Turbine Contract is the
primary cause of such delay and the denominator of which is the total number of
days of delay in which the Units do not achieve Commercial Operation by the
Scheduled Dates of Commercial Operation (the "Turbine Portion of Commercial
Operation Liquidated Damages"). The difference, if any, between the total
Commercial Operation Liquidated Damages accrued by the EPC Contractor and the
Turbine Portion of Commercial Operation Liquidated Damages shall be the
"Non-Turbine Portion of Commercial Operation Liquidated Damages." The EPC
Contractor shall provide reasonable evidence to the partnership to support the
number of days of delay in which the Units do not achieve Commercial Operation
by the Scheduled Dates of Commercial Operation and for which the performance of
General Electric under the Turbine Contract is the primary cause of such delay.
(b) If the Turbine Portion of Commercial Operation Liquidated Damages is
less than or equal to the aggregate liquidated damages which accrue under the
Turbine Contract in the event of delay in the Delivery (as defined in the
Turbine Contract) or Shipment (as defined in the Turbine Contract) of one or
more of the Units (as defined in the Turbine Contract), or delay in achieving
Commercial Operation (as defined in the Turbine Contract) of one or more such
Units ("Schedule Liquidated Damages"), as limited by the General Electric Cap,
the EPC Contractor shall be responsible for the full amount of the Commercial
Operation Liquidated Damages.
(c) If the Turbine Portion of Commercial Operation Liquidated Damages is
greater than the aggregate Schedule Liquidated Damages which accrue under the
Turbine Contract, the Commercial
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Operation Liquidated Damages shall be reduced to an amount which is equal to the
aggregate Schedule Liquidated Damages which accrue under the Turbine Contract
and such amount shall be added to the Non-Turbine Portion of Commercial
Operation Liquidated Damages to determine the total amount of Commercial
Operation Liquidated Damages.
The total Schedule Liquidated Damages which may become due from General
Electric to the EPC Contractor under the Turbine Contract is calculated as
follows:
(a) for each full day that Shipment or Delivery (as applicable) of a Unit
occurs after the Guaranteed Date for a Unit, Twenty Thousand Dollars ($20,000)
per day per Unit for days one (1) through fourteen (14) and Forty Thousand
Dollars ($40,000) per day per Unit for days beyond the fourteenth (14th) day;
plus
(b) for each full day that General Electric's failure to comply with the
requirements of the Turbine Contract is the primary cause of one or more days
that a Unit does not achieve Commercial Operation by the Scheduled Date of
Commercial Operation for such Unit, Thirty Thousand Dollars ($30,000) per day
for days one (1) through fourteen (14) and Fifty Thousand Dollars ($50,000) per
day for days beyond the fourteenth (14th) day.
In addition to the foregoing Schedule Liquidated Damages, if, despite the
efforts of the EPC Contractor to mitigate the effects of late Shipment or
Delivery, late Shipment or Delivery of a Unit is the primary cause of a delay of
any day the Unit does not achieve Commercial Operation by the Scheduled Date of
Commercial Operation for such Unit (excluding the first thirty (30) days of late
Shipment or Delivery which are deemed to have no effect on the achievement of
Commercial Operation), General Electric will pay additional Schedule Liquidated
Damages to the EPC Contractor under the higher schedule of damages set forth in
(b) above, except that in determining the amount of any additional Schedule
Liquidated Damages for delay after the first thirty (30) days, the liquidated
damages paid by General Electric under (a) with respect to each day of delay
shall reduce the amount of liquidated damages due for such corresponding day of
delay in achieving Commercial Operation.
The obligations of General Electric to pay Schedule Liquidated Damages for
delay of Commercial Operation are contingent upon: General Electric having a
minimum time period of thirty-one (31) days after each of Units #1, #4, #5 and
#6 is Mechanically Complete and twenty-seven (27) days after each of Units #2
and #3 is Mechanically Complete for inspecting the Unit and its installation,
the performance of pre-testing, startup, commissioning, correction of discovered
problems, tuning, verification that the Unit is in proper adjustment and
condition to begin Acceptance Testing and the performance of Acceptance Testing
by the EPC Contractor (extended for any time periods when General Electric
reasonably needs to perform services or tests on a Unit and does not have access
and availability to such Unit consistent with the Contractor's EPC project
schedule), provided that General Electric must notify the EPC Contractor, in
writing, if General Electric believes that it has not had the access to such
Unit which it reasonably needs and the EPC Contractor has 24 hours in which to
cure the problem by providing access to General Electric. If, prior to
Commercial Operation of a Unit, General Electric recommends repair activities
for a Unit which the EPC Contractor has the responsibility to perform, General
Electric will not be charged for liquidated damages for delay in achieving
Commercial Operation of the Unit for any period of time which is longer than the
normal period of time which would be required to accomplish such repairs or for
any period of time after such repairs are completed which is longer than
reasonably necessary to prepare the Unit for testing or retesting.
PERFORMANCE LIQUIDATED DAMAGES. Each Unit must produce and deliver for sale
the Commercial Operation Output, or the EPC Contractor will be subject to $300
per KW in liquidated damages for each KW that net power output of a Unit is less
than 156,410 KW as measured in the most recent Performance Test. For the
purposes of final determination of Commercial Operation Output liquidated
damages, the Commercial Operation Output of the six Units will be aggregated,
and the EPC
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Contractor will be subject to liquidated damages of $300 per KW for each KW that
the aggregate is less than 938,460 KW.
Each Unit must operate at the Commercial Operation Net Heat Rate or less, or
the EPC Contractor will be subject to liquidated damages of $5,860 per BTU/KW-HR
for each BTU/KW-HR that Commercial Net Heat Rate exceeds 10,683 BTU/KW-HR (HHV)
when operating on natural gas plus $950 per BTU/KW-HR for each BTU/KW-HR that
Commercial Net Heat Rate exceeds 10,821 BTU/KW-HR (HHV) when operating on fuel
oil as measured in the most recent Performance Tests. Final determination of
Commercial Net Heat Rate liquidated damages will be based upon the average
Commercial Net Heat Rate of all six Units.
FURTHER LIMITATIONS. The EPC Contractor warrants the net power output of
the facility will be at least 891,540 KW and the net heat rate of each Unit will
be less than 11,217 BTU/KW-HR (HHV) when operating on natural gas and 11, 362
BTU/KW-HR (HHV) when operating on fuel oil (the "Performance Minimums"). If the
six Units attain the Performance Minimums, liquidated damages are the
partnership's sole remedy. The maximum liability of the EPC Contractor for
liquidated damages for Performance Liquidated Damages is capped at 22.5% of the
Guaranteed Lump Sum Price.
The aggregate amount of Commercial Operation Liquidated Damages and
Performance Liquidated Damages under the EPC Contract is capped at a maximum of
30% of the Guaranteed Lump Sum Price. The EPC Contractor is not liable to the
partnership for replacement power, or for any consequential, indirect, special
or incidental damages in connection with the EPC Contract except for:
- willful misconduct, gross negligence or fraud by the EPC Contractor or any
Subcontractor;
- tortious interference by the EPC Contractor or any Subcontractor; and
- third party claims for personal injury, death or damage to property,
including strict liability or tort liability.
The partnership is not liable to the EPC Contractor or any Subcontractor for any
losses or damages caused by loss of profit or any consequential damages in
connection with the EPC Contract. The EPC Contractor's total liability for
damages resulting from performance or breach of the EPC Contract are capped at
the Guaranteed Lump Sum Price.
INSURANCE. The EPC Contractor's insurance certificates and underlying
policies required or purchased pursuant to the EPC Contract must provide
30 days advance written notice be given to the partnership and the Construction
Lender before any material change in, termination or cancellation of any
insurance policy. From the date on which the Work is to commence until the Date
of Commercial Operation of the Final Units, the EPC Contractor and all
Subcontractors must maintain and provide the required insurance coverages.
The EPC Contractor is required to maintain the following insurance policies
at all times while performing the Services: Worker's Compensation, Commercial
General Liability, Comprehensive Automobile Liability, and Excess Umbrella
Liability. The partnership will maintain and provide All Risk Builders' Risk
insurance.
Prior to any transfer of risk of loss to the partnership, the partnership is
not accountable or responsible for any loss or damage to any part of the
facility, facility site or the Work, except for: (1) the partnership's
intentional, wrongful or negligent acts, and (2) "collateral damage" as defined
in the Turbine Contract caused by Equipment supplied by General Electric under
the Turbine Contract which is not covered by insurance and for which General
Electric is not responsible, and then only to the extent such loss or damage is
not covered by the All Risk Builders' Risk policy. Except for the All Risk
Builders' Risk insurance and Ocean/Transit/Air insurance, prior to Commercial
Operation, all risk of loss or damage to the Units will be borne by the EPC
Contractor. On the date of Commercial
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Operation of a Unit, the partnership will assume the risk of loss or damage to
that Unit. On the date of Commercial Operation of the final Unit, the
partnership will assume the risk of loss or damage to the facility, facility
site, and the Work.
FORCE MAJEURE. A "Force Majeure Event" means any act or event that prevents
or delays the affected party from performing its obligations (other than the
payment of money) under the EPC Contract, or complying with any conditions
required to be complied with under the EPC Contract if such act or event is
beyond the control of and not the fault of the affected party or any
Subcontractor, and the affected party has been unable by the exercise of due
diligence to overcome or mitigate the effects of such act or event.
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; PROVIDED that:
- the non-performing party gives the other party prompt notice, describing
the particulars of the occurrence and when the party anticipates it will
be able to resume performance;
- the suspension of performance is of no greater scope and of no longer
duration than is reasonably required by the Force Majeure Event;
- the non-performing party uses all reasonable efforts to limit delays and
remedy the inability to perform during and after the Force Majeure Event;
- when the non-performing party is able to resume performance of its
obligations, that party gives the other written notice and promptly
resumes performance; and
- unless the Force Majeure Event proximately causes a change in the ability
of the EPC Contractor to achieve Commercial Operation by the Scheduled
Date of Commercial Operation, there will be no extension of the Scheduled
Date of Commercial Operation.
If an Excusable Delay under the Turbine Contract causes a delay in delivery,
for which General Electric is not liable, the EPC Contractor will not be liable
for the same delay in delivery.
A time extension will be granted in such instance, PROVIDED that the EPC
Contractor promptly notifies the partnership, the delay is beyond the control of
the EPC Contractor, and was not caused by an act or failure to act by the EPC
Contractor, its employees, agents or Subcontractors.
If one or more Force Majeure Events cause more than 45 aggregated days of
delay, the partnership shall reimburse the EPC Contractor, beginning with the
46th day for its out-of-pocket costs actually and necessarily incurred,
including demobilization, remobilization, insurance, stand-by and escalation
costs. The partnership retains all rights to terminate the EPC Contract.
INDEMNIFICATION. The EPC Contractor shall defend, protect, indemnify, and
hold harmless the partnership, the partners, Construction Lender, Independent
Engineer and PECO, their stockholders, officers, directors, agents, servants,
employees, and others (the "Indemnitees") from and against any damages, losses
or expenses arising in favor of any person arising from claims and/or causes of
action of every kind and character. However, no Indemnitee shall be indemnified
for damages, losses or expenses arising out of the negligence of that
Indemnitee.
The EPC Contractor shall indemnify and hold the partnership harmless from
and against any and all loss, cost, expense, liability and damage incurred by
the partnership arising from Subcontractor liens or Lower-tier Subcontractor
liens filed against the facility site.
The EPC Contractor is not obligated to indemnify the partnership for any
infringement, actual or alleged, attributable to any Equipment supplied, or
services rendered by General Electric beyond the obligation of General Electric
to indemnify the EPC Contractor.
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AUTHORIZATION TO PROCEED. The authorization to proceed, given to the EPC
Contractor on November 10, 1999, grants the EPC Contractor the authority to
proceed with performance (the "Authorization to Proceed").
Solely for the purpose of determining the Scheduled Date of Commercial
Operation for any Unit and dates for the partnership's obligation pursuant to
the EPC Contract, the Authorization to Proceed Date shall be deemed to be the
later of: (1) the date on which the Authorization to Proceed was actually
delivered to the EPC Contractor, and (2) 113 days after September 10, 1999 (the
date on which the Limited Notice to Proceed was delivered to the EPC
Contractor).
TERMINATION
TERMINATION SUBSEQUENT TO AUTHORIZATION TO PROCEED. Following the issuance
of the Authorization to Proceed, the partnership may terminate the EPC Contract
for convenience. Termination, for any reason other than the EPC Contractor's
default (as described below), entitles the EPC Contractor solely to receive
reimbursement from the partnership of an amount equal to the sum of:
(1) that portion of the Guaranteed Lump Sum Price applicable to the Work
performed to the date of termination which has not been previously paid
(including applicable Retainage)
(2) the reasonable out-of-pocket costs actually and necessarily incurred by
the EPC Contractor in withdrawing its equipment and personnel from the
facility site and
(3) the actual, reasonable and necessary costs incurred by the EPC
Contractor in terminating those contracts, not assumed by the
partnership, with Subcontractors pertaining to the Work.
TERMINATION BY PARTNERSHIP ON EPC CONTRACTOR'S DEFAULT. The EPC Contractor
is in default if it:
(a) fails to timely perform the Work;
(b) fails to supply enough properly skilled workers, or proper materials or
Subcontractors to timely perform the Work;
(c) fails to make payment (not reasonably in dispute) to Subcontractors for
materials or labor under their agreements pertaining to the Work, unless
the subject of a reasonable dispute and no resulting liens are filed;
(d) is in violation or breach of any applicable laws or Applicable Insurance
Policies;
(e) fails to comply promptly with rejection notices or notices to correct
Defects;
(f) causes or permits any repudiation, lapse or cancellation of performance
security;
(g) fails to commence Work promptly following Authorization to Proceed;
(h) assigns the EPC Contract in violation of the terms of the EPC Contract;
(i) fails to pay liquidated damages when due; or
(j) otherwise materially breaches the EPC Contract.
If the EPC Contractor (1) does not cure any default under (a) through (j)
above within thirty (30) days after notice or, if the default is such that it
cannot be cured within such period of time and the EPC Contractor does not
promptly commence and diligently pursue action which is calculated to cure such
default within a reasonable period of time and achieve such cure within ninety
(90) days after such notice or (2) fails to achieve Commercial Operation within
one hundred eighty (180) days after the Scheduled Date of Commercial Operation,
the partnership has right to terminate the EPC Contract.
Whenever the EPC Contract is terminated for the EPC Contractor's default,
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(1) the partnership may, without prejudice to any other rights or remedies,
(a) take possession of the facility site, the Equipment, and all other
materials for use by the partnership to complete the Work, (b) mandate
assignment by the EPC Contractor of other contracts or subcontracts to
the partnership or its designee for Work, and (c) finish the Work by
whatever reasonable method the partnership, in its absolute discretion,
deems expedient,
(2) the EPC Contractor shall not be entitled to receive further payment and
(3) the EPC Contractor shall also be liable to the partnership for the
additional costs of debt service (from and after the date of
termination), plus all costs and expenses reasonably incurred and damages
sustained (subject to some exceptions set forth in the EPC Contract) by
the partnership.
TERMINATION FOR INSOLVENCY BY EITHER PARTY. Either party may terminate the
EPC Contract by written notice to the other party if particular events of
bankruptcy occurs, as described in the EPC Contract.
SUSPENSION BY EPC CONTRACTOR. If the partnership fails to timely pay the
EPC Contractor any undisputed amounts due pursuant to the terms of the EPC
Contract following receipt of written notice, and fails to remedy such default
within fifteen (15) days from the receipt of such notice, the EPC Contractor has
the right to suspend the Work. If the EPC Contractor elects to suspend the Work
and such suspension is subsequently removed and the Work is continued by the EPC
Contractor, the Guaranteed Lump Sum Price will be increased by an amount equal
to the increase, if any, in the reasonable and necessary cost actually incurred
by the EPC Contractor. If the EPC Contractor suspends performance of Work, the
Scheduled Date of Commercial Operation shall be extended on a day-for-day basis
by Change Order for the number of days of delay caused by the suspension. The
partnership shall have the right to cure at any time during suspension,
provided, however, if the partnership has not cured such default within
seventy-five (75) days after such suspension, the EPC Contractor has the right
to terminate the EPC Contract. In such an event, the EPC Contractor shall be
paid the reasonable and necessary costs actually incurred and resulting directly
from such suspension by the EPC Contractor, but only to the extent that such
costs are over and above those incurred and included in the Guaranteed Lump Sum
Price, plus those amounts described above as being available to Contractor in
the event of a termination by the partnership subsequent to the Authorization to
Proceed. The EPC Contractor shall also remain subject to the various obligations
as provided in the EPC Contract.
TERMINATION BY EPC CONTRACTOR. If the partnership fails to timely pay the
EPC Contractor any undisputed amounts due pursuant to the terms of the EPC
Contract following receipt of written notice, and fails to remedy such default
within thirty (30) days from the receipt of such notice, the EPC Contractor has
the right to terminate the EPC Contract.
SUSPENSION OF WORK. The partnership has the right (without prejudice to its
other right to terminate the EPC Contract) to suspend Work for convenience upon
giving seven days prior notice to the EPC Contractor ("Suspension Notice")
following the issuance of the Authorization to Proceed or any Limited Notice to
Proceed. Seven days after receipt of a Suspension Notice, the EPC Contractor
shall suspend performance of all Work and notify Subcontractors of such
suspension, and the Scheduled Date of Commercial Operation will be extended on a
day-for-day basis by Change Order for the number of days of delay caused by such
suspension.
During such suspension period (which begins seven days after the receipt of
the Suspension Notice), the partnership and the EPC Contractor:
(1) shall not be required to take further action regarding performance,
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(2) shall cooperate in good faith to maintain the commitments of
Subcontractors and Lower-tier Subcontractors, and
(3) the EPC Contractor shall not incur any obligation or liability, whether
financial, performance or otherwise for which the partnership shall be
liable.
ASSIGNMENT. The partnership may assign any or all of its rights under the
EPC Contract to an Affiliate of Tenaska, Inc. or an entity in which an Affiliate
of Tenaska, Inc. has an ownership interest, provided such assignee has adequate
resources (as determined by the EPC Contractor in the exercise of its reasonable
judgment) to fulfill those obligations of the partnership which are assigned,
and any defaults of the partnership existing at such time are cured.
Notwithstanding any provision in the EPC Contract to the contrary, the
partnership and the partnership's assignee, if applicable, have the absolute
right, without the consent of the EPC Contractor, to assign the EPC Contract or
any rights reserved by the partnership after assignment, to the Collateral Agent
and its successors for collateral security purposes.
All subcontracts shall be written and assignable to the partnership without
the need for the Subcontractors' consents.
If the EPC Contract is suspended or terminated, the partnership has the
right to require the EPC Contractor to assign all of the EPC Contractor's
rights, titles, and interests in and to any of the EPC Contractor's outstanding
subcontracts. The EPC Contractor may not assign any benefits or obligations
under the EPC Contract, nor may it assign the Turbine Contract without the
partnership's prior written consent.
LIMITATION OF LIABILITIES. To the extent that General Electric is excused
from liability with respect to any Unit (as defined in the Turbine Contract),
the EPC Contractor shall also be excused from liability with respect to such
Unit after the occurrence of various events or after the date specified in the
Turbine Contract, provided that the foregoing shall not excuse the EPC
Contractor with respect to any liability which arises out of the acts or
omissions of the EPC Contractor, Subcontractors (other than General Electric) or
Lower-tier Subcontractors under the EPC Contract.
Notwithstanding any provision to the contrary in the EPC Contract, the EPC
Contractor shall not be liable to the partnership for consequential damages of
any kind arising from the acts or omissions of, or breach of contract by,
General Electric under the Turbine Contract to the extent that General Electric
is not liable to the EPC Contractor for such consequential damages under the
Turbine Contract.
PARTNERSHIP RESERVED RIGHTS UNDER THE TURBINE CONTRACT.
SCOPE OF WORK. The EPC Contractor, with the written agreement of the
partnership, shall reject any nonconforming or defective Equipment supplied
under the Turbine Contract and require correction, repair or replacement of such
Equipment by General Electric, provided that the partnership shall have the
right to direct the EPC Contractor to reject any nonconforming or defective
Equipment supplied under the Turbine Contract and to direct the EPC Contractor
to require correction, repair or replacement of such Equipment by General
Electric. The EPC Contractor shall not change or amend the Turbine Contract,
without the written consent of the partnership. The partnership and the EPC
Contractor will cooperate with each other in connection with the assignment of
rights under the Turbine Contract to the EPC Contractor so as to permit the
partnership to retain such rights in the Turbine Contract as are necessary such
that no sales or use tax is required to be paid upon the purchase of the
Equipment supplied under the Turbine Contract, and for such purpose the
partnership and the EPC Contractor will take such actions as are reasonably
necessary to obtain such result, including providing for the transfer of title
to any Equipment supplied under the Turbine Contract
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directly from General Electric to the partnership and the remittance of payments
for all Equipment under the Turbine Contract directly by the partnership to
General Electric.
GUARANTEED LUMP SUM PRICE AND PAYMENT. At the request of the partnership,
the EPC Contractor shall dispute amounts otherwise due to General Electric under
the Turbine Contract under the rights of Buyer set forth in the Turbine Contract
and, as between the partnership and the EPC Contractor, the partnership shall
have the same right to withhold payment to General Electric as is provided to
Buyer in the Turbine Contract and shall not, as a result of withholding such
payments, be in breach of the EPC Contract.
CHANGE ORDERS. The partnership has the right to negotiate directly with
General Electric regarding the approval of any Change Order issued under the EPC
Contract, to the extent that such Change Order affects the Equipment or services
furnished under the Turbine Contract.
TERMINATION BY THE EPC CONTRACTOR; SUSPENSION OF THE TURBINE CONTRACT. In
the event the EPC Contractor terminates the EPC Contract, it shall give the
partnership fifteen days' notice of its intent to terminate the Turbine
Contract. If the partnership does not require the EPC Contractor to assign the
Turbine Contract to the partnership within such period, the EPC Contractor has
the right to terminate the Turbine Contract. Upon such termination, the
partnership will pay to General Electric any amounts due to General Electric
pursuant to the Turbine Contract, subject to compliance with the procedures set
forth in the EPC Contract.
O&M AGREEMENT
PARTIES. The parties to the O&M Agreement are the partnership and the
Operator.
OVERVIEW. The O&M Agreement provides for initial startup support during
turnover, testing, operation, maintenance and management of the facility and the
performance of other defined services by the Operator. The partnership has
agreed to pay the Operator a possible incentive fee, a fixed management fee and
an availability adjustment fee.
TERM AND TERMINATION. Unless sooner terminated, the primary term of the O&M
Agreement is 29 years from the Date of Commercial Operation.
SCOPE OF SERVICES. During the pre-Commercial Operating Period, the Operator
has agreed, among other things, to:
- Provide the services of a plant manager and a project manager;
- Review the EPC Contractor's planning and facility engineering design with
regard to facility reliability, availability and maintainability and
review design manuals, system descriptions, tool lists, spare parts lists,
training programs, and operation methodology of the facility;
- Prepare the pre-commercial operating budget 9 months prior to the
scheduled date of Power Purchase Agreement Commercial Operation;
- Perform routine maintenance and scheduled maintenance actions on facility
systems and equipment as they are turned over to the Operator;
- Prepare a maintenance plan for the facility to include planning for
scheduled outages, handling of forced outages, preventive and predictive
maintenance philosophy;
- Prepare lists of the initial inventory of tools and spare parts to be
purchased for maintenance and repair of the facility and its equipment;
- Recruit, hire, transfer, or otherwise obtain qualified personnel; and
- Procure, for the account of the partnership, all materials, equipment,
chemicals, supplies, services, and parts required for daily operation and
maintenance of the facility under the partnership-approved pre-commercial
operating budget.
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During the Commercial Operating Period, the Operator has agreed, among other
things, to continue applicable services of the Pre-Commercial Operating Period
and to:
- Prepare annual operating budgets under the O&M Agreement. Report to the
partnership monthly on the status of the operating budget and process
budget variance reports, as required. To the extent that the Operator has
the information, the Operator will meet the requirements of the
partnership for providing information to the Senior Parties regarding the
operation of the facility as set forth in the Common Agreement;
- Perform or arrange for all maintenance required on all facility systems
and equipment;
- Arrange for scheduled inspections and overhauls on major equipment items
under the Long Term Service Agreement and other maintenance schedules;
- Prepare and submit periodic reports relative to daily operation and
maintenance of the facility including environmental compliance records,
maintenance and repair status, facility operating data, and any other
information reasonably requested by the partnership; and
- Comply with all applicable laws.
REPORTS. The Operator is required to submit to the partnership, on a
monthly basis, reports on (a) the hourly, daily and weekly electric energy
generated and exported from the facility; (b) the hourly, daily and weekly fuel
consumption; (c) daily and weekly reports on makeup water received and pipeline
status; and (d) weekly and monthly consumption of chemicals for water treatment
plant. Tenaska Operations is also required to submit to the partnership, on a
monthly basis performance test results, emission data in support of federal and
state and local reporting requirements, wastewater effluent data in support of
federal, state and local permits, maintenance reports, and any other report
regarding the operation of the facility reasonably requested by the partnership
or required by the Power Purchase Agreement.
FACILITY MAINTENANCE. Within 90 days after Commercial Operation, the
Operator, with the approval of the partnership, will furnish PECO with a
long-term preventative maintenance program for each major item of equipment
constituting a part of the facility. This maintenance program can be altered,
with the approval of the partnership, from time to time by reason of later
manufacturers' releases pertaining to major items of equipment of the facility
and facility operating experience.
BUDGET. Ninety days prior to the scheduled date of Power Purchase Agreement
Commercial Operation and after the date of commercial operation and at least
120 days prior to the effective date of each annual budget, the Operator will
submit to the partnership, for approval, a budget, which will include the
information required by the Common Agreement. The budget will be for all
reimbursable costs to be incurred in the operation of the facility. The
partnership and the Operator will use all reasonable efforts to resolve all
budget differences. If, with respect to any operating year, the partnership and
the Operator do not resolve all budget differences, the most recently approved
operating budget (escalated by three and one-half percent (3.5%)), without
regard to amounts budgeted for extraordinary or non-recurring items, but
including all costs for the Long Term Parts and Long Term Service Contract and
all contingency funds, will be applicable until an operating budget is approved
for such operating year.
COMPENSATION. During the Pre-Commercial Operating Period, the Operator will
invoice the partnership the amount of $75,000 to cover all costs of overhead
during the Pre-Commercial Operating Period. In addition, during the Commercial
Operating Period (other than calendar year 2003), the partnership will pay to
the Operator an annual fixed management fee of $225,000 (subject to escalation)
at the rate of $18,750 per month.
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During or prior to the Pre-Commercial Operating Period, the partnership and
the Operator will mutually agree upon the incentive criteria for the Operator to
earn an incentive fee during the pre-Commercial Operating Period. The maximum
value of the incentive fee during the Pre-Commercial Operating Period is
$75,000. Annually during the Commercial Operating Period, the Operator can earn
an incentive fee to be paid on the basis of the partnership's assessment of the
Operator's performance against mutually agreed upon incentive criteria. The
maximum value of the incentive fee to be earned for the first full year of the
Commercial Operating Period and each subsequent year of the O&M Agreement is
$100,000 for each such period. The incentive fee will be invoiced at 5% each
month and if 60% of the incentive fee is not earned in any year, then the
unearned portion shall be returned to the partnership.
An availability adjustment will be paid for each contract year during the
Commercial Operating Period. The availability adjustment will vary with the
Operator's performance in maintaining the annual availability percentage for the
facility during the contract year and may result in a payment being made to the
Operator or by the Operator. The annual availability percentage for the contract
year is determined based on the availability percentage under the Power Purchase
Agreement, with some adjustments.
TERMINATION. The partnership may terminate the O&M Agreement upon the
occurrence of set events including, but not limited to, the sale or other
disposition of the facility, material defaults or violations of law and various
bankruptcy events. Tenaska Operations may terminate the O&M Agreement in the
event that the partnership becomes bankrupt, fails to pay amounts when due, or
for a material breach. Payment defaults are to be remedied within 15 days and
non-payment defaults are to be remedied within 15 days unless a longer period is
reasonable.
If a project agreement is terminated and the partnership elects to terminate
the operation of the facility, it may do so on 30 days notice to the Operator
and payment of the Operator's direct costs reasonably incurred in withdrawing
personnel and damages, attorney fees and expenses reasonably incurred in
terminating contracts entered into by the Operator.
The Tenaska Operations may elect to terminate the O&M Agreement if 20% or
more of equity interest in the partnership is transferred during any 6 month
period of the O&M Agreement or an affiliate of Tenaska, Inc. ceases to be the
managing partner of the partnership.
ASSIGNMENT. Other than the partnership's assignment to the Collateral
Agent, neither party will assign its interest in the O&M Agreement without the
prior consent of the other. If the Operator obtains the partnership's consent to
assignment, a full release will be given.
GOVERNING LAW. The O&M Agreement is governed by the law of the State of
Georgia, excluding conflict of law rules that may call for the law of another
jurisdiction to be applied.
GEORGIA POWER INTERCONNECTION AGREEMENT
PARTIES. The parties to the Georgia Power Interconnection Agreement are the
partnership and Georgia Power.
OVERVIEW. The Georgia Power Interconnection Agreement (the "Georgia Power
Interconnection Agreement") provides for the direct interconnection of the
partnership's electric generation facilities with the Georgia Integrated
Transmission System. The Georgia Integrated Transmission System is a contractual
joint use arrangement applicable to the transmission systems owned by Georgia
Power, Georgia Transmission Corp. and two other owners of electric transmission
systems in Georgia. The term of Georgia Power's participation in Georgia
Integrated Transmission System will end in 2012 if either Georgia Power or
Georgia Transmission Corp. gives notice of termination, and such term can end
prior to or after such date upon the occurrence of an insolvency of, or default
by, either Georgia
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Power or Georgia Transmission Corp.. The point of interconnection
("Interconnection Point") on the Georgia Integrated Transmission System is on a
part of the Georgia Integrated Transmission System that is owned by Georgia
Transmission Corp.
TERM AND TERMINATION. The Georgia Power Interconnection Agreement continues
for an indefinite term, and is subject to termination by mutual agreement of the
parties, through regulatory proceedings before the Federal Energy Regulatory
Commission, or by either party to the Georgia Power Interconnection Agreement if
the other party has breached any of its material obligations and has not cured
(or begun taking diligent actions to cure) such breach within thirty days
following written notice of such breach. In addition, Georgia Power could
disconnect the facility in the event of a breach by the partnership of the
material terms and conditions of the Georgia Power Interconnection Agreement, in
the event that any representation or warranty made by the partnership under the
Georgia Power Interconnection Agreement shall prove false or misleading, or if
the partnership should become the subject of insolvency proceedings.
INTERCONNECTION. The partnership is responsible for the design, procurement
and installation of the facilities necessary for Georgia Power to provide
interconnection service to the partnership (the "Interconnection Facilities").
As a consequence of the Georgia Power Interconnection Agreement, the scope of
work by the EPC Contractor has been amended by a change order to include the
design, procurement and installation of these Interconnection Facilities. The
Georgia Power Interconnection Agreement requires that such facilities conform to
Good Utility Practices, defined as the practices, methods and acts engaged in or
approved by a significant portion of the electric utility industry or any other
practices, methods and acts which, in the exercise of reasonable judgment in the
light of facts known at the time a decision was made, could have been expected
to accomplish the desired result at a reasonable cost consistent with good
business practices, reliability, safety and expedition and that such facilities
conform to the requirements of Georgia Power's transmission system. Prior to
commercial operation of the facility, the partnership is required to convey such
facilities to Georgia Power at no cost. In the event that Georgia Power incurs
any tax liability as a result of such transfer, the partnership is required to
reimburse Georgia Power for the amount of such liability.
Georgia Power's obligations under the Georgia Power's Interconnection
Agreement are dependent upon its securing and retaining necessary easements and
similar rights, as well as permits and equipment, for meeting its obligations,
and Georgia Power is obligated only to use reasonable efforts to secure and
obtain these rights, permits and equipment. The partnership is required to
reimburse Georgia Power for all costs and expenses incurred by Georgia Power in
connection with the planning, design, construction, installation, testing,
inspection, ownership, operation and maintenance of the Interconnection
Facilities.
COSTS. The partnership is required to reimburse Georgia Power for all costs
and expenses incurred by or on behalf of Georgia Power in connection with its
activities with respect to the Interconnection Facilities. Georgia Power is
required to develop and provide to the partnership an estimate of all such
costs. Georgia Power is required to obtain the partnership's consent prior to
proceeding with the planning, construction and installation of the
Interconnection Facilities. Such costs are trued-up periodically after the
actual costs and expenses are known, but not less often than annually. The
partnership is required to reimburse Georgia Power monthly for one-twelfth of
the estimated annual costs of operating and maintaining the Interconnection
Facilities, and such estimate would be trued-up within a reasonable period of
time after actual costs and expenses are known, but not less often than
annually. In addition, the partnership is responsible for any cost incurred by
Georgia Power as a result of any disconnection or reconnection caused by the
partnership's negligence or by force majeure. Also, the partnership is required
to pay Georgia Power a monthly administration charge of $5,000 per month, and
Georgia Power reserves the right to seek a revision of this amount through a
filing with the Federal Energy Regulatory Commission.
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RIGHTS OF WAY AND ACCESS. The facility site is contiguous to the
Interconnection Point on the Georgia Integrated Transmission System. The
partnership is required to convey to Georgia Power any and all necessary rights
of way and easements for the purpose of providing interconnection service under
the Georgia Power Interconnection Agreement. Tenaska is also required to convey
to Georgia Power such rights of way for transmission and distribution lines and
easements for such transformer substations across the partnership's property as
may be required for rendering service to the partnership and to others who may
economically be served from such lines and substations, provided that such
conveyance does not materially and adversely affect the partnership's use of its
property.
TEMPORARY DISCONNECTION OF PARTNERSHIP'S FACILITIES. Georgia Power could
direct that the facility be temporarily disconnected from the Georgia Integrated
Transmission System
(1) during an Emergency, defined as a condition or situation associated
with the transmission and distribution of electricity, including voltage
abnormalities, that, in the sole reasonable judgment of Georgia Power,
adversely affects or is eminently likely to adversely affect: (A) public
health, life or property; (B) Georgia Power's employees, agents or property;
or (C) Georgia Power's ability to maintain safe, adequate, and continuous
electric service to its customers and the customers of any member of the
North American Electric Reliability Counsel;
(2) the operation and output of the facility do not comply with the
terms of the Georgia Power Interconnection Agreement (whether or not the
partnership has commenced actions to cure such non-compliance);
(3) if a hazardous condition exists on the facility site or in the
facility's equipment that could reasonably be expected to adversely affect
the safe and reliable operation of the Georgia Integrated Transmission
System;
(4) if the partnership has modified the interconnection equipment or
interconnection protective devices in a manner that could reasonably be
expected to adversely affect the safe and reliable operation of the Georgia
Integrated Transmission System;
(5) if Georgia Power determines it is necessary to temporarily
disconnect the facility in order to perform work on or inspect or test any
part of the Interconnection Facilities or the Georgia Integrated
Transmission System;
(6) in the event of tampering with or unauthorized use of, Georgia Power
equipment or
(7) if the partnership fails to pay in full the undisputed amounts
billed by Georgia Power under the Georgia Power Interconnection Agreement.
OPERATION AND MAINTENANCE. Following commencement of commercial operation
of the facility, Georgia Power shall be responsible for determining the need
for, design, construction, installation, operation, maintenance and testing of
any equipment that may be required for interconnection service in a manner
consistent with Good Utility Practices.
The partnership is required to operate and maintain the facility under Good
Utility Practices and to comply with various fire and safety codes and other
applicable code requirements in the same manner as required by Georgia Power for
generating plants owned and operated by Georgia Power. In addition, the
partnership is required to comply with various interconnection procedures to be
attached as Appendix A to the Georgia Power Interconnection Agreement in the
same manner as required for generating plants owned or operated by Georgia
Power.
The partnership is responsible for ensuring that its actual generation
matches its scheduled delivery, on an integrated hourly basis, to the Georgia
Integrated Transmission System at the Interconnection Point. The Georgia Power
Interconnection Agreement requires that the partnership make arrangements for
the supply of energy and/or capacity when there is a difference between actual
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generation and the scheduled delivery. However, generator backup service
arrangements will not be required if the facility is "electrically located" in a
control area other than Southern Companies' control area. In addition, the
partnership is not required to make arrangements for generator backup services
as contemplated by the Georgia Power Interconnection Agreement if generator
backup service is offered under the Southern Companies' Open Access Transmission
Tariff and each transmission customer receiving electric power from the facility
is required by Federal Energy Regulatory Commission to purchase such service.
Under the Power Purchase Agreement, PECO is responsible for scheduling
deliveries of generation from the facility and for arranging for any required
generator back-up services. PECO, as the party arranging for transmission of
electricity generated by the facility, would determine in which control area the
facility is electrically located.
CREDIT SUPPORT. The partnership is obligated to maintain a letter of credit
for Georgia Power's benefit during the term of the Georgia Power Interconnection
Agreement in the amount of $100,000 or other acceptable credit support as
security for the partnership's obligations under the Georgia Power
Interconnection Agreement.
REPRESENTATIONS AND COVENANTS. The Partnership is required to represent,
among other things:
- that it is a duly organized and validly existing Delaware limited
partnership;
- that the Georgia Power Interconnection Agreement has been duly authorized
by all necessary action and does not require any additional consent or
approval;
- that the execution and delivery of the Georgia Power Interconnection
Agreement, does not conflict and shall not conflict with any other
agreement;
- that the Georgia Power Interconnection Agreement is a binding obligation
of the partnership; and
- that there is no pending or threatened litigation against the partnership
which purports to affect the Georgia Power Interconnection Agreement.
In addition, the partnership covenants (i)(1) that at all times during the
Georgia Power Interconnection Agreement, it will pay all charges, taxes and fees
assessed against the facility or against the partnership through Georgia Power
by reason of the sale or purchase of electricity by the partnership and (2) that
it will maintain various specified insurance.
FORCE MAJEURE. The parties are excused from performing their obligations
under the Georgia Power Interconnection Agreement and are not liable for damages
to the extent that they are unable to perform or are prevented from performing
by Force Majeure, which includes circumstances that are beyond the reasonable
control of the affected party and are not caused by such party's fault; provided
that Force Majeure does not include the inability to meet a legal requirement or
the change in a legal requirement or a site specific strike or other labor
dispute. The affected party is required to use its reasonable best efforts to
remedy its inability to perform as soon as practical and to resume performance
of its obligations as soon as reasonably practicable following cessation of the
force majeure event.
INDEMNIFICATION. The partnership is required to indemnify Georgia Power and
some related parties against all injury or damage resulting from:
(1) defects or events on the partnership's side of the Interconnection
Point;
(2) negligence (including strict liability) or intentional wrongful acts or
destruction of GPC's Georgia Power's and certain some related party's
property by the partnership, its agents or representatives;
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(3) misuse, damage or destruction to Georgia Power (and some related
parties' property by the partnership, its agents or representatives,
whether or not such damage or loss resulted from concurrent or
contributory negligence of the indemnified persons); and
(4) any claims, actions and liability arising from damage or injury to
property or person due in whole or in part to the installation,
maintenance or operation of any electrical equipment on the partnership's
premises or arising out of or in any way connected with the service
furnished or to be furnished to the partnership.
Georgia Power agrees to indemnify the partnership and some related parties
against loss or damage incurred by the sole negligence of Georgia Power in
performing its obligations under the Georgia Power Interconnection Agreement or
Georgia Power's failure to abide by the provisions of the Georgia Power
Interconnection Agreement.
LIMITATION OF LIABILITY. Neither party is liable to the other for
incidental, punitive, special, indirect, or consequential damages, including
loss of profits due to service interruptions, regardless of the fault of the
defaulting party.
REGULATORY FILINGS. The Georgia Power Interconnection Agreement is subject
to approval by any governmental authorities (including Federal Energy Regulatory
Commission) having jurisdiction over the matters provided for in such agreement.
The Georgia Power Interconnection Agreement provides that nothing in the Georgia
Power Interconnection Agreement is to be construed as affecting the right of
either party to unilaterally make application to any applicable governmental
authority (including Federal Energy Regulatory Commission) for a change in terms
and conditions or for termination under applicable law.
DELIVERY AND MEASUREMENT OF ELECTRIC ENERGY. The facility is required to
maintain a nominal operating frequency of 60 hertz, and the partnership may be
required to assist in supporting system frequency if requested by Georgia Power.
The partnership is required when delivering power to the Georgia Integrated
Transmission System to operate its generation to meet the voltage schedule,
provided that the partnership could not be required to hold voltage schedule if
so doing would require it to produce more than the maximum amount of MVARS than
it is capable of producing.
ASSIGNMENT. The partnership is not permitted to assign the Georgia Power
Interconnection Agreement or any of its rights or interests or obligations
thereunder; provided that if the partnership is not in default or breach of the
Georgia Power Interconnection Agreement, then upon prior written notice to
Georgia Power, the partnership could collaterally assign its rights, interests
and obligations under the Georgia Power Interconnection Agreement to its lender
or an agent on behalf of its lenders providing financing or refinancing for the
design, construction or operation of the facility (a "Permitted Financing
Assignee") provided that the partnership remains fully liable for its
obligations under the Georgia Power Interconnection Agreement. At no time could
there be more than one Permitted Financing Assignee. A Permitted Financing
Assignee is not entitled to foreclose or exercise its rights and remedies with
respect to any such collateral assignment unless the purchaser at foreclosure,
purchaser in lieu of foreclosure or similar purchaser or transferee ("Purchaser
in Foreclosure") has (1) executed and delivered to Georgia Power and is in
compliance with an agreement in form and substance acceptable to Georgia Power
under which the Purchaser in Foreclosure assumes and agrees to perform then
outstanding and thereafter arising obligations of the partnership under the
Georgia Power Interconnection Agreement and (2) established to Georgia Power's
reasonable satisfaction that such Purchaser in Lieu of Foreclosure has all
licenses, permits and approvals and financial and technical wherewithal as may
be required to execute, deliver and perform such agreement. The partnership may
assign the Georgia Power Interconnection Agreement to third parties under
similar conditions.
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Georgia Power could at any time without notice to or consent from the
partnership or any other person, including, without limitation, any Permitted
Financing Assignee, assign, encumber or transfer its rights and obligations
under the Georgia Power Interconnection Agreement to its indentured trustee, any
of its affiliates or any successor owner or operator of the Georgia Integrated
Transmission System.
GOVERNING LAW. The Georgia Power Interconnection Agreement is governed by
the laws of the State of Georgia, without giving effect to conflict of law
principles.
PIPELINE EPC CONTRACT
The partnership and Willbros Engineers, Inc. (the "Pipeline Contractor") are
parties to a Fixed Price Engineering, Procurement and Construction Contract
effective September 23, 1999 (the "Pipeline EPC Contract") on a turnkey basis,
which provides for the Pipeline Contractor to perform services in connection
with the design, engineering, equipment and materials procurement, construction,
start-up, training, and testing of the Pipeline (collectively, the "Work").
SCOPE OF WORK. The Pipeline Contractor shall:
- furnish the design and engineering for the Pipeline, including the
preparation of all Drawings, with design and engineering that meet the
requirements of the Pipeline EPC Contract and that are prepared and
implemented under all applicable laws;
- provide and implement purchasing, construction, expediting, inspection,
and testing under the Pipeline EPC Contract and all applicable laws
(together with all services related thereto) as required by the Pipeline
EPC Contract or as may be necessary to provide the partnership with the
Pipeline meeting all specifications and standards set forth in the
Pipeline EPC Contract;
- provide all labor, equipment, procurement of equipment, (together with all
services provided or to be provided by the Pipeline Contractor) necessary
to fulfill its obligations to provide the Pipeline;
- perform all change orders; and
- perform the Work under all of its representations, covenants and
warranties as set forth in the Pipeline EPC Contract.
PARTNERSHIP RESPONSIBILITIES. The partnership shall furnish the Pipeline
Contractor with all right-of-way easements, and the Pipeline Contractor shall be
required to obtain all other construction permits. The partnership shall also
furnish the Pipeline Contractor with basic design criteria and process
descriptions as a basis for the Pipeline Contractor's performance of the Work.
If the partnership has not furnished the Pipeline Contractor with all
right-of-way easements necessary for the Pipeline by January 1, 2000, then the
Pipeline Contractor shall be entitled to an extension of the Scheduled
Completion Date (as defined below) by up to one day for each day until all such
right-of-way easements are obtained by the partnership.
COMMENCEMENT AND COMPLETION OF THE WORK. Upon execution of the Pipeline EPC
Contract, the Pipeline Contractor shall commence performance of the Work and
shall achieve Substantial Completion by September 1, 2000, subject to any
extensions permitted in accordance with under the Pipeline EPC Contract
("Scheduled Completion Date").
LIQUIDATED DAMAGES. The Pipeline Contractor shall pay to the partnership
liquidated damages in the amount of five thousand dollars for each full day or
part thereof that Substantial Completion is not achieved after the Liquidated
Damages Date, with a maximum cap of forty days. The Liquidated Damages Date
shall be the later of (a) the Scheduled Completion Date, as extended in the
event of a force majeure (as defined below) and (b) November 20, 2000. Subject
to the right of the partnership to terminate the Pipeline EPC Contract,
liquidated damages shall be the sole and exclusive liability of the Pipeline
Contractor for any delay in achieving the Scheduled Completion Date.
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NO REPRESENTATIONS TO THE PIPELINE CONTRACTOR. The Pipeline Contractor
acknowledges that it has, by examination, satisfied itself as to (1) the nature
and location of the worksite on which the Work is to be performed; (2) the
character, quantity and kind of (a) materials and conditions to be encountered
and (b) equipment, tools, machinery, supplies, manpower and other items needed
to perform the Work; and (3) all other matters which may affect the performance
of the Work.
The Pipeline Contractor is responsible for all worksite preparation,
provision of drainage and drainage structures, removal of debris, and all
necessary investigation, analysis, testing and determination concerning the
condition, contents or integrity of the subsurface, underground and/or soils of
the worksite. In performing worksite preparation, the Pipeline Contractor is
responsible for and assumes the cost of any construction, engineering or
structural conditions (except those caused by the presence of hazardous
materials which were present prior to the execution of the Pipeline EPC Contract
("Pre-existing Hazardous Materials"), archaeological remains or artifacts).
LIENS. The final payment to the Pipeline Contractor under the Pipeline EPC
Contract shall not become due until the Pipeline Contractor delivers to the
partnership a complete release and waiver of all claims for taxes, liens, or
attachments arising out of the performance of the Work, and/or, at the
partnership's sole option, receipts showing the discharge thereof.
INDEMNIFICATION. The Pipeline Contractor shall indemnify and hold the
partnership, the partners, any affiliates of the partnership, the Construction
Lender, the Independent Engineer, and the directors, officers, shareholders,
partners, employees and agents thereof (the "Indemnitees") harmless from any
liability, loss and expense arising from injury or death to persons or damage to
property, to the extent that such loss, injury, death or damage is directly
attributable to the negligence or willful misconduct of the Pipeline Contractor
or any subcontractor, or breach of the Pipeline EPC Contract by the Pipeline
Contractor, in the performance of the Work. The Pipeline Contractor will not
indemnify the Indemnitees for their own acts of negligence or willful
misconduct.
In no event shall the Pipeline Contractor or an Indemnitee, be responsible
for any special, indirect or consequential damages suffered by the other, as the
case may be, arising out of the Work or the Pipeline EPC Contract.
ENVIRONMENTAL MATTERS. During construction, the Pipeline Contractor shall
not contaminate ground water, in any manner, including by spilling Hazardous
Materials. All spills or releases of Hazardous Materials caused by the Pipeline
Contractor or any subcontractor shall be properly disposed of and/or remedied by
the Pipeline Contractor, at the Pipeline Contractor's expense; PROVIDED that,
the Pipeline Contractor is not responsible for the disposal or remediation of
Hazardous Materials which were present at any particular worksite prior to the
commencement of Work by the Pipeline Contractor at such particular worksite.
Notwithstanding the foregoing, the Pipeline Contractor is responsible for the
disposal and remediation of any spills or releases of Hazardous Materials which
result from damage or injury to underground tanks or pipelines located on the
worksite caused by the Pipeline Contractor, but only to the extent that the
Pipeline Contractor was aware or should have been aware, using standard industry
practices, of the existence of such pipeline or tank.
INSURANCE. The Pipeline Contractor shall maintain, and shall cause each
authorized subcontractor to maintain, the insurance set forth in the Pipeline
EPC Contract.
SECURITY FOR PERFORMANCE. Under the terms of the Pipeline EPC Contract, the
Pipeline Contractor's obligations under the Pipeline EPC Contract have been
guaranteed by its parent company, Willbros Group, Inc., a Panama corporation.
In lieu of retainage, the Pipeline Contractor shall deliver to the
partnership an irrevocable letter of credit in the amount of $232,620 issued by
a bank or other financial institution acceptable to the partnership in the form
attached to the Pipeline EPC Contract.
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TERMINATION OF THE PIPELINE EPC CONTRACT.
TERMINATION BY THE PARTNERSHIP FOR BREACH OF THE PIPELINE EPC CONTRACT. In
the event that the Pipeline Contractor:
(1) fails to (a) diligently perform the Work, (b) make such progress in the
performance of the Work as may be required to coordinate with, or to
prevent delay in the performance of, other operations of the partnership
that are necessary in the performance of the Pipeline EPC Contract, or
(c) perform in any material way the Work under the Pipeline EPC Contract
or otherwise be in material breach of the Pipeline EPC Contract;
(2) abandons the performance of the Work or any significant portion thereof;
or
(3) becomes insolvent, commits any act of bankruptcy or makes an assignment
for the benefit of creditors, the partnership shall have the right,
without prejudice to any other right or remedy, upon fifteen days written
notice to the Pipeline Contractor, unless such breach is cured prior to
the expiration of such notice period, or if such breach cannot reasonably
be cured within such period, cure is commenced within such period and
diligently pursued to completion, to terminate the Work and enter upon
and take over the worksite and all machinery, equipment, tools, supplies
and other items found thereon or enroute thereto, and may perform or
cause to be performed the Work in such a manner as to complete the
performance contemplated by the Pipeline EPC Contract in whatever
reasonable manner the partnership may deem expedient.
TERMINATION BY THE PARTNERSHIP FOR CONVENIENCE. The partnership may, at any
time, in its sole and exclusive discretion, by written notice to the Pipeline
Contractor, instruct the Pipeline Contractor to postpone or abandon the Work, in
whole or in part, or terminate the Pipeline EPC Contract.
TERMINATION BY THE PIPELINE CONTRACTOR FOR DEFAULT. The partnership shall
be in default to the Pipeline Contractor if the partnership fails to pay in a
timely manner any undisputed amounts due pursuant to the terms of the Pipeline
EPC Contract following receipt by the partnership from the Pipeline Contractor
of a written notice of such default. The partnership shall be allowed thirty
days from receipt of a notice of default to remedy such default after which the
Pipeline Contractor may immediately terminate the Pipeline EPC Contract by
written notice to the partnership.
WORKMANSHIP AND MATERIAL WARRANTIES. Notwithstanding the other provisions
in the Pipeline EPC Contract regarding workmanship and material warranties, the
Pipeline Contractor shall remedy any defects in the Work which appear within two
years from the date of Substantial Completion under the remedy provisions of the
Pipeline EPC Contract.
Unless otherwise approved in writing by the partnership, the Pipeline
Contractor shall use its best efforts to include in all subcontracts entered
into under the Pipeline EPC Contract a warranty of materials, equipment and
workmanship extending to the partnership and the Pipeline Contractor which shall
provide that defects in materials, equipment and workmanship which may appear
within two years from the date of acceptance of the subcontractor's Work shall
be repaired at the subcontractor's expense.
REMEDIES. The partnership shall notify the Pipeline Contractor in writing
within fifteen days of discovery by the partnership of any defects in the Work;
PROVIDED that, any delay by the partnership beyond such fifteen days shall
relieve the Pipeline Contractor from liability only to the extent of any
additional expense which may arise as the direct result of such delay. At no
additional cost, the Pipeline Contractor shall proceed promptly to take such
action relating to its Work as is necessary to cause its Work to comply with the
warranties specified in the Pipeline EPC Contract, and shall take such steps
pursuant to the provisions of the Pipeline EPC Contract regarding workmanship
and material warranties to enforce subcontractor or vendor warranties.
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TITLE. The title to all materials and consumables to be used in connection
with the performance of the Work shall transfer to the partnership upon delivery
of the same to the worksite, and title to all Work, completed or in the course
of construction, shall be in the partnership but the ownership thereof shall not
absolve the Pipeline Contractor from liability for loss or damage to the same,
nor from any other duty or responsibility for the same as provided in the
Pipeline EPC Contract. Upon transfer of title to the partnership, the
partnership shall have title free and clear of claims and liens of all persons
(subject to the statutory lien rights of the Pipeline Contractor until payment
for the Work has been received by the Pipeline Contractor).
RISK OF LOSS. On the date of Substantial Completion, the partnership shall
assume the care, custody and control of the Pipeline, including risk of loss or
damage to the Pipeline and the Work.
INVOICING AND PAYMENT. The Pipeline Contractor shall submit to the
partnership a monthly written invoice based on the percentage of completion of
individual bid items set forth in a list attached to the EPC Pipeline Contract
along with any appropriate supporting documentation. The partnership shall pay
the Pipeline Contractor the amount due under the invoice, within twenty-five
days of the receipt of the invoice. In the event of a dispute as to a portion of
an invoice, the partnership will make timely payment of the undisputed portion
and will withhold the disputed portion until the same is resolved. Compensation
shall be paid to the Pipeline Contractor for the performance of the Work
according to a fixed price schedule attached to the Pipeline EPC Contract.
FORCE MAJEURE. The partnership and the Pipeline Contractor shall give
prompt written notice to the other, as the case may be, of any event or
situation arising from circumstances beyond their reasonable control or which
could not have been reasonably foreseen and which, by the exercise of due
diligence, such party is unable to prevent or overcome, that render the
performance of the Work impossible ("force majeure"). It is the duty of the
party claiming force majeure to prove all the elements of force majeure
including:
- specific action taken to work around or mitigate the impact,
- specific event dates, durations and logic to support the claim, and
- specific cause for the claim of force majeure and to provide written
documentation of such proof to the other party as soon as reasonably
possible.
The Pipeline Contractor shall not be entitled to increase the fixed price on
account of an event of force majeure until it has established the existence of
more than twenty five days (on a cumulative basis) of delays actually caused by
force majeure.
DISPUTES. In the event of a dispute between the partnership and the
Pipeline Contractor with respect to the interpretation of, or the performance
required by, the Pipeline EPC Contract, including any dispute which may result
in a claim (a "Dispute"), the parties shall make a good faith attempt to resolve
the Dispute; PROVIDED that, the provisions of the Pipeline EPC Contract
governing Disputes shall not override, delay or in any way prevent termination
of the Pipeline EPC Contract by the partnership or the Pipeline Contractor
pursuant to the provisions of the Pipeline EPC Contract governing termination.
During such attempted Dispute resolution, except as otherwise provided in the
Pipeline EPC Contract, the parties shall continue to proceed diligently and in
good faith under the terms of the Pipeline EPC Contract. In the event a Dispute
is not resolved within sixty days following the date of the Dispute Notice,
thereafter either party, in its sole discretion, may invoke litigation. During
any litigation which arises out of a Dispute, all parties will continue to
proceed under the terms of the Pipeline EPC Contract without prejudice to the
rights of the partnership or the Pipeline Contractor to terminate as provided
therein.
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ASSIGNMENT. The Pipeline Contractor shall not assign, subcontract or
otherwise transfer the obligations or the benefits of the Pipeline EPC Contract
without the prior written consent of the partnership.
GOVERNING LAW. The Pipeline EPC Contract is governed by and construed
according to the laws of the State of Texas excluding their conflict of laws
provisions.
THE GAS INTERCONNECT AGREEMENT
The partnership and Transcontinental Gas Pipe Line Corporation ("Transco")
are parties to the Transcontinental Gas Pipe Line Corporation Interconnect,
Reimbursement and Operating Agreement (the "Gas Interconnect Agreement"), which
provides for Transco to construct and operate a natural gas delivery point to
the partnership and associated meter station on Transco's mainline in Heard
County, Georgia (the "Tenaska Meter Station").
GENERAL PROVISIONS FOR CONSTRUCTION. As soon as reasonably practicable
after the execution of the Gas Interconnect Agreement and prepayment by the
partnership, which occurred on December 27, 1999, Transco will begin engineering
design and material procurement for the Tenaska Meter Station, and Transco shall
provide for a target in-service date for Transco's Facilities nine months from
the date that the partnership made the prepayment to Transco.
In order to establish the interconnection between the natural gas facilities
of Transco and the partnership, each of Transco and the partnership shall
design, construct, own, operate and maintain various facilities (individually,
"Transco's Facilities" and "Customer's Facilities" and, collectively, the
"Interconnection").
Subject to the terms and conditions of the Gas Interconnect Agreement,
Transco will construct the Tenaska Meter Station pursuant to the automatic
authorizations provisions of the Federal Energy Regulatory Commission ("Federal
Energy Regulatory Commission") regulations, and in compliance with various other
specifications issued by the American Gas Association.
Transco's data acquisition and communications equipment shall be integrated
with the meter station and associated facilities and shall provide for
electronic flow measurement and an electric signal that is proportional to the
flow rate. The partnership shall not make repairs, adjustments or modifications
to that equipment without the prior written consent of Transco.
The designated point of tie-in and ownership change between Transco's
Facilities and the Customer's Facilities at the Interconnection shall be located
at the isolating flange immediately downstream of Transco's meter tube outlet
header. Transco shall own such flange and all facilities upstream thereof, and
the partnership shall own all facilities downstream of such flange. Transco and
the partnership shall each be responsible for the cathodic protection of their
respective facilities.
Transco shall acquire the necessary land rights for the Tenaska Meter
Station subject to review by the partnership, which review shall not be
unreasonably withheld.
Upon request by Transco, the partnership shall procure and install, at its
sole cost and expense, the electric utility service required to operate the
Tenaska Meter Station, including the station lighting, communication equipment
and associated facilities. The installation of such equipment shall be scheduled
at a time agreeable to Transco and the partnership.
Transco's pressure and transportation service obligations for deliveries to
the partnership at the Tenaska Meter Station shall be governed by the
transportation service agreements between Transco and the partnership and
Transco's Federal Energy Regulatory Commission Gas Tariff.
REIMBURSEMENT. The partnership shall reimburse Transco for all costs,
expenses, overheads and, if applicable, AFUDC incurred by Transco pursuant to
the Gas Interconnect Agreement.
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After execution of the Gas Interconnect Agreement and prior to commencement
of engineering design and material procurement by Transco, the partnership paid
Transco $1,208,000 (the estimated total reimbursable cost under the Gas
Interconnect Agreement) on December 27, 1999, and Transco shall credit this
amount as a prepayment toward the actual reimbursable costs. The total amount
due Transco shall be increased to the extent necessary to reimburse Transco for
the income tax effect of all payments to Transco for Transco's Facilities.
All costs will be accumulated and recorded under the Federal Energy
Regulatory Commission's Uniform System of Accounts. The partnership, after
fifteen (15) days notice in writing to Transco, shall have the right during
normal business hours to audit, at the partnership's own expense, all books and
records of Transco relating to Transco's construction of the facilities
described in the Gas Interconnect Agreement. The partnership shall have one
(1) year after the date of receipt of the detailed cost listing described above
in which to make such an audit. After such one (1) year period, the
partnership's right to audit shall expire and Transco's records shall be
presumed to be correct.
OPERATION AND MAINTENANCE. Transco and the partnership shall operate and
maintain their respective facilities under sound and prudent practices existing
in the pipeline industry and in compliance with all valid and applicable laws,
orders, directives, rules and regulations of governmental authorities having
jurisdiction.
Transco shall be responsible for the custody transfer of gas at the
Interconnection and shall provide two (2) electric signals at the
Interconnection from Transco's data acquisition equipment that is proportional
to the flow rate. Such signals will include temperature, pressure, Btu content,
gas quality and flow data.
The quality and measurement of gas delivered to the partnership at the
Interconnection shall be under Transco's currently effective Federal Energy
Regulatory Commission Gas Tariff, as amended from time to time.
The partnership shall operate the Customer's Facilities at pressures which
are lower than Transco's daily operating pressures at the Tenaska Meter Station.
If the partnership, in Transco's sole opinion reasonably exercised, fails to
comply with any provision of the Gas Interconnect Agreement, Transco shall have
the right, upon reasonable notification to the partnership and subject to any
necessary regulatory authorizations, to suspend the flow of gas through the
Interconnection. The partnership shall reimburse Transco for any costs incurred
as a result of such suspension of gas flow. Transco shall not be required to
resume gas flow through the Interconnection until the partnership has corrected,
in Transco's sole opinion, the area(s) of noncompliance with the Gas
Interconnect Agreement.
INDEMNIFICATION; DAMAGES. Transco shall hold harmless, defend and indemnify
the partnership, its agents, partners, officers, directors, stockholders,
lenders, representatives and employees (collectively, "Partnership Indemnified
Parties") from and against any and all claims, actions, settlements,
liabilities, losses, costs, damages, fines, judgments, demands and expenses
(including, without limitation, attorney fees) (collectively "Claims") for
injury to or death of persons or damage to or loss of property incurred by or
asserted against any of the Partnership Indemnified Parties which are
(1) caused by the activities of, or due to the placement of materials by,
Transco, its agents, affiliates, officers, directors, representatives,
employees, contractors or subcontractors, and/or (2) otherwise resulting from
the actions or omissions of Transco, its parent and affiliated companies, and
its and their respective agents, officers, directors, representatives,
employees, contractors or subcontractors arising out of, relating to or incident
to the performance of the Gas Interconnect Agreement. Notwithstanding the
foregoing, Transco shall not be required to indemnify the Partnership
Indemnified Parties for any environmental claims which are attributable to the
condition of the land upon which the Interconnection is constructed or from
activities by any party other than Transco, its parent and affiliated companies,
and
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their respective agents, officers, directors, representatives, employees,
contractors or subcontractors on or with respect to such land.
The partnership shall hold harmless, defend and indemnify Transco, its
parent and affiliated companies, and its and their respective agents, officers,
directors, stockholders, lenders, representatives and employees (collectively
"Transco Indemnified Parties") from and against all claims for injury to or
death of persons or damage to or loss of property incurred by or asserted
against any of the Transco Indemnified Parties which are (1) caused by
activities of, or due to the placement of materials by, the partnership, its
agents, affiliates, officers, directors, representatives, employees, contractors
or subcontractors, and/or (2) otherwise resulting from the actions or omissions
of the partnership, its agents, affiliates, officers, directors,
representatives, employees, contractors or subcontractors arising out of,
relating to or incident to the performance of the Gas Interconnect Agreement.
Without limitation of the foregoing, if damage occurs to either party's
pipeline for which the other party shall be obligated to indemnify such party
under the Gas Interconnect Agreement, Transco or the partnership, as the case
may be, shall (1) reimburse the other party for all reasonable costs and
expenses incurred to repair the damage and replace any lost natural gas, and
(2) hold harmless, defend and indemnify the Transco Indemnified Parties or the
Partnership Indemnified Parties, as the case may be, from and against all claims
resulting from any inability by Transco or the partnership, as the case may be,
to render service obligations to its customers. The method of repair,
replacement, remediation and other remedies shall be at the sole discretion of
the party whose pipeline was damaged.
INSURANCE. Each of Transco and the partnership are required to maintain
insurance policies under the Gas Interconnect Agreement.
Under the partnership's general liability and automobile liability policies,
Transco, its parent, subsidiary and affiliated companies will be named as
additional insureds.
TERM. The Gas Interconnect Agreement was effective on August 18, 1999 and
shall continue in force and effect unless and until terminated (1) upon default
by either party in the performance of any provision, condition or requirement
therein, by the other party, unless such default is cured within sixty
(60) days; (2) upon the occurrence and continuance of various bankruptcy events;
and (3) by mutual agreement of the parties in writing.
Termination of the Gas Interconnect Agreement shall not relieve either party
from any obligation accruing or accrued prior to the date of such termination,
nor shall such termination deprive a party not in default of any remedy
otherwise available to it.
Upon termination of the Gas Interconnect Agreement, Transco shall have the
right to abandon all or a portion of the Tenaska Meter Station in place. Transco
shall use all reasonable efforts to salvage any equipment reimbursed by the
partnership and refund the recovered amount to the partnership.
GOVERNING LAW. The Gas Interconnect Agreement and any claims thereunder
shall be governed by the laws of the State of Texas, excluding any conflicts of
law rules that might require the application of the laws of another
jurisdiction.
WATER AGREEMENT
OVERVIEW. The partnership and the Heard County Water Authority are parties
to the Water Agreement. The Water Agreement provides for the partnership to
receive potable water at the 350 gallons per minute (504,000 gallons per day)
(the "Committed Amount"). Under normal circumstances, the partnership will be
expected to take a base quantity of $20,000 worth of water per year, and is
obligated to pay the Heard County Water Authority at least $20,000 per year
commencing after the Date of Commercial Operation, regardless of how much water
is actually used.
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The Heard County Water Authority may not add customers or sell unused
capacity which would deny or tend to deny the partnership the Committed Amount.
While not obligated to supply the partnership any water in excess of the
Committed Amount, the Heard County Water Authority may elect to supply such
excess amount. If the partnership anticipates that it will need water in excess
of 100 gallons per minute, it must make reasonable efforts to give the Heard
County Water Authority notice.
If the Heard County Water Authority contracts to provide water with a
non-governmental entity involved in the generation of energy or governmental
entity reselling water to users involved in the generation of energy at terms
more favorable than those in the Water Agreement, it is obligated to give the
partnership the benefit of the better terms, refunding any excess charges
incurred by the partnership.
TERM AND TERMINATION. The term of the Water Agreement is for 30 years after
the first date the partnership purchases water under the Water Agreement (the
"Water Term"). The partnership may terminate the Water Agreement if it decides
to abandon its plan to build a power plant on the facility site. The
partnership's obligations are subject to closing on the land purchase and lease
by the Development Authority to the partnership of the facility site, both of
which have occurred.
The Heard County Water Authority may terminate the Water Agreement upon
failure by the partnership to obtain financing for the construction of the
facility or execute the Lease Agreement by December 31, 1999. However, the
partnership may pay a non-refundable extension fee of $100,000 to extend the
date to June 30, 2000. The Heard County Water Authority may also terminate the
Water Agreement if the partnership:
- fails to begin Commercial Operation by April 1, 2002,
- the partnership files a voluntary petition for bankruptcy, or
- a receiver is appointed for the partnership and not dismissed within
180 days after appointment.
If the partnership fails to pay its invoices after 60 days notice is given
to both it and its Lenders, the Heard County Water Authority has the right to
terminate the Water Agreement by giving written notice of termination.
ACCOUNTING FOR THE WATER. The Heard County Water Authority must own,
install, test, calibrate, adjust, operate and maintain a metering station to
measure and record the quantity of water purchased by the partnership. The
partnership will pay the Heard County Water Authority $15,000 for the purchase
and installation of the necessary equipment, and has the right to choose the
equipment purchased by the Heard County Water Authority. However, if the cost of
purchase and installation exceeds $15,000, and the partnership has specified
equipment with a greater cost than that selected by the Heard County Water
Authority, the partnership will pay the Heard County Water Authority the
difference in price.
If the partnership requests a copy of regulatory and chemical analysis
reports on the water as submitted to any governmental authority, the Heard
County Water Authority will provide it.
RATES, INVOICING AND PAYMENT. The partnership paid the Heard County Water
Authority $500,000 in consideration for the services and commitments of the
Heard County Water Authority. If the Heard County Water Authority enters into
any agreements with any person (other than a municipality or government agency
that does not resell the water) at a rate or capacity exceeding 230 gallons per
minute or 331, 200 gallons per day at a rate lower than that charged to the
partnership, with an upfront cost of less than $500,000 or on terms more
favorable than as specified in the Water Agreement, then such rates or cost
shall be reduced pro rata or the partnership shall have the benefit of such
terms.
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The partnership will pay $1.57 per 1,000 gallons of water (1999), subject to
an annual cost of living adjustment (the "Contract Rate"). The annual rates will
be calculated by multiplying the initial rate by a fraction, the numerator of
which is the Consumer Price Index as reported for December of the previous year
and the denominator of which is the Consumer Price Index as reported for
December, 1999. If the Heard County Water Authority is required by law to make
capital improvements to comply with environmental statutes, rules or
regulations, the partnership will, in addition to the Consumer Price Index
increase, pay the increase in water rates attributable to such improvements as
charged to all Heard County water users.
If the Heard County Water Authority agrees to sell the partnership water in
excess of its Commiteed Amount, the partnership shall pay $2.00 per 1,000
gallons for the water exceeding the 504,000 gallons per day. This rate is
subject to the same annual adjustments as the Contract Rate.
Invoices are to be submitted to the partnership by the fifth day of each
month, and the partnership must remit payment by the 15th day of the same month.
Failure to pay within 10 days of notification of default for failure to pay
charges will result in a 10% penalty on the unpaid amount. Disputed amounts paid
to the Heard County Water Authority will bear 10% interest from the date of
payment until the date of the refund.
INTERRUPTION OF SERVICE. The Heard County Water Authority may not interrupt
its provision of water to the facility for necessary scheduled maintenance
unless it has given at least 5 days prior notice. Whenever possible,
interruptions will be scheduled during a shut-down of the facility.
FORCE MAJEURE. Events of force majeure include drought, storm, earthquakes
and other natural calamities, as well as acts by third parties beyond the Heard
County Water Authority's control. These events excuse the Heard County Water
Authority from delivering water to the partnership, so long as it notifies the
partnership as soon as practicable, and the Heard County Water Authority's
suspension of performance is no longer than necessary to remedy its inability to
perform with reasonable dispatch.
ASSIGNMENT AND DELEGATION. Neither party may assign its rights or interests
or delegate its obligations under the Water Agreement to any party other than an
affiliate or subsidiary without the written permission of its counterparty. This
does not restrict the partnership's right to assign or transfer its rights,
titles and interests or to delegate its duties and obligations to any Lender.
TAXES. Each party will pay its own taxes with respect to the activities of
generation, transportation, delivery, sale, emission, disposal, or use of water.
INDEMNIFICATION. Under the Water Agreement, both parties agree to release,
defend, indemnify and hold harmless the other for damages arising out of its own
negligent acts or omissions in connection with the Water Agreement. In the event
that both parties are negligent and their negligence contributes to the cause of
a third party's claim, each party will be responsible and liable in proportion
to its own negligence.
WAIVER OF SUBROGATION. Both parties agree to waive and release all rights
of subrogation against the other party and its affiliates, owners, employees and
representatives for any loss or damage that would be covered by the following
insurance policies, regardless of any policy limits: primary commercial general
liability, excess commercial general liability, and automobile liability.
SOVEREIGN IMMUNITY. The Heard County Water Authority agrees to waive and
not raise any defense of sovereign immunity it may have in connection with the
Water Agreement or its performance under it.
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LEASE AGREEMENT
Pursuant to the Lease Agreement, dated as of November 1, 1999, the
Development Authority leases to the partnership, subject to Permitted Liens, the
facility, facility site, some related infrastructure facilities and related
easements and those items of machinery, equipment and related property required
under the Lease to be acquired and/or installed in the facility or on the
facility site or easements (the "Leased Property").
TERM. The Lease will terminate no earlier than the date of payment in full
of the revenue bonds issued by the Development Authority of Heard County.
RENTS. On or before February 1 and August 1 in each year, commencing
August 1, 2000, until payment in full of the revenue bonds issued by the
Development Authority of Heard County, the partnership shall pay or cause to be
paid to the Collateral Agent, for the account of the Development Authority and
the Development Authority Trustee, as rents, a sum equal to the amount payable
on such date as principal and redemption premium (if any) and interest on the
revenue bonds issued by the Development Authority of Heard County, as provided
in the Development Authority Indenture, and shall also pay, or cause to be paid,
as additional rents, certain various fees and expenses of the Development
Authority (which may be retained by the Development Authority or paid by the
Development Authority to Heard County) and various fees and expenses of the
Trustee.
TITLE TO THE LEASED PROPERTY. Upon the request of the partnership, the
Development Authority will join, where necessary, in any proceeding to protect
and defend its title in and to the Leased Property; PROVIDED that, the
partnership shall pay the entire cost of any such proceeding or reimburse the
Development Authority therefor and indemnify and hold harmless the Development
Authority from any cost or liability.
QUIET ENJOYMENT. The Development Authority warrants and covenants that it
will defend the partnership in the quiet enjoyment and peaceable possession of
the leased land and all appurtenances thereto, from all claims of all persons
acting by, through or under the Development Authority, throughout the term of
the Lease. In addition, the Development Authority will not take or cause another
party to take any action to interfere with the partnership's peaceful and quiet
enjoyment of the Leased Property.
AGREEMENT TO EXECUTE AMENDMENT TO LEASE AND RELEASE FROM SECURITY DEED. The
Development Authority and the partnership agree that (1) various items of
personal property may be acquired by the partnership and conveyed to the
Development Authority or acquired directly by the Development Authority from
time to time, (2) under the terms of the Lease, items of leased equipment and/or
portions of the leased land may be removed or released from the Lease, and (3)
easements and various other rights of way across the leased land may be granted
by the partnership under the Lease.
The Development Authority agrees, at the request of the partnership, to
execute an amendment to the Lease in the form attached to the Lease, without
further action on its part unless further action is otherwise required under the
Lease, and the equipment or property added or released thereby shall become
subject to or be released from the Lease. In connection with any amendment to
the Lease providing for the removal of leased equipment or the release of leased
land, the Development Authority shall execute and deliver such amendments,
releases and/or termination statements as may be necessary to release the lien
on such leased equipment or leased land created under the Security Deed between
the Development Authority and the Development Authority Trustee.
DISBURSEMENTS FROM THE CONSTRUCTION FUND. In the Development Authority
Indenture, the Development Authority has authorized and directed the Development
Authority Trustee to designate the Collateral Agent as agent for the Development
Authority Trustee with respect to the disbursement
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of moneys from the Construction Fund under the provisions of the Collateral
Agency Agreement for the payment of all Project Costs.
GRANTING AND RELEASE OF EASEMENTS; AMENDING OR MODIFYING EASEMENTS. Subject
to the provisions of the Collateral Agency Agreement and the Common Agreement,
the partnership may (a) cause to be granted easements, licenses, rights-of-way
and other rights or privileges in the nature of easements with respect to any
property included in the Leased Property and such grant will be free from the
lien or security interests created by the Development Authority Indenture or the
Lease, or (b) cause to be amended, modified or released existing easements,
licenses, rights-of-way and other rights or privileges in the nature of
easements, held with respect to any property included in the Leased Property
with or without consideration. The Development Authority agrees that it shall
execute and deliver and will cause the Development Authority Trustee to execute
and deliver any instrument necessary or appropriate to confirm and grant, amend,
modify or release any such easement, license, right-of-way or other right or
privilege under the terms of the Lease.
RELEASE OF CERTAIN LAND. Notwithstanding any other provision of the Lease,
but subject to the provisions of the Collateral Agency Agreement and the Common
Agreement, the Development Authority and the partnership reserve the right by
mutual agreement to amend the Lease for the purpose of effecting the release and
removal from the Lease of:
(a) any unimproved part of the leased land (on which neither the facility
nor any leased equipment is located but on which parking, transportation,
utility facilities or other support facilities may be located) on which
the Development Authority proposes to construct improvements for lease
under another and different lease agreement,
(b) any part of the leased land with respect to which the Development
Authority proposes to convey a fee or other title to a railroad or other
public body or quasi-public body or to a public utility in order that
transportation facilities or services by rail, water, road or other means
or utility services for the Leased Property, for the benefit of the
partnership may be provided, increased or improved or
(c) that portion of the leased land and related facilities constituting or
relating to the electric switchyard.
ENVIRONMENTAL INDEMNIFICATION. The partnership shall indemnify, hold
harmless, and defend the Development Authority, its officers, directors, agents,
and employees from and against any and all claims, losses, damages, expenses,
causes of action, lawsuits, government regulatory enforcement actions, and
liability asserted against the Development Authority arising out of alleged or
actual Environmental Contamination (as defined below) arising from the
partnership's leasing and operation of the Leased Property.
Environmental Contamination means damages to persons or property or
violations of state or federal environmental laws or regulations arising out of
the partnership's operations at the Leased Property with respect to, but not
limited to, air emissions, water effluent discharges, and waste generation,
transportation, storage, disposal, or the handling of hazardous materials.
CONVEYANCE OF LEASED PROPERTY BY DEVELOPMENT AUTHORITY SECURITY DEED. The
Development Authority has (1) conveyed its title in and to that portion of the
Leased Property consisting of real property and granted a security interest in
that portion of the Leased Property consisting of personal property to the
Development Authority Trustee by Deed to Secure Debt, Security Agreement and
Assignment of Rents and Leases, dated as of November 1, 1999, by and between the
Development Authority and the Development Authority Trustee, as amended from
time to time (the "Development Authority Security Deed"), and (2) assigned,
pledged and created a security interest in the property secured by the terms of
the Development Authority Indenture, as security for the payment of the
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principal of and the interest on the revenue bonds issued by the Development
Authority of Heard County, but such Security Deed and said assignment and pledge
shall be subject and subordinate to the Lease so long as there shall not exist a
default under the Lease or the Development Authority Indenture.
EVENTS OF DEFAULT. The Lease provides that the existence of a Trigger Event
under the Collateral Agency Agreement shall be an Event of Default under the
Lease.
REMEDIES ON DEFAULT. If an Event of Default has occurred and is continuing,
the Development Authority or the Development Authority Trustee, as provided in
the Development Authority Indenture, may, with the written consent of the
Collateral Agent, or shall, upon the written direction of the Collateral Agent,
take various remedial steps including, but not limited to (a) declare all
installments of rent payable under the Lease for the remainder of the term of
the Lease to be immediately due and payable, whereupon the same shall become
immediately due and payable; (b) re-enter and take possession of the Leased
Property without terminating the Lease and without any liability to the
Development Authority for such entry and repossession, and sublease the Leased
Property for the account of the partnership, holding the partnership liable for
the difference in the rents and other amounts payable by such sublessee in such
subleasing and the rents and other amounts payable by the partnership under the
Lease; and (c) terminate the Lease, exclude the partnership from possession of
the Leased Property and use its best efforts to lease the Leased Property to
another for the account of the partnership, holding the partnership liable for
all rent and other payments due up to the effective date of such leasing.
Any amounts collected pursuant to any such remedial action shall be paid and
applied under the provisions of the Collateral Agency Agreement and after
payment in full of the revenue bonds issued by the Development Authority of
Heard County and the payment of any costs occasioned by an Event of Default
under the Lease, and subject to the provisions of and the lien and security
interest created under the Security Agreement, and, subject to the provisions of
the Collateral Agency Agreement, any excess moneys in the bond fund under the
Development Authority Indenture shall be returned to the partnership as an
overpayment of rent.
The Development Authority will not exercise any remedies without the consent
of the Collateral Agent and the Development Authority will grant any consents or
waivers or take any other actions under the Lease (subject to such actions being
consistent with the terms of the Lease and provisions of law applicable to the
Development Authority) upon the direction of the Collateral Agent.
OPTIONS TO TERMINATE THE LEASE TERM. At any time prior to payment in full
of the revenue bonds issued by the Development Authority of Heard County, the
partnership may terminate the Lease giving the Development Authority and the
Development Authority Trustee notice in writing of such termination and by
paying to the Development Authority Trustee (or providing for its benefit) an
amount which, when added to the funds in the bond fund under the Development
Authority Indenture, will be sufficient to pay, retire and/or redeem all of the
outstanding revenue bonds issued by the Development Authority of Heard County
under the provisions of the Development Authority Indenture and, in case of
redemption, making arrangements satisfactory to the Development Authority
Trustee for the giving of the required notice of redemption.
At any time after payment in full of the revenue bonds issued by the
Development Authority of Heard County, the partnership may terminate the Lease
by giving the Development Authority notice in writing of such termination and
such termination shall forthwith become effective.
Upon any such termination of the Lease, the partnership shall purchase and
the Development Authority shall sell the Development Authority's right, title
and interest in the Leased Property to the partnership for the amount and under
the terms set forth in the Lease.
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CONVEYANCE. Upon any succession of the partnership to ownership of the
Leased Property pursuant to the Lease (including pursuant to any purchase or the
exercise of any option to purchase granted therein), the Development Authority
will, under the terms of the Lease, deliver to the partnership the quitclaim
deed in the form attached to the Lease or similar documents satisfactory to the
partnership, conveying to the partnership title in and to the property with
respect to which such obligation or option was exercised, subject to:
(a) liens and encumbrances (if any) to which such title in and to said
property was subject when conveyed to the Development Authority;
(b) liens and encumbrances created by the partnership, or to the creation or
suffering of which the partnership consented in writing, or resulting
from the failure of the partnership to perform or observe any of the
agreements on its part contained in the Lease; and
(c) Permitted Liens other than the Development Authority Indenture, the
Development Authority Security Deed and the Lease.
SUCCESSION RIGHTS OF THE PARTNERSHIP. The Development Authority and the
partnership agree that, whether or not the option to purchase the Leased
Property has been exercised, the partnership shall be entitled to succeed to the
ownership of the Leased Property upon and after the payment in full of the
revenue bonds issued by the Development Authority of Heard County.
SECURITY INTEREST OF THE PARTNERSHIP. The Development Authority grants to
the partnership a security interest in and lien upon any amounts realized upon
the foreclosure sale or exercise of other remedies under the Development
Authority Security Deed between the Development Authority and the Development
Authority Trustee, and such amounts shall, after satisfaction of the
indebtedness described therein, be paid to the Collateral Agent, on behalf of
the partnership, for application under the terms of the Collateral Agency
Agreement.
AD VALOREM TAXATION AGREEMENT
OVERVIEW. The parties to the Ad Valorem Taxation Agreement ("Tax
Agreement") are the Board of Commissioners of Heard County (the
"Commissioners"), the Board of Tax Assessors of Heard County (the "Board") and
the partnership. The parties agree that the facility will not be subject to ad
valorem taxation because it will be owned by the Development Authority, but that
the partnership's leasehold interest will be subject to ad valorem taxes. The
Tax Agreement sets forth how the partnership's interest under the Lease
Agreement will be valued before the completion of construction, and for the
20 year period following the year in which the facility is completed.
CONSTRUCTION OF THE FACILITY. Until January 1 of the year after the
construction of the facility is complete and revenue generating operations
commence, there will be no value to the Lease Agreement, and no real property or
personal property taxes on the facility or the facility site.
COMPLETION OF CONSTRUCTION. In the year following the completion of the
facility and the commencement of revenue generating operations and for the next
20 years, ad valorem taxes will be computed based on the hypothetical amount of
the cumulative principal reduction of the outstanding bond indebtedness incurred
for engineering, procurement or construction costs (the "Cumulative Principal
Reduction"), as if it were amortized by equal quarterly payments of principal
and interest at a rate of 6% per year over a period of 20 years. The
amortization will be calculated in the following manner:
AMOUNT OF INVESTMENT. The amount of bond proceeds invested in the
engineering, procurement or construction costs in leased land and equipment will
be determined.
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CUMULATIVE PRINCIPAL REDUCTION. On January 1 of each of the 20 years, the
amount of Cumulative Principal Reduction will be computed for the leased land
and buildings, and leased equipment. Depreciation of the leased property will be
taken into account by multiplying the Cumulative Principal Reduction by a stated
factor (the "Depreciation Factors").
TAXABLE PROPERTY VALUE. THE CUMULATIVE PRINCIPAL REDUCTION WILL BE
MULTIPLIED BY THE DEPRECIATION FACTORS AND 40%. THE PRODUCT WILL THEN BE
MULTIPLIED BY THE HEARD COUNTY MILLAGE RATE TO DETERMINE THAT YEAR'S AD VALOREM
TAX.
REPAIRS AND REPLACEMENT. Repairs and Replacement of leased equipment will
not affect their valuation for tax purposes.
EXPANSION OF THE FACILITY. If after completion of the facility, any leased
buildings or equipment are purchased as part of an expansion of the facility,
taxes will be computed on those buildings and equipment following the same
methodology set forth for the initial facility.
149
<PAGE>
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES
The following is a discussion of the material United States federal income
tax consequences of participating in the exchange offer and owning and disposing
of new bonds and, insofar as it relates to matters of law or legal conclusions,
constitutes the opinion of Winthrop, Stimson, Putnam & Roberts. Except where
noted, this discussion deals only with old bonds acquired upon original
issuance, and new bonds issued in exchange therefor, in each case held as
capital assets. It does not address all aspects of United States federal income
taxation that may be relevant to particular holders in light of their
circumstances or status, nor does it address any United States income tax
consequences to holders that may be subject to special tax rules, such as
financial institutions, insurance companies, dealers in securities or
currencies, tax-exempt organizations, persons that hold old bonds, or that will
hold new bonds, as part of a straddle, hedge, conversion or constructive sale
transaction, persons who mark to market their securities, or persons who have a
functional currency other than the United States dollar. In addition, this
discussion does not address any aspect of state, local or foreign taxation. This
section is based on the Internal Revenue Code of 1986, as amended (the "Code"),
its legislative history, existing and proposed regulations thereunder, and
published rulings and court decisions, all as currently in effect and all
subject to change at any time, possibly with retroactive effect.
As used in this discussion, the term "United States Holder" means a
beneficial owner of an old bond or new bond that is, for United States federal
income tax purposes:
- a citizen or resident of the United States,
- a corporation, or other entity treated as a corporation for United States
federal income tax purposes, created or organized in or under the laws of
the United States or any State of the United States or the District of
Columbia,
- an estate the income of which is subject to United States federal income
tax regardless of its source, or
- a trust the administration of which is subject to the primary supervision
of a court in the United States and for which one or more United States
persons have the authority to control all substantial decisions.
If a partnership holds old bonds or new bonds, the tax treatment of a
partner will generally depend upon the status of the partner and the activities
of the partnership. Partners of partnerships holding old bonds or new bonds
should consult their tax advisors. As used in this discussion, the term
"Non-United States Holder" means a beneficial owner of an old bond or a new bond
that is not a United States Holder.
YOU SHOULD CONSULT WITH YOUR OWN TAX ADVISOR CONCERNING THE UNITED STATES
FEDERAL, STATE AND LOCAL, AS WELL AS FOREIGN, TAX CONSEQUENCES TO YOU, IN LIGHT
OF YOUR PARTICULAR SITUATION, OF PARTICIPATING IN THE EXCHANGE OFFER AND OWNING
AND DISPOSING OF NEW BONDS.
THE EXCHANGE OFFER
An exchange of old bonds for new bonds pursuant to the exchange offer will
not be a taxable event for United States federal income tax purposes.
Accordingly, a Holder will not recognize gain or loss upon receipt of a new bond
in exchange for an old bond, the new bond will have the same issue price as the
old bond in exchange for which it was issued, and a Holder will have the same
adjusted tax basis and holding period in the new bond as it had in the old bond
immediately before the exchange.
150
<PAGE>
UNITED STATES HOLDERS
PAYMENTS OF INTEREST
Interest on a new bond will be taxable to a United States holder as ordinary
income at the time it is received or accrued under the United States holder's
regular method of accounting for United States federal income tax purposes.
MARKET DISCOUNT
If a United States holder purchased an old bond for less than its stated
redemption price at maturity, the difference will be treated as "market
discount" for United States federal income tax purposes, unless the difference
is less than a specified DE MINIMIS amount. Under the market discount rules, the
United States holder will be required to treat any gain on the sale, exchange,
redemption or other disposition of the new bond received in exchange for the old
bond as ordinary income to the extent of the market discount that has not
previously been included in income and that is treated as having accrued on the
old bond or the new bond at the time of the disposition. In addition, the United
States holder may be required to defer, until the maturity or earlier
disposition of the new bond, the deduction of all or a portion of the interest
expense on any indebtedness incurred or continued to purchase or carry the old
bond or new bond.
Any market discount will be considered to accrue ratably during the period
from the date of acquisition of the old bond to the maturity date of the new
bond unless the United States holder elects to accrue under a constant yield
method. A United States holder may elect to include market discount in income
currently as it accrues (either ratably or under a constant yield method), in
which case the rule described above regarding deferral of interest deductions
will not apply. This election to include market discount in income currently,
once made, applies to all market discount obligations held or subsequently
acquired by the United States holder on or after the first day of the first
taxable year to which the election applies and may not be revoked without the
consent of the Internal Revenue Service ("IRS").
AMORTIZABLE BOND PREMIUM
A United States holder that purchased an old bond for an amount greater than
its stated redemption price at maturity will be considered to have purchased the
old bond at a "premium." A United States holder generally may elect to amortize
the premium over the remaining term of the new bond received in exchange for the
old bond under a constant yield method. The amount amortized in any year will be
treated as a reduction of the United States holder's interest income from the
new bond. Bond premium on a new bond held by a United States holder that does
not make such an election will decrease the gain or increase the loss otherwise
recognized on disposition of the new bond. The election to amortize premium on a
constant yield method, once made, applies to all debt obligations held or
subsequently acquired by the United States holder on or after the first day of
the first taxable year to which the election applies and may not be revoked
without the consent of the IRS.
SALE, EXCHANGE, RETIREMENT AND OTHER DISPOSITION OF NEW BONDS
Upon the sale, exchange, retirement or other taxable disposition of a new
bond, a United States holder will recognize gain or loss equal to the difference
between the amount realized on such disposition (less any accrued but unpaid
interest, which will be taxable as ordinary income) and the United States
holder's adjusted tax basis in the new bond. Except as described above with
respect to market discount, such gain or loss will be capital gain or loss and
will be long-term capital gain or loss if the old bond and the new bond have, in
the aggregate, been held for more than one year. Generally, for noncorporate
United States holders, long-term capital gains are subject to United States
federal income taxation at reduced rates. The deductibility of capital losses is
subject to limitations. A United
151
<PAGE>
States holder's adjusted tax basis in a new bond received in exchange for an old
bond will, in general, be the cost of the old bond to the United States holder,
increased by any market discount previously included in income and reduced by
any amortized premium.
NON-UNITED STATES HOLDERS
PAYMENTS OF INTEREST
Subject to the discussion of backup withholding below, interest on a new
bond received or accrued by a non-United States holder will generally be
considered "portfolio interest" and will generally not be subject to United
States federal income tax or withholding tax, as long as the non-United States
holder:
- does not conduct a trade or business in the United States with respect to
which the interest is effectively connected,
- does not actually or constructively own a 10 percent or greater interest
in the capital or profits of the partnership,
- is not a "controlled foreign corporation" with respect to which the
partnership is a "related person" within the meaning of Section 864(d)(4)
of the Code,
- is not a bank whose receipt of the interest is described in
Section 881(c)(3)(A) of the Code, and
- provides an appropriate statement, signed under penalties of perjury,
certifying that such holder is a non-United States holder and providing
such holder's name and address. If the information provided in this
statement changes, the non-United States holder must provide notice within
30 days of such change.
If such interest were not portfolio interest, then it would be subject to
United States federal income and withholding tax at a rate of 30% unless reduced
or eliminated pursuant to an applicable income tax treaty.
SALE, EXCHANGE, RETIREMENT AND OTHER DISPOSITION OF NEW BONDS
A non-United States holder generally will not be subject to United States
federal income tax on any gain realized on the sale, exchange, retirement or
other disposition of a new bond unless (1) this gain is effectively connected
with the conduct by the holder of a United States trade or business or (2) in
the case of an individual holder, the holder is present in the United States for
183 days or more during the taxable year in which such gain is realized and
certain other conditions exist.
INFORMATION REPORTING AND BACKUP WITHHOLDING
A United States holder (other than an "exempt recipient," including a
corporation and some other persons who, when required, demonstrate their exempt
status) may be subject to backup withholding at a rate of 31% on, and to
information reporting requirements with respect to, payments of principal of, or
interest on, and to proceeds from the sale, exchange or retirement of, new
bonds. Backup withholding will apply to a United States holder only if such
holder fails to furnish a correct taxpayer identification number or
certification of exempt status, fails to report dividend and interest income in
full, or fails to certify that such holder has provided a correct taxpayer
identification number and is not subject to backup withholding. The backup
withholding tax is not an additional tax and may be credited against a United
States holder's regular United States federal income tax liability or refunded
by the IRS where applicable.
Information reporting and backup withholding generally do not apply to
payments of interest to a non-United States holder if the certification
described above under "non-United States holders--Payments of Interest" is
received, provided the payor does not have actual knowledge that the holder is
152
<PAGE>
a United States person. Payments of principal and interest made to the
beneficial owner of a new bond by or through the foreign office of a custodian,
nominee or other agent acting on behalf of the beneficial owner, and payment of
the proceeds of a sale, exchange or other disposition of a new bond by the
foreign office of a broker, generally will not be subject to backup withholding.
However, if the custodian, nominee, other agent or broker is a United States
person, a controlled foreign corporation for United States federal income tax
purposes, or a foreign person 50% or more of whose gross income is effectively
connected with a United States trade or business for a specified three-year
period, information reporting will be required with respect to these payments
unless the custodian, nominee, other agent or broker has in its records
documentary evidence that the beneficial owner is not a United States person and
various conditions are met or the beneficial owner otherwise establishes an
exemption. Payments by a United States office of a custodian, nominee, other
agent or broker are subject to both backup withholding and information reporting
unless the beneficial owner certifies as to its non-United States holder status
under penalties of perjury or otherwise establishes an exemption.
Income tax regulations that are generally effective for payments made after
December 31, 2000, subject to transition rules, modify in some respects the
backup withholding and information reporting rules. In general, these
regulations do not significantly alter the substantive requirements of these
rules, but unify current procedures and forms and clarify reliance standards.
You should consult your own tax advisor regarding these regulations.
153
<PAGE>
PLAN OF DISTRIBUTION
Until , 2000, all dealers effecting transactions in the new bonds,
whether or not participating in this distribution, may be required to deliver a
prospectus. This is in addition to the obligation of dealers to deliver a
prospectus when acting as underwriters and with respect to their unsold
allotments or subscriptions.
Each broker-dealer that receives new bonds for its own account pursuant to
the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of those new bonds. This prospectus, as it may be
amended or supplemented from time to time, may be used by a broker-dealer in
connection with resales of new bonds received in exchange for old bonds only
where those old bonds were acquired as a result of market-making activities or
other trading activities. The partnership has agreed that, for a period of
180 days from the date on which the exchange offer is consummated, they will
make this prospectus, as amended or supplemented, available to any broker-
dealer for use in connection with any such resale.
The partnership has not received any proceeds from any sale of new bonds by
broker-dealers. New bonds received by broker-dealers for their own account
pursuant to 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 new bonds or a combination of such methods of
resale, at prices related to such prevailing market prices or at negotiated
prices. Any such resale may be made directly to purchasers or to or through
brokers or dealers who may receive compensation in the form of commissions or
concessions from any such broker-dealer or the purchasers of any new bonds. Any
broker-dealer that resells new bonds that were received by it for its own
account pursuant to the exchange offer and any broker or dealer that
participates in a distribution of those new bonds may be deemed to be an
"underwriter" within the meaning of the Securities Act of 1933 and any profit on
any such resale of new bonds and any commissions or concessions received by any
such persons may be deemed to be underwriting compensation under the Securities
Act of 1933. 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 of
1933.
For a period of 180 days from the date on which the exchange offer is
consummated, the partnership will promptly send additional copies of this
prospectus and any amendment or supplement to this prospectus to any
broker-dealer that requests those documents in the letter of transmittal. The
partnership has agreed to pay all expenses incident to the exchange offer
(including the expenses of one counsel for holders of the bonds) other than
commissions or concessions of any broker-dealers and will indemnify the holders
of the bonds (including any broker-dealers) against some liabilities, including
liabilities under the Securities Act of 1933.
ERISA CONSIDERATIONS
ANY EMPLOYEE BENEFIT PLAN THAT PROPOSES TO PURCHASE THE BONDS SHOULD CONSULT
WITH ITS COUNSEL WITH RESPECT TO THE POTENTIAL CONSEQUENCES OF SUCH INVESTMENT
UNDER THE FIDUCIARY RESPONSIBILITY PROVISIONS OF THE EMPLOYEE RETIREMENT INCOME
SECURITY ACT OF 1974, AS AMENDED ("ERISA"), AND THE PROHIBITED TRANSACTION
PROVISIONS OF ERISA AND THE CODE.
ERISA and the Code impose various requirements on employee benefit plans and
some other retirement plans and arrangements, including individual retirement
accounts and annuities, that are subject to ERISA or the Code (all of which are
hereinafter referred to as "ERISA Plans") and on persons who are fiduciaries
with respect to such ERISA Plans. A person who exercises discretionary authority
or control with respect to the management or assets of an ERISA Plan will be
considered a fiduciary of such ERISA Plan under ERISA. Under ERISA's general
fiduciary standards, before investing in the bonds, an ERISA Plan fiduciary
should determine whether such an investment is permitted under the governing
ERISA Plan instruments and is appropriate for the ERISA Plan in view
154
<PAGE>
of its overall investment policy and the composition and diversification of its
portfolio. Other provisions of ERISA and the Code prohibit certain transactions
involving the assets of such ERISA Plan and persons who have set specified
relationships to the ERISA Plan ("parties in interest" within the meaning of
ERISA or "disqualified persons" within the meaning of the Code). Thus, such
ERISA Plan fiduciary considering an investment in the bonds should also consider
whether such an investment may constitute or give rise to a prohibited
transaction under ERISA or the Code and whether an administrative exemption may
be applicable to such investment.
An ERISA Plan fiduciary considering the purchase of the bonds should consult
its tax and/or legal advisors regarding the availability, if any, of exemptive
relief from any potential prohibited transaction and other fiduciary issues and
their potential consequences. Each purchaser acquiring the bonds with the assets
of an ERISA Plan with respect to which the partnership, an initial purchaser, or
any party related thereto is a party in interest or a disqualified person shall
be deemed to have represented that a statutory or an administrative exemption
from the prohibited transaction rules under Section 406 of ERISA and
Section 4975 of the Code is applicable to such purchaser's acquisition and
holding of the bonds.
LITIGATION
There is no litigation of any nature pending or threatened against the
partnership as of the date of this prospectus affecting our project, or
contesting or affecting the validity of the bonds or any proceedings of the
partnership taken with respect to the authorization, issuance, sale or delivery
of the bonds, or the pledge or the application of any monies or the security
provided for the payment of the bonds, or the existence or powers of the
partnership.
LEGAL MATTERS
The validity of the new bonds has been passed upon for us by Winthrop,
Stimson, Putnam & Roberts, New York, New York, our special New York counsel.
EXPERTS
The financial statements for the partnership at December 31, 1999 and for
the year then ended included in this prospectus have been audited by Arthur
Andersen LLP, independent public accountants, as indicated in their report with
respect thereto, and are included herein in reliance upon the authority of said
firm as experts in accounting and auditing in giving said reports.
R. W. Beck has prepared the Independent Engineer's Report that is included
as Appendix B to this prospectus. The Independent Engineer's Report has been
included in this prospectus in reliance upon the conclusions therein and upon R.
W. Beck's experience in the review of the design, development, construction and
operation of electric generation projects, including those similar to this
project.
Resource Data has prepared the Independent Market Consultant's Report that
is included as Appendix C to this prospectus. The Independent Market
Consultant's Report has been included in this prospectus in reliance upon the
conclusions therein and upon the authority of Resource Data as an expert 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.
MISCELLANEOUS
All estimates and assumptions herein are believed to be reasonable, but no
warranty, guaranty or other representation is made that such estimates or
assumptions will be realized or are correct. So far as any statements herein
involve matters of opinion, whether or not expressly so stated, they are
intended merely as such and not as representations of fact.
155
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Public Accountants.................... F-2
Financial Statements:
Balance Sheet December 31, 1999............................. F-3
Statement of Operations for the Year Ended December 31,
1999........................................................ F-4
Statement of Partners' Deficit for the Year Ended December
31, 1999.................................................... F-5
Statement of Cash Flows for the Year Ended December 31,
1999........................................................ F-6
Notes to Financial Statements--December 31, 1999............ F-7
Financial Statements:
Balance Sheet March 31, 2000 (unaudited).................... F-12
Statement of Operations for the Three Months Ended
March 31, 2000 (unaudited).................................. F-13
Statement of Partners' Deficit for the Three Months Ended
March 31, 2000 (unaudited).................................. F-14
Statement of Cash Flows for the Three Months Ended
March 31, 2000 (unaudited).................................. F-15
Notes to Financial Statements--March 31, 2000............... F-16
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Tenaska Georgia Partners, L.P.:
We have audited the accompanying balance sheet of Tenaska Georgia Partners,
L.P. (a Delaware limited partnership in the development stage) as of
December 31, 1999, and the related statements of operations, partners' deficit
and cash flows for the year then ended. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Tenaska Georgia Partners,
L.P. as of December 31, 1999, and the results of its operations and its cash
flows for the year then ended, in conformity with generally accepted accounting
principles.
Omaha, Nebraska,
February 14, 2000
F-2
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
BALANCE SHEET--DECEMBER 31, 1999
<TABLE>
<S> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 40,225,109
Short-term investments.................................... 163,621,403
Restricted short-term investments......................... 37,516,471
Interest receivable....................................... 1,780,090
Prepaid insurance......................................... 1,027,243
------------
Total current assets.................................... 244,170,316
DEVELOPMENT WORK IN PROGRESS................................ 20,056,087
------------
LAND........................................................ 602,529
------------
OTHER ASSETS:
Contract costs............................................ 2,235,490
Deferred finance charges.................................. 4,190,156
------------
Total other assets...................................... 6,425,646
------------
Total assets............................................ $271,254,578
============
LIABILITIES AND PARTNERS' DEFICIT
CURRENT LIABILITIES:
Accounts payable.......................................... $ 264,706
Payable to affiliate...................................... 53,698
Accrued interest payable.................................. 3,628,472
------------
Total current liabilities............................... 3,946,876
------------
CONTRACT RETAINAGE PAYABLE.................................. 86,501
------------
LONG-TERM DEBT.............................................. 275,000,000
------------
Total liabilities....................................... 279,033,377
------------
COMMITMENTS AND CONTINGENCIES
PARTNERS' DEFICIT:
Tenaska Georgia, Inc...................................... (77,788)
Tenaska Georgia I, L.P.................................... (7,701,011)
------------
Total partners' deficit................................. (7,778,799)
------------
Total liabilities and partners' deficit................. $271,254,578
============
</TABLE>
The accompanying notes are an integral part of this balance sheet.
F-3
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1999
<TABLE>
<S> <C>
EXPENSES:
Start-Up Costs:
Management fees and expenses............................ $ 3,524,129
Professional and consulting fees........................ 2,626,098
General and administrative expenses..................... 161,214
Other expenses.......................................... 81,037
-----------
Total operating expenses.............................. 6,392,478
-----------
INTEREST EXPENSE:
Interest expense.......................................... 3,628,472
Interest expense capitalized.............................. (219,059)
-----------
Interest expense, net..................................... 3,409,413
-----------
INVESTMENT INCOME........................................... 2,023,092
-----------
NET LOSS TO PARTNERS ACCUMULATED DURING
THE DEVELOPMENT STAGE..................................... $(7,778,799)
===========
</TABLE>
The accompanying notes are an integral part of this statement.
F-4
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
STATEMENT OF PARTNERS' DEFICIT
FOR THE YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
TENASKA TENASKA
GEORGIA, INC. GEORGIA I, L.P. TOTAL
------------- --------------- -----------
<S> <C> <C> <C>
BALANCE, January 1, 1999................................ $ -- $ -- $ --
Net loss to partners accumulated during the
development stage................................... (77,788) (7,701,011) (7,778,799)
-------- ----------- -----------
BALANCE, December 31, 1999.............................. $(77,788) $(7,701,011) $(7,778,799)
======== =========== ===========
</TABLE>
The accompanying notes are an integral part of this statement.
F-5
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1999
<TABLE>
<S> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss to partners accumulated during the development
stage..................................................... $ (7,778,799)
Adjustments to reconcile net loss to partners accumulated
during the development stage to net cash from operating
activities-
Increase in short-term investments........................ (163,621,403)
Increase in restricted short-term investments............. (37,516,471)
Increase in interest receivable........................... (1,780,090)
Increase in prepaid insurance............................. (1,027,243)
Increase in accounts payable.............................. 264,706
Increase in payable to affiliate.......................... 53,698
Increase in contract retainage payable.................... 86,501
Increase in accrued interest payable...................... 3,628,472
-------------
Total adjustments....................................... (199,911,830)
-------------
Net cash from operating activities...................... (207,690,629)
-------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Development work in progress.............................. (20,056,087)
Contract costs............................................ (2,235,490)
Purchase of land.......................................... (602,529)
-------------
Net cash from investing activities...................... (22,894,106)
-------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt.................. 275,000,000
Deferred finance charges.................................. (4,190,156)
-------------
Net cash from financing activities...................... 270,809,844
-------------
NET INCREASE IN CASH AND CASH EQUIVALENTS................... 40,225,109
CASH AND CASH EQUIVALENTS, beginning of period.............. --
-------------
CASH AND CASH EQUIVALENTS, end of period.................... $ 40,225,109
=============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest.................................... $ --
</TABLE>
The accompanying notes are an integral part of this statement.
F-6
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1999
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
ORGANIZATION
Tenaska Georgia Partners, L.P. (the Limited Partnership) was formed on
April 16, 1998, to develop, finance, construct, lease, operate and maintain a
936 megawatt, natural gas-fired electric generation peaking facility (the
Facility) located in Heard County, Georgia. The Facility will generate electric
power for sale and the Limited Partnership expects to incur costs of
approximately $310,500,000 to complete the Facility. The Limited Partnership was
inactive prior to calendar year 1999 and commenced development activities during
such year. The Limited Partnership is scheduled to terminate December 31, 2050.
The following are the partners and their respective ownership interests and
their percentage share of net income or loss:
<TABLE>
<CAPTION>
PERCENTAGE INTEREST
PERCENTAGE INTEREST (FOR (FOR ALLOCATION OF NET
PARTNER EQUITY CONTRIBUTION PURPOSES) INCOME OR LOSS)
------- ----------------------------- ----------------------
<S> <C> <C>
Tenaska Georgia, Inc. (General)... 1.00% 1.00%
Tenaska Georgia I, L.P.
(Limited)....................... 99.00 99.00
------ ------
100.00% 100.00%
====== ======
</TABLE>
The Partners have committed to fund up to $35,500,000 of equity and the
Limited Partnership has issued senior secured bonds for $275,000,000 to fund
construction of the Facility.
The day-to-day management of the affairs of the Limited Partnership,
including preparation and maintenance of the financial and other records and
books of account of the Limited Partnership and supervision of the ongoing
operations of the facilities, loan administration and activities of the Limited
Partnership, are the responsibility of the managing partner (Tenaska
Georgia, Inc.) subject to the direction of the Executive Review Committee.
Tenaska Georgia, Inc. does not have the authority to incur any obligations or
liabilities on behalf of the Limited Partnership, except as approved by the
Executive Review Committee.
USE OF ESTIMATES
The preparation of these financial statements required the use of certain
estimates by management in determining the Limited Partnership's assets,
liabilities, revenue and expenses. Actual results could differ from those
estimates.
FINANCIAL STATEMENT PRESENTATION
At December 31, 1999, the Limited Partnership was a development stage
enterprise as defined in Financial Accounting Standards Board Statement No. 7
"Accounting and Reporting by Development Stage Enterprises."
SHORT-TERM INVESTMENTS
Short-term investments consist of investments in commercial paper with
maturities of less than one year.
F-7
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1999
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
RESTRICTED SHORT-TERM INVESTMENTS
Restricted short-term investments consist of investments in commercial paper
with maturities of less than one year that are restricted specifically for
interest payments on the Limited Partnership's long-term debt.
DEFERRED FINANCE CHARGES
During the development phase, the Limited Partnership incurred charges and
fees necessary to obtain financing. These costs have been capitalized and
deferred and upon completion of construction, will be amortized to expense over
the term of the related debt (see Note 4) using the bonds outstanding method.
CONTRACT COSTS
The Limited Partnership incurred direct costs associated with its contract
to supply power (see Note 5). These costs were capitalized and will be amortized
to expense over the term of the power contract once operations commence.
INCOME TAXES
The Limited Partnership has no liability for income taxes. Income is taxed
to the partners based on their proportionate share of the Limited Partnership's
taxable income. Therefore, no provision or liability for income taxes has been
included in the accompanying financial statements.
PREPAID INSURANCE
The Limited Partnership has a prepaid for general liability insurance,
excess general liability insurance, umbrella liability insurance and business
interruption insurance coverage. This prepayment is being amortized on a
straight-line basis over the term of the policies. The amortization of the
prepayments is being capitalized as contract costs until the plant produces
energy.
RISKS AND UNCERTAINTIES
The Limited Partnership is subject to several risks, including but not
limited to, risks associated with the cost and timely construction of the
Facility, the nature of and reliance on long-term contractual obligations with
various third parties, the ability to operate the Facility in order to meet
long-term contractual obligations, regulatory risks and other uncertainties in
the power industry.
START-UP COSTS
The Limited Partnership incurred start-up costs such as management fees,
professional and consulting fees, and other costs during the period. These items
were expensed in the accompanying statement of operations in accordance with the
AICPA's Statement of Position 98-5 "Reporting on the Costs of Start-Up
Activities."
F-8
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1999
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
STATEMENT OF CASH FLOWS
The Limited Partnership considers cash and cash equivalents to be all highly
liquid securities purchased with an original maturity date of three months or
less. Due to their short-term maturities, the fair value of the cash
equivalents, short-term investments and restricted short-term investments
approximates their book value.
2. TRANSACTIONS WITH AFFILIATES:
As of December 31, 1999, the Limited Partnership had a payable to Tenaska
Georgia, Inc. of $53,698. During the year ended December 31, 1999, billings from
Tenaska Georgia, Inc. to the Limited Partnership for development activities were
$6,985,185, of which $6,392,478 was expensed as start-up costs, $503,373 was
capitalized as contract costs and $89,334 was capitalized as land.
The Limited Partnership Agreement provides for the payment of an annual fee
of $599,000 to the General Partner commencing on January 1, 2010, and on each
subsequent anniversary date escalating 5 percent annually until the operation of
the Facility terminates.
On September 10, 1999, the Limited Partnership entered into the Operations
and Maintenance Agreement (O&M Agreement) with an affiliate, Tenaska
Operations, Inc. (the Operator). The Operator will provide services for the
start-up, commissioning, operation and maintenance of the Facility. The Operator
will receive a fixed fee, may receive an incentive fee, may receive an
availability bonus or may pay an availability penalty on an annual basis.
3. DEVELOPMENT WORK IN PROGRESS:
The Limited Partnership entered into an Engineering, Procurement and
Construction Agreement (EPC Agreement) with Zachry Construction Corporation
(Zachry) to design, engineer, procure, expedite and supply all labor, materials
(including the gas turbines), supervision and tools for the construction of the
cogeneration plant for a total guaranteed lump-sum price of $229,064,832.
The Limited Partnership entered into a contract with General Electric
Company (GE) for the purchase of six gas turbines. This turbine contract was
assigned to Zachry on November 10, 1999. Under the terms of the turbine
contract, GE is scheduled to deliver the six gas turbines beginning
September 30, 2000, continuing through December 15, 2001. The EPC Agreement
requires that the first three gas turbine units be completed for commercial
operation by June 1, 2001, and the second three gas turbine units be completed
for commercial operation by June 1, 2002.
Zachry is to pay liquidated damages if commercial operation is not achieved
by specific dates or if the performance of the Facility does not meet minimum
contractual requirements. The aggregate liability for late completion and/or
performance shortfalls is limited to 30 percent of the guaranteed lump-sum
price.
The Limited Partnership entered into a separate $2,300,000 EPC agreement
with Willbros Engineers, Inc. to construct a natural gas pipeline from the
Facility to an interconnection point with a regional natural gas pipeline.
F-9
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1999
4. LONG-TERM DEBT:
On November 10, 1999, the Limited Partnership completed a private offering
of $275 million of 9.5 percent fixed rate Senior Secured Bonds (Bonds) with a
final maturity date of February 1, 2030. The Limited Partnership intends to
file a registration statement with the Securities and Exchange Commission
relating to the Bonds.
In order to receive certain tax incentives, the Limited Partnership entered
into a conduit financing arrangement with the Development Authority of Heard
County (the Authority). The Authority owns the Facility, the facility site and
certain related infrastructure facilities and easements (collectively, the
Properties). The Limited Partnership used the proceeds from the Bonds to
purchase certain revenue bonds issued by the Authority and enter into a lease
agreement with the Authority.
Under the lease agreement, the Authority leases the Properties to the
Limited Partnership and the Limited Partnership has agreed to make rent payments
sufficient to pay, when due, the principal of and interest on the revenue bonds
issued by the Authority. The revenue bonds are secured by a mortgage on the
Properties. The Limited Partnership has guaranteed the payment obligations of
the Authority on its revenue bonds. The revenue bonds have been issued in the
same principal amount as, and bear interest at the same rate as the Bonds and
are redeemable at the option of the Limited Partnership. The Authority
transferred the proceeds of the revenue bonds into a special construction fund,
which will be used to fund construction and related costs of the Facility. Upon
payment in full on the revenue bonds, the Properties will be conveyed to the
Limited Partnership.
Interest on the Bonds will be payable semiannually in arrears on each
February 1 and August 1, commencing August 1, 2000. Principal payments on the
Bonds will also be each February 1 and August 1, commencing February 1, 2006.
The Bonds have various restrictive covenants related to, among other things,
maintenance of a specified debt coverage ratio, maintenance of specified levels
of reserve account balances (which may be satisfied by using letters of credit),
limitations on additional debt and lease obligations, mergers, sale or purchase
of assets, and restrictions on certain payments. The Limited Partnership was in
compliance with all covenants that were operative as of December 31, 1999.
Net interest expense during the year ended December 31, 1999, was
$3,409,413. Interest capitalized as Development Work in Progress during the year
ended December 31, 1999, was $219,059.
The estimated fair value represents the amount at which the Bonds could be
exchanged in a current transaction between willing parties. At December 31,
1999, the carrying value of the Bonds approximated fair value.
On November 10, 1999, The Toronto Dominion Bank (TD) issued a $15,000,000
letter of credit to support the Limited Partnership's obligations under the
power purchase agreement. This letter of credit increases to $25,000,000 on
April 1, 2001. As of December 31, 1999, no funds have been drawn. TD may also
issue a letter of credit up to a maximum of $16,000,000 for the Limited
Partnership's debt service reserve ("DSR") obligation. As of December 31, 1999,
no DSR letter of credit had been issued.
On November 4, 1999, The First National Bank of Omaha (FNBO) issued letters
of credit in the amounts of $35,145,000 and $355,000 on behalf of Tenaska
Georgia I, L.P. and Tenaska Georgia, Inc, respectively, to support each
partner's equity funding commitments. As of December 31, 1999, no funds have
been drawn. Both of the letters of credit issued by FNBO were confirmed by
LaSalle Bank N.A.
F-10
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1999
4. LONG-TERM DEBT: (CONTINUED)
As of December 31, 1999, Tenaska Georgia, Inc. had approximately $10,000 of
cash, ($155,000) of investments in affiliated companies, and ($145,000) of
shareholder's deficit on its balance sheet. Furthermore, Tenaska Georgia, Inc.
had no other commitments for financial assistance to the Limited Partnership
other than that provided by the letter of credit in the amount of $355,000.
5. SIGNIFICANT CONTRACTS:
POWER PURCHASE AGREEMENT (PPA)
The Limited Partnership entered into the PPA with PECO Energy Co. (PECO)
whereby PECO will purchase the entire net electric power generated from the
cogeneration plant for a term of 29 years commencing on the commercial operation
of the initial gas turbine units. The PPA provides for certain fixed payments,
an availability bonus, along with variable payments. The Limited Partnership
will recognize revenue from the sale of electricity in the month energy is
delivered upon output delivered and capacity provided at rates specified in the
PPA. Availability bonuses or penalties will be recognized as revenue or expense
in the month the Limited Partnership achieves or fails to achieve the
availability targets defined in the PPA.
The Limited Partnership is to pay liquidated damages to PECO if commercial
operation is not achieved by specific dates which may be extended for certain
events. The aggregate liability for late completion of the Facility is limited
to $25,000,000.
The PPA provides PECO a contract termination option if the commercial
operation date is not achieved by the 365th day after the applicable scheduled
commercial operation date as may be extended for force majeure. Also, PECO has a
termination option if the Limited Partnership does not meet 67 percent annual
availability requirements for two consecutive years and the most recent capacity
test is less than 550 megawatts. Finally, the PPA provides PECO a termination
option for a shortened operating term after 20 years of commercial operation.
This termination option would require PECO to pay the Limited Partnership
$175,000,000.
PECO will market the power through its Power Team division to various
customers. Also, PECO is responsible for supplying all the natural gas and fuel
oil necessary to fulfill the Limited Partnership's obligations under the PPA.
LONG-TERM PARTS AND LONG-TERM SERVICE AGREEMENT (LTSA)
Tenaska, Inc., an affiliate of the Limited Partnership, entered into the
LTSA with General Electric International, Inc. (GEI), a wholly owned affiliate
of GE, whereby GEI will provide maintenance services, cover major parts
replacement and repair, inspection, and overhaul services for the gas turbines.
This LTSA was assigned to the Limited Partnership on November 10, 1999.The
Limited Partnership will pay GEI an initial fee of $110,000 in January 2001 and
$3,600,000 for the initial supply of spare parts for the gas turbines. In
addition, the Limited Partnership will be required to pay maintenance expenses
of approximately $1,038,000 in 2001 and $2,085,000 in 2002. These expenses will
include payments to GEI under the LTSA which include monthly fixed charges and
availablility bonuses or penalty payments. After 2002, these annual maintenance
expenses are assumed to escalate at 3 percent per year through January 31, 2011
and at the rate of general inflation thereafter.
F-11
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
BALANCE SHEET
(UNAUDITED)
<TABLE>
<CAPTION>
MARCH 31,
2000
------------
<S> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 9,036,892
Restricted cash and cash equivalents...................... 109,948
Short-term investments.................................... 179,620,872
Restricted short-term investments......................... 37,516,471
Interest receivable....................................... 4,535,422
Prepaid insurance......................................... 920,976
------------
Total current assets.................................... 231,740,581
DEVELOPMENT WORK IN PROGRESS................................ 38,008,696
------------
LAND........................................................ 602,529
------------
OTHER ASSETS:
Contract costs............................................ 3,379,825
Deferred finance charges.................................. 4,223,081
------------
Total other assets...................................... 7,602,906
------------
Total assets............................................ $277,954,712
============
CURRENT LIABILITIES:
Accounts payable.......................................... $ 2,655,413
Payable to affiliate...................................... 99,442
Accrued interest payable.................................. 10,159,722
------------
Total current liabilities............................... 12,914,577
------------
CONTRACT RETAINAGE PAYABLE.................................. 216,622
------------
LONG-TERM DEBT.............................................. 275,000,000
------------
Total liabilities....................................... 288,131,199
------------
COMMITMENTS AND CONTINGENCIES
PARTNERS' DEFICIT:
Tenaska Georgia, Inc...................................... (101,765)
Tenaska Georgia I, L.P.................................... (10,074,722)
------------
Total partners' deficit................................. (10,176,487)
------------
Total liabilities and partners' deficit................. $277,954,712
============
</TABLE>
The accompanying notes are an integral part of this balance sheet.
F-12
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
STATEMENTS OF OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
-------------------------
2000 1999
----------- -----------
<S> <C> <C>
EXPENSES:
Start-Up Costs:
Management fees and expenses............................ $ -- $ 2,288,452
Professional and consulting fees........................ -- 1,251,017
General and administrative expenses..................... -- 104,717
Other expenses.......................................... -- 10,068
----------- -----------
Total operating expenses............................ -- 3,654,254
----------- -----------
INTEREST EXPENSE:
Interest expense.......................................... 6,531,250 --
Interest expense capitalized.............................. (647,771) --
----------- -----------
Interest expense, net..................................... 5,883,479 --
----------- -----------
INVESTMENT INCOME........................................... 3,485,791 --
----------- -----------
NET LOSS TO PARTNERS ACCUMULATED DURING THE DEVELOPMENT
STAGE..................................................... $(2,397,688) $(3,654,254)
=========== ===========
</TABLE>
The accompanying notes are an integral part of these statements.
F-13
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
STATEMENT OF PARTNERS' DEFICIT
(UNAUDITED)
<TABLE>
<CAPTION>
TENASKA TENASKA
GEORGIA, INC. GEORGIA I, L.P. TOTAL
------------- --------------- ------------
<S> <C> <C> <C>
BALANCE, December 31, 1999............................ $ (77,788) $ (7,701,011) $ (7,778,799)
Net loss to partners accumulated
during the development stage...................... (23,977) (2,373,711) (2,397,688)
--------- ------------ ------------
BALANCE, March 31, 2000............................... $(101,765) $(10,074,722) $(10,176,487)
========= ============ ============
</TABLE>
The accompanying notes are an integral part of this statement.
F-14
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
--------------------------
2000 1999
------------ -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss to partners accumulated during the development
stage................................................... $ (2,397,688) $(3,654,254)
Adjustments to reconcile net loss to partners accumulated
during the development stage to net cash from operating
activities--
Increase in restricted cash and cash equivalents........ (109,948)
Increase in short-term investments...................... (15,999,469) --
Increase in interest receivable......................... (2,755,332) --
Decrease in prepaid insurance........................... 106,267 --
Decrease in accounts payable............................ (38,017) --
Increase in payable to affiliate........................ 45,744 3,706,310
Increase in contract retainage payable.................. 130,121 --
Increase in accrued interest payable.................... 6,531,250 --
------------ -----------
Total adjustments..................................... (12,089,384) 3,706,310
------------ -----------
Net cash from operating activities.................... (14,487,072) 52,056
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Development work in progress.............................. (15,523,885) --
Contract costs............................................ (1,144,335) --
Purchase of land.......................................... -- (52,056)
------------ -----------
Net cash from investing activities...................... (16,668,220) (52,056)
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt.................. -- --
Deferred finance charges.................................. (32,925) --
------------ -----------
Net cash from financing activities...................... (32,925) --
------------ -----------
NET DECREASE IN CASH AND CASH EQUIVALENTS................... (31,188,217) --
CASH AND CASH EQUIVALENTS, beginning of period.............. 40,225,109 --
------------ -----------
CASH AND CASH EQUIVALENTS, end of period.................... $ 9,036,892 $ --
============ ===========
SUPPLEMENTAL DISCLOSURE OF NONCASH TRANSACTIONS:
Excluded from decrease in accounts payable and development work in progress is
$2,428,724 of accrued EPC costs that were capitalized as development work in progress.
</TABLE>
The accompanying notes are an integral part of these statements.
F-15
<PAGE>
TENASKA GEORGIA PARTNERS, L.P.
(A DEVELOPMENT STAGE LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
MARCH 31, 2000
(UNAUDITED)
1. GENERAL
The financial statements included herein as of March 31, 2000 and for the
three months ended March 31, 2000 and 1999, have been prepared by Tenaska
Georgia Partners, L.P. (the Limited Partnership) without audit pursuant to the
rules and regulations of the Securities and Exchange Commission. Accordingly,
the financial statements reflect all adjustments which are, in the opinion of
management, necessary for a fair presentation of the financial results for the
interim periods. Certain information and notes normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to such rules and regulations. However,
the Limited Partnership believes that the disclosures are adequate to make the
information presented not misleading. These financial statements should be read
in conjunction with the Limited Partnership's audited financial statements and
the notes thereto for the year ended December 31, 1999.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
2. DEVELOPMENT WORK IN PROGRESS
In 1999, the Limited Partnership entered into an Engineering, Procurement
and Construction Agreement (EPC Agreement) with Zachry Construction Corporation
(Zachry) to design, engineer, procure, expedite and supply all labor, materials
(including the gas turbines), supervision and tools for the construction of the
cogeneration plant for a total guaranteed lump-sum price of $229,064,832. As of
March 31, 2000 the Limited Partnership has incurred costs of $35,253,068 under
the terms of the EPC Agreement. This amount has been capitalized and is included
on the Balance Sheet as Development Work in Progress.
As of March 31, 2000, $867,328 of interest has been capitalized and included
on the Balance Sheet as Development Work in Progress.
3. SUBSEQUENT EVENT
On April 20, 2000, Diamond Georgia, LLC, indirect, wholly owned subsidiary
of Mitsubishi Corporation (Mitsubishi) acquired 0.30 percent of Tenaska Georgia,
Inc.'s original 1.0 percent ownership interest in the Limited Partnership. In
addition, Mitsubishi acquired an indirect ownership interest of approximately
30 percent in Tenaska Georgia I, L.P., through subsidiaries of its U.S.
affiliate, Diamond Generating Corporation. In connection with these
acquisitions, on April 24, 2000, the letters of credit issued on November 4,
1999 by The First National Bank of Omaha (FNBO) in the amounts of $35,145,000
and $355,000 on behalf of Tenaska Georgia I, L.P. and Tenaska Georgia, Inc.,
respectively, to support each partner's equity funding commitments, were amended
and reduced in amount to $1,322,500 and $248,500, respectively. Mitsubishi
issued a Guaranty in the amount of $33,929,000 to replace the amount by which
the letters of credit were reduced.
F-16
<PAGE>
APPENDIX A: DEFINED TERMS
Capitalized terms used but not defined in the foregoing shall have the
following meanings:
"ACCEPTABLE CREDIT SUPPORT" means with respect to the Power Purchase
Agreement:
(a) one or more letters of credit issued by one or more domestic or foreign
banks whose long term debt is rated at the Closing Date at least BBB+ or
the equivalent by S&P or Moody's or any successor Rating Agency,
provided, that if Acceptable Credit Support is issued prior to the
Closing Date, then for the period prior to the Closing Date such
Acceptable Credit Support may be issued by The First National Bank of
Omaha, provided, that its long term debt is rated on the date of issuance
of the letter of credit no lower than BBB--or the equivalent) or
(b) a guaranty or several guaranties issued by parties or by other
creditworthy parties reasonably satisfactory to PECO.
"ACCEPTABLE LETTER OF CREDIT" means with respect to the Equity Contribution
Agreement, one or more irrevocable letters of credit in the form attached to the
Equity Contribution Agreement, issued to Collateral Agent as named beneficiary
and for the account of a Contributing Partner or an Affiliate thereof other than
the partnership, in an initial stated amount equal to the Contributing Partner's
Support Amount on the date of issuance of such letter of credit, issued by a
domestic or foreign commercial bank whose outstanding senior unsecured long-term
debt is rated at least A--or the equivalent by S&P or Moody's.
"ACCEPTABLE GUARANTY" means a guaranty in the form attached to the Equity
Contribution Agreement, in favor of the Collateral Agent, guaranteeing the
obligations of a Contributing Partner to make all of the Equity Contributions
required to be made by such Contributing Partner under the Equity Contribution
Agreement, entered into, executed and delivered by the parent company or other
Affiliate of such Contributing Partner, which parent company or other Affiliate
(a) is rated Investment Grade by S&P and Moody's, and (b) has net worth of not
less than $100,000,000.
"ACCRUED SENIOR DEBT" means, on the date on which the Commercial Operation
Certificate is delivered, the amount at least equal to principal, interest and
letter of credit fees on all Senior Debt due and payable on the Scheduled
Payment Date immediately succeeding the date of such Commercial Operation
Certificate multiplied by a fraction (a) the numerator of which is the number of
complete months since the immediately preceding Scheduled Payment Date and
(b) the denominator of which is six.
"ADDITIONAL PROJECT DOCUMENT" means:
(a) any material contract or undertaking entered into by the partnership
after the Closing Date relating to the sale of electricity from the
project or to capital improvements for, operation or maintenance of, the
project and
(b) any consent or security instrument entered into by the partnership or
any other relevant party in connection with an Additional Project
Document.
"AFFILIATE" means, with respect to any Person directly or indirectly
controlling or controlled by, or under direct or indirect common control with,
such Person. For purposes of this definition, the term "control" (including the
correlative meanings of the terms "controlled by" and "under common control
with"), as used with respect to any Person, means the possession, directly or
indirectly, of the power to direct or cause the direction of the management
policies of such Person, whether through the ownership of securities or
partnership or other ownership interests or by contract or otherwise.
Notwithstanding the foregoing, each Person owning, directly or indirectly, 10%
or more of the partnership interests in the partnership shall be deemed to be an
Affiliate of the partnership.
A-1
<PAGE>
"AFFILIATE SUBORDINATED DEBT" means Indebtedness (including any note or
other instrument evidencing the same) advanced by Affiliates of the partnership
which has been subordinated to the Senior Debt, on the terms and conditions
substantially in the form of the subordination provisions set forth in the
Collateral Agency Agreement.
"ANNUAL AVAILABILITY ADJUSTMENT" means for a contract year the amount, if
any, owed by the partnership to PECO, calculated under the Power Purchase
Agreement.
"ANNUAL AVAILABILITY PERCENTAGE" means the percentage calculated at the end
of each contract year under the Power Purchase Agreement that equals the
quotient of annual output divided by annual potential as set forth under the
Power Purchase Agreement.
"APPLICABLE LAW" means with respect to any Person, property or matter, any
of the following applicable thereto: any statute, law, regulation, ordinance,
rule, judgment, rule of common law, order, decree, Governmental Approval,
approval, concession, grant, franchise, license, agreement, directive,
guideline, policy, requirement, or other governmental restriction or any similar
form of decision of, or determination by, or any interpretation or
administration of any of the foregoing, by any Governmental Authority, whether
in effect as of the date of the Common Agreement or thereafter and in each case
as amended (including, without limitation, any pertaining to land use or zoning
restrictions).
"AUTHORIZED OFFICER" OR "AUTHORIZED REPRESENTATIVE" means (a) in the case of
any corporation or limited liability company, the chief executive officer, the
president, the chief financial officer, a vice president, the treasurer or an
assistant treasurer of such corporation or limited liability company and (b) in
the case of any general or limited partnership, any Person authorized by the
executive review committee (or such other Person that is responsible for the
management of such partnership) to take the applicable action on behalf of such
partnership or any officer (with a title specified in clause (a) above) or
Authorized Officer of such partnership's managing general partner (or such other
Person that is responsible for the management of such managing general partner).
"AVAILABILITY PERCENTAGES" means for a contract year the amounts, if any,
owed by the partnership to PECO, as calculated under the Power Purchase
Agreement.
"AVAILABILITY SCHEDULE" means the information provided in writing by the
partnership listing for each hour of the applicable day in Summer each month of
the year (1) the number of Units available to deliver energy, (2) the
partnership's good faith estimate of maximum available output from the facility
per Unit, and (3) the number of Units available which are in fuel oil capable
mode.
"AVAILABILITY TEST" means the test set forth by the EPC Contract to
demonstrate the ability of the Plant and each Unit to operate reliably.
"BASE UNIT OUTPUT" means a mode of facility operation during which (1) each
Unit in operation during such hour is operated entirely on natural gas for the
entire hour, and (2) each operating Unit generates energy for the entire hour at
an output equal to or greater than Unit Capacity for such Contract Year less 5
MW.
"BUSINESS DAY" means any day that is not a Saturday, Sunday or legal holiday
in the State of New York, or a day on which banking institutions chartered by
the State of New York, or the United States, are legally required or authorized
to close.
"CASH FLOW AVAILABLE FOR DEBT SERVICE" means, in respect of a specified
period, (a) all Revenues deposited in the Revenue Fund, if such specified period
occurred prior to the date of determination or (b) all Revenues projected to be
deposited in the Revenue Fund during such period if such specified period is to
occur subsequent to the date of determination less amounts paid, or projected to
be paid, as applicable, in respect of Operating and Maintenance Expenses,
Collateral Agent Claims, all obligations of the partnership, now or hereafter
existing, to pay administrative fees, costs, expenses, liabilities and
indemnities to the Depositary Bank under the Financing Documents, Trustee
Claims,
A-2
<PAGE>
Development Authority Trustee Claims, Power Purchase Agreement Letter of Credit
Agent Claims and Debt Service Reserve Letter of Credit Agent Claims, and under a
Working Capital Facility during such period.
"COLLATERAL AGENCY AGREEMENT" means the Collateral Agency and Intercreditor
Agreement, dated as of November 1, 1999, among the partnership, the Development
Authority Trustee, the Trustee, the Debt Service Reserve Letter of Credit Agent,
the Power Purchase Agreement Letter of Credit Agent, the Collateral Agent and
the Depositary Bank.
"COMBINED EXPOSURE" means, as of any date of calculation, the sum(,
calculated without duplication), of the following, to the extent the same is
held by or represented by a Senior Party:
(a) the aggregate principal amount of all Outstanding Bonds;
(b) 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 Required Balance);
(c) the maximum amount available to be drawn as of such date under the Power
Purchase Agreement Letter of Credit;
(d) the maximum amount available to be drawn under a Working Capital
Facility;
(e) the amount, without duplication, of any unreimbursed drawing under a
Working Capital Facility, the Debt Service Reserve Letter of Credit and
the Power Purchase Agreement Letter of Credit;
(f) the aggregate amount of all undrawn financing commitments under the
documents governing Other Senior Debt, which the creditors party thereto
have no right to terminate; and
(g) the amount, without duplication, of any unreimbursed drawing under the
documentation governing such Other Senior Debt.
"COMMERCIAL OPERATING PERIOD" means the period of time between Commercial
Operation and the termination of the O&M Agreement.
"COMMERCIAL OPERATION" means, with respect to a Unit, that it has passed
each of the following tests: (a) Functional Testing, (b) the Demonstration
Tests, (c) PECO Tests, and (d) the Availability Test, each under the EPC
Contract.
"COMMERCIAL OPERATION CERTIFICATE" has the meaning set forth under "SUMMARY
DESCRIPTION OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency Agreement--The
Project Funds--CONSTRUCTION FUND."
"COMMON AGREEMENT" means the Agreement as to Certain Undertakings, Common
Representations, Warranties, Covenants and Other Terms, dated as of November 1,
1999, among the partnership, the Trustee, the Debt Service Reserve Letter of
Credit Agent, the Power Purchase Agreement Letter of Credit Agent and the
Collateral Agent.
"COMPETITOR" means any entity which is on a list of three maintained by PECO
which cannot be amended without first providing 90 days prior written notice.
The designation of each competitor is conditioned on PECO having determined in
good faith that such Person is a competitor of PECO in the sale, brokering or
marketing of electrical energy or capacity and (a) the sale or transfer of the
facility to such Competitor would be detrimental to PECO's competitive interests
in the sale, brokering or marketing of electrical energy and capacity or (b) the
operation or maintenance of the facility by such Competitor would be detrimental
to PECO's competitive interests in the sale, brokering or marketing of
electrical energy and capacity.
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"CONSTRUCTION INTEREST ACCOUNT" means the account so designated, established
and created under the Indenture. See "SUMMARY DESCRIPTION OF PRINCIPAL FINANCING
DOCUMENTS--Indenture--Accounts--CONSTRUCTION INTEREST ACCOUNT."
"CONTRACT YEAR" means the period beginning on the Date of Commercial
Operation ending on the next May 31, each one-year period thereafter during the
Operating Term, and the period from the last June 1 during the Operating Term
until the last day of the Operating Term.
"CONTRIBUTING PARTNER" means each partner listed as a Contributing Partner
under the Equity Contribution Agreement.
"CONTRIBUTING PARTNER'S EQUITY CONTRIBUTION COMMITMENT" means, as to any
Contributing Partner, on any date, the aggregate amount such Contributing
Partner's commitment to contribute equity to the partnership.
"CONTRIBUTING PARTNER EVENT OF DEFAULT" means, as to any Contributing
Partner, any of the following events shall occur and be continuing:
(a) such Contributing Partner shall fail to make or cause to be made any
Equity Contribution when required under the Equity Contribution
Agreement;
(b) a bankruptcy event in respect of such Contributing Partner shall have
occurred and be continuing; or
(c) the Equity Contribution Agreement shall at any time for any reason cease
to be valid and binding and in full force and effect or the validity or
enforceability thereof shall be contested by any party thereto or any
party thereto (other than the Collateral Agent) shall deny that it has
any liability or obligation thereunder.
"CONTRIBUTING PARTNER SUPPORT ACCOUNT" means, as to any Contributing
Partner, an account established by the Collateral Agent upon the request of such
Contributing Partner, into which the proceeds of drawings upon such Contributing
Partner's Support Instrument shall be deposited as provided under the Equity
Contribution Agreement.
"CONTRIBUTING PARTNER SUPPORT AMOUNT" means, as to any Contributing Partner,
as of any date, such Contributing Partner's Equity Contribution Commitment,
reduced by all Equity Contributions made by such Contributing Partner prior to
such date.
"CONTRIBUTING PARTNER SUPPORT INSTRUMENT" means, as to any Contributing
Partner, an Acceptable Letter of Credit, (ii) a Cash Deposit with Support
Account Documentation as set forth in the Equity Contribution Agreement,
(iii) an Acceptable Guaranty or (iv) a Contributing Partner Substitute Support
Instrument, in each case provided by or in support of the obligations of such
Contributing Partner.
"DAILY GAS PRICE" means the amount in $/MMBtu equal to the daily midpoint of
the Daily Index Citation.
"DAILY INDEX CITATION" means for a day the citation labeled "Transco, St.
85" as published by Gas Daily for such day. If the Gas Daily index for "Transco,
St. 85" ceases to be published, such index shall be replaced by such other
comparable index mutually agreed upon by the parties, or failing such mutual
agreement, by an index as determined by arbitration. In the event that the Daily
Index Citation is not published for the day on which the natural gas is
purchased, the published index citation for the immediately preceding day for
which an index citation is published shall be used.
"DATE OF COMMERCIAL OPERATION" means the date not earlier than June 1, 2001,
on which the Initial Units have achieved Power Purchase Agreement Commercial
Operation.
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"DATE OF COMMERCIAL OPERATION OF THE FINAL UNITS" means the date not earlier
than June 1, 2002 on which all the Final Units have achieved Power Purchase
Agreement Commercial Operation.
"DEBT SERVICE" means, without duplication, all principal, interest, premium
(if any) and letter of credit fees due with respect to the bonds and all other
Permitted Indebtedness due during such period.
"DEBT SERVICE COVERAGE RATIO" means for any period the ratio of (a) Cash
Flow Available for Debt Service for such period to (b) Debt Service (other than
Debt Service for Subordinated Debt) for such period.
"DEBT SERVICE FUND" means the Debt Service Fund so designated, established
and created under the Collateral Agency Agreement for the benefit of the Senior
Parties.
"DEBT SERVICE RESERVE ACCOUNT" means the account under the Debt Service Fund
established pursuant to the terms of the Collateral Agency Agreement into which
monies are to be deposited as set forth under the heading "SUMMARY DESCRIPTION
OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency Agreement--The Project
Funds--Debt Service Fund--DEBT SERVICE RESERVE ACCOUNT."
"DEBT SERVICE RESERVE LETTER OF CREDIT" or "DEBT SERVICE RESERVE LOC" means
a letter of credit provided by the partnership to the Collateral Agent from a
financial institution rated at least "A-" by S&P and "A3" by Moody's in respect
of all or a portion of the Debt Service Reserve Required Balance.
"DEBT SERVICE RESERVE LETTER OF CREDIT AGENT" means initially, The
Toronto-Dominion Bank and any other financial institution acting as the agent
for the Debt Service Reserve Letter of Credit Issuer and the Debt Service
Reserve Letter of Credit Banks under the Debt Service Reserve Letter of Credit
Reimbursement Agreement.
"DEBT SERVICE RESERVE LETTER OF CREDIT AGENT CLAIMS" means all obligations
of the partnership, now or hereafter existing, to pay administrative fees,
costs, expenses, liabilities and indemnities under the Debt Service Reserve
Letter of Credit Reimbursement Agreement.
"DEBT SERVICE RESERVE LETTER OF CREDIT BANK" means each bank or financial
institution that becomes party to the Debt Service Reserve Letter of Credit
Reimbursement Agreement.
"DEBT SERVICE RESERVE LETTER OF CREDIT ISSUER" means initially, The
Toronto-Dominion Bank or any other financial institution providing the Debt
Service Reserve Letter of Credit pursuant to the Debt Service Reserve Letter of
Credit Reimbursement Agreement.
"DEBT SERVICE RESERVE LETTER OF CREDIT LOAN" means each drawing, and "DEBT
SERVICE RESERVE LETTER OF CREDIT LOANS" means all drawings, by the Collateral
Agent under the Debt Service Reserve Letter of Credit.
"DEBT SERVICE RESERVE LETTER OF CREDIT REIMBURSEMENT AGREEMENT"means the
Debt Service Reserve Letter of Credit and Reimbursement Agreement, dated as of
the Closing Date, among the partnership, the Debt Service Reserve Letter of
Credit Issuer, the Debt Service Reserve Letter of Credit Agent and the Debt
Service Reserve Letter of Credit Banks or another agreement providing for the
issuance of a Debt Service Reserve Letter of Credit.
"DEBT SERVICE RESERVE LOANS" means, individually or collectively, Debt
Service Reserve Bonds, Debt Service Reserve Term Loans and Debt Service Reserve
Letter of Credit Loans.
"DEBT SERVICE RESERVE TERM LOAN" means a loan resulting from a conversion of
a Debt Service Reserve Letter of Credit Loan to a Debt Service Reserve Term Loan
or a draw on the Debt Service Reserve Letter of Credit after the occurrence of a
Step-up Event.
"DEBT SERVICE RESERVE REQUIRED BALANCE" means the amount equal to the next
succeeding semi-annual scheduled payment of principal and interest due and
payable on Outstanding Bonds plus,
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if a Debt Service Reserve Letter of Credit is to be provided, an amount
corresponding to six months of interest on the maximum amount of such Debt
Service Reserve Letter of Credit, as established by the partnership and the Debt
Service Reserve Letter of Credit Agent pursuant to the Debt Service Reserve
Letter of Credit Reimbursement Agreement.
"DEBT TERMINATION DATE" means the date on which all Finance Liabilities,
other than contingent liabilities and obligations which are unasserted at such
date, have been paid and satisfied in full and all Finance Commitments have been
terminated.
"DEFAULT" means an event or condition that, with the giving of notice, lapse
of time, or failure to satisfy certain specified conditions, or any combination
thereof, would become an Event of Default.
"DELAY TERMINATION DATE OF THE INITIAL UNITS" means June 1, 2002, as such
date may be extended under the Power Purchase Agreement.
"DELAY TERMINATION DATE OF THE FINAL UNITS" means June 1, 2003, as such date
may be extended under the Power Purchase Agreement.
"DELIVERED ENERGY" for a period of time shall mean the amount of energy
expressed in MWh (rounded to the nearest whole MWh, with 0.50 MWh's being
rounded to the next highest MWh) delivered to PECO at the applicable points of
delivery during such period pursuant to an energy request.
"DEMONSTRATION TEST" means the tests to demonstrate satisfaction of the
requirements for Unit, Plant and component capabilities as set forth in the EPC
Contract.
"DISTRIBUTION CONDITIONS" has the meaning set forth under "SUMMARY
DESCRIPTION OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency Agreement--The
Project Funds--PARTNERSHIP DISTRIBUTION FUND."
"DISTRIBUTION SUSPENSE ACCOUNT" means the account under the Partnership
Distribution Fund established pursuant to the terms of the Collateral Agency
Agreement into which monies are to be deposited as set forth under the heading
"SUMMARY DESCRIPTION OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency
Agreement--The Project Funds--PARTNERSHIP DISTRIBUTION FUND."
"DTC" means The Depository Trust Company, having a principal office at 55
Water Street, New York, New York, 10041-0099, together with any Person
succeeding thereto by merger, consolidation or acquisition of all or
substantially all of its assets, including substantially all of its securities
payment and transfer operations.
"ENERGY CONTRACT BUY-OUT" means any cash payment by a purchaser of capacity
and/or energy, including by PECO, the effect of which is to result in the
termination or cancellation of, reduce future payments under, or change the term
of, the purchase contract between such purchaser and the partnership.
"ENERGY CONTRACT BUY-OUT PROCEEDS SUB-ACCOUNT"means the sub-account of the
Loss Proceeds Account established by the Collateral Agent pursuant to the
Collateral Agency Agreement into which all proceeds received by or on behalf of
the partnership in respect of an Energy Contract Buy-Out are to be deposited.
"ENERGY DELIVERY TOLERANCE" means, with respect to an hour, the greater of
1% of the energy request or 2 MWhs.
"ENERGY PAYMENTS" mean the monthly energy payments payable by PECO to the
partnership pursuant to the Power Purchase Agreement.
"EPC BUY-DOWN" means any cash payment by the EPC Contractor or the EPC
Guarantor, or by the Issuer of any performance bond securing the performance by
the EPC Contractor of the EPC
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Contract, in respect of performance liquidated damages paid under the EPC
Contract and no longer subject to refund to the EPC Contractor due to subsequent
enhanced facility performance, all under the EPC Contract.
"EPC BUY-DOWN PROCEEDS SUB-ACCOUNT" means the sub-account of the Revenue
Fund established by the Collateral Agent pursuant to the Collateral Agency
Agreement into which all proceeds received on behalf of the partnership in
respect of an EPC Buy-Down are to be deposited.
"EPC CONTRACT" means the Engineering, Procurement and Construction
Agreement, dated September 15, 1999, as amended, between the partnership (as
assignee of Tenaska Georgia I, L.P.) and the EPC Contractor.
"EPC CONTRACTOR" means Zachry Construction Corporation, a Delaware
corporation.
"EPC GUARANTOR" means H.B. Zachry Company, a Delaware corporation.
"EQUITY CONTRIBUTION" means an equity contribution required to be made by
each Contributing Partner under the Equity Contribution Agreement.
"EQUITY CONTRIBUTION AGREEMENT" means the Equity Contribution Agreement,
dated as of November 1, 1999, among the Contributing Partners, the partnership
and the Collateral Agent pursuant to which the Contributing Partners will agree
to contribute to the partnership equity aggregating up to $35.5 million from
time to time prior to the Date of Commercial Operation of the Final Units.
"EVENT OF DEFAULT" OR "EVENT OF DEFAULT" means, (a) with respect to the
Financing Documents, an "Event of Default" under the Common Agreement and
(b) with respect to the various Project Documents, the meaning ascribed to such
term in the various summaries of such Project Documents.
"EVENT OF EMINENT DOMAIN" means any compulsory transfer or taking, or
transfer under threat of compulsory transfer or taking, of a material part of
the project by any governmental authority or any Person acting with the
authority thereof for more than six months, unless such transfer or taking is
being contested by the partnership in good faith.
"EVENT OF LOSS" means any event of damage, destruction, condemnation,
seizure or appropriation of all or any part of the project.
"EXCESS LOSS PROCEEDS" means any excess Loss Proceeds on deposit in the Loss
Proceeds Account after the partnership has delivered to the Collateral Agent a
certificate certifying that the Event of Loss in respect of which such Loss
Proceeds were received has been fully repaired or restored.
"FINAL ACCEPTANCE" means the conditions listed under which the owner of the
Plant and Plant premises will issue to the EPC Contractor a certificate of final
acceptance evidencing that various work has been completed as outlined under the
EPC Contract.
"FINANCE COMMITMENT" means any commitment pursuant to any of the Financing
Documents (or any other similar agreement entered into by the partnership with
respect to the incurrence of Permitted Indebtedness (other than the bonds, the
Debt Service Reserve Letter of Credit, the Power Purchase Agreement Letter of
Credit and Subordinated Debt)) to provide credit to the partnership.
"FINANCE LIABILITIES" means all Indebtedness, liabilities and obligations of
the partnership to the Senior Parties under the Financing Documents and any
other Senior Debt.
"FINANCING DOCUMENTS" means, collectively, the bonds, the Indenture, 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 issued
thereunder, the Collateral Agency Agreement, any Working Capital Facility, the
Equity Contribution Agreement and the Security Documents.
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"FUNCTIONAL TESTING" means the operational tests of a system (i.e.,
equipment and its associated components) which verify that the controls for a
system are tested, tuned and operate efficiently and that a system works
properly and as designed under specifications and is ready for Acceptance
Testing and for normal and continuous operation.
"FUNDING DATE" means the 23rd day of each month, or, if such day is not a
business day, the next succeeding business day.
"FUNDING PERIOD" means a period commencing on a Funding Date and ending on
the day preceding the next succeeding Funding Date.
"GAS INTERCONNECT AGREEMENT" means the Interconnect, Reimbursement and
Operating Agreement, dated as of August 18, 1999, between the partnership and
Transco.
"GOVERNMENTAL APPROVALS" means all governmental approvals, authorizations,
consents, decrees, licenses, permits, waivers, privileges, filings, or
franchises with all Governmental Authorities.
"GOVERNMENTAL AUTHORITY" means the government of any federal, state,
municipal or other political subdivision in which the project is located, and
any other government or political subdivision thereof exercising jurisdiction
over the project or any party to any of the Project Documents, including all
agencies and instrumentalities of such governments and political subdivisions.
"GUARANTY" means the guarantee by the partnership of the Development
Authority's obligations on the Development Authority Bonds.
"GUARANTEED LUMP SUM PRICE" has the meaning set forth under "SUMMARY OF
PRINCIPAL PROJECT DOCUMENTS--EPC Contract--GUARANTEED LUMP SUM PRICE AND
PAYMENT."
"HOLDER" means, with respect to any bond, the Person in whose name such bond
is registered in the securities register; provided that the partnership or any
Affiliate thereof shall not be deemed a Holder with respect to any matter under
the Indenture or any other Financing Document requiring a vote of the Holders.
"INDEBTEDNESS" of any Person means, at any date, without duplication:
(a) all obligations of such Person for borrowed money,
(b) all obligations of such Person evidenced by bonds, debentures, notes or
other similar instruments (excluding "deposit only" endorsements on
checks payable to the order of such Person),
(c) all obligations of such Person to pay the deferred purchase price of
property or services (except accounts payable and similar obligations
arising in the ordinary course of business shall not be included as
Indebtedness),
(d) all obligations of such Person as lessee under capital leases to the
extent required to be capitalized on the books of such Person under GAAP
and
(e) all obligations of others of the type referred to in clause (a) through
(d) above guaranteed by such Person, whether or not secured by a lien or
other security interest on any asset of such Person.
"INDENTURE" means the Indenture of Trust, dated as of November 1, 1999,
among the partnership, the Depositary Bank and the Trustee.
"INDEPENDENT CONSULTANTS" means, collectively, the Independent Engineer and
Resource Data.
"INDEPENDENT ENGINEER" means R. W. Beck, Inc., its successors and assigns or
such other independent engineer as may be appointed under the terms of the
Common Agreement.
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"INITIAL PURCHASERS" means, collectively, Goldman, Sachs & Co. and TD
Securities (USA) Inc.
"INITIAL UNITS" means the first three Units scheduled to be placed into
Power Purchase Agreement Commercial Operation.
"INSURANCE CONSULTANT" means Marsh U.S.A., Inc.
"INTEREST SUB-ACCOUNT" means the account so designated, established and
created under the Indenture into which amounts are to be deposited in respect of
interest payments due on the bonds, described under "SUMMARY OF PRINCIPAL
FINANCING DOCUMENTS--The Indenture--Accounts."
"INVOLUNTARY BUYOUT EVENT" means the Energy Contract Buy-Out which is
provided for in the Power Purchase Agreement and any Energy Contract Buy-Out
which is certified by the partnership as not voluntarily sought by the
partnership, but into which the partnership is contractually, legally or
practically required to enter by contract, force of law or regulation. However,
in the case of a threatened (a) condemnation, expropriation or other taking,
(b) bankruptcy proceeding or (c) termination of full performance, such threat
shall be express and in writing, and the partnership shall have certified that
such threat has resulted in the bonds being placed on a negative credit watch or
in a Rating Downgrade by either Rating Agency, or, either Rating Agency shall
have indicated that any such threatened action should result in either the bonds
being placed on a negative credit watch or a Rating Downgrade.
"LEASE AGREEMENT" means the Lease Agreement, dated as of November 1, 1999,
between the Development Authority and the partnership pursuant to which the
partnership has agreed to lease from the Development Authority the facility, the
facility site and some related infrastructure facilities and easements on the
terms and conditions set forth thereunder.
"LETTER OF CREDIT SWEEP NOTICE" means a notice by the partnership, furnished
to the Collateral Agent no earlier than February 1, 2012, directing and
authorizing the Collateral Agent to apply available cash to the prepayment of
Debt Service Reserve Bonds, Debt Service Reserve Term Loans and Power Purchase
Agreement Term Loans, under the provisions of the Collateral Agency Agreement.
"LETTER OF CREDIT SWEEP PERIOD" means the period commencing on the
commencement date specified by the partnership in the Letter of Credit Sweep
Notice, and ending on the Letter of Credit Sweep Termination Date.
"LETTER OF CREDIT SWEEP TERMINATION DATE" means the earliest of the
following dates:
(a) the date of receipt by the Collateral Agent of notice from the
partnership stating that the partnership had not received any notice from
PECO of its intention to exercise its early termination right under the
Power Purchase Agreement prior to the close of business on the date
365 days before the 20th anniversary of the Date of Commercial Operation,
under Section 3.06 of the Power Purchase Agreement,
(b) the date of receipt by the Collateral Agent of notice from the
partnership stating that the partnership had not received from PECO prior
to the close of business on the date 30 days before such 20thanniversary
a letter of credit complying with the provisions of Section 3.06 of the
Power Purchase Agreement,
(c) the date of receipt by the Collateral Agent of the $175,000,000 of
proceeds from PECO, and
(d) if and to the extent that the Letter of Credit Sweep Notice permits the
partnership to revoke the same, receipt by the partnership of a notice
from the partnership revoking its Letter of Credit Sweep Notice.
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"LIEN" means any mortgage, pledge, hypothecation, assignment, mandatory
deposit arrangement with any Person owning Indebtedness of such Person,
encumbrance, lien (statutory or other), preference, priority or other security
agreement of any kind or nature whatsoever which has the substantial effect of
constituting a security interest, including, without limitation, any conditional
sale or other title retention agreement, any financing lease having
substantially the same effect as any of the foregoing and the filing of any
financing statement or similar instrument under the Uniform Commercial Code or
comparable law of any jurisdiction, domestic or foreign.
"LOSS PROCEEDS" means, individually and collectively, any Insurance Proceeds
and Eminent Domain Proceeds.
"LOSS PROCEEDS ACCOUNT" means the sub-account of the Revenue Fund
established by the Collateral Agent pursuant to the terms of the Collateral
Agency Agreement into which monies are deposited as set forth under the heading
"SUMMARY DESCRIPTION OF PRINCIPAL FINANCING DOCUMENTS--Collateral Agency
Agreement--The Project Funds--LOSS PROCEEDS ACCOUNT."
"MAJOR MAINTENANCE REQUIRED AMOUNT" means, for any Funding Period following
termination of the initial long-term parts and service contract covering the
Units described in the Independent Engineer's Report in the event that such
contract is not replaced with an agreement similar in scope to such contract, an
amount equal to the amount that would have been required to be paid by the
partnership under such contract during such Funding Period using the same
escalation formulas and indices provided for in such contract had such contract
remained in effect, as such amount may be adjusted by the partnership with the
written consent of the Independent Engineer.
"MAJOR MAINTENANCE SUB-ACCOUNT" means the sub-account of the Operating Fund
established by the Collateral Agent pursuant to the terms of the Collateral
Agency Agreement.
"MAKE WHOLE PREMIUM" means an amount equal to the Discounted Present Value
calculated for any bond subject to redemption minus the unpaid principal amount
of the initial bond; PROVIDED that the Redemption Premium shall not be less than
zero.
For purposes of this definition, the "DISCOUNTED PRESENT VALUE" of any bond
subject to redemption shall be equal to the discounted present value of all
principal and interest payment scheduled to become due in respect of such bond
after the date of such redemption, calculated using a discount rate equal to the
sum of (a) the yield to maturity on the United States treasury security having
an average life equal to the remaining average life of such bond and trading in
the secondary market at the price closest to par and (b) 50 basis points;
PROVIDED, HOWEVER, that if there is no United States treasury security having an
average life equal to the remaining average life of such bond, such discount
rate shall be calculated using a yield to maturity interpolated or extrapolated
on a straight-line basis (rounding to the nearest month, if necessary) from the
yields to maturity for two (2) United States treasury bonds having average lives
most closely corresponding to the remaining average life of such bond and
trading in the secondary market at the price closest to par.
"MATERIAL ADVERSE EFFECT" means a material adverse effect on:
(a) the business, operations, properties, assets, or condition (financial or
otherwise) of the partnership,
(b) the validity or priority of the Liens on the Collateral,
(c) the ability of the partnership to observe and perform its obligations
under the Indenture, the bonds or any of the other Financing Documents to
which it is a party, or
(d) the ability of the partnership to perform its material obligations under
the Project Documents; provided that in the case of clause (d), if each
Rating Agency then rating the bonds shall provide written confirmation
within sixty (60) days after the event or action in question that
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such event or action would not result in a Rating Downgrade, then this
clause (d) shall not be applicable.
"MATURITY DATE" means, with respect to any bond, the date on which the
principal of such bond or an installment of principal becomes due and payable as
herein or therein provided, whether at stated maturity, acceleration, redemption
or otherwise.
"NON-RENEWAL EVENT" means, with respect to any Power Purchase Agreement
Letter of Credit, such Power Purchase Agreement Letter of Credit has not been
extended or replaced within ten days prior to the stated expiration date
thereof.
"NON-SUMMER PEAK HOUR" means with respect to a Unit each of the one hour
periods during the Non-Summer months other than June, July, August and September
in which (a) PECO makes an energy request for at least the minimum load, or (b)
such Unit is on the Unit Call Schedule.
"O&M AGREEMENT" means the Operating and Maintenance Agreement, dated as of
September 10, 1999, as amended, between the partnership and the Operator.
"ON-PEAK ENERGY PRICE" means, for a day, the arithmetic average of the
entries for "Daily Price Indexes On- Peak" (measured in $/MWh) corresponding to
the price citations corresponding to the regional labels of the Southeastern
Electric Reliability Council, "Into TVA," "Into Entergy," and "Florida-Georgia
Border," as published in Daily Price Report, a McGraw-Hill publication,
PROVIDED, that if such publication or any of such citations, shall cease to be
currently available the parties shall endeavor in good faith to select an
alternative publication or alternate citations, as the case may be, and failing
such an agreed selection the alternative publication or alternative citations
will be determined by arbitration or such other publication mutually agreed in
writing by the parties.
"ONE-QUARTER HOLDERS" means Holders holding, in the aggregate, greater than
twenty-five percent (25%) principal amount of the Outstanding Bonds.
"OPERATING AND MAINTENANCE EXPENSES" means all actual cash maintenance and
operation costs to be incurred and paid with respect to the facility in any
particular period, including:
- franchise, sales, property and other similar taxes (but not taxes on or
measured by net income),
- payments under the Project Documents and the Tax Agreement,
- payments for the supply and transportation of fuels, insurance,
consumables,
- payments under any lease,
- repair and replacement costs for equipment included in the facility,
- legal fees and expenses paid by the partnership 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 general
and administrative expenses,
- all fees, expenses and other payments due to all indemnities and other
arrangements providing for the payment of amounts to the initial
purchasers of the old bonds, independent consultants, their counsel and
employees in connection with the Indebtedness of the partnership (but
excluding transaction costs associated with the offering and issuance of
bonds), and
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- expenses related to maintaining with the Rating Agencies a credit rating
for the bonds, but exclusive in all cases of:
(a) non-cash charges, including depreciation or obsolescence charges or
reserves therefor, amortization of intangibles or other bookkeeping
entries of a similar nature,
(b) interest charges and
(c) all commitment fees, underwriting fees and other similar fees due and
payable in connection with Indebtedness of the partnership. In the event
that the initial long-term parts and service contract covering the Units
described in the Independent Engineer's Report is terminated and not
replaced with an agreement similar in scope to such contract, Operating
and Maintenance Expenses shall also include an amount equal to the Major
Maintenance Required Amount for the relevant period, which amount shall
be deposited in the Major Maintenance Sub-account of the Operating Fund.
"OPERATING FUND" means the fund so designated, established and created under
the Collateral Agency Agreement used for the payment of Operating and
Maintenance Expenses.
"OPERATING TERM" means the period beginning on the Date of Commercial
Operation and ending on the 29th anniversary thereof, unless terminated earlier
as provided in the Power Purchase Agreement.
"OTHER SENIOR DEBT" means all Senior Debt, except:
(a) the Development Authority Bonds, the Lease and the Guaranty,
(b) the bonds,
(c) Indebtedness incurred under the Debt Service Reserve Letter of Credit
Reimbursement Agreement, the Power Purchase Agreement Letter of Credit
Reimbursement Agreement and any Working Capital Facility and
(d) any Subordinated Debt.
"OTHER SENIOR DEBT AGENT CLAIMS" means, as to the agent or representative in
respect of any Other Senior Debt, all obligations of the partnership, now or
hereafter existing, to pay administrative fees, costs, expenses, liabilities and
indemnities under the documentation relating to such Other Senior Debt.
"OUTSTANDING BONDS" or "OUTSTANDING" when used in connection with any bond,
means, as of the time in question, all bonds authenticated and delivered under
the Indenture, except (a) bonds theretofore cancelled or required to be
cancelled pursuant to the Indenture, (b) bonds for which provision for payment
shall have been made pursuant to the Indenture and (c) bonds in substitution for
which other bonds have been authenticated and delivered pursuant to the
Indenture.
"PARTNERS" mean Tenaska, Inc. and Tenaska Georgia I, L.P., and each other
partner added to the partnership.
"PARTNERSHIP AGREEMENT" means the Amended and Restated Limited Partnership
Agreement, dated as of April 16, 1998, among Tenaska Georgia I, L.P. and
Tenaska, Inc., as the same may from time to time be amended, modified or
supplemented.
"PARTNERSHIP DISTRIBUTION FUND" means the Fund so designated, established
and created under the Collateral Agency Agreement.
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"PARTNERSHIP SECURITY DEED" means the Deed to Secure Debt, Security
Agreement and Assignment of Rents and Leases, dated as of November 1, 1999, by
and between the partnership and the Collateral Agent, as amended from time to
time.
"PEAK DAYS AVAILABILITY" means a measurement of the facility's availability
during the five highest-priced days of the Summer Months of each year of the
Power Purchase Agreement contract term, as calculated pursuant to the Power
Purchase Agreement.
"PECO BUY-OUT PROCEEDS" means the proceeds of the cash payment required to
be made under the Power Purchase Agreement in connection with a termination by
PECO of the Power Purchase Agreement on the 20thanniversary of the Date of
Commercial Operation.
"PECO TESTS" mean the tests which will be developed encompassing the
requirements of PECO, including a test determining capacity output after
completion of each phase and tests which demonstrate various Plant and component
capabilities, including a test of the combustion turbine evaporative cooler as
set forth in the EPC Contract.
"PERMITTED INVESTMENTS" shall mean, as to any Person:
(a) securities issued or directly and fully guaranteed or insured by the
United States or any agency or instrumentality thereof (provided that the
full faith and credit of the United States is pledged in support thereof)
having maturities of not more than six (6) months from the date of
acquisition by such Person;
(b) time deposits and certificates of deposit, with maturities of not more
than six (6) months from the date of acquisition by such Person, of any
international commercial bank of recognized standing having capital and
surplus in excess of $500,000,000 and having a rating on its commercial
paper of at least A-1 or the equivalent thereof by S&P or at least P-1 or
the equivalent thereof by Moody's;
(c) commercial paper issued by any Person, which commercial paper is rated
at least A-1 or the equivalent thereof by S&P or at least P-1 or the
equivalent thereof by Moody's and matures not more than six (6) months
after the date of acquisition by such Person;
(d) investments in money market funds substantially all the assets of which
are comprised of securities of the types described in clauses (a) and
(b) above;
(e) SEC-registered money market mutual funds conforming to Rule 2a-7 of the
Investment Company Act of 1940 in effect in the United States, that
invest primarily in direct obligations issued by the United States
Treasury and repurchase obligations backed by those obligations, and
rated in the highest category by S&P and Moody's; and
(f) any dollar investment which the Collateral Agent agrees in writing shall
constitute a dollar-denominated Permitted Investment; PROVIDED that, with
respect to amounts on deposit in the Local Accounts, the dollar amount
set forth in clause (b) hereof shall equal $250,000,000 and the
references to both S&P and Moody's and the respective ratings thereof in
clauses (b), (c) and (e) shall not be applicable.
"PERSON" means any individual, sole proprietorship, corporation,
partnership, limited liability company, joint venture, trust, unincorporated
association, governmental authority or any other entity.
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"PIPELINE EPC CONTRACT" means the Fixed Price Engineering, Procurement and
Construction Contract, effective September 23, 1999, between the partnership and
Willbros Engineers, Inc., a Delaware corporation.
"PLANT" means the dispatchable electric generating facility together with
all equipment, systems, buildings and other structures, wiring, foundations,
supports, controls, piping, valves, paving and fencing, which are a part of the
work, existing structures and elements below and above ground which are to be
incorporated in the facility, and all other necessary items to construct the
electric generating facility on the Plant Premises as required by the EPC
Contract.
"PLANT PREMISES" means the site described in the EPC Contract on, over or
under which the Plant will be located.
"POWER PURCHASE AGREEMENT" OR "POWER PURCHASE AGREEMENT" means the Power
Purchase Agreement, dated as of August 24, 1999, between the partnership and
PECO.
"POWER PURCHASE AGREEMENT COMMERCIAL OPERATION" of a Unit shall be deemed to
be achieved at 00:01 hours on the day next following the day:
(a) such Unit has been declared to have a generating capacity of at least
150 MW if such Unit is one of the Initial Units or at least 146 MW if
such Unit is one of the Final Units,
(b) the Unit shall be capable of producing energy through "firing" with
natural gas,
(c) interconnection of the Unit and the delivery point shall have been
achieved,
(d) sufficient gas supply facilities and interconnection facilities shall be
in operation to accept capacity from all Units which are in commercial
operation and
(e) the partnership shall have delivered written notice to PECO that such
Unit is placed in commercial operation provided that, in the case of the
Initial Units, such date may not be earlier than June 1, 2001, and in the
case of the Final Units, such date may not be earlier than June 1, 2002.
"POWER PURCHASE AGREEMENT LOANS" means, individually or collectively, Power
Purchase Agreement Term Loans and Power Purchase Agreement Letter of Credit
Loans.
"POWER PURCHASE AGREEMENT LETTER OF CREDIT" means the letter of credit
provided by the Power Purchase Agreement Letter of Credit Issuer to be issued as
security for PECO in connection with the Power Purchase Agreement.
"POWER PURCHASE AGREEMENT LETTER OF CREDIT AGENT" means initially, The
Toronto-Dominion Bank and any other financial institution acting as the agent
for the Power Purchase Agreement Letter of Credit Issuer and Power Purchase
Agreement Letter of Credit Banks under the Power Purchase Agreement Letter of
Credit Reimbursement Agreement.
"POWER PURCHASE AGREEMENT LETTER OF CREDIT AGENT CLAIMS" means all
obligations of the partnership, now or hereafter existing, to pay administrative
fees, costs, expenses, liabilities and indemnities under the Power Purchase
Agreement Letter of Credit Reimbursement Agreement.
"POWER PURCHASE AGREEMENT LETTER OF CREDIT BANK" means each bank or
financial institution that becomes party to the Power Purchase Agreement Letter
of Credit Reimbursement Agreement.
"POWER PURCHASE AGREEMENT LETTER OF CREDIT ISSUER" means initially, The
Toronto-Dominion Bank or any other financial institution providing the Power
Purchase Agreement Letter of Credit pursuant to a Power Purchase Agreement
Letter of Credit Reimbursement Agreement.
"POWER PURCHASE AGREEMENT LETTER OF CREDIT LOAN" means a loan resulting from
the drawing on the Power Purchase Agreement Letter of Credit, other than a Power
Purchase Agreement Term Loan.
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<PAGE>
"POWER PURCHASE AGREEMENT LETTER OF CREDIT REIMBURSEMENT AGREEMENT" means
the Power Purchase Agreement Letter of Credit and Reimbursement Agreement, dated
as of the Closing Date, among the partnership, the Power Purchase Agreement
Letter of Credit Issuer, the Power Purchase Agreement Letter of Credit Agent and
Power Purchase Agreement Letter of Credit Banks or another reimbursement
agreement providing for the issuance of a Power Purchase Agreement Letter of
Credit.
"POWER PURCHASE AGREEMENT TERM LOAN" means a loan resulting from a
conversion of a Power Purchase Agreement Letter of Credit Loan to a Power
Purchase Agreement Term Loan or draw on the Power Purchase Agreement Letter of
Credit after the occurrence of a Non-Renewal Event.
"PRE-COMMERCIAL OPERATING PERIOD" means the time period between the
effective date of the O&M Agreement and the Date of Commercial Operation.
"PRINCIPAL SUB-ACCOUNT" means the account so designated, established and
created under the Indenture into which funds in the Construction Fund are
deposited under the priority described under "SUMMARY DESCRIPTION OF PRINCIPAL
FINANCING DOCUMENTS--Collateral Agency Agreement--The Project
Funds--CONSTRUCTION FUND."
"PROJECT" means the facility together with the Project Documents,
governmental approvals relating to the facility or the Project Documents and any
other item relating to the facility, including any improvements to, and the
operation of, the facility and all activities related thereto.
"PROJECT COSTS" means all costs of developing, financing, constructing,
testing and initial operation (through Power Purchase Agreement Commercial
Operation of the Final Units) of the facility, including but not limited to:
(a) all amounts payable under the Project Documents 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
partnership, all water interconnection costs payable by the partnership
and all gas interconnection and pipeline costs payable by the
partnership;
(b) all development costs, which shall be paid to, or as designated by, the
partnership;
(c) all other project-related costs, including but not limited to insurance
costs, fees and expenses payable pursuant to the O&M Agreement and
expenses to complete the construction and financing of the project,
including any project management costs and costs related to the
acquisition of all necessary easements;
(d) start-up and testing costs and initial working capital costs;
(e) initial reserve fund requirements;
(f) fees and costs payable during construction with respect to any Debt
Service Reserve Letter of Credit and any other letters of credit or
security provided under any Project Document;
(g) payments in respect of the Tax Agreement;
(h) the amount required to cash collaterize the obligations of the
partnership in respect of the security provided under the Georgia Power
Interconnection Agreement;
(i) payments to the Power Purchase Agreement Letter of Credit Issuer in
respect of amounts advanced under the Power Purchase Agreement Letter of
Credit to make payments to PECO;
(j) legal and other transaction costs and financing-related fees;
(k) any other out-of-pocket expenses related to the financing; and
(l) interest on the bonds.
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<PAGE>
"PROJECTED DEBT SERVICE COVERAGE RATIO" for any period means, on any date of
determination, a projection of the Debt Service Coverage Ratio for the
applicable time period.
"PROJECT DOCUMENTS" shall mean, collectively, the Power Purchase Agreement,
EPC Contract, O&M Agreement, the initial long-term parts and service contract
covering the Units described in the Independent Engineer's Report, Georgia Power
Interconnection Agreement, the Gas Interconnect Agreement, the Pipeline EPC
Contract, the Turbine Contract, Water Agreement, and the Lease Agreement.
"PROJECT FUNDS" means, collectively, the Construction Fund, the Debt Service
Fund, the Operating Fund, the Revenue Fund and the Partnership Distribution
Fund, including all accounts and sub-accounts thereof.
"RATING AGENCIES" means either of Moody's or S&P or if either shall cease to
rate securities of the type equivalent to the bonds, another nationally
recognized rating agency.
"RATING DOWNGRADE" means a lowering or withdrawal by a Rating Agency of its
then current credit rating of the bonds.
"REDEMPTION DATE" means, with respect to the bonds, any date established
pursuant to the Indenture (or any supplemental indenture) (as the case may be)
for the redemption of such bonds.
"REDEMPTION ACCOUNT" means a non-interest bearing special purpose trust fund
established by the Trustee upon receipt from the partnership of an authorized
officer's certificate in respect of a redemption of bonds under the Indenture.
"REDEMPTION PRICE" means, with respect to the bonds, the principal amount
thereof to be redeemed in whole or in part, payable upon redemption thereof
pursuant to the Indenture, plus accrued interest thereon to the Redemption Date.
"REMAINING REQUIRED EQUITY CONTRIBUTION" means the amount required as of the
Date of Commercial Operation of the Final Units to pay the required amounts
under the Collateral Agency Agreement, less the aggregate of the amounts then on
deposit in or credited to the Construction Fund.
"REQUIRED RATING" means a rating of at least "A-" by S&P and "A3" by
Moody's.
"REQUIRED SENIOR PARTIES" means the affirmative vote of 51% of the Combined
Exposure.
"RESERVATION PAYMENTS" shall mean the monthly reservation payments payable
under the Power Purchase Agreement by PECO to Tenaska.
"RESTRICTED PAYMENT" means, with respect to any Person, (a) the declaration
or payment of distributions, dividends or any other payment made in cash,
property, obligations or other securities or (b) any payment of the principal of
or interest on any Affiliate Subordinated Debt, in each case from cash,
investments, securities or other funds from time to time in the Distribution
Suspense Account.
"REVENUE FUND" means the fund so designated, established and created by the
deposit of various amounts as set forth under the Collateral Agency Agreement
after the Date of Commercial Operation of the final three Units.
"REVENUES" means the partnership's revenues or income calculated on a cash
basis and received under the terms of the relevant Project Documents, including,
without limitation,:
(a) proceeds of an Event of Loss, any EPC Buy-Down, any Energy Contract
Buy-Out not required to be used to redeem the Senior Debt, and any draws
with respect to any Working Capital Facility;
(b) refunds or returns of any amounts previously paid for Operating and
Maintenance Expenses of the partnership;
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<PAGE>
(c) any income from the investment of monies in any fund pursuant to the
Collateral Agency Agreement and
(d) any income received as holder of the Development Authority Bonds;
PROVIDED that for purposes of calculating any Debt Service Coverage Ratio,
"Revenues" shall not include draws with respect to any Working Capital Facility
or any proceeds of any Event of Loss, EPC Buy-Down or Energy Contract Buy-Out.
"SCHEDULED DATE OF COMMERCIAL OPERATION" means June 1, 2001, subject to any
extension of such date under the EPC Contract.
"SCHEDULED DATE OF COMMERCIAL OPERATION FOR THE FINAL UNITS"means June 1,
2002, subject to any extension of such date in accordance with under the EPC
Contract.
"SCHEDULED PAYMENT DATE" means, with respect to any bond, each February 1
and August 1, commencing August 1, 2000.
"SECURITY AGREEMENT" means the Partnership Assignment and Security
Agreement, dated as of the Closing Date between the partnership and the
Collateral Agent.
"SECURITY DOCUMENTS" means, collectively, the Indenture, the Lease
Agreement, the Development Authority Bonds, the Guaranty, the General Partner
Pledge and Security Agreement and the Limited Partner Pledge and Security
Agreement, the Security Agreement, the Collateral Agency Agreement, the
Partnership Security Deed, the Development Authority Security Deed and each
Third Party Consent.
"SEMI-ANNUAL PERIOD" means a period commencing on a Scheduled Payment Date
and ending on the day preceding the next Scheduled Payment Date; provided that
the first Semi-Annual Period shall mean the period commencing on the Closing
Date and ending on the day preceding the first Scheduled Payment Date.
"SENIOR DEBT" means Permitted Indebtedness other than Subordinated Debt and
indebtedness described in clause (vi) of the definition of Permitted
Indebtedness.
"SENIOR PARTIES" means collectively, the Trustee, the Collateral Agent, the
Debt Service Reserve Letter of Credit Agent, the Power Purchase Agreement Letter
of Credit Agent, a Working Capital Agent, any holder of Senior Debt (other than
the bonds) and any other Person that becomes a secured party under any Security
Document.
"SHELF REGISTRATION STATEMENT" means a registration statement providing for
the registration of, and the sale on a continuous or delayed basis by the
holders of, all of the Registrable Securities, pursuant to Rule 415 or any
similar rule that may be adopted by the SEC.
"STATED MATURITY" means, when used with respect the bonds or any installment
of principal thereof or payment of interest thereon, the date specified in such
bond as the fixed date on which such bond or all such installment of principal
or payment of interest is due and payable.
"STEP-UP EVENT" means in respect of any Debt Service Reserve Letter of
Credit:
(a) such Debt Service Reserve Letter of Credit has not been extended or
replaced within 45 days prior to the stated expiration date of such Debt
Service Reserve Letter of Credit, or
(b) the credit rating of the Debt Service Reserve Letter of Credit Provider
is less than the Required Rating and such that 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 such Debt Service Reserve
Letter of Credit in an amount
A-17
<PAGE>
sufficient to fund the Debt Service Reserve Account up to the Debt
Service Reserve Required Balance.
"SUBORDINATED DEBT" means, individually and collectively, Third Party
Subordinated Debt and Affiliate Subordinated Debt.
"SUBORDINATED DEBT ACCOUNT" means the sub-account of the Debt Service Fund
established by the Collateral Agent pursuant to the Collateral Agency Agreement.
"SUBSTITUTE SUPPORT INSTRUMENT" means, as to any Contributing Partner,
(i) an:
(a) an Acceptable Letter of Credit,
(b) a Cash Deposit with Support Account Documentation as set forth in the
Equity Contribution Agreement, or
(c) an Acceptable Guaranty, in each case provided by or in support of the
obligations of such Contributing Partner.
"SUMMER AVAILABILITY ADJUSTMENT" means for each contract year the amount, if
any, owed by the partnership to PECO, calculated under the Power Purchase
Agreement.
"SUMMER AVAILABILITY PERCENTAGE" means the availability determination
calculated at the end of September for the summer months of each contract year
beginning in June under the formula set forth in the Power Purchase Agreement.
"SUMMER PEAK HOURS" shall mean each of the one hour periods during the
months of June, July, August and September of each contract year as such peak
availability periods are specified from time to time by PECO under the Power
Purchase Agreement.
"SUPPORT ACCOUNT DOCUMENTATION" means documentation in form and substance
reasonably satisfactory to the Collateral Agent which (a) grants the Collateral
Agent, for the benefit of the Senior Parties, a security interest in any Cash
Deposit or other amounts deposited in the Contributing Partner Support Account
and (b) contains the agreement of such Contributing Partner to transfer
additional cash to the Contributing Partner Support Account in the event that
the aggregate market value of the Permitted Investments (plus any cash deposits)
in such Contributing Partner Support Account is, at any time, less than such
Contributing Partner's Support Amount.
"TAX AGREEMENT" means the Ad Valorem Taxation Agreement, dated July 30,
1999, among the partnership, the Board of Commissioners of Heard County and the
Board of Tax Assessors of Heard County.
"THIRD PARTY ENGINEER" means a single independent engineer designated
pursuant to the Common Agreement from a pre-established list to consider and
decide a dispute between the partnership and the Independent Engineer.
"THIRD PARTY SUBORDINATED DEBT" means Indebtedness (and each note or other
instrument evidencing the same) advanced by Persons who are not Affiliates of
the partnership which has been subordinated to the Senior Debt, on the terms and
conditions substantially in the form of the subordination provisions set forth
in the Collateral Agency Agreement.
"TRIGGER EVENT" means:
(a) an Event of Default under the Indenture and an acceleration of all
indebtedness issued thereunder,
(b) an Event of Default under the Debt Service Reserve Letter of Credit
Reimbursement Agreement and an acceleration of all indebtedness incurred
thereunder,
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<PAGE>
(c) an Event of Default under the Power Purchase Agreement Letter of Credit
Reimbursement Agreement and an acceleration of all indebtedness incurred
thereunder or
(d) an event of default under any other Senior Debt instrument and an
acceleration of all of the Indebtedness issued thereunder in an aggregate
principal amount in excess of $10 million; provided that, in each case,
the Collateral Agent has, upon direction from the Required Senior
Parties, declared such event to be a "Trigger Event."
"TRUST INDENTURE ACT" shall mean the Trust Indenture Act of 1939, or any
successor thereto, and the rules, regulations and forms promulgated thereunder,
all as the same shall be amended from time to time.
"TRUSTEE CLAIMS" means all obligations of the partnership, now or hereafter
existing, to pay administrative fees, costs, expenses, liabilities and
indemnities under the Indenture.
"TURBINE CONTRACT" means the Contract for Purchase, dated August 27, 1999
between General Electric and the partnership, as assignee of Tenaska Georgia I,
L.P.
"UNIT" means one of the six General Electric PG7241 (FA) heavy-duty single
shaft gas turbine-generators, nominal 175 MW ratings at ISO conditions (59(o)F,
sea level) purchased by the partnership pursuant to the Turbine Contract.
"UNIT CALL SCHEDULE" means with respect to a Unit, the schedule detailing
the hours of the following day in which such Unit is requested to be available
under the dispatch principles set forth in the Power Purchase Agreement and
detailing during which hours, if any, during the following day such Unit is to
be in a standby mode.
"UNIT CAPACITY" means for the first year the greater of (a) Contract
Capacity divided by the number of Units that are in commercial operation or (b)
150 MW, and for each year thereafter the greater of (a) Contract Capacity
divided by six (6) or (b) 146 MW.
"UNRESTRICTED ACCOUNT" means an account established by the partnership which
shall be funded with amounts withdrawn from the Partnership Distribution Fund
and otherwise available to the partnership.
"WATER AGREEMENT" means the Water Purchase Agreement, dated February 25,
1999, between the partnership and the Water Authority.
"WATER TERM" means the period of time lasting 30 years from the
partnership's first purchase of water pursuant to the Water Agreement.
"WORKING CAPITAL AGENT" means any financial institution serving as agent
under a Working Capital Facility and provider of amounts available thereunder.
"WORKING CAPITAL FACILITY" means a working capital facility in an amount up
to $10,000,000 used for the payment of Operating and Maintenance Expenses in
connection with the project.
"WORKING CAPITAL FACILITY PROVIDER" means the provider of the Working
Capital Facility.
A-19
<PAGE>
APPENDIX B
INDEPENDENT ENGINEER'S REPORT
TENASKA GEORGIA FACILITY
[LOGO]
<PAGE>
APPENDIX B
INDEPENDENT ENGINEER'S REPORT
TENASKA GEORGIA FACILITY
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
--------
<S> <C>
PROJECT PARTICIPANTS........................................ B-2
The Sponsor............................................... B-2
The EPC Contractor........................................ B-2
The Operator.............................................. B-3
LTSA Provider............................................. B-3
THE PROJECT................................................. B-3
The Facility Site......................................... B-4
Subsurface Conditions................................... B-6
Environmental Site Assessment........................... B-7
Description of the Facility............................... B-8
Mechanical Equipment and Systems........................ B-8
Environmental Systems and Control Equipment............. B-8
Structural.............................................. B-9
Electrical and Control Systems.......................... B-9
Off-Site Requirements................................... B-10
Review of Technology...................................... B-11
7FA Production Problems and Status...................... B-13
Summary................................................. B-14
Heat Rate and Output...................................... B-14
Heat Rate............................................... B-14
Output.................................................. B-14
Summary................................................. B-15
Availability.............................................. B-15
Operating Experience.................................... B-15
Availability Under the PPA.............................. B-16
Summary................................................. B-17
Estimated Useful Life of the Facility..................... B-17
Construction Schedule..................................... B-17
Performance Guarantees and Acceptance Tests............... B-18
Performance Guarantees.................................. B-18
Functional Testing...................................... B-19
Acceptance Testing...................................... B-19
Owner Tests............................................. B-19
PECO Tests.............................................. B-20
Summary................................................. B-21
Liquidated Damages........................................ B-21
Status of Permits and Approvals........................... B-22
Corps Permit............................................ B-22
Air Permit.............................................. B-22
Stormwater Discharge Permit............................. B-23
Pending Changes in Regulations.......................... B-23
</TABLE>
B-i
<PAGE>
APPENDIX B
INDEPENDENT ENGINEER'S REPORT
TENASKA GEORGIA FACILITY
TABLE OF CONTENTS
(CONTINUED)
<TABLE>
<CAPTION>
PAGE
--------
<S> <C>
THE FINANCING OF THE PROJECT................................ B-24
Facility Construction Cost................................ B-24
Sources and Uses of Funds................................. B-25
PROJECTED OPERATING RESULTS................................. B-26
Annual Operating Revenues................................. B-26
Reservation Payments.................................... B-26
Energy Payments......................................... B-26
Replacement Energy Payment.............................. B-26
Start Charges........................................... B-26
Miscellaneous Charges................................... B-27
Availability Incentive Payment.......................... B-27
Availability Adjustments Payments....................... B-27
Fuel Adjustment Payments................................ B-27
Annual Operating Expenses................................. B-27
Fuel Cost............................................... B-27
Operation and Maintenance Expenses...................... B-27
Other Expenses.......................................... B-29
Annual Debt Service....................................... B-29
Debt Service Coverage..................................... B-29
Sensitivity Analyses...................................... B-30
Summary Comparison of Projected Operating Results......... B-30
Liquidated Damages Analyses............................... B-31
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS USED IN THE
PROJECTION OF OPERATING RESULTS........................... B-31
CONCLUSIONS................................................. B-32
EXHIBITS
EXHIBIT B-1 Base Case.................................. B-35
EXHIBIT B-2 Sensitivity Case A--Reduced Availability... B-39
EXHIBIT B-3 Sensitivity Case B--Increased Heat Rate.... B-43
EXHIBIT B-4 Sensitivity Case C--Increased Operating
Expenses............................................... B-47
EXHIBIT B-5 Sensitivity Case D--Increased Inflation.... B-51
EXHIBIT B-6 Sensitivity Case E--Reduced Contract
Capacity............................................... B-55
EXHIBIT B-7 Sensitivity Case F--Zero Dispatch.......... B-59
EXHIBIT B-8 Sensitivity Case G--Increased Capacity
Factor................................................. B-59
</TABLE>
COPYRIGHT -C- 1999, R.W. BECK, INC.
ALL RIGHTS RESERVED
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<PAGE>
November 3, 1999
Tenaska Georgia Partners, L.P.
1044 N. 115 Street
Suite 400
Omaha, Nebraska 68154-4446
SUBJECT: INDEPENDENT ENGINEER'S REPORT ON THE TENASKA GEORGIA FACILITY
Ladies and Gentlemen:
Presented herein is the report (the "Report") of our review and analysis of
the Tenaska Georgia 936 megawatt ("MW") simple-cycle plant being developed in
Heard County, Georgia (the "Facility"). The Facility includes dual fuel
combustion turbine generators ("CTGs") guaranteed at 156.4 MW each at the
guarantee point when firing natural gas. The Facility will be leased by Tenaska
Georgia Partners, L.P. (the "Partnership") and operated by Tenaska
Operations, Inc. (the "Operator") under the terms of an Operations and
Maintenance Agreement dated September 10, 1999 (the "O&M Agreement").
The Facility is to be comprised of six simple-cycle General Electric ("GE")
Frame 7FA CTGs and associated auxiliary equipment with a combined rating of 936
MW when firing natural gas, and 983 MW when firing No. 2 oil. The Facility is to
be constructed on a 101-acre tract of land in Heard County, Georgia (the
"Facility Site"). The Facility is being designed and constructed by Zachry
Construction Corporation (the "EPC Contractor") pursuant to a fixed price
engineering, procurement and construction contract (the "EPC Contract"). The
major maintenance of the CTGs is to be performed by General Electric
International, Inc. ("GE International") under the Long Term Parts and Long Term
Service Contract dated June 24, 1999 (the "LTSA").
The Partnership has developed the Facility and will transfer the Facility
Site and the Facility under development to the Development Authority of Heard
County, GA (the "Authority"). The Authority will then lease it back to the
Partnership, which will construct, commission, operate and maintain it on behalf
of the Authority. Construction, testing, start-up and initial operation of the
Facility will be funded through the issuance by the Partnership of $275,000,000
in aggregate principal amount of 9.50% Senior Secured Bonds Due 2030 (the
"Bonds"). The proceeds from the sale of the Bonds will be used to purchase an
equal amount of the Authority's Taxable Industrial Development Revenue Bonds,
Series 1999 (Tenaska Georgia Partners, L.P. Project). The proceeds from the sale
of the Bonds to the Partnership will be placed in a construction fund and,
together with equity contributions from the Partnership and net operating
revenues from the Facility's operations prior to commercial operation of the
Final Units, as described later herein, will be used to: (1) pay the costs of
development, construction, start-up, testing, and initial operation of the
Facility; (2) pay the interest on the Bonds until June 1, 2002; and (3) pay
certain financing costs.
The Partnership has executed a 29-year Power Purchase Agreement with PECO
Energy Company ("PECO") dated August 24, 1999 (the "PPA") under which it will
sell electrical capacity and energy on a dispatchable basis. Under the terms of
the PPA, natural gas and No. 2 fuel oil will be supplied by PECO to the Gas
Delivery Point and the Fuel Oil Unloading Facilities, respectively. Natural gas
will be delivered to the Facility Site by a lateral which will be constructed
and leased by the Partnership.
During the preparation of our Report, we have reviewed the executed
agreements related to the construction and operation of the Facility and to
which the Partnership is a party. The agreements which we have reviewed set
forth the obligations of each of the parties with respect to the construction
and operation of the Facility. As Independent Engineer, we have made no
determination as to the validity and enforceability of these agreements;
however, for the purposes of this Report, we have assumed these agreements will
be fully enforceable in accordance with their terms and that all parties will
comply with the provisions of their respective agreements.
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In addition, we have reviewed: (1) the design criteria (the "Scope of
Work"), which is part of the EPC Contract, and preliminary general engineering
plans and specifications for the Facility; (2) the status of permits and
approvals; (3) major permits, permit applications, and environmental site
assessment reports; (4) the projected levels of production of the Facility;
(5) the projected operation and maintenance expenses; (6) the projected
revenues; and (7) the construction costs and schedule. Based on our review, we
have prepared a projection of revenues, expenses, and debt service coverage
ratios on the Bonds (the "Projected Operating Results").
During the course of our review of the Facility, we have visited and made
general observations of the Facility Site. The general field observations were
visual, above-ground examinations of selected areas, which we deemed adequate to
comment on the existing condition of the Facility Site and which were not in the
detail which would be necessary to reveal conditions with respect to geological
or environmental conditions, or the conformance with agreements, codes, permits,
rules, or regulations of any party having jurisdiction with respect to the
Facility.
Certain analyses relied upon for the purposes of this Report, specifically
those related to the economic dispatch of electric energy, were performed by
others and relied upon by us. The projections for electric energy and economic
dispatch were prepared by Resource Data International, Inc. ("RDI"), whose
report is included as Appendix C to the Offering Circular.
PROJECT PARTICIPANTS
The sponsors, contractors, vendors and other service providers responsible
for the development, design, construction, and operation of the Facility are
discussed below. Construction will be performed pursuant to the EPC Contract by
the EPC Contractor. Under the terms of the EPC Contract, the EPC Contractor will
be responsible for the performance of all subcontractors and all vendors
providing equipment for the Facility, except for the natural gas lateral
pipeline, to be constructed by Willbros Engineers, Inc. under a fixed price
contract. Under the O&M Agreement, the Operator will manage the performance of
GE International under the LTSA and all other subcontractors which it engages
related to the operation of the Facility. Based on our review, we are of the
opinion that the EPC Contractor, the Operator, and GE International have
previously demonstrated the capability to perform their responsibilities under
the EPC Contract, the O&M Agreement, and the LTSA, respectively.
THE SPONSOR
Tenaska Inc. ("Tenaska") is an energy project development and management
services organization specializing in independent power generation, electricity
and natural gas marketing and natural gas supply and transportation systems.
Tenaska's affiliates have approximately 4,900 MW of energy-related projects in
operation, construction, and development throughout the United States and
internationally. Tenaska is headquartered in Omaha, Nebraska with additional
offices in Arlington, Texas and Calgary, Alberta.
THE EPC CONTRACTOR
The EPC Contractor is responsible for the EPC Contract, which includes the
design, engineering, procurement, construction, start-up, and testing of the
Facility in accordance with the EPC Contract. The EPC Contractor, a subsidiary
of H.B. Zachry Company ("Zachry"), has contracted with Utility Engineering to
perform the engineering, design, and procurement specifications for the
Facility. Both Zachry and Utility Engineering independently have extensive
experience on similar projects, to engineer, procure, and construct power plant
projects. The EPC Contractor has experience on similar projects both
domestically and internationally.
Included in the EPC Contractor's design-construct portfolio are: (1) the
Tenaska IV Texas Partners, Ltd. Plant, a 263 MW gas-fired combined cycle
cogeneration facility in Cleburne, Texas, which
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utilizes one Westinghouse 501F CTG, a three pressure level, supplementary fired
HRSG, and a Westinghouse reheat steam turbine; (2) the Tenaska Gateway
Generating Station, a 845 MW combined cycle facility located in Rusk County,
Texas, which utilizes three GE 7FA CTGs, three pressure supplemental fired
HRSGs, and a GE reheat steam turbine; (3) the E.I. Mid-Georgia Kathleen Project,
a 250 MW combined cycle cogeneration facility in Georgia which utilized two
Westinghouse 501D5A CTGs with dry low NO(X) combustors, a 100 MW non-reheat MHI
steam turbine generator and two Nooter/Erikson HRSGs; and (4) the Batesville
Combined Cycle Project, an 837 MW combined cycle facility in Batesville,
Mississippi, which utilizes three Westinghouse 501F CTGs, three pressure level,
reheat, supplementary fired Nooter/Erikson HRSGs, and ABB Power Generation
reheat steam turbines.
THE OPERATOR
The Operator, organized under Delaware law, is a wholly owned subsidiary of
Tenaska and was formed to provide operations and maintenance services to
electric generating facilities owned and managed by affiliates of Tenaska. The
Operator has been designated as the operations and maintenance contractor for
the Facility.
The Operator will provide personnel, procedures, training, administrative,
management, and professional and technical services necessary for the start-up,
commissioning, operation and maintenance of the Facility. In performing its
responsibilities, the Operator will rely upon the experience of its personnel
which have related experience in every aspect of power generation, including
with architects, engineers, manufacturers, and electric generating companies.
Currently, Tenaska manages and administers third-party operation and maintenance
contracts with North American Energy Services, a subsidiary of Illinova, which
provides manpower for the operation and maintenance services for the Paris (223
MW), Ferndale (245 MW), and Cleburne (263 MW) combined cycle cogeneration
plants. The Operator has contracts to operate the Frontier (830 MW) and Gateway
(845 MW) combined cycle plants. The Facility is to be Tenaska's sixth facility
for which it will be responsible.
LTSA PROVIDER
GE International is a wholly-owned affiliate of General Electric Company and
will be the LTSA provider. Its principal office is in Wilmington, Delaware. GE
International has provided operating and maintenance services under contracts
similar to the LTSA worldwide. GE International currently has over 1,500
employees engaged in over 100 contracts in 22 countries. It reports that it has
a current capacity under contracts like the LTSA of 16,860 MW and total
contracted capacity for operating and maintenance services of 27,335 MW. These
contracts include 87 GE Frame 7s, 35 GE Frame 6s, and 13 GE Frame 9s, for a
total of 135 combustion turbines totaling 21,183 MW.
THE PROJECT
This section describes the Facility Site and the environmental site studies,
the equipment and systems, the technology, the reliability and availability, the
estimated useful life, the construction schedule, the performance guarantees and
tests, and the status of permits and approvals for the Facility.
The Facility is to be comprised of six natural gas-fired simple-cycle CTGs
(each a "Unit") and will sell electrical capacity and energy to PECO under the
PPA. The Facility will be constructed in two phases. The first phase includes
CTG Units 1, 2, and 3 (the "Initial Units"), and the second phase includes CTG
Units 4, 5, and 6 (the "Final Units"). The CTGs installed by the EPC Contractor
under the EPC Contract will be capable of net electrical output at the operating
conditions defined in the EPC Contract as summarized in Table 1 and discussed in
greater detail in other sections of this Report.
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TABLE 1
CTG NET ELECTRICAL OUTPUT
(MW)
<TABLE>
<CAPTION>
NATURAL NO. 2 FUEL OIL
OPERATING CONDITION GAS FUEL WITH WATER INJECTION
------------------- -------- --------------------
<S> <C> <C>
Guarantee Point(1)................................ 943 992
Summer(2)......................................... 928 978
Winter(3)......................................... 1,082 1,113
</TABLE>
------------------------
(1) At 94 DEG.F dry bulb, 74 DEG.F wet bulb and no degradation.
(2) At 95 DEG.F dry bulb, 78 DEG.F wet bulb and no degradation.
(3) At 20 DEG.F dry bulb, 60 DEG.F wet bulb and no degradation.
The GE Frame 7FA CTGs will be equipped with dry low-NO(X)("DLN") combustors
to control the formation of oxides of nitrogen. Electric generators will be
rated at 18 kV and deliver electricity to the 500 kV switching substation
through three winding step-up transformers. Support auxiliary systems are to be
provided as required to ensure safe, reliable operation.
The Facility's process and potable water needs will be supplied by the Heard
County Water Authority (the "HCWA") via a connection to the local HCWA water
supply system. The Facility will be interconnected for natural gas with
Transcontinental Gas Pipe Line Corporation's ("Transco") natural gas pipeline
system. Sanitary waste will be disposed of in an on-site septic system. Process
wastewaters and stormwater are to be treated as necessary and discharged to
Hilly Mill Creek.
THE FACILITY SITE
The Facility, shown in Figure B-1, is to be constructed on a tract of
approximately 101 acres of land located about 9 miles northeast of Franklin, in
Heard County, Georgia, less than one half mile from the Coweta County line. The
Partnership has advised that Tenaska has purchased the Facility Site and
additional property adjacent to the Facility Site. The Partnership will purchase
the Facility Site from Tenaska simultaneously with the issuance of the Bonds.
The Partnership will also have the option to purchase from Tenaska an additional
parcel of approximately 8 acres for construction of the 500 kV switchyard.
Approximately 46 acres of the Facility Site will be developed for construction
of the Facility and an additional three-acre portion will be used for
construction of the gas pipeline. The remaining 52 acres, consisting of three
parcels on the south and southwest sides of the Facility Site, will be left
undeveloped as part of a wetlands mitigation plan. In accordance with the
conditions of its wetlands permit, the Partnership will file restrictive
covenants with Heard County for the portion of the Facility Site needed to
satisfy the wetland mitigation plan. This will occur after title to the land is
transferred to the Partnership and transferred by the Partnership to the
Authority.
In addition to the Facility Site, the Partnership will also secure rights to
other surrounding property to support construction of the Facility and the
lateral gas pipeline that is to connect the Facility to the Transco mainline. On
the north and northeast side of the Facility Site, the Partnership will obtain
an 80-foot wide permanent access easement from Tenaska for the access road to
the Facility from George Brown Road. To provide additional construction parking
and lay-down space, the Partnership will also obtain a temporary lease from
Tenaska for a 13-acre parcel of land on the north side of George Brown Road at
the intersection with Joe Stephens Road. For construction of the lateral gas
pipeline connecting the Facility to the Transco mainlines approximately one mile
south of the Facility Site, the Partnership will obtain permanent easements for
the remaining length of the pipeline, and temporary construction easements for
installation of the pipeline.
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The Facility Site is bordered on north and east by forested land owned by
Tenaska. A 500 kV electrical transmission line also runs in a right of way
adjacent to the east side of the Facility Site from north to south. Beyond the
Tenaska property on the north is George Brown Road, and on the east is light
residential property. Farther east of the Facility Site is Joe Stephens Road.
Forested land, wetlands and tributaries of Hilly Mill Creek border the Facility
Site on the south and southwest. To the west are forest, light residential
property and Hilly Mill Creek.
The Facility Site consists of forested land with slightly rolling topography
and a general slope down towards the wetlands on the southwest. Existing grade
elevations vary from El 800 ft in the northeast portion of the Facility Site to
El 765 ft in the south and southwest portions of the Facility Site. The Facility
is to be constructed in the northern portion of the Facility Site, west of the
500 kV transmission line.
The principal access to the Facility will be by road. The Facility Site is
approximately 40 miles southwest of Atlanta, Georgia, which is the nearest major
city with an airport. From Atlanta, access to the Facility Site is obtained by
following Interstate Highway 85 south to Georgia State Highway 34 west through
Newnan, Georgia. Approximately 10 miles west of Newnan just before the Heard
County line, turn north on Joe Stephens Road for approximately 1.4 miles and
then west on George Brown Road approximately 900 feet where a new access drive
will be constructed southwest from George Brown Road to the Facility Site. Joe
Stephens Road is a paved road, and George Brown Road is currently a gravel road,
which will be widened and paved by Heard County to serve the Facility.
Construction was in progress on the George Brown Road improvements when we
visited the Facility Site.
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FIGURE B-1
TENASKA GEORGIA FACILITY
FACILITY LAYOUT
INSERT SEPARATE PDF FILE OVER THIS PAGE
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A flood plain evaluation was prepared by Rindt-McDuff Associates, Inc. of
Marietta, Georgia ("Rindt-McDuff") and documented in its letter dated
September 30, 1999. Rindt-McDuff's evaluation is based on data obtained from the
Heard County Planning and Zoning Department, which consists of the Department of
Housing and Urban Development Federal Insurance Administration Flood Hazard
Boundary Maps Dated April 6, 1976 (the "HUD Maps"), and the Facility layout and
existing site topographical survey information provided by the Partnership.
Rindt-McDuff notes that a small area of the western portion of the Facility
comprising the earthen dike that serves as a containment for the fuel oil tank
appears to protrude into the shaded area designated as a special flood hazard
area on the HUD Maps, which the Federal Emergency Management Agency designated
as Zone A, within the 100-year flood plain, by issuing a special notice letter
in October 1986. However, at that time FEMA did not do any additional hydraulic
studies or analyses to refine the boundaries of the shaded area or to establish
what the actual 100-year flood water levels would be. Based on their review of
the surface elevations shown on the existing site topographic survey, which
shows that the portion of the Facility in question is located on an area of the
Facility Site that is elevated significantly above the tributary of Hilly Mill
Creek, Rindt-McDuff concluded that the approximate flood boundary shown on the
HUD Maps was in error in this area and certified that the proposed construction
will not result in any conflict with the 100-year floodplain.
SUBSURFACE CONDITIONS
We have reviewed an EMCON ("EMCON") report titled "PRELIMINARY GEOTECHNICAL
EVALUATION HEARD COUNTY GEORGIA POWER GENERATION FACILITY HEARD COUNTY,
GEORGIA", and dated June 1998 (the "Subsurface Report"). The Subsurface Report
is included as Attachment IV to Exhibit A of the EPC Contract. The subsurface
investigation performed by EMCON for the Facility Site included 10 soil borings
drilled up to 65 feet deep, two percolation tests, and laboratory tests on soil
samples taken during the drilling. The Subsurface Report includes a site
location plan, boring location plan, boring logs, and laboratory test results.
The report also contains an analysis of the data obtained in the field,
recommendations for suitable foundation types, allowable soil bearing pressures,
and some recommendations for construction activities including impacts of the
apparent high groundwater table and suitability of the onsite materials for use
as structural fill.
The boring location plan shows the boring locations superimposed on a layout
of the Facility. This layout is not referenced to survey coordinates or to
existing property boundaries or landmarks and some revisions have been made to
the layout since 1998. The EPC Contract Exhibits also contain drawing
0990947-000S001, Rev C, which presents the layout of the equipment and
structures to be constructed. Based on the shape of the site, the latest layout
of the equipment, and the switchyard layout in relation to the existing overhead
transmission line, it appears that the soil borings were drilled in the general
area of the major equipment and structures that are to be constructed.
The boring logs presented in the Subsurface Report indicate that the soils
underlying the Facility Site are comprised of several layers of soil most of
which are sand with varying amounts of silt, clay and traces of mica. The
density of the sand layers varies and does not always increase with depth in the
upper layers.
The groundwater table was encountered in all of the borings and water levels
were measured during drilling of the borings and 24 hours later. The 24-hour
groundwater level reading varied from 1 foot-5 inches to 12 feet 3 inches below
the ground surface. The groundwater level will vary seasonally, but it appears
that groundwater will be encountered in the excavations and dewatering will be
required.
In the Subsurface Report, EMCON provides foundation design and construction
criteria. EMCON indicates that shallow spread footing foundations can be used to
support lightly loaded structures. EMCON also notes that with some subsurface
improvement consisting of over-excavating and backfilling with several feet of
structural fill, the allowable bearing pressure could be improved enough
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to support equipment generating dynamic loads. EMCON notes that this excavation
and filling would require dewatering. EMCON does not discuss the anticipated
settlements associated with the allowable bearing capacities for shallow
foundations. Settlement analysis will have to be performed by the EPC Contractor
and the results included in the EPC Contractor's civil and structural design
criteria described below. Based on the borings, the latter recommendation and
particularly the depth of over-excavation and filling are dependent on the
specific location and extent of the foundation and must be confirmed prior to
construction. EMCON also provides a discussion of pile-type deep foundations
that would be acceptable for the support of heavily loaded foundations.
The EPC Contract technical appendices reference the Subsurface Report and
indicate that the foundation design described in that preliminary report may be
used for preliminary design, but that the EPC Contractor shall obtain a final
geotechnical report from a qualified firm for the design of the foundations. The
EPC Contractor is also required to develop civil and structural design criteria
based upon the final geotechnical report.
The EPC Contract technical appendices also include basic foundation design
criteria including allowable settlements and require that the CTG foundation
support mats shall be designed to meet the total and differential settlement
established by the manufacturer if it is more stringent than the criteria in the
EPC Contract.
Under the terms of the EPC Contract, the Partnership shares some
responsibility for subsurface risk, but this risk is limited. As found in most
EPC Contracts with which we are familiar, the EPC Contractor is not responsible
for additional costs or schedule delays due to the discovery of pre-existing
hazardous materials, archeological remains or artifacts. The EPC Contractor is
also required to notify the Partnership if unforeseen conditions are encountered
that increase the cost or schedule required to complete the work such as:
(1) subsurface conditions of an unusual nature differing materially from those
represented in the preliminary Subsurface Report included in the EPC Contract;
(2) rock excavation requiring blasting; or (3) the existence of man-made
obstructions which must relocated. The Partnership's liability for valid claims
for unforeseen conditions is limited to $1,500,000 regardless of the actual cost
to the EPC Contractor, and the time for submitting claims for unforeseen
conditions is also limited in relation to construction progress. Under the terms
of the EPC Contract, the EPC Contractor is to take into account the
recommendation in the Subsurface Report and the EPC Contract design criteria.
Based on our review, we are of the opinion that, provided that, as required
by the EPC Contract, the EPC Contractor takes into account the recommendations
in the Subsurface Report and in the EPC Contract design criteria regarding site
development, subsurface conditions and foundations during design and
construction of the Facility, the Facility Site is suitable for construction and
operation of the Facility.
ENVIRONMENTAL SITE ASSESSMENT
We have reviewed four environmental reports for the Facility Site and one
for the lay-down area prepared by EMCON for the Partnership, regarding
assessment of potential site contamination issues, including: (1) the "PHASE I
ENVIRONMENTAL SITE ASSESSMENT" of an approximately 74-acre tract, dated May 12,
1998; (2) the "PHASE I ENVIRONMENTAL SITE ASSESSMENT" of an approximately
54-acre tract, dated August 25, 1999; (3) the "PHASE I ENVIRONMENTAL SITE
ASSESSMENT" of an approximately 13-acre tract, dated July 20, 1999; (4) the
"PHASE I ENVIRONMENTAL SITE ASSESSMENT" of an approximately 15-acre tract, dated
October 6, 1998; and (5) the "PHASE I ENVIRONMENTAL SITE ASSESSMENT" of an
approximately 3-acre tract, dated September 27, 1999. EMCON's investigations of
these properties consisted of a site reconnaissance, review of historical data,
review of relevant government agency files and environmental databases, and
interviews with persons knowledgeable about the sites. EMCON conducted
additional site reconnaissance of the 74-, 54-, 13-, and 15-acre tracts on
September 24, 1999 during their property
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inspection of the 3-acre tract. All of the properties are currently undeveloped,
wooded properties, containing minor amounts of residential-type debris, also
with shingles, concrete, and wire fencing found at the 74-acre site. With the
exception of the 54-acre and 3-acre tracts, evidence of former site use for
agricultural production was observed in historical aerial photos. A residential
structure formerly existed on the 74-acre tract. No evidence of soil staining,
chemical storage or underground storage tanks were encountered by EMCON on any
of the properties. Surrounding properties generally consist of wooded or
residential areas, and EMCON's report did not indicate any potential
environmental impacts to the properties from off-site sources. EMCON concluded
that its reviews encountered no adverse environmental conditions on any of the
properties.
Based upon our review of the environmental site assessments conducted by
EMCON for the Facility Site and the construction lay-down area, we are of the
opinion that the investigations appear to have been conducted in a manner
consistent with industry standards, using comparable industry protocols for
similar studies with which we are familiar. Although we have not conducted an
independent assessment of the Facility Site, the conclusions reached by EMCON
appear to be supported by the data we have reviewed.
DESCRIPTION OF THE FACILITY
MECHANICAL EQUIPMENT AND SYSTEMS
The major mechanical equipment and systems include six simple cycle dual
fuel GE PG7241 FA CTGs equipped with GE's DLN-2.6 combustors. The GE PG7241 FA
is a 3,600-rpm heavy duty CTG nominally rated at 171.7 MW at ISO conditions and
designated to serve the 60 Hz power generation needs for utility and industrial
service. For this particular application, in a new and clean condition, each CTG
Unit will be guaranteed at 156.4 MW net by the EPC Contractor when firing
natural gas at operating conditions of 94 DEG.F dry bulb and 74 DEG.F wet bulb
ambient and site elevation of 785 feet. Evaporative coolers will be located at
the inlet of each compressor section to maintain rated unit output and will only
operate when the ambient temperature is 60 DEG.F or greater. The cooling medium
will be fresh water with demineralized water backup. The minimum efficiency of
the coolers will be 85 percent at 95 DEG.F ambient dry bulb and 78 DEG.F wet
bulb. Water from the coolers will discharge to a 300,000-gallon retention pond.
The CTG inlet air system also includes filtration and silencing. There is also a
natural gas heating system. Other systems provided include starting, lubrication
and hydraulic, cooling water, fuel and offline and online water wash.
Natural gas will be the primary fuel with low sulfur No. 2 fuel oil used for
backup. A 165,000-barrel No. 2 fuel oil storage tank will be provided to meet
the PPA requirement that fuel oil be stored sufficient for oil-fired operation
at contract capacity for 16 hours of each day for five consecutive days. Fuel
oil deliveries will be made by truck. Unloading systems with pumps capable of
unloading four trucks simultaneously and up to six trucks per hour are included.
Water for the Facility will be of potable quality, will be provided from the
HCWA and stored in a 2,000,000-gallon Fresh Water Storage Tank. The bottom
200,000 gallons of the Fresh Water Storage Tank will be reserved as fire
protection water. Demineralized water will be produced onsite using
self-contained mobile demineralizer units which will be regenerated offsite.
Demineralized water for water wash and injection for NO(X)control when firing
No. 2 oil will be stored onsite in a 7,000,000-gallon demineralized water tank.
Process equipment areas will be curbed with drains directed to sumps where
sump pumps will deliver the water collected to an oil/water separator. Sanitary
wastewater will be discharged to a septic tank and field. Fire protection
systems will meet applicable National Fire Protection Association ("NFPA")
Standard 850, Recommended Practice for Fire Protection for Electric Generating
Plants. The fire protection water system will include a fire water loop with
hose stations, deluge sprinkler systems at the main and auxiliary transformers
and dry pipe sprinkler systems in the warehouse and
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maintenance areas, and portable fire extinguishers. A diesel engine driven and
an electric motor driven fire pump drawing water from the Fresh Water Storage
Tank will be provided as well as an electric motor driven jockey pump. A foam
system will be provided at the No. 2 fuel oil storage tank. Fire detection
equipment and protective signaling system, including a main fire alarm
annunciator panel in the control room, will be provided. Fire extinguishing
systems for the CTGs will be provided.
Other mechanical systems will be conventional in nature for operation and
safety and consist of compressor wash, heating/ventilation and air conditioning
for Facility buildings, two compressed air systems, lubricating oil, cooling
water and hoists.
ENVIRONMENTAL SYSTEMS AND CONTROL EQUIPMENT
The CTGs are to be equipped with GE's latest version of its DLN combustors,
the DLN-2.6, which are guaranteed to control NO(X) emissions to 15 ppm when
burning natural gas. "Dry" means that no water or steam is injected for NO(X)
emissions control during gas firing. These combustors require water injection to
control NO(X) emissions to 42 ppm when firing No.2 oil.
Sulfur dioxide and particulate matter are controlled by use of natural gas
and very low sulfur distillate oil for fuels. Carbon monoxide and volatile
organic compound emissions are controlled by the inherent combustion efficiency
of the CTGs.
Continuous emissions monitoring systems ("CEMS") will monitor NO(X), O(2)
and flow from each CTG. All CTG emissions guaranteed by GE are at least as
stringent as the Facility's Air Permit requirements. Plant noise is controlled
by acoustic enclosures for noisy equipment and silencers in the CTG air inlets
and exhaust stacks.
Plant process wastewaters, consisting primarily of evaporative cooler
blowdown and process area drains, are collected, treated for potential oil
removal as needed, and discharged to an unnamed tributary to Hilly Mill Creek.
Sanitary waste is disposed of in an on-site septic system. Stormwater is
directed offsite to the creek via a retention pond and a biofiltration swale.
STRUCTURAL
The major Facility equipment, which consists mainly of the CTGs, is to be
designed for outdoor installation and furnished with weathertight enclosures
where required. The only major building to be constructed is a multi-purpose
building that will include spaces for administration, control, personnel
facilities, maintenance and warehousing. The construction type for the building
is specified as steel frame or pre-engineered metal structure with insulated
metal siding and roofing.
The EPC Contract technical appendices include references to national codes
and standards that will govern the structural design of the Facility, including
the Standard Building Code ("SBC") promulgated by the Southern Building Code
Congress International ("SBCCI"), and also require compliance with local codes.
The technical appendices indicate that the seismic risk zone for the Facility
Site is Zone 2A as determined from the Uniform Building Code ("UBC"). The
technical appendices also include supplemental design criteria for structural
loading not commonly provided in codes and standards.
ELECTRICAL AND CONTROL SYSTEMS
Electricity is generated at 18 kV by each of the six CTGs and stepped up to
500 kV in three three-winding generator step-up ("GSU") transformers, one per
pair of CTGs, for interconnection with the 500 kV Georgia Integrated
Transmission System ("GITS"). Each CTG has a generator circuit breaker
interposed between the generator and its respective GSU winding to isolate and
protect the generator and the Facility in the event of an electrical fault. The
connection between the generators, generator breakers, and GSU transformer is
made with isolated phase bus duct. The isolated phase bus duct for one of each
pair of generators is tapped between the generator breaker and GSU transformer
to provide a source of station service power from the generators or via backfeed
from the 500 kV system. Appropriate protective relaying systems are included in
the zones created by the GSU transformer, the generators and 4,160 V station
service systems.
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Station service power from the three taps is fed to a 4.16 kV switchgear bus
through three 18-4.16 kV auxiliary transformers. The bus is connected to the
transformers through circuit breakers and split into three sections by two bus
tie circuit breakers. This allows for auxiliary power to be supplied to more
than one bus section from one of the auxiliary transformers in the event that
one of the transformers is out of service.
The 4,160 V system is used to provide power to motors greater than 300
horsepower ("hp") and step-down transformers which feed the 480 V switchgear.
The 4,160 V motors and the CTG static start excitation transformers are fed via
medium-voltage motor controllers. The 4,160/480 V step-down transformers are fed
via circuit breakers.
The 480 V system consists of drawout-type switchgear fed from the step-down
transformers and feeds the motor control centers ("MCCs") associated with the
CTGs (supplied with the CTGs), water treatment systems, and balance of plant
systems, which contain motor starters for motors in the 1/2 to 250 hp range. The
480 V bus will include a connection point for a temporary 1,000 kW diesel
generator. A battery and charger system provides 125 V dc power for switchgear
control and the UPS system. Lower voltage ac systems, lighting, grounding and
plant wiring systems are addressed in the EPC Contract conceptual design.
The Facility uses a distributed control system ("DCS") to provide integrated
control of the various project elements from the Facility's control room. The
DCS will process most major balance of plant instrument and control loops
through a programmable logic controller and also communicate with the
proprietary Mark V control systems supplied with each of the CTGs. Where the DCS
communicates with these remote control systems over a redundant ethernet data
highway, it provides control functionality from the DCS console, but the
operational processing is accomplished within the remote system. The DCS is
equipped with multiple operator workstations and redundant processors in order
to provide the required level of control system reliability.
Every organization in the country is faced with a potential problem on
January 1, 2000 when the calendars on the millions of computers and
microprocessors in the country change from the year 99 to 00 and certain other
dates (for example, but not limited to, Leap Year and 9/9/99), (the "Y2K
Issue"). It is unclear at this time how extensive the Y2K Issue may be, but
organizations should be reviewing their systems and undertaking whatever
remediation is required. The Y2K Issue occurs when computers or microcomputers
which use two-digit years misinterpret the year 2000 to be "00", zero, 1900, or
some other erroneous date. Some embedded software or hardware does not recognize
the year 2000 as a Leap Year or recognize 9/9/99 as an error code. It is
uncertain what action will be initiated by computers or microprocessors which
are programmed (software or firm-ware) with these instructions. The Y2K Issue
has the potential to affect any computer system, including hardware that is
microprocessor based, software, and databases at, among other places,
administration/office facilities, electric generating power plants, and
transmission and distribution systems. The Y2K Issue has the potential to impact
the Facility as well as organizations other than the Facility, the continued
performance which is also critical to the Facility. These other organizations
may be located either "upstream" or "downstream" of the Facility.
Under the terms of the EPC Contract, GE is to provide equipment which
already has features that accommodate the change in dates without the Y2K Issue.
While this mitigates the date problem for the Facility, it does not mitigate the
Y2K Issue for other organizations upstream or downstream from the Facility which
might impact the operation of the Facility. The Facility is not scheduled to be
in commercial operation until the summer of 2001. It would be anticipated that,
by that time, the Y2K issue would be identified and, if not corrected, then
mitigative actions would be underway.
Evaluation of the actual status of the Facility, as well as other entities
with whom the Partnership has business or operational relations, relative to the
Y2K Issue is well beyond the scope of this Report. We have not been engaged to
conduct, and in fact have not conducted, any independent evaluation or
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on-site testing of the aforesaid entities in any way to independently ascertain
the actual hardware and software status. We caution that it is entirely possible
that presently unknown conditions could arise which lead to significant
operational and/or administrative problems, and that these problems could have
an adverse impact on the Facility.
OFF-SITE REQUIREMENTS
ELECTRICAL INTERCONNECTION
The Facility will be connected to the GITS 500 kV system at a ring bus
switching station to be constructed on or adjacent to the Facility Site. The
switching station will include three circuit breakers to tap the transmission
line running through the Facility Site from Plant Wansley to Fortson and provide
connection to the high voltage terminals of the three GSU transformers for CTG
Units 1 through 6.
The electrical interconnection service will be supplied by Georgia Power
Company ("GPC") under an interconnection agreement between the Partnership and
GPC. The Partnership shall design, procure, and install all facilities needed
for GPC to provide interconnection service. The Partnership shall convey, at no
cost, such facilities to GPC. GPC shall have no obligation to pay the
Partnership any wheeling or other charges for electric power and/or energy
transferred through the Partnership's equipment. The Partnership shall pay GPC a
monthly administration fee of $5,000 for all costs and expenses incurred by GPC.
NATURAL GAS INTERCONNECTION
The Facility will be interconnected with Transco's interstate natural gas
pipeline system. PECO is responsible for providing fuel to the Facility, and
will contract with natural gas and fuel oil suppliers, as well as with Transco
to arrange delivery of fuel to the Facility. The interconnection and metering
station is to be constructed and operated under the terms of the Transco's
Interconnect, Reimbursement and Operating Agreement between Transco and the
Partnership dated August 18, 1999 (the "Transco Agreement"). Construction of a
pipeline lateral approximately 1 mile long is required to connect the Facility
to two of Transco's 36 inch lines, which are both located south of the Facility
Site. Under the terms of the Transco Agreement, Transco is responsible for
design, construction, operation and maintenance, and ownership of the
interconnection facilities on its side of the pipeline insulating flange at the
interconnection. These facilities include piping, gas metering and remote
transmission facilities and installation of pipeline tees for connection to the
new lateral pipeline to the Facility. Under the terms of the Transco Agreement,
the Partnership must reimburse Transco for 100 percent of the actual Transco
costs for the interconnection facilities provided by Transco. PECO will pay
Tenaska up to $784,000, or 56 percent of the cost, whichever is less, as PECO's
obligation for the installation of the natural gas metering facility. Transco
has estimated the total amount to be reimbursed to be $1,570,400. In addition,
the Partnership is responsible for the construction and operation of the
interconnection facilities on its side of the pipeline insulating flange
including the lateral pipeline, and pressure reduction station. The Partnership
has entered into a fixed price EPC contract with Willbros Engineers, Inc., dated
September 23, 1999, to construct the lateral pipeline and pressure reducing
station. The Partnership's interconnection facilities are required to be
designed for a pressure equal to or greater than the 800 pounds per square inch
gauge ("psig") maximum operating pressure at the Transco metering station.
WATER SUPPLY INTERCONNECTION
Under a Water Purchase Agreement dated February 25, 1999, water will be
supplied to the Facility by the HCWA. The HCWA obtains and treats water taken
from the Centralhatchee Creek. The HCWA
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<PAGE>
will supply approximately 500,000 gallons per day. The Partnership will
reimburse the HCWA for the cost to construct a metering station at the border of
the Facility Site.
REVIEW OF TECHNOLOGY
In general, the Facility will utilize equipment common in the industry and
with substantial operating history. The GE Frame 7FA CTGs (model PG 7241FA) to
be installed at the Facility represent a mature combustion turbine technology
with over 1 million hours of fleet-wide operating experience. The GE Frame 7F/FA
combustion turbine family is a two bearing machine. There is a single rotor
comprised of a compressor section and a turbine section. Each section consists
of a series of discs or wheels and spacers held together with tie bolts. The
following discussion presents an overview of the technical development of the GE
Frame 7 combustion turbine.
The Frame 7FA technology represents advances made by GE since the
introduction of the Frame 7F machine in June of 1987. With advancements in
component cooling, materials, and associated increases in firing temperatures,
the Frame 7F unit has been uprated and the improved unit is now designated as
the Frame 7FA. Within the Frame 7FA designation there has been additional subset
designations of uprates, such as the Model PG7241FA, to be utilized at the
Facility. The Model PG7241FA has a 2,420 DEG.F firing temperature compared to
2400 DEG.F on the earlier Model PG7231FA, a compressor pressure ratio of 14.9 to
1 and a simple-cycle efficiency of 36.2 percent.
GE's approach to combustion turbine development has traditionally followed
the philosophy of evolution of designs, use of geometric scaling, and strong
reliance on pre-production development. The result of the evolution of designs
is a family of axial-flow compressors improved in several discrete steps that
allow retention of the proven reliability of existing designs. As an example,
the Frame 7 combustion turbine has been improved in performance through seven
models, the A, B, C, E, EA, and F; and now the FA machine. GE has historically
applied scaling of both compressors and turbines in the development of its
combustion turbine product line.
The progressive step towards the Frame 7F was taken by increasing compressor
air flow and firing temperature resulting in an increase in the ISO base rating
from 83,500 kW to 159,000 kW. The 7F design has a compression ratio higher than
the 7E's, and retains GE's bolted-disk rotor construction, but without the 7E's
mid-bearing, replaced by the simpler 2-bearing system.
The design of GE's 7F/FA combustion turbine is supported by a three-phase
test program prototypical of the evolution of GE combustion turbines: Phase I,
where accessory systems are tested for performance and individual components are
tested in support of design activities; Phase II, where the entire machine is
tested to verify the design assumptions; and finally Phase III, where a
full-load on-line operating test is conducted on an electric utility system.
The first 7F combustion turbine testing was performed during the winter and
spring of 1990 at Virginia Power Corporation's Chesterfield No. 7 combined cycle
power station. Based on these favorable results including experience at a firing
temperature of 2,350 DEG.F, GE uprated the unit to its current "FA" model with
minor design modifications. These modifications consisted of raising the firing
temperature to 2,400 DEG.F and then to 2,420 DEG.F, closing the first stage
nozzle to raise the pressure ratio in order to maintain the same exhaust
temperature, adjusting the cooling flows to retain design life and opening up
the inlet guide vanes. The structural design was modified to improve
productability and inspectability. In addition, metallurgical changes were made
to the turbine shaft and third stage turbine wheel based on lower than expected
temperatures experienced with the 7F units located at the Chesterfield Station.
Shaft cooling was also added to the 7FA turbine rotor.
A partial list of completed and planned GE 7FA installations is presented in
Table 2.
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<PAGE>
TABLE 2
FRAME 7FA INSTALLATION TABLE
<TABLE>
<CAPTION>
ACTUAL/PLANNED
COMMERCIAL CUSTOMER STATION COUNTRY QUANTITY OPERATION DATE
------------------- --------------------- -------- -------- ----------------
<S> <C> <C> <C> <C>
Florida Power & Light.............................. Martin USA 4 1992
Chubu Electric Power............................... Chita Japan 3 1992
Hartwell Energy.................................... Oglethorpe USA 2 1993
Tiger Bay Co-gen................................... Fort Mead USA 1 1993
Sithe Energies/Independence........................ Independence USA 4 1993
Chubu Electric Power............................... Kawagoe Japan 4 1993
PSI Energy......................................... Wabash USA 1 1994
Baltimore Gas & Electric........................... Perryman USA 1 1994
Portland General Electric.......................... Coyote Springs USA 1 1994
Kansai Electric Power.............................. Hemeji Japan 3 1994
Energy National.................................... Crockett USA 1 1994
Chubu Electric Power............................... Kawagoe Japan 2 1994
Korea Electric Power............................... Seo Inchon Korea 8 1995
Hermiston Generating, LP........................... Hermiston USA 2 1995
Chubu Electric Power............................... Kawagoe Japan 1 1995
Tampa Electric..................................... Polk USA 1 1995
Public Service of Colorado......................... Fort St. Vrain USA 1 1995
Chuba Electric Power............................... Chita Japan 1 1995
Compania Samalayuca................................ Samalayuca Mexico 1 1996
Cogentrix/Clark Co................................. River Road, Clark Co. USA 1 1996
Chubu Electric Power............................... Shin-Nagoya Japan 3 1996
POSCO.............................................. Kwangyang Korea 2 1997
Kyushu Electric Power.............................. Shin Aita Japan 3 1997
Compania Samalayuca................................ Samalayuca Mexico 2 1997
Chubu Electric Power............................... Shin-Nagoya Japan 3 1997
Exxon.............................................. Exxon-Baton Rouge USA 1 1997
Empresa Pub Medellin............................... Puerto Nare Columbia 2 1997
Public Service of Colorado......................... Ft. St. Vrain USA 1 1998
SkyGen............................................. DePere USA 1 1998
Gilbert Energy..................................... Mustang USA 2 1998
Carolina Power & Light............................. Asheville USA 1 1998
Occidental Chemical................................ Ingleside USA 2 1998
CSW Energy......................................... Frontera USA 2 1998
Korea Electric Power............................... Pusan Korea 2 1999
City of Tallahassee *.............................. Purdom USA 1 1999
SEI................................................ State Line USA 2 1999
SEI................................................ Neenah USA 2 1999
City of San Antonio *.............................. Braunig USA 2 1999
City of Jacksonville............................... Kennedy USA 1 1999
Elwood Energy...................................... Elwood USA 4 1999
Duke Energy *...................................... Maine Independence USA 2 1999
Duke Energy *...................................... Hidalgo USA 2 1999
Carolina Power & Light *........................... Lee USA 4 1999
Carolina Power & Light............................. Asheville USA 1 1999
Alabama Power...................................... Barry USA 2 1999
Bechtel/Gregory *.................................. Gregory USA 2 1999
Tenaska Frontier Gen Partner....................... Tenaska Frontier USA 3 2000
Southern Company................................... Theodore USA 1 2000
Sonat Energy Services.............................. Cataula USA 2 2000
SEI................................................ Ohio USA 2 2000
SEI................................................ Cape Cod USA 2 2000
SkyGen*............................................ RockGen USA 3 2000
Mississippi Power.................................. Daniels USA 4 2000
Korea Electric Power............................... Pusan Korea 6 2000
City of Jacksonville............................... Northside USA 2 2000
Alabama Power...................................... SELCO USA 1 2000
Florida Power & Light Company*..................... Ft. Myers USA 6 2000
Bucksport Energy/Champion*......................... Bucksport Energy USA 1 2000
City of Jacksonville............................... Northside USA 1 2001
SkyGen*............................................ Broad River USA 3 2001
SkyGen*............................................ Pine Bluff USA 1 2001
</TABLE>
------------------------------
* Model PG7241FA
7FA PRODUCTION PROBLEMS AND STATUS
The first series of GE Frame 7FA combustion turbines experienced three types
of problems since being introduced. These are: (1) compressor issues;
(2) turbine rotor flexibility issues; and (3) DLN-2
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<PAGE>
combustor flashback. GE has been able to correct the compressor and turbine
rotor problems, but has not yet completely resolved the combustor flashback
issue.
COMPRESSOR ISSUES
The rotor for the Frame 7FA combustion turbines is a series of discs and
spacers held together axially with tie-bolts and is supported at each end by
bearings. The compressor section of the rotor utilizes 15 tie-bolts. In an
isolated event, compressor wheel slippage occurred on one Frame 7FA unit. This
was caused by insufficient and uneven tensioning of the tie-bolts. The solution
was a matter of changing the tension to a level which was consistent with GE's
previous experience with the older Frame 7E technology units and to require a
sequence in tensioning. In another isolated event, one Frame 7FA unit
experienced a compressor blade rub resulting from out of tolerance components.
Early compressor related issues associated with insufficient and uneven
tensioning and also manufacturing and assembly defects in the rotor compressor
section tie bolts have been resolved.
In 1998, vibration level changes were reported by five users of the Frame
7FA combustion turbine and the 50 cycle Frame 9FA version of the 7FA. Inspection
has revealed cracking in the seventeenth stage wheel of the compressor rotor on
the five units. GE commissioned a task force to determine the root cause of the
cracking and the subsequent countermeasures required. Findings indicate the
problem emanated from handling damage which occurred during stacking operations
that was acted on by thermal stresses generated during cold starts. GE observed
that the characteristic of successful fleet leaders is reducing the number of
unit trips and the number of hot starts. Because the Frame 7 F/FA rotors are
supported only at each end, the rotor is subjected to greater sag due to gravity
than the three bearing design used on the Frame 7E, resulting in higher stress
and strain levels if not cooled properly. The problem is exacerbated at start-up
and shut-down when stress and strain on the rotor are highest. GE issued revised
operating recommendations to address the issue. Subsequently, GE undertook a
broad rotor redesign that is used for the current FA product line that includes
the Facility's CTGs. These rotor modifications, GE reports, allow operation
without hold times or starting modification recommendations.
TURBINE ISSUES
Because the Frame 7 F/FA rotors are only supported at each end, large
centrifugal forces and rotor sag have caused cracks and distress of the rotor
components between the second and third stage wheels of the turbine section.
Incidents of cracks were found in the upper web area and bolt circle of the
turbine 2-3 spacer and 23 incidents of stage 3 wheel fatigue were observed. GE
identified the problem to be the flexibility of these components. In addition,
as a result of the rotor flexibility a rub was observed in this area. This
problem was more severe on the GE 9FA combustion turbine than the 7FA. GE
corrected the 2-3 spacer problem by installing a "Generation 4" all inconel
turbine rotor with a redesigned stiffer spacer subassembly beginning in
June 1995. No turbine section rotor problems have been observed with the
Generation 4 turbine section rotor modification.
DLN-2.6 COMBUSTION SYSTEM
GE has been developing DLN combustor technology since at least the early
1990s. Improvements over the decade have included control over a wider load
range, greater flexibility of operation, and progressively lower NO(X) emission
rates.
The DLN-2.6 is the latest version of this technology. The DLN 2.6 combustion
system technology developed by GE regulates the distribution of fuel to a
multi-nozzle premix combustor arrangement to maintain unit load and fuel split
for optimal emissions. It has six fuel nozzles per combustion can, five in the
periphery and one central, and offers standard NO(X) emission guarantees of 15
ppm when firing gas over a range of approximately 50 percent to 100 percent
load. The DLN 2.6 fuel system operation
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<PAGE>
is fully automated, sequencing the combustion system through a number of staging
modes prior to reaching full load. The primary controlling parameter for fuel
staging is the calculated combustion reference temperature. Other DLN 2.6
operation-influencing parameters available to the operator are inlet guide vane
("IGV") temperature control and the use of inlet bleed heat.
Flashback has occurred in some Frame 7FAs, and to a greater degree in Frame
9FA combustors. It is often referred to as humming. Flashback occurs when the
flame pattern becomes unstable and moves backward into the fuel nozzle thus
overheating the nozzle tip. GE has formed a task force to identify all of the
causes of flashback and to determine solutions to the problem. Flashback can be
detected by an increase in NO(X) emissions, combustor dynamics and a spread in
the turbine exhaust temperature profile. GE reports that, when a flashback
happens, a reduction in combustion turbine load stops the occurrence. GE has
tested various combustor configurations to reduce the risk of flashback. GE has
selected a DLN fuel--air-staged combustor design and is equipping all of its
current and future Frame 7FA units with this design, including the Facility. GE
is recommending that its on-site monitoring service be installed to assist the
user in monitoring the occurrence of flashback, and the LTSA provides for this
service. GE can then alert the customer if a flashback incident has occurred so
that corrective action can be taken.
Condensation of liquid hydrocarbons in gas fuel have been identified as one
cause of flashback. Therefore, it is incumbent on the power plant operator to
monitor the gas fuel supply to ascertain that it is meeting the requirements of
the GE gas fuel specification. To mitigate this potential problem, the
Facility's design incorporates a heater in the gas supply line to be used if
necessary to raise the temperature of the incoming fuel gas above the liquid
dewpoint before the gas enters the feed lines to the individual CTGs.
SUMMARY
Based on our review, we are of the opinion that the technology proposed for
the Facility is a sound and proven method of electric generation. If operated
and maintained consistent with generally accepted industry practices, the
Facility should be capable of passing the Acceptance Tests pursuant to the EPC
Contract and meeting the requirements of the PPA and the current environmental
permits. Further, the Facility has adequately provided for all off-site
requirements, including fuel supply and transportation, water supply, wastewater
disposal, and electrical interconnection.
Based on our review, we are of the opinion that the proposed method of
design, construction and operation of the Facility has been developed in
accordance with generally accepted industry practices and has taken into
consideration the current environmental, license and permit requirements that
the Facility must meet.
HEAT RATE AND OUTPUT
HEAT RATE
The EPC Contract guarantees a Facility net heat rate of 10,683 Btu/kWh (HHV)
or less when operated on natural gas and 10,821 Btu/kWh (HHV) or less when
operated on fuel oil when measured in performance tests in accordance with the
EPC Contract Exhibit D. The basis for any corrections to the as-tested values
are 94 DEG.F dry bulb, 74 DEG.F wet bulb, 14.29 psia and 0.95 power factor.
There is an instrument measurement uncertainty, or deadband, of plus or
minus1.5 percent on the guaranteed heat rates. Accounting for the potential
impact of the 1.5 percent tolerance, the equivalent net heat rates are 10,843
Btu/kWh (HHV) for gas and 10,983 Btu/kWh (HHV) for oil.
Adjusting the GE guaranteed heat rate on gas for measurement uncertainty,
commercial operation conditions, non-recoverable equipment degradation
(fouling), and using the specified summer
B-16
<PAGE>
performance parameters and the expected dispatch scenario developed by RDI, we
have projected the levelized average net plant heat rate to be approximately
11,088 Btu/kWh (HHV).
OUTPUT
The PPA sets forth the terms and conditions under which PECO will purchase
the capacity and net electric output from the Facility for a term of 29 years,
commencing on the Commercial Operation of the Initial Units. The PPA provides
that, except for limited circumstances, PECO shall be the exclusive recipient of
all capacity, energy and ancillary services or products available from the
Facility, at a level equal to the Contract Capacity established for the
Facility. The Contract Capacity will be established and declared by the
Partnership each Contract Year following a Capacity Test, and shall be within
the following limits: (1) for the first Contract Year, Contract Capacity shall
equal the product of 150 MW and the number of Units that have achieved
Commercial Operation; (2) for the second Contract Year, Contract Capacity shall
be between 875 MW and 950 MW, based on all Units having achieved Commercial
Operation; and (3) for Contract Years thereafter, Contract Capacity shall be no
less than 875 MW and no greater than within 50 MW of the then-current Contract
Capacity based on six Units having achieved Commercial Operation, up to a
maximum of 950 MW.
The EPC Contract guarantees that the Facility shall deliver for sale at
least 938,460 kW when measured by the Performance Tests, though the output must
be adjusted for transformer losses, auxiliary loads, and balance of plant
restrictions. The basis for any corrections to the as-tested output are 94 DEG.F
dry bulb, 74 DEG.F wet bulb, 14.29 psia and 0.95 power factor.
There is an instrument measurement uncertainty, or deadband, of plus or
minus1 percent on the guaranteed output. Accounting for the potential impact of
the 1 percent tolerance, auxiliary loads and losses, and adjustments for
commercial operation, fouling, and non-recoverable equipment degradation, we
have projected the levelized average net plant output to be approximately 908
MW.
SUMMARY
For the purposes of the Projected Operating Results, we are of the opinion
that if designed, constructed, operated and maintained as currently proposed,
the Facility should be capable of operating in a peaking operation mode and of
achieving an average annual output of 908 MW, and an average annual net plant
heat rate of 11,088 Btu/kWh (HHV). The average annual output of 908 MW is within
the range where neither party shall owe a penalty or adjustment under the PPA.
The average annual net plant heat rate of 11,088 Btu/kWh (HHV) is within the
range where neither party shall owe a Fuel Adjustment Payment under the PPA.
AVAILABILITY
OPERATING EXPERIENCE
As of June 1999 GE reported that over 130 combustion turbines that
incorporate "F" (7F and 9F) technology have in excess of 2 million hours of
firing time logged. Projects presently using or expected to use the Frame 7FA
are listed in Table 2. The first Frame 7F units, which were delivered to
Virginia Power's Chesterfield Power Station, now have more than 37,500 hours of
service. As of June 1999, the 7 F/FA fleet has accumulated more than
1.35 million operating hours. We have reviewed data provided by GE that
indicates that there are units in the fleet that are subject to daily start-stop
duty with a duty cycle of approximately 15 hours per start. These units have a
total of 1,200 to 1,500 starts with between 23,000 and 25,000 hours of fired
operation. This data indicates that the fleet has significant operating history.
In early 1997, GE initiated a survey of fleet performance of their operating
"F" technology units as measured by customers. GE surveyed all units that had
been in regular commercial service for at
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<PAGE>
least one year. GE requested operating data by annual increments and did not
include any year's data that represented less than 10 months of reported
operation. These criteria were intended to lead to more representative
reliability and availability statistics as they include all maintenance and
inspection protocols and exclude partial-year operations. On the basis of these
selection criteria, GE sent out questionnaires to all 16 of the qualifying sites
covering 42 combustion gas turbines and 97 unit-years of operation. A total of
12 sites with 31 combustion gas turbines responded to the survey and, of these
3 sites, representing six Frame 9F machines, turned out not to meet the full
selection criteria. The remaining sample included 9 sites representing 25 Frame
7F/FA gas turbines. Table 3 summarizes the performance reported by GE for these
25 Frame 7F/FA combustion gas turbines which are considered to represent the
reliability and availability performance for the fleet.
While there is no operating experience with the PG 7241FA, there is
experience with its predecessors, the PG 7231FA and the PG 7221FA. The
difference between the PG 7231FA and the PG 7241FA include an increase in the
firing temperature from 2,400 DEG.F to 2,420 DEG.F, additional use of thermal
barrier coatings to maintain parts life, and the use of cloth-metal seals
between the nozzle and diaphragm blocks. GE documents report that 35 PG 7241FA
units are on order for shipment in 1999 and 2000.
TABLE 3
FRAME 7 F/FA
FLEET PERFORMANCE
<TABLE>
<CAPTION>
YEAR UNIT AVAILABILITY STARTING RELIABILITY
---- ----------------- --------------------
<S> <C> <C>
1993........ 95.0% 97.4%
1994........ 93.1% 96.7%
1995........ 90.2% 99.1%
1996........ 95.1% 99.4%
1997........ 93.0% 96.0%
</TABLE>
The decrease in unit availability during 1995 was primarily a result of the
unit outages taken to rectify the rotor spacer problem discussed previously.
As indicated in Table 3, the unit availability and starting reliability for
the surveyed units have been high. We would expect similar performance for the
Frame 7FAs being installed at the Facility, providing the operation and
maintenance of the CTG is in accordance with GE's recommended practices. The
unit availability presented here should not be confused with the availability
under the PPA as explained below.
AVAILABILITY UNDER THE PPA
Each Contract Year, PECO will designate one of two Peak Availability Options
which will establish the hours of the day in which PECO may issue Energy
Requests from the Facility during Summer Months, designated as June through
September. Under Peak Availability Option #1, PECO shall be entitled to request
energy from the Facility for sixteen hours of each day during Summer Months.
Under Peak Availability Option #2, PECO shall be entitled to request energy from
the Facility for twenty hours on each Monday through Friday, and for sixteen
hours of each Saturday and Sunday during Summer Months.
PECO is required to provide the Partnership each day with a Unit Call
Schedule, which will indicate a schedule detailing the hours of the following
day in which a Unit will be requested by PECO to be available for dispatch,
pursuant to an Availability Schedule provided to PECO by the Partnership. During
all Summer Months, the Partnership shall make all Units available for dispatch
by PECO, and PECO shall place all Units on the Unit Call Schedule for each
Summer Peak Hour for the following day. During all Winter Months, designated as
December, January and February, the Partnership shall
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<PAGE>
make all Units available for dispatch by PECO, and PECO may place up to all of
the Units on the Unit Call Schedule for each following day of the Winter Months.
For all other months of the year, the Partnership shall make four Units
available for dispatch by PECO, and PECO may place up to four Units on the Unit
Call Schedule for the following day. PECO may also place Units available
pursuant to the preceding seasonal criteria in a Standby Mode during each day of
the Non-Summer Months.
If PECO requests Peak Availability Option #1, it is required to place Units
on the Unit Call Schedule during Non-Summer Months for a minimum of the lesser
of 2,091 Unit Hours, or the number of Unit Hours during Non-Summer Months
allowed pursuant to the Air Permit. The effect of this clause is to produce an
equivalent amount of Unit-hours that Units are placed on the Unit Call Schedule
each Contract Year under either Peak Availability Option, which are then used to
determine adherence to the Facility's targeted Availability Percentages under
the PPA.
Energy can be requested by PECO, subject to a minimum load for each Unit of
90 MW when fired by natural gas, and 95 MW when fired by No. 2 fuel oil. If a
Unit is called upon by PECO pursuant to the daily Unit Call Schedule, the
Partnership shall cause the Unit to deliver Unit Capacity on a continuous basis
within 60 minutes if the Unit is in Cold Shutdown status, or within 30 minutes
if the Unit is in Hot Shutdown status. The Facility will be capable of starting
no more than three Units simultaneously.
Contractual availability under the PPA will be determined on the basis of
credited hourly output from the Facility compared to the hourly potential output
from the Facility, which is specified under a variety of operating and dispatch
conditions in the PPA, during all hours Units are placed on the Unit Call
Schedule by PECO. With certain exceptions during Unit start-up and shut down
hours and certain other conditions, the credited hourly output of the Units
during each Contract Year will equal: (1) either the hourly energy delivered to
PECO or the Units' hourly Contract Capacity, provided PECO has dispatched the
Units during such hours and the delivered energy is within a specified tolerance
band, or (2) the Units' hourly Contract Capacity each hour the Units are on the
Unit Call Schedule and no energy is dispatched from said Units during such
hours. The hourly potential output from the Facility will be, with certain
exceptions during Unit start-up and shut-down periods and certain other
conditions, equal to: (1) either the hourly Contract Capacity of the Facility
during Summer Months, or (2) the hourly Unit Capacity during Non-Summer Months
times the number of Units on the Unit Call Schedule during such Non-Summer
Months. Each year, the Summer Availability Percentage will be calculated at the
end of the Summer Months as the credited Summer Output divided by the Summer
Potential output during all hours of the Summer Months. At the end of each
Contract Year, the Annual Availability Percentage will be calculated as the
actual Annual Output divided by the Annual Potential output during all hours of
the Contract Year. The Partnership shall endeavor to cause the Facility to
achieve Summer Availability Percentages and Annual Availability Percentages of
at least 97 percent throughout the term of the PPA. PECO will compensate the
Partnership for achieving a Summer Availability Percentage in excess of
97 percent and the Partnership will compensate PECO for failing to achieve an
Annual Availability Percentage of at least 97 percent. The Partnership will
compensate PECO at the end of each Summer Season if the Summer Availability
Percentage is less than 87 percent. Any compensation paid during a contract year
will be subtracted from any Partnership obligation as a result of the Annual
Availability Percentage for the year being less than 97 percent.
The Summer and Annual Availability Percentages calculated for the Facility
pursuant to the PPA are based on the actual energy deliveries from the Facility
to PECO, compared to the potential energy deliveries that could have occurred to
PECO over the entire requisite Summer Peak hour period of each contract year.
Reductions in Availability Percentages occur only as a result of shortfalls in
energy deliveries from the Facility when requested by PECO. During hours when
Units are placed on the Unit Call Schedule and energy is not requested by PECO,
all such Units are deemed to be 100 percent available under the PPA. Therefore,
at low annual capacity factors, the Summer and Annual
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<PAGE>
Availability Percentages calculated under the PPA may be considerably higher
than the actual availability of the Facility calculated using more traditional
methods.
For example, if the Facility is dispatched at a 4 percent annual capacity
factor, which is representative of the relatively low annual capacity factors
projected by RDI over the term of the Bonds, and the Facility actually had one
of its six Units out of service during the entire time energy was requested by
PECO, the actual Facility availability would be 83.33 percent. However, the
Annual Availability Percentage calculated pursuant to the PPA would be
97.5 percent, which is within the contractual range of the PPA, and no penalty
payments would occur to PECO under this example.
SUMMARY
Based on the projected levels of dispatch, we are of the opinion that the
Facility should be capable of achieving a Summer Availability Percentage of
98 percent and an Annual Availability Percentage of 97 percent, both as defined
in the PPA. The Annual Availability Percentage of 97 percent is the level
required to avoid reductions in the reservation payments under the PPA.
ESTIMATED USEFUL LIFE OF THE FACILITY
The EPC Contract requires the Facility to be designed and constructed in
accordance with recognized codes and standards typical of central power stations
in the United States. We have reviewed the list of qualified vendors and the
configuration of systems proposed for the Facility as well as the proposed
general plans for operating and maintaining the Facility. On the basis of this
review and assuming: (1) the Facility is designed, constructed, operated, and
maintained as proposed by the Partnership, the EPC Contractor, and the Operator;
(2) all equipment is operated in accordance with manufacturer's recommendations;
(3) all required renewals and replacements are made on a timely basis; and
(4) natural gas and water used by the Facility are within the expected range
with respect to quantity and quality, we are of the opinion that the Facility
should have a useful life extending beyond the term of the Bonds.
CONSTRUCTION SCHEDULE
We have reviewed Exhibit F of the EPC Contract that presents a summary level
computer generated bar chart schedule dated August 2, 1999 (the "Project
Schedule"). The Project Schedule was prepared by the EPC Contractor representing
its summary level plan to complete the Facility in accordance with the terms and
conditions of the EPC Contract. The Project Schedule is grouped into the major
areas of project planning, engineering, construction, plant start-up and
commercial operation. Within these larger categories the EPC Contractor is
planning its work by CTG unit which supports the completion requirements of the
EPC Contract.
Major milestones to be completed by the EPC Contract identified in the
Project Schedule include Limited Notice to Proceed (September 10, 1999), Execute
EPC Contract (September 10, 1999), Mechanical Completion Unit 1 (March 14,
2001), Mechanical Completion Unit 2 (May 9, 2001), Mechanical Completion Unit 3
(May 9, 2001), Mechanical Completion Unit 4 (February 25, 2002), Mechanical
Completion Unit 5 (March 26, 2002), Mechanical Completion Unit 6 (April 14,
2002), Commercial Operation Units 1, 2 & 3 (June 1, 2001), Commercial Operation
Units 4, 5 & 6 (June 1, 2002) and Project Completion July 1, 2002. A key
milestone identified in the Project Schedule is Mobilize for Construction
(April 17, 2000).
The EPC Contract identifies the dates by which the Partnership must provide
certain items to support the Project Schedule. According to the EPC Contract:
the Partnership is required to provide backfeed power from the electrical
interconnection point no later than 14 months after Authorization to Proceed
("ATP"); the Partnership is required to provide a water supply of 432,000
gallons per day no later than 12 months following ATP; and the Partnership is
required to provide the natural gas supply no later than 13 months following
ATP. The Partnership issued a Limited Notice to Proceed to the EPC Contractor on
September 10, 1999 allowing the EPC Contractor to commence engineering,
procurement with acceptable cancellation terms and construction planning
activities. The EPC Contractor reports that currently it is performing its
duties in accordance with the Limited Notice-to-Proceed including engineering,
procurement, project planning, and support General Electric Order Definition
meetings. The EPC Contractor reported that it is preparing to conduct its
geotechnical analysis of the Facility Site. No on-site work has commenced at
this time.
B-20
<PAGE>
Based on our review and assuming the absence of events such as delivery
delays, labor difficulties, unusually adverse weather conditions, force majeure
events, the discovery of underground obstructions or hazardous materials or
wastes not previously known, or other abnormal events that are prejudicial to
normal construction or installation, we are of the opinion that, based on a
Limited Notice-to-Proceed of September 10, 1999, the scheduled Commercial
Operation Dates of June 1, 2001 for the Initial Units and June 1, 2002 for the
Final Units are achievable using generally accepted project and construction
management practices.
PERFORMANCE GUARANTEES AND ACCEPTANCE TESTS
PERFORMANCE GUARANTEES
Under the terms of the EPC Contract, the EPC Contractor guarantees the
performance of each CTG Unit with respect to net electrical output, net heat
rate, and exhaust emission levels. The guarantees and the conditions under which
these are guaranteed are summarized in Tables 5 and 6.
In addition, near-field and far-field noise guarantees are provided. The
near-field guarantee is 90 dBA at one meter from equipment and the far-field
guarantee is 58 dBA at 1,200 ft from the nearest unit with all units and other
noise sources, such as ventilation systems, operating.
TABLE 5
PERFORMANCE GUARANTEES AND CONDITIONS(1)
NEW & CLEAN CONDITIONS
<TABLE>
<CAPTION>
FUEL
----------------------------
GUARANTEE NATURAL GAS DISTILLATE OIL
--------- ----------- --------------
<S> <C> <C>
Net Unit Output (kW)................................. 156,410 N/A
Net Unit Heat Rate (HHV)(Btu/kWh).................... 10,683 10,821
</TABLE>
------------------------
(1) Subject to measurement uncertainty deadband not to exceed plus or minus1.0
percent on net plant output and plus or minus1.5 percent on net unit heat
rate; test results adjusted to 94 DEG.F dry bulb and 74 DEG.F wet bulb
ambient temperature; and evaporative coolers in service.
The Performance Guarantees are further based on the design natural gas
composition in the EPC Contract, and the net power measured at the high side of
each step-up transformer with the utility kilowatt hour meter(s).
The EPC Contract guarantees that stack emissions of each Unit will comply
with the Facility's Air Permit. Although the Air Permit's limits vary, in some
cases with load, the principal limits are presented in Table 6.
TABLE 6
AIR PERMIT EMISSIONS LIMITS (FULL LOAD)
<TABLE>
<CAPTION>
FUEL
----------------------------
LOAD LEVEL AND EMISSION NATURAL GAS DISTILLATE OIL
----------------------- ----------- --------------
<S> <C> <C>
AT BASE LOAD TO 50% LOAD
NO(X) (ppm @ 15% O(2)).................................... 15 42
CO (ppm).................................................. 15 20
PM(10) (lb/MMBtu)......................................... 0.010 0.013
VOC (lb/MMBtu)............................................ 0.003 0.005
Opacity (%)............................................... 10 20
</TABLE>
B-21
<PAGE>
FUNCTIONAL TESTING
Functional Testing consists of operational tests of systems performed after
Mechanical Completion occurs. The tests are to verify that the controls are
tested and tuned and that the systems work properly and are ready for normal and
continuous operation. Functional Testing requirements for each Unit must be
satisfied prior to commencement of Acceptance Testing.
ACCEPTANCE TESTING
In order to demonstrate that the Facility meets or exceeds the performance
guarantees, the EPC Contract requires the EPC Contractor to successfully
complete a series of tests defined as the Owner Tests and the PECO Tests.
Acceptance Testing must be satisfactorily completed before the EPC Contractor
can achieve Commercial Operation for the Facility.
OWNER TESTS
The Owner Tests consists of the following six tests:
(1) PERFORMANCE TESTS
Performance Test will be conducted to measure net power output and net
heat rate of each Unit including Integrated Plant Systems Tests for the
entire Facility.
(2) INTEGRATED PLANT SYSTEMS TESTS
Three Integrated Plant Systems Tests will be performed to demonstrate
that the Facility is not limited in its capability to produce the Commercial
Operation Output of 938,460 kW:
- Phase I--Units 1, 2 and 3 operating simultaneously
- Phase II--Units 4, 5 and 6 operating simultaneously
- Final--All six units operating simultaneously
(3) DEMONSTRATION TESTS
Demonstration tests to be performed to confirm certain Facility and
system capabilities are as follows:
- Gas Turbine Fuel Oil Firing
Each CTGs shall operate for one hour at base load while fired
100 percent with fuel oil without any combustion system or gas turbine
temperature alarms.
- Gas Turbine Fuel Switching
Each CTG will switch from natural gas to fuel oil and back to natural
gas.
- Gas Turbine Startup and Startup Durations
Each CTG, when on turning gear, must be able to reach base load output
within 30 minutes of start initiation when firing natural gas and fuel
oil
- CTG Response Characteristics
Each CTG must achieve a loading/unloading rate of no less than
8.3 percent of base load output per minute between 0-100 percent of
base load on either fuel.
- Generators Leading/Lagging Operation
Each CTG must operate at each power factor constant limit of 0.95
leading to 0.85 lagging for a period of one hour.
- Minimum Load Operation
B-22
<PAGE>
Each CTG must operate stable at a power output of 50 percent of base
load for a duration of two hours.
- Automatic Generation Control
Automatic generation control must be demonstrated for the entire
Facility and individual CTGs from 50 percent base load to maximum
output.
(4) EMISSIONS TESTS
During the Performance Tests, Gas Turbine Fuel Oil Firing Tests, Minimum
Load Tests, Unit Availability Tests and Unit Capacity Tests, each unit must
be operated within the Air Permit limits for emissions. This will be
determined by monitoring NO(X) emissions using the Facility's CEM systems
after calibration.
A Source Emissions Test conducted on each unit in accordance with a
protocol approved by the Georgia Department of Natural Resources ("GA DNR")
will demonstrate compliance with the Air Permit. The CEM systems will be
demonstrated to be in compliance with state and federal requirements in
accordance with a protocol to be approved by the GA DNR. The Source
Emissions Tests and CEMS demonstrations are required for Final Acceptance,
but not for Commercial Operation.
Noise audits for each Phase will be conducted to verify compliance with
noise guarantees. Satisfactory demonstration with both Phases in full load
operation is a requirement of Final Completion.
(5) UNIT AVAILABILITY TEST
Each Unit must operate with a 99 percent availability for 12 consecutive
hours per day over a period of 2 consecutive days or if the unit cannot run
due to reasons beyond the EPC Contractor's control, 99 percent availability
for 40 hours.
(6) PLANT AVAILABILITY TEST
The Facility must operate with a 99 percent availability for 12
consecutive hours per day over a period of 2 consecutive days.
PECO TESTS
The PECO tests are used to determine the net electrical output capability of
the Facility and the effectiveness of each evaporative cooler.
(1) UTILITY CAPACITY TEST
After the completion of each phase, two 1-hour tests will be performed
to determine the net electrical output capability of the Facility to be used
in establishing Contract Capacity in the PPA. The Phase I and II Integrated
Plant Systems Tests described above may be considered to be the Phase I and
II PECO Tests.
(2) EVAPORATIVE COOLER EFFECTIVENESS TESTING
As part of the Utility Capacity Test, tests will be performed to
determine the effectiveness of each evaporative cooler, but only when the
dry bulb temperature exceeds 60 DEG.F and there is a minimum of 10 DEG.F
difference between the wet bulb and dry bulb temperatures. The coolers must
maintain at least 85 percent effectiveness for a duration of one hour.
B-23
<PAGE>
SUMMARY
Based on our review, we are of the opinion that, given the range of dispatch
factors projected by RDI, which is typical of peaking operation, and the
requirements of the PPA, the Acceptance Tests and guarantees included in the EPC
Contract are adequate to estimate the future performance of the Facility.
LIQUIDATED DAMAGES
Liquidated damages ("LDs") are available under the EPC Contract in the event
that the EPC Contractor is unable to meet schedule milestones, or unable to
successfully complete the Acceptance Testing.
Schedule LDs, available in the event the EPC Contractor fails to achieve
Commercial Operation of a Unit by the Scheduled Date of Commercial Operation for
such Unit, consist of the sum of the following amounts: $40,000 per Unit for
each full day or part thereof by which the Commercial Operation of any such Unit
is delayed up to and including the 14th day after the Scheduled Commercial
Operation Date for such Unit; $65,000 per Unit for each full day or part thereof
by which the Commercial Operation of any such Unit is delayed beyond the 14th
day and up to and including the 30th day after the Scheduled Commercial
Operation Date for such Unit; and $82,000 per Unit for each full day or part
thereof by which the Commercial Operation of any such Unit is delayed beyond the
30th day after the Scheduled Commercial Operation Date for such Unit. Such LDs
will be offset by any net revenues received by the Partnership from the
operation of such affected Units during the period that the LDs apply, prior to
their respective Commercial Operation Dates. The aggregate LDs for delays in
Unit completion are limited to a maximum of 22.5 percent of the Guaranteed Lump
Sum price of the EPC Contract, or approximately $51,539,587. These LDs may be
limited to the damages available to the EPC Contractor from GE to the extent
that the delay is caused primarily due to GE's failure to perform. GE will be
obligated to pay damages to the EPC Contractor (1) for unexcused late delivery
of the Units and (2) if the performance of the Units is not as required under
the GE Turbine Contract. GE will also issue certain warranties in connection
with the performance of the Units. For additional discussion, please refer to
the section of the Offering Circular entitled "Summary of Principal Project
Documents, EPC Contract".
Under the PPA, the Partnership is obligated to pay LDs to PECO for failure
of a Unit to achieve its Scheduled Date of Commercial Operation in amounts equal
to: (1) $25,000 per Unit for each full day or part thereof by which the
Commercial Operation of any such Unit is delayed up to and including the 14th
day after the Scheduled Commercial Operation Date for such Unit; (2) $50,000 per
Unit for each full day or part thereof by which the Commercial Operation of any
such Unit is delayed beyond the 14th day and up to and including the 30th day
after the Scheduled Commercial Operation Date for such Unit; and (3) $66,667 per
Unit for each full day or part thereof by which the Commercial Operation of any
such Unit is delayed beyond the 30th day after the Scheduled Commercial
Operation Date for such Unit. The aggregate amount of LDs payable by the
Partnership to PECO shall not exceed $8,000,000 per Unit and $25,000,000 in the
aggregate.
Performance LDs are available in the event that the EPC Contractor fails to
meet the guaranteed net power output ("Commercial Operation Output") of at least
938,460 kW for the Facility, and 156,410 kW for each Unit ("Unit Output
Requirement"), when measured during the Performance Tests. Output performance
LDs are set at $300 for each kilowatt by which the demonstrated Commercial
Operation Output and Unit Output Requirements fall below these guaranteed
values. The aggregate LDs for reduced Facility and Unit output are limited to a
maximum of 22.5 percent of the Guaranteed Lump Sum price of the EPC Contract, or
approximately $51,539,587.
Performance LDs are also available in the event that the EPC Contractor
fails to meet the guaranteed Commercial Operation Net Heat Rates of 10,683
Btu/kWh or less when operated on
B-24
<PAGE>
natural gas and 10,821 Btu/kWh when operated on fuel oil, both when measured
during the Performance Tests. Net Heat Rate LDs are set at $5,860 per Btu/kWh
for each Btu/kWh by which the demonstrated net heat rate of the Facility or any
Unit exceeds the Commercial Net Heat Rate when operated on natural gas, plus
$950 per Btu/kWh by which the demonstrated net heat rate of the Facility or any
Unit exceeds the Commercial Net Heat Rate when operated on fuel oil. The
aggregate LDs for increased Plant and Unit net heat rates are limited to a
maximum of 22.5 percent of the Guaranteed Lump Sum price of the EPC Contract, or
approximately $51,539,587.
The aggregate liability of the EPC Contractor for liquidated damages under
the EPC Contract for delays in Commercial Operation, Commercial Operation Output
and Commercial Operation Net Heat Rate is limited to 30 percent of the
Guaranteed Lump Sum Price under the EPC Contract price, or approximately
$68,719,450.
STATUS OF PERMITS AND APPROVALS
The Facility must be designed, constructed and operated in accordance with
applicable environmental laws, regulations and codes. On the basis of our
review, we are of the opinion that the Partnership has received the key
environmental permits and approvals required from the various federal, state,
and local agencies, that are currently necessary to construct the Facility.
While not all the required permits and approvals have been issued, including
some which cannot be obtained until the Facility is ready to operate, we are not
aware of any technical circumstances that would prevent the issuance of the
remaining permits. Certain permits related to construction require detailed
design drawings for their application, are the EPC Contractor's responsibility,
and are procedural in nature.
The status of key permits and approvals for the construction and operation
of the Facility is presented in Table 7. Additional information is provided
following the table, where necessary for completeness or clarification.
B-25
<PAGE>
TABLE 7
STATUS OF KEY PERMITS AND APPROVALS
<TABLE>
<CAPTION>
PERMIT OR APPROVAL FOR AGENCY STATUS REMARKS
------------------ --------------------- --------------------- --------------------- ---------------------
<S> <C> <C> <C> <C>
FEDERAL
Determination Exempt Wholesale Federal Energy Approved 7/9/99
Generator status Regulatory Commission
Authorization under Filling and U.S. Army Corps of Authorized 4/21/99 see text
Nationwide Permit disturbance of Engineers ("Corps")
No. 26 wetlands
Approval of Facility Oil storage U.S. Environmental Plan submittal not
Response Plan Protection Agency required until tank
("EPA") is filled.
STATE
Air Permit Construction and GA DNR Issued 12/18/98
initial operation of
a source of air
pollution
Title V Operating Operation of a major GA DNR Application required
Permit source of air within 12 months
pollution after start of
operations
Stormwater discharge Construction GA DNR Not available--see EPC Contractor
permit stormwater discharge text responsibility
NPDES Permit Discharge of GA DNR Issued 7/9/99, Renewal application
wastewater expires 6/30/04 due 1/9/04
LOCAL
Zoning Approval Facility Heard County Obtained June 8, 1998
Disturbance Permit Facility Site grading Heard County Detailed grading EPC Contractor
plans, necessary for responsibility
application, in
progress
</TABLE>
CORPS PERMIT
As a condition of the Corps' authorization under Nationwide Permit No. 26,
the Partnership is required to obtain Corps approval of certain restrictive
covenants for parcels of land related to the approved wetlands mitigation plan.
The Partnership has indicated its intent to obtain this Corps approval in
adequate time to comply with the further requirement to register the covenants
with the property deeds within 60 days of commencing construction in the
wetlands. We know of no technical reason why this approval should not be
attainable.
AIR PERMIT
The Air Permit includes emission limits, operating restrictions, testing
requirements, and monitoring and reporting requirements. Principal emission
limits are described in Table 6 herein. No. 2 fuel oil is limited to
0.05 percent (by weight) sulfur content and the Facility is limited to use of
57 million gallons of No. 2 fuel oil per 12-month period. The average
utilization of the Facility shall not exceed 3,066 hrs/unit/year.
These limits and operating restrictions and the testing, monitoring and
recording requirements are similar to the requirements of air permits for other
facilities with which we are familiar.
STORMWATER DISCHARGE PERMIT
Disturbance of greater than five acres for construction would require a
Construction Stormwater NPDES Permit. The EPA has delegated authority for
administering this permit program to the GA DNR, which has issued a General
Permit covering construction activities throughout the State of Georgia.
However, we understand that this General Permit has been appealed, and that
until these
B-26
<PAGE>
appeals are settled, GA DNR is neither issuing authorizations under the General
Permit or individual construction stormwater permits. The Partnership has
received a letter from the GA DNR indicating that it will consider the
Partnership in compliance provided it implements all of the technical
requirements of the General Permit.
PENDING CHANGES IN REGULATIONS
There are two pending changes in the GA DNR's air pollution regulations
which, when and if finalized, may have an effect on operation of the Facility.
SIP CHANGE
The Atlanta, GA area is not attaining the National Ambient Air Quality
Standard for ozone. In order to achieve that standard in the coming years,
GA DNR has proposed a change to its State Implementation Plan ("SIP") comprised
of a series of regulatory changes affecting stationary sources, including power
plants, and mobile sources. The focus of this SIP Change is reductions in
emissions of NO(X) and volatile organic compounds ("VOC"), which are pollutants
involved in the formation of ozone, in northern Georgia.
This SIP Change must be submitted to the EPA for approval. We have not
reviewed the SIP Change in detail. The Partnership indicated that there are
reasons to believe that the SIP Change, in its current form, is not approvable
by the EPA, in which case the process could start over during 2000. A first
attempt at a SIP Change to address the same non-attainment issue was rejected by
EPA in 1998.
The SIP Change may be modified at any step in this process; therefore it is
uncertain what, if any, impact the SIP Change may have when it is finally
implemented. However, a general observation can be made. As the Facility has
been issued its Air Permit, it is likely that most, if not all, of the
regulations changes in the SIP Change will not be applicable; i.e., the Facility
will be "grandfathered" from most of the requirements. The permitted emission
rates for the Facility are, in general, below the targeted emission rates for
new sources in the proposed SIP Change. If implemented as currently proposed,
there would be little, if any, impact expected on Facility operations.
EPA SIP CALL
As numerous eastern states have had a persistent ozone attainment problem,
part of which is due to transport of ozone precursors from adjacent states, EPA,
in September 1998, issued a rule calling for 22 states, including GA, to prepare
and submit revisions to their SIPs to provide for further reduction of emissions
of NO(X) commencing with the 2003 ozone season (May-September) (the "SIP Call").
Under the EPA rules, the affected states were to submit these SIP revisions by
September 1999. However, on May 26, 1999, the U.S. Circuit Court of Appeals for
the District of Columbia stayed the effect of the SIP Call, pending resolution
of challenges brought by various entities; thus, states were not required to
submit revised SIPs by the September 1999 deadline. This action places in doubt
the scope, timing and content of the EPA mandate to further reduce NO(X)
emissions, and will likely delay implementation of the NO(X) reductions and
cap-and-trade program envisioned by the EPA.
In general, the EPA SIP Call envisioned a regional NO(X) cap-and-trade
system similar to the national SO(2) emissions allowance program in effect under
Title IV of the Clean Air Act. Each state would be assigned a NO(X) emissions
cap for the ozone season, and would implement regulations (referred to as the
"NO(X) Budget Rule") distributing these allowances and requiring each affected
source to hold allowances for its actual ozone season NO(X) emissions each year.
If a facility were to emit more NO(X) than its allocation, it would have to
obtain additional allowances on the open market. If it emitted less, it might be
able to sell the excess allowances. This system was to go into effect for the
2003 ozone season.
B-27
<PAGE>
Prior to the Circuit Court decision, the GA DNR had developed a draft of
"Main Principles for Utilities," a preliminary concept for allowance allocation
for the years 2003 and beyond. This methodology would assign allowances for the
years 2003-2007 to existing units using an undefined method, although EPA
guidance would suggest it would be based on actual fuel use during some
historical baseline period multiplied by an emission factor of 0.15 lb/MMBtu.
For units permitted after 1995 (i.e., not operating during the initial
baseline period), including the Facility, allowances for the period 2003-2007
would be allocated on a first-come, first-served basis from a 900 tons per
season ("tps") set-aside pool, and would be based on a nominal NO(X) emission
rate of 0.04 lbs/MMBtu, the maximum heat input capacity of the unit, and an
assumed capacity factor of 20 percent, or 734 hrs/season. For the Facility, this
would be approximately 154 tps. The Partnership expects actual NO(X) emissions
from the Facility to be somewhat less than 154 tps. Excess allowances could be
sold.
Beginning with the 2008 ozone season, the Facility would be considered an
existing unit and would share in the allocation of the cap based on whatever
scheme is adopted. EPA guidance suggests an allocation scheme based on actual
seasonal NO(X) emissions during a baseline period that is shortly before the
date of the allocation and a factor in pounds of NO(X) per MWh or MMBtu.
If, in fact, the EPA prevails and the SIP Call goes forward, the exact
allocations of allowances for year 2003 and beyond will not be specifically
known for some time. For the purposes of the Projected Operating Results, we
have conservatively assumed that:
- a NO(X) budget rule with a cap-and-trade system will be in place by 2003,
- the Facility will only be allocated half the allowances necessary for the
Facility's expected NO(X) emissions, and
- allowances will cost $1,400/ton in 1995 dollars, which is comparable to
the price of recent trades of NO(X) allowances in the Northeast where such
a trading system went into effect this year, and will escalate at the rate
of inflation.
THE FINANCING OF THE PROJECT
FACILITY CONSTRUCTION COST
The EPC Contract includes a "Guaranteed Lump Sum Price" of $229,064,832 (the
"EPC Contract Price"). The EPC Contract Price includes the EPC Contractor's
fixed price for labor and material and the cost of the GE Turbine Contract.
Additionally, $302,000 is included in the Total Construction Cost for late scope
changes which are anticipated to be added to the EPC Contract Scope. The EPC
Contractor's estimate which serves as the basis of the EPC Contract Price is
based on the Partnership's Request for Proposal, preliminary design drawings,
preliminary site plans and general arrangement drawings, and quotes the EPC
Contractor obtained from manufacturers, suppliers, vendors and subcontractors
with whom the EPC Contractor is familiar. A Tenaska affiliate executed an
agreement with GE for the supply of the CTGs and will assign the agreement to
the Partnership upon issuance of the Bonds. The Partnership will immediately
assign the agreement to the EPC Contractor.
The EPC Contract stipulates that if the Authorization to Proceed ("ATP") is
not issued by July 1, 2000, the EPC Contract Price shall be escalated per
Exhibit P. Should the ATP not be issued by December 31, 2000, the EPC Contractor
may request that the EPC Contract Price may be renegotiated.
The Partnership has estimated other construction costs of $31,262,000 (the
"Other Construction Costs"), as shown in Table 8, and together with the EPC
Contract Price and Scope Changes is the Total Construction Cost. The Other
Construction Costs includes $11,962,000 of project contingency (the "Project
Contingency"). The Partnership's Project Contingency budget falls in a range of
project
B-28
<PAGE>
contingency that we would anticipate based on the contingency requirements of
other similar projects with which we are familiar. The Partnership prepared its
budgets for electrical, gas and water interconnection costs based on estimates
provided by the entities that will be responsible for completing the
interconnection work. The Partnership estimated its project management,
insurance, start-up and contingency budgets based on its experience on other
similar projects and its estimated project specific requirements of the
Facility. The Partnership's estimate for spare parts is based on the recommended
spare parts as provided in Exhibit I of the LTSA.
TABLE 8
TOTAL CONSTRUCTION COST(1)
($000)
<TABLE>
<S> <C>
EPC Contract Price.......................................... $229,065
Scope Changes............................................. 302
--------
Total EPC Price........................................... $229,367
Other Construction Costs
O&M Mobilization Costs.................................... $ 110
Electrical Interconnection Costs.......................... 1,000
GPC Monthly Fees.......................................... 158
Gas Interconnection Costs................................. 3,123
Heard County Water Authority.............................. 515
Land...................................................... 712
Project Management Costs.................................. 4,643
Insurance (Builder's Risk/Marine/Liability)............... 1,350
Sales Tax................................................. 1,000
Spare Parts............................................... 3,649
Start-up Costs............................................ 3,040
Project Contingency....................................... 11,962
--------
Subtotal--Other Construction Costs........................ $ 31,262
Total Construction Cost..................................... $260,629
</TABLE>
------------------------
(1) As estimated by the Partnership.
Based on our review, we are of the opinion that the estimates which serve as
the basis for the EPC Contract Price and the Total Construction Cost were
prepared in accordance with generally accepted engineering and estimating
practices and methods. The EPC Contract Price and the Total Construction Cost,
including Project Contingency, are comparable to the costs of simple cycle
projects at similar stages of development utilizing similar technologies with
which we are familiar.
SOURCES AND USES OF FUNDS
The estimated sources and uses of funds in connection with the Financing of
the Facility, including the issuance of Bonds, as estimated by the Partnership
based on interest and reinvestment rate assumptions provided by Goldman,
Sachs & Co. and TD Securities (collectively, the "Initial Purchasers"), are
summarized in Table 9.
B-29
<PAGE>
TABLE 9
ESTIMATED SOURCES AND USES(1)
($000)
<TABLE>
<S> <C>
Sources of Funds
Gross Proceeds of the Bonds............................... $275,000
Equity Contribution....................................... 35,500
Revenue from Operations of the Initial Units.............. 20,089
--------
Total Sources of Funds.................................... $330,589
Uses of Funds
Total Construction Cost................................... $260,629
Development Costs......................................... 7,000
Financing Fees and Costs.................................. 5,114
Interest During Construction(2)........................... 52,757
Expenses from Operations of the Initial Units............. 4,831
Working Capital........................................... 258
--------
Total Uses of Funds......................................... $330,589
</TABLE>
------------------------
(1) As estimated by the Partnership.
(2) Based on an interest rate of 9.50 percent on the Bonds and assumes that
unspent proceeds earn interest income at a rate of 5.0 percent per year, as
estimated by the Initial Purchasers.
Based on our review, we are of the opinion that, based upon the interest and
reinvestment rates as estimated by the Initial Purchasers and the total uses of
funds as estimated by the Partnership, the principal amount of the Bonds, when
combined with the equity from the Partnership, PPA revenue during the
construction period from the Initial Units, and interest income during the
construction period, should be sufficient to fund the Total Construction Cost
and interest on the Bonds through May 31, 2002.
PROJECTED OPERATING RESULTS
We have reviewed estimates and projections of electric generating capacity,
fuel consumption and operating costs for the Facility as made available to us by
the Partnership. On the basis of such data, we have prepared the Projected
Operating Results. The Projected Operating Results are presented herein for each
calendar year beginning on June 1, 2002, the expected Commercial Operation Date
of the entire Facility, and ending on February 1, 2030, the scheduled maturity
of the Bonds. Revenues will be derived from the sale of electrical capacity and
energy to PECO under the PPA. Expenses for the Facility consist primarily of
fixed and variable operations and maintenance expenses, based on our review of
projected operating and maintenance expenses provided by the Partnership. Debt
service on the Bonds has been estimated by the Initial Purchasers. Projected
sources of revenues and expenses have been set forth in the Projected Operating
Results presented in Exhibit B-1. The Projected Operating Results are based on
current contractual commitments as described herein and have been prepared using
assumptions and considerations set forth in this Report and the footnotes to
Exhibit B-1.
ANNUAL OPERATING REVENUES
Under the pricing provisions of the PPA, the Partnership will receive
several different revenue streams from PECO and may incur incentive and/or
penalty payments for certain operational conditions. The term of the PPA
commences on the date of Commercial Operation and ends on the 29th anniversary
of Commercial Operation (the "Operating Term"). PECO may terminate the PPA on
B-30
<PAGE>
the 20th anniversary of Commercial Operation upon payment to the Partnership of
$175,000,000. For the purposes of the Projected Operating Results, we have
assumed that PECO would purchase electricity from the Facility under the terms
of the PPA for the full Operating Term. The payment streams and incentive and
penalty provisions under the PPA are determined as follows:
RESERVATION PAYMENTS
Reservation payments will be calculated monthly as the product of (1) a
reservation rate, in dollars per kilowatt per month, (2) the number of Units in
Commercial Operation, (3) the Unit capacity, and (4) 1,000. The annual
reservation rates are specified in Exhibit 8.02 to the PPA, and increase from
$3.50/kW-mo for the first Contract Year to $6.00/kW-mo during the 29th Contract
Year.
ENERGY PAYMENTS
Energy payments will be calculated monthly as the product of (1) the total
amount of delivered energy from the Facility received by PECO, and (2) either a
gas energy rate or fuel oil energy rate, depending on the fuel used to generate
such delivered energy. The annual gas energy rates and fuel oil energy rates are
specified in Exhibit 8.03 to the PPA, and increase from $0.16/MWh for the first
Contract Year to $0.56/MWh during the 29th Contract Year for the gas energy
rate, and from $1.06/MWh for the first Contract Year to $1.46/MWh during the
29th Contract Year for the fuel oil energy rate.
REPLACEMENT ENERGY PAYMENT
Replacement energy payments will equal the aggregate replacement fuel cost
incurred each month by the Facility.
START CHARGES
Start charges will be calculated monthly as the product of (1) the number of
starts requested by PECO and (2) a start charge, equal to $11,000 for each start
during the first Contract Year, escalating by 3 percent per year thereafter.
MISCELLANEOUS CHARGES
PECO may also incur miscellaneous charges through excess run time payments
and standby mode charges.
AVAILABILITY INCENTIVE PAYMENT
If the Summer Availability Percentage for each Contract Year exceeds
97 percent, but the Peak Days Availability (determined as the Facility
Availability Percentage calculated during the five days during the immediately
preceding Summer Period with the highest On-Peak Energy Prices) is below
99 percent, PECO shall pay to the Partnership $150,000 for each percentage point
the Summer Availability Percentage exceeds 97 percent. If the Summer
Availability Percentage for each Contract Year exceeds 97 percent and the Peak
Days Availability exceeds 99 percent, PECO shall pay to the Partnership $500,000
for each percentage point the Summer Availability Percentage exceeds
97 percent, up to a maximum of $1,500,000 for each Contract Year.
AVAILABILITY ADJUSTMENTS PAYMENTS
If the Summer Availability Percentage is less than 87 percent, the
Partnership shall pay PECO an amount equal to 3.34 percent of the total
reservation payments for such Contract Year for each percentage point the Summer
Availability Percentage is below 97 percent. If the Annual Availability
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Percentage is greater than 76.9 percent but less than 97 percent, the
Partnership shall pay PECO an amount equal to 3.34 percent of the total
reservation payments for such Contract Year for each percentage point the Annual
Availability Percentage is below 97 percent. Amounts paid to PECO under the
Summer Availability Adjustment will be credited against amounts due under the
Annual Availability Adjustment. If the Annual Availability Percentage is below
76.9 percent, the Partnership shall pay PECO an amount equal to 66.8 percent of
the total reservation payments for such Contract Year plus 0.432 percent of the
total reservation payments for such Contract Year for each percentage point the
Annual Availability Percentage is below 76.9 percent. As mentioned previously,
based on the projected level of dispatch, the Facility should be capable of
achieving a Summer Availability Percentage of 98 percent and an Annual
Availability Percentage of 97 percent, as defined in the PPA.
FUEL ADJUSTMENT PAYMENTS
For each Contract Year in which the Facility is operated during the summer
months at Base Unit Output for at least 2,000 Unit Hours, if the Summer Months
Base Heat Rate is greater than 11,300 Btu/kWh, the Partnership shall pay PECO a
fuel adjustment payment for the difference between the actual heat rate and
11,300 Btu/kWh multiplied by the Daily Index Citation gas price. If the actual
Summer Months Base Heat Rate is less than 10,800 Btu/kWh, PECO shall pay a fuel
adjustment payment to the Partnership based on the difference between 10,800
Btu/kWh and the actual Summer Months Base Heat Rate multiplied by the Daily
Index Citation gas price.
The operating revenues under the PPA, as shown in the Base Case Projected
Operating Results are based on: (1) an average annual Contract Capacity level of
908,000 kW; (2) a Summer Availability Percentage equal to 98 percent and an
annual Peak Days Availability average less than 99 percent but greater than
97 percent; (3) an Annual Availability Percentage equal to 97 percent; (4) net
annual capacity factors and number of Unit Starts as estimated by RDI; and
(5) an average annual Facility net heat rate of 11,088 Btu/kWh.
ANNUAL OPERATING EXPENSES
FUEL COST
The Partnership will incur no annual fuel-related costs or charges during
the term of the PPA provided PECO remains the exclusive recipient of all
capacity and energy generated by the Facility, except for the fuel payment
adjustment, if any. For the purposes of calculating an Efficiency Adjustment
under the PPA, RDI has projected the price of fuel for the Facility.
OPERATION AND MAINTENANCE EXPENSES
The Operator is responsible for operation and maintenance of the Facility.
The Facility has negotiated and executed the O&M Agreement with the Operator for
the administration, operation and maintenance of the Facility, including
providing initial start-up support during the pre-commissioning period. Tenaska
has executed, and will assign to the Partnership, an LTSA with GE International
for the long-term maintenance of the CTGs.
The Partnership's estimate of operating and maintenance expenses includes
provisions for labor, repair and maintenance, including renewals and
replacements, utilities, and consumables. The Partnership has also included a
provision for operating and maintenance contingency beginning in 2004. For the
purposes of the Projected Operating Results, we have assumed that any
extraordinary repair costs prior to 2004 will be covered by the EPC Contractor
or GE under their warranties pursuant to the EPC Contract and the GE Turbine
Contract, respectively.
The Partnership will pay the Operator a fixed management fee, an incentive
fee, and, potentially, an availability bonus. There is also a corresponding
availability penalty. Pursuant to the O&M
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Agreement, the fixed management fee is $225,000 in 1999 dollars, except during
2003 for which the fee has been waived. In addition, the Facility will reimburse
the Operator for operations and maintenance expenses based on an annual budget
agreed to by the Operator and the Partnership. The O&M Agreement provides for
incentive payments by the Partnership for Contract Availability and other
mutually agreed upon incentive criteria. We have also included the
administration fee under the interconnection agreement with GPC. We have assumed
that, except as noted above, all O&M costs will increase at the rate of general
inflation of 2.5 percent per year.
OPERATIONS AND MAINTENANCE AGREEMENT
The O&M Agreement has a term commensurate with that of the PPA, and
establishes the terms and conditions to which Operator will perform management
and operating services including providing initial start-up support prior to the
Date of Commercial Operation.
The Operator will provide personnel, procedures, training and
administrative, management, and professional/technical services necessary for
the safe and reliable start-up, commissioning, operation and maintenance of the
Facility. The Operator will warrant that the services performed by the Operator
and/or its subcontractors and suppliers shall be done in a good and workmanlike
manner in accordance with Prudent Utility Practice and standard industry
practice and in accordance with Facility manuals.
The structure of the O&M Agreement is a cost reimbursable plus fee basis. In
addition to cost reimbursement, the Partnership will pay the Operator an annual
fixed management fee of $225,000 during the first Contract Year, escalated
thereafter at the rate of inflation. Under the terms of the O&M Agreement, there
will be no fixed management fee during 2003. In addition, the Operator is
eligible to earn an incentive fee which shall be paid on the basis of the
Partnership's assessment of the Operator's performance against mutually agreed
upon incentive criteria. The maximum value of the incentive fee to be earned
during the first Contract Year is $100,000, adjusted annually thereafter at a
rate of 3.5 percent per year beginning on January 1, 2001. The Operator is also
subject to an Availability Adjustment bonus, or penalty for each Contract Year
on the basis of the Facility's Annual Availability Percentage. The bonus and
penalty amounts are $25,000 per 1 percent above or below a 97 percent Annual
Availability Percentage threshold, respectively; both the bonus and penalty fees
are subject to an initial maximum annual amount of $75,000, escalating each year
at an annual rate of 3.5 percent, beginning on January 1, 2001. During the
pre-commissioning period the Partnership will pay the Operator a fixed
management fee of $75,000 and an incentive fee of up to $75,000.
LONG TERM PARTS AND LONG TERM SERVICE CONTRACT
The Initial Term of the LTSA shall expire upon the earlier of:
(1) completion of the first Major Inspection of each Unit; or (2) thirty years
after the Performance Start Date for each Unit. The Partnership has the option
to extend the term of the LTSA for any or all of the Units through the next
major inspection interval.
The LTSA covers planned and unplanned maintenance, technical advisory,
diagnostic, spare parts, major parts replacement, parts repair, and inspection
and overhaul services. In conjunction with the LTSA, GE International will
provide availability guarantees on a long-term basis for the turbine generators.
Under the terms of the LTSA, the Partnership will initially pay GE
International a monthly fixed charge per Unit throughout the initial term of the
LTSA. In addition, the Facility will incur a Factored Start charge for starts in
excess of 24 starts per Unit during any calendar year, and will incur a Factored
Fired Hour Adjustment charge for fired hours in excess of a base amount of
sixteen Factored Fired Hours per Factored Start per Unit. All rates and charges
under the LTSA are based on 2001 dollars and will escalate at 3 percent per year
through January 31, 2011, and then will escalate based
B-33
<PAGE>
on a composite index made up of 40 percent Materials Index and 60 percent U.S.
Labor Index beginning with payments due on or after February 1, 2011.
Under the LTSA, GE International will guarantee an Annual Availability
Percentage, calculated in accordance with terms which are similar to the terms
of the PPA. If the Annual Availability Percentage in a given year is greater
than the guaranteed percentage, the Partnership shall pay a bonus for each
percentage point exceeding the guaranteed percentage. If the Annual Availability
Percentage in a given year is less than the guaranteed percentage, GE
International shall pay a penalty for each percentage point below the guaranteed
percentage. There is a maximum amount to be paid by either party under these
provisions based on February 1, 2001 dollars, escalated at 3 percent per year
thereafter.
Based on our review, we are of the opinion that the methodology used by the
Partnership in preparing the operation and maintenance cost estimate for the
Facility, including the provision for major maintenance provided by the LTSA, is
reasonable.
OTHER EXPENSES
We have also included other expenses as estimated by the Partnership. These
expenses include the Partnership management fee and the cost of insurance,
property taxes and certain home office costs. Under the terms of the Partnership
Agreement, the payment of the Partnership's management fee will be waived
through 2009.
ANNUAL DEBT SERVICE
Based on information provided by the Initial Purchasers, we have included an
amount for the total annual debt service payments on the principal amount of the
Bonds of $275,000,000. Interest has been included at an annual interest rate on
the Bonds of approximately 9.50 percent as reported by the Initial Purchasers.
Principal payments and interest payments are due each February 1 and August 1 of
each year, with principal payments commencing on February 1, 2006. Deposits into
the Debt Service Fund are to be made to the Trustee in monthly installments over
the six months prior to the due date. Interest is assumed to be paid from the
proceeds of the Bonds and from operating revenues obtained during the period
between the Commercial Operation Dates of the Initial and Final Units until
June 1, 2002, the expected Commercial Operation Date of the Final Units.
Under the terms of the Collateral Agency and Intercreditor Agreement, total
letter-of-credit fees are included in the definition of debt service for
coverage calculation purposes. A Debt Service Reserve Account is to be
established pursuant to the Indenture for the purpose of funding any shortfalls
in the payment of principal and interest on the Bonds. A Debt Service Reserve
Account letter-of-credit will be put in place on June 1, 2002. The Debt Service
Reserve Account requirement will change over time and will be equal to the next
scheduled semi-annual debt service payment for the remainder of the term of the
Bonds plus six months' interest on any draws on the letter-of-credit, up to a
maximum Debt Service Reserve Account letter-of-credit amount of $16,000,000. For
the purposes of estimating the Debt Service Reserve Account requirement, the
Partnership has assumed annual draws on the letter-of-credit equal to the next
scheduled semi-annual debt service payment and an interest rate equal to the
rate on the Bonds. In addition, the Partnership is required to establish up to a
$25,000,000 letter-of-credit to be used as Acceptable Credit Support required
under the PPA, and is also allowed to establish a $10,000,000 Working Capital
Line of Credit in connection with the Facility. For the purposes of estimating
the letter-of-credit fees, the Partnership has assumed that it will establish a
Working Capital Line of Credit in the amount of $5,000,000. Fees on the Working
Capital Line of Credit and letter-of-credit facilities and on any unused amounts
have been included based on various rates provided by the Partnership. For the
purposes of the Projected Operating Results, we have assumed that there will be
no draws on any of the letters-of-credit or the Working Capital Line of Credit.
B-34
<PAGE>
DEBT SERVICE COVERAGE
On the basis of our studies and analyses of the Facility and the assumptions
set forth in this Report, we are of the opinion that, for the Base Case
Projected Operating Results for the Facility, the projected revenues under the
PPA are adequate to pay annual operating and maintenance expenses (including
provisions for major maintenance as provided by the LTSA) and other operating
expenses and provide an annual debt service coverage ratio of at least 1.30
times the annual debt service requirement on the Bonds and a weighted average
debt service coverage ratio of 1.49 times the annual debt service requirement
over the term of the Bonds. The weighted average debt service coverage ratio has
been calculated as the total net operating revenues divided by the total debt
service over the term of the Bonds. Annual debt service coverages for the term
of the Bonds are presented in Exhibit B-1.
SENSITIVITY ANALYSES
Due to the uncertainties necessarily inherent in relying on assumptions and
projections, it should be anticipated that certain circumstances and events may
differ from those assumed and described herein and that such will affect the
results of our Base Case Projected Operating Results for the Facility. In order
to demonstrate the impact of certain circumstances on the Base Case Projected
Operating Results, certain sensitivity analyses have been developed. It should
be noted that other examples could have been considered and those presented are
not intended to reflect the full extent of possible impact on the Facility. The
sensitivities are not presented in any particular order with regard to the
likelihood of any case actually occurring. In addition, no assurance can be
given that all relevant sensitivities have been presented, that the level of
each sensitivity is the appropriate level for testing purposes, or that only one
(rather than a combination of more than one) of such variations or sensitivities
could impact the Facility in the future.
These sensitivity analyses present the Projected Operating Results assuming,
respectively, that: (a) the Facility availability is reduced by 5 percentage
points, which results in a reduction in the Summer Availability and Annual
Availability Percentages under the PPA of approximately 1 percentage point;
(b) the heat rate of the Facility increases by 5 percent over that assumed in
the Base Case; (c) operating and maintenance expenses increase by 10 percent
over those assumed in the Base Case; (d) the rate of general inflation is
increased to 6 percent per year; (e) the Contract Capacity levels to PECO are
reduced to the minimum contractual value of 875,000 kW each year; (f) the
Facility operates at a "zero dispatch" level annually; and (g) the annual
capacity factors and annual number of Unit starts of the Facility are twice
those assumed in the Base Case. The sensitivity analyses are presented as
Exhibits B-2 through B-8 to this Report. For the purposes of sensitivity cases
(e), and (f), we have assumed there would be no changes in annual maintenance
costs or periodic maintenance activities under the LTSA.
SUMMARY COMPARISON OF PROJECTED OPERATING RESULTS
A summary of the debt service coverages on the Bonds for the Base Case
Projected Operating Results and each sensitivity case is presented in Table 10.
B-35
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TABLE 10
PROJECTED DEBT SERVICE COVERAGE
<TABLE>
<CAPTION>
BASE CASE SENSITIVITY CASES
--------- ----------------------------------------------------------------------------------
A B C D E F G
------------ --------- --------- --------- -------- -------- ---------
YEAR INCREASED REDUCED INCREASED
ENDING REDUCED INCREASED OPERATING INCREASED CONTRACT ZERO CAPACITY
DEC 31, AVAILABILITY HEAT RATE EXPENSES INFLATION CAPACITY DISPATCH FACTORS
------- ------------ --------- --------- --------- -------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
2002....................... 1.33 1.29 1.33 1.32 1.32 1.28 1.23 1.34
2003....................... 1.30 1.26 1.30 1.29 1.28 1.25 1.24 1.30
2004....................... 1.31 1.27 1.31 1.29 1.28 1.26 1.25 1.32
2005....................... 1.34 1.29 1.33 1.31 1.30 1.28 1.28 1.35
2006....................... 1.35 1.30 1.33 1.32 1.30 1.29 1.28 1.36
2010....................... 1.35 1.30 1.33 1.31 1.27 1.29 1.28 1.36
2015....................... 1.40 1.35 1.39 1.37 1.25 1.34 1.33 1.41
2020....................... 1.51 1.46 1.51 1.48 1.28 1.45 1.43 1.52
2025....................... 1.72 1.66 1.72 1.68 1.31 1.65 1.62 1.74
2029....................... 1.99 1.92 1.99 1.94 1.39 1.90 1.86 2.01
Minimum.................... 1.30 1.26 1.30 1.29 1.18 1.25 1.23 1.30
Average.................... 1.49 1.44 1.48 1.45 1.28 1.42 1.40 1.50
</TABLE>
LIQUIDATED DAMAGES ANALYSES
We have performed a series of analyses to estimate the impact on the average
debt service coverage ratio if the EPC Contractor fails to pass certain
performance tests and there is a long-term performance deficiency over the term
of the Bonds. In these analyses, we have assumed that, if performance liquidated
damages are paid to the Partnership by the EPC Contractor, the total damages
payment will be used to redeem the principal of the Bonds on pro rata basis.
These analyses have been performed to demonstrate the sufficiency of the
performance liquidated damages to maintain debt service coverage at the level
projected in the Base Case Projected Operating Results. These analyses assume
that: (1) the deficiency would exist in all units; and (2) that the maximum
aggregate liquidated damages of 22.5 percent of the EPC Contract Price would be
available to pay the damages associated with that deficiency and such damages
would be used to repay the debt, assumed for our purposes to be only the Bonds,
on a pro rata basis. Under the terms of the Collateral Agency and Intercreditor
Agreement, in the event that the average debt service coverage ratio is
projected to exceed 1.50, all or a portion of the liquidated damage payments
would not be used to repay the debt. Based on the projected average debt service
coverage ratio in the Base Case Projected Operating Results, we have assumed
that the entire liquidated damages payment would be used to repay the Bonds.
Based on these analyses, we are of the opinion that, if the EPC Contractor
pays the Partnership performance liquidated damages due to a failure to achieve
the Guaranteed Net Electrical Output and Guaranteed Net Heat Rate, then the
weighted average debt service coverage ratio over the term of the Bonds is
projected to remain generally at the same level as in the Base Case Projected
Operating Results for deficiencies in Guaranteed Net Electrical Output and
Guaranteed Net Heat Rate equivalent to the Performance Minimums under the EPC
Contract.
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
USED IN THE PROJECTION OF OPERATING RESULTS
In the preparation of this Report and the opinions that follow, we have made
certain assumptions with respect to conditions which may exist or events which
may occur in the future. While we believe these assumptions to be reasonable for
the purpose of this Report, they are dependent upon future events, and actual
conditions may differ from those assumed. In addition, we have used and relied
B-36
<PAGE>
upon certain information provided to us by sources which we believe to be
reliable. While we believe the use of such information and assumptions to be
reasonable for the purposes of our Report, we offer no other assurances with
respect thereto and some assumptions may vary significantly due to unanticipated
events and circumstances. To the extent that actual future conditions differ
from those assumed herein or provided to us by others, the actual results will
vary from those projected herein. This Report summarizes our work up to the date
of the Report. Thus, changed conditions occurring or becoming known after such
date could affect the material presented to the extent of such changes.
The principal considerations and assumptions made by us in developing the
Base Case Projected Operating Results and the principal information provided to
us by others include the following:
1. As Independent Engineer, we have made no determination as to the
validity and enforceability of any contract, agreement, rule, or regulation
applicable to the Facilities and their operations. However, for purposes of
this Report, we have assumed that all such contracts, agreements, rules, and
regulations will be fully enforceable in accordance with their terms and
that all parties will comply with the provisions of their respective
agreements.
2. Our review of the design of the Facility was based on information
provided by the Partnership.
3. The Operator will maintain the Facility in accordance with good
engineering practice, will perform all required major maintenance in a
timely manner, and will not operate the equipment to cause it to exceed the
equipment manufacturers' recommended maximum ratings.
4. The Operator will employ qualified and competent personnel and will
generally operate the Facility in a sound and businesslike manner.
5. The Facility will identify and implement solutions to the Y2K Problem
in a manner which will not impact the projected net revenues of the
Facility.
6. Inspections, overhauls, repairs and modifications are planned for and
conducted in accordance with manufacturers' recommendations, and with
special regard for the need to monitor certain operating parameters to
identify early signs of potential problems.
7. All licenses, permits and approvals, and permit modifications
necessary to operate the Facility have been, or will be, obtained on a
timely basis and any changes in required licenses, or permits and approvals
will not require reduced operation of, or increased costs to, the Facility.
8. The CPI and general inflation will increase at an average annual rate
of 2.5 percent per year.
9. The performance of the Facility will be as assumed in the Projected
Operating Results.
10. The Facility will sell the quantities of electricity under the PPA
as projected in the dispatch analyses performed by RDI. PECO will purchase
electricity from the Facility under the terms of the PPA for the full
Operating Term.
11. In the event the Facility experiences an Efficiency Adjustment, the
price of fuel for the Facility will be as projected by the RDI.
12. The non-fuel operating and maintenance expenses will be consistent
with the information provided by the Partnership, and will increase
thereafter at the assumed change in the general inflation rate, except for
certain expenses under the LTSA and O&M Agreement, as described in the
Report, and property taxes and certain fees, which are based on a schedule
provided by the Partnership.
13. Any extraordinary repair costs prior to 2004 will be covered by the
EPC Contract or GE under their warranties pursuant to the EPC Contract and
GE Turbine Contract, respectively.
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<PAGE>
14. There will be no additional capital improvements to the Facility
other than those assumed in the Projected Operating Results.
15. The Debt Service Reserve Account requirements will be provided for
through a letter of credit.
16. The principal amount of the Bonds will be $275,000,000 and the
annual interest rate will be 9.50 percent, as reported by the Initial
Purchasers. The amortization schedule of the Bonds will be as reported by
the Initial Purchasers.
17. If performance liquidated damages are paid to the Partnership by the
EPC Contractor, the total damages payment will be used to repay the debt,
assumed to be only the Bonds, on a pro rata basis.
CONCLUSIONS
Set forth below are the principal opinions which we have reached regarding
our review of the Facility. For a complete understanding of the estimates,
assumptions, and calculations upon which these opinions are based, the Report
should be read in its entirety. On the basis of our studies, analyses, and
investigations of the Facility and the assumptions set for in this Report, we
are of the opinion that:
1. The EPC Contractor, the Operator, and GE International have
previously demonstrated the capability to perform their responsibilities
under the EPC Contract, the O&M Agreement, and the LTSA, respectively.
2. Provided that, as required by the EPC Contract, the EPC Contractor
takes into account the recommendations in the Subsurface Report and in the
EPC Contract design criteria regarding site development, subsurface
conditions, and foundations during design and construction of the Facility,
the Facility Site is suitable for construction and operation of the
Facility.
3. Based upon our review of the environmental site assessments conducted
by EMCON for the Facility Site and the construction lay-down area, the
investigations appear to have been conducted in a manner consistent with
industry standards, using comparable industry protocols for similar studies
with which we are familiar. Although we have not conducted an independent
assessment of the Facility Site, the conclusions reached by EMCON appear to
be supported by the data we have reviewed.
4. The technology proposed for the Facility is a sound and proven method
of electric generation. If operated and maintained consistent with generally
accepted industry practices, the Facility should be capable of passing the
Acceptance Tests pursuant to the EPC Contract and meeting the requirements
of the PPA and the current environmental permits. Further, the Facility has
adequately provided for all off-site requirements, including fuel supply and
transportation, water supply, wastewater disposal, and electrical
interconnection.
5. The proposed method of design, construction and operation of the
Facility has been developed in accordance with generally accepted industry
practices and has taken into consideration the current environmental,
license and permit requirements that the Facility must meet.
6. If designed, constructed, operated and maintained as currently
proposed, the Facility should be capable of operating in a peaking operation
mode and of achieving an average annual output of 908 MW, and an average
annual net plant heat rate of 11,088 Btu/kWh (HHV). The average annual
output of 908 MW is within the range where neither party shall owe a penalty
or adjustment under the PPA. The average annual net plant heat rate of
11,088 Btu/kWh (HHV) is within the range where neither party shall owe a
Fuel Adjustment Payment under the PPA.
B-38
<PAGE>
7. Based on the projected level of dispatch, the Facility should be
capable of achieving a Summer Availability Percentage of 98 percent and an
Annual Availability Percentage of 97 percent, both as defined in the PPA.
The Annual Availability Percentage of 97 percent is the level required to
avoid reductions in the reservation payments under the PPA.
8. The Facility should have a useful life extending beyond the term of
the Bonds.
9. Assuming the absence of events such as delivery delays, labor
difficulties, unusually adverse weather conditions, force majeure events,
the discovery of underground obstructions or hazardous materials or wastes
not previously known, or other abnormal events that are prejudicial to
normal construction or installation, based on a Limited Notice-to-Proceed of
September 10, 1999, the scheduled Commercial Operation Dates of June 1, 2001
for the Initial Units and June 1, 2002 for the Final Units are achievable
using generally accepted project and construction management practices.
10. Given the range of dispatch factors projected by RDI, which is
typical of peaking operation, and the requirements of the PPA, the
Acceptance Tests and guarantees included in the EPC Contract are adequate to
estimate the future performance of the Facility.
11. The Partnership has received the key environmental permits and
approvals required from the various federal, state, and local agencies, that
are currently necessary to construct the Facility. While not all the
required permits and approvals have been issued, including some which cannot
be obtained until the Facility is ready to operate, we are not aware of any
technical circumstances that would prevent the issuance of the remaining
permits.
12. The estimates which serve as the basis for the EPC Contract Price
and the Total Construction Cost were prepared in accordance with generally
accepted engineering and estimating practices and methods. The EPC Contract
Price and the Total Construction Cost, including Project Contingency, are
comparable to the costs of simple cycle projects at similar stages of
development utilizing similar technologies with which we are familiar.
13. Based upon the interest and reinvestment rates as estimated by the
Initial Purchasers and the total uses of funds as estimated by the
Partnership, the principal amount of the Bonds, when combined with the
equity from the Partnership, PPA revenue during the construction period from
the Initial Units, and interest income during the construction period,
should be sufficient to fund the Total Construction Cost and interest on the
Bonds through May 31, 2002.
14. The methodology used by the Partnership in preparing the operation
and maintenance cost estimate for the Facility, including the provision for
major maintenance provided by the LTSA, is reasonable.
15. For the Base Case Projected Operating Results for the Facility, the
projected revenues under the PPA are adequate to pay annual operating and
maintenance expenses (including provisions for major maintenance as provided
by the LTSA) and other operating expenses and provide an annual debt service
coverage ratio of at least 1.30 times the annual debt service requirement on
the Bonds and a weighted average debt service coverage ratio of 1.49 times
the annual debt service requirement over the term of the Bonds.
16. If the EPC Contractor pays the Partnership performance liquidated
damages due to a failure to achieve the Guaranteed Net Electrical Output and
Guaranteed Net Heat Rate, then the weighted average debt service coverage
ratio over the term of the Bonds is projected to remain generally at the
same level as in the Base Case Projected Operating Results for deficiencies
in Guaranteed Net Electrical Output and Guaranteed Net Heat Rate equivalent
to the Performance Minimums under the EPC Contract.
Respectfully Submitted,
/s/ R. W. BECK, INC.
B-39
<PAGE>
EXHIBIT B-1
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
BASE CASE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2002(1) 2003 2004 2005 2006 2007 2008 2009
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0% 3.0% 4.0% 5.0% 5.0% 5.0% 6.0%
Unit Starts Year (7).................. 181 181 272 363 454 454 454 544
Energy Generation (MWh)............... 159,082 159,082 238,622 318,163 397,704 397,704 397,704 477,245
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 42.00 42.21 43.34 44.74 45.73 46.43 47.03 48.19
Unit Start Up Rates ($/Start)....... $ 11,330 11,670 12,020 12,381 12,752 13,135 13,529 13,934
Energy Charges ($/MWh).............. $ 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23
OPERATING REVENUES ($000)
Reservation Payments.................. $ 22,246 38,327 39,353 40,624 41,523 42,158 42,703 43,757
Unit Startup Charges.................. $ 1,921 1,979 3,057 4,198 5,405 5,567 5,734 7,088
Energy Payments....................... $ 27 29 43 60 80 84 87 110
Availability Incentive Adjustment
(11)................................ $ 87 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 24,282 40,485 42,603 45,032 47,158 47,959 48,674 51,105
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 914 1,622 2,057 2,152 2,251 2,308 2,364 2,472
Capital Expenditures.................. $ 32 55 57 58 59 61 62 64
Major Maintenance (17)................ $ 1,559 2,477 3,502 4,583 5,727 5,895 6,068 7,348
Operator Fee, Incentive and Bonus
(18)................................ $ 202 107 366 376 386 397 408 420
Home Office Expenses (19)............. $ 422 742 761 780 799 819 840 861
Insurance............................. $ 224 394 404 414 424 435 446 457
Property and Other Taxes.............. $ 52 142 189 305 339 365 382 391
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 3,405 5,539 7,336 8,669 9,985 10,280 10,569 12,014
NET OPERATING REVENUES ($000)........... $ 20,877 34,945 35,267 36,364 37,173 37,679 38,105 39,091
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $275,000 275,000 275,000 275,000 274,714 274,026 273,052 271,391
Annual Principal.................... $ 0 0 0 286 688 974 1,661 2,349
Annual Interest..................... $ 15,240 26,125 26,125 26,125 26,081 26,016 25,907 25,733
Letter of Credit Fees................. $ 429 735 735 738 810 812 819 825
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 15,669 26,860 26,860 27,149 27,579 27,802 28,388 28,907
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.33 1.30 1.31 1.34 1.35 1.36 1.34 1.35
AVERAGE DEBT COVERAGE (21).............. 1.49
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 7,982 13,683 13,683 13,833 14,020 14,136 14,439 14,708
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2010 2011
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0%
Unit Starts Year (7).................. 454 454
Energy Generation (MWh)............... 397,704 397,704
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 49.68 51.40
Unit Start Up Rates ($/Start)....... 14,353 14,783
Energy Charges ($/MWh).............. 0.24 0.25
OPERATING REVENUES ($000)
Reservation Payments.................. 45,109 46,671
Unit Startup Charges.................. 6,084 6,266
Energy Payments....................... 95 99
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 51,438 53,186
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,486 2,546
Capital Expenditures.................. 66 67
Major Maintenance (17)................ 6,430 6,591
Operator Fee, Incentive and Bonus
(18)................................ 431 444
Home Office Expenses (19)............. 1,480 1,532
Insurance............................. 468 480
Property and Other Taxes.............. 429 416
------- -------
Total Operating Expenses.............. 11,790 12,077
NET OPERATING REVENUES ($000)........... 39,648 41,110
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 269,042 266,005
Annual Principal.................... 3,036 4,010
Annual Interest..................... 25,494 25,189
Letter of Credit Fees................. 893 900
------- -------
Total Debt Service.................... 29,423 30,099
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.35 1.37
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 14,943 15,293
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-40
<PAGE>
EXHIBIT B-1
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
BASE CASE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2012 2013 2014 2015 2016 2017 2018 2019
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0% 4.0% 4.0% 3.0% 3.0% 3.0% 2.0%
Unit Starts per Year (7).............. 454 454 363 363 272 272 272 181
Energy Generation (MWh)............... 397,704 397,704 318,163 318,163 238,622 238,622 238,622 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 53.18 54.79 55.93 56.91 57.99 59.42 61.17 63.39
Unit Start Up Rates ($/Start)....... $ 15,227 15,683 16,154 16,638 17,138 17,652 18,181 18,727
Energy Charges ($/MWh).............. $ 0.26 0.27 0.29 0.30 0.31 0.33 0.34 0.36
OPERATING REVENUES ($000)
Reservation Payments.................. $ 48,287 49,749 50,784 51,674 52,655 53,953 55,542 57,558
Unit Startup Charges.................. $ 6,454 6,648 5,478 5,642 4,358 4,489 4,624 3,175
Energy Payments....................... $ 103 107 92 95 74 79 81 57
Availability Incentive Adjustment
(11)................................ $ 150 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 54,994 56,654 56,504 57,561 57,237 58,671 60,397 60,940
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 2,612 2,676 2,687 2,754 2,764 2,837 2,907 2,917
Capital Expenditures.................. $ 69 71 72 74 76 78 80 82
Major Maintenance (17)................ $ 6,756 6,924 5,843 5,990 4,821 4,943 5,066 3,773
Operator Fee, Incentive and Bonus
(18)................................ $ 456 469 482 496 510 524 539 555
Home Office Expenses (19)............. $ 1,586 1,642 1,701 1,762 1,824 1,890 1,958 2,030
Insurance............................. $ 492 504 517 530 543 557 571 585
Property and Other Taxes.............. $ 497 532 569 693 735 803 851 900
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 12,467 12,819 11,871 12,300 11,273 11,632 11,973 10,843
NET OPERATING REVENUES ($000)........... $ 42,527 43,836 44,633 45,262 45,964 47,039 48,424 50,098
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $261,995 256,609 250,135 242,688 234,151 224,641 213,755 201,495
Annual Principal.................... $ 5,385 6,474 7,448 8,536 9,510 10,885 12,260 13,349
Annual Interest..................... $ 24,775 24,231 23,600 22,859 22,032 21,096 20,029 18,832
Letter of Credit Fees................. $ 901 933 933 933 965 965 965 965
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 31,062 31,638 31,981 32,329 32,508 32,946 33,255 33,146
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.37 1.39 1.40 1.40 1.41 1.43 1.46 1.51
AVERAGE DEBT COVERAGE (21).............. 1.49
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 15,797 16,000 16,000 16,000 16,000 16,000 16,000 16,000
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2020 2021
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0%
Unit Starts per Year (7).............. 181 181
Energy Generation (MWh)............... 159,082 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 62.90 61.10
Unit Start Up Rates ($/Start)....... 19,289 19,867
Energy Charges ($/MWh).............. 0.37 0.39
OPERATING REVENUES ($000)
Reservation Payments.................. 57,113 55,479
Unit Startup Charges.................. 3,270 3,368
Energy Payments....................... 59 62
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 60,592 59,059
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,991 3,064
Capital Expenditures.................. 84 86
Major Maintenance (17)................ 3,868 3,965
Operator Fee, Incentive and Bonus
(18)................................ 570 586
Home Office Expenses (19)............. 2,103 2,180
Insurance............................. 600 615
Property and Other Taxes.............. 1,127 1,183
------- -------
Total Operating Expenses.............. 11,342 11,679
NET OPERATING REVENUES ($000)........... 49,249 47,380
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 188,146 174,109
Annual Principal.................... 14,036 14,724
Annual Interest..................... 17,547 16,198
Letter of Credit Fees................. 965 964
------- -------
Total Debt Service.................... 32,549 31,885
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.51 1.49
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 16,000 16,000
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-41
<PAGE>
EXHIBIT B-1
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
BASE CASE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030(1)
------------------------ -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2).................... 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity
(Kw)(3).................... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the
PPA (%)(4)................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the
PPA (%)(5)................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)....... 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%
Unit Starts per Year (7)..... 181 181 181 181 181 181 181 181 0
Energy Generation (MWh)...... 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 0
Net Plant Heat Rate
(Btu/kWh)(8)............... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9)..... 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges
($/kW-yr)................ $ 60.67 60.86 62.71 65.29 67.01 69.03 70.57 71.55 72.00
Unit Start Up Rates
($/Start)................ $ 20,463 21,077 21,709 22,361 23,032 23,723 24,434 25,167 25,922
Energy Charges ($/MWh)..... $ 0.41 0.43 0.45 0.47 0.49 0.51 0.53 0.56 0.56
OPERATING REVENUES ($000)
Reservation Payments......... $ 55,088 55,261 56,941 59,283 60,845 62,679 64,078 64,967 5,448
Unit Startup Charges......... $ 3,470 3,574 3,681 3,791 3,905 4,022 4,143 4,267 0
Energy Payments.............. $ 65 68 72 75 78 81 84 89 0
Availability Incentive
Adjustment (11)............ $ 150 150 150 150 150 150 150 150 12
Summer Availability
Adjustment (12)............ $ 0 0 0 0 0 0 0 0 0
Annual Availability
Adjustment (13)............ $ 0 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)... $ 0 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues..... $ 58,773 59,053 60,844 63,299 64,978 66,932 68,455 69,473 5,461
OPERATING EXPENSES ($000)(15)
Fuel......................... $ 0 0 0 0 0 0 0 0 0
Operations (16).............. $ 3,141 3,220 3,300 3,384 3,467 3,555 3,643 3,734 306
Capital Expenditures......... $ 88 90 93 95 97 100 102 105 9
Major Maintenance (17)....... $ 4,064 4,165 4,270 4,377 4,487 4,598 4,713 4,831 349
Operator Fee, Incentive and
Bonus (18)................. $ 603 620 638 656 674 694 713 734 63
Home Office Expenses (19).... $ 2,261 2,344 2,431 2,522 2,616 2,713 2,815 2,922 253
Insurance.................... $ 630 646 662 678 695 713 731 749 64
Property and Other Taxes..... $ 1,609 1,587 1,566 1,545 1,524 1,504 1,484 1,465 117
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses..... $ 12,396 12,672 12,960 13,257 13,560 13,878 14,201 14,540 1,161
NET OPERATING REVENUES
($000)....................... $ 46,377 46,381 47,884 50,042 51,418 53,055 54,254 54,933 4,299
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance........ $159,385 143,688 126,901 109,427 91,266 72,130 50,760 26,812 2,062
Annual Principal........... $ 15,698 16,786 17,474 18,161 19,135 21,370 23,948 24,750 2,063
Annual Interest............ $ 14,782 13,258 11,647 9,971 8,229 6,379 4,267 1,959 98
Letter of Credit Fees........ $ 964 964 962 951 942 946 952 934 77
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service........... $ 31,444 31,009 30,083 29,084 28,307 28,695 29,167 27,643 2,237
TRANSFERS FROM DSRF............ $ 0 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE... 1.47 1.50 1.59 1.72 1.82 1.85 1.86 1.99 1.92
AVERAGE DEBT COVERAGE (21)..... 1.49
DEBT SERVICE RESERVE ACCOUNT
LOC (22)..................... $ 15,964 15,736 15,252 14,734 14,332 14,533 14,778 13,989 1,132
WORKING CAPITAL LOC (23)....... $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
</TABLE>
B-42
<PAGE>
FOOTNOTES TO EXHIBIT B-1
1. Represents seven months beginning June 1, 2002 and one month in year 2030.
2. Projected net summer installed capacity, as estimated by the Partnership.
3. Projected average amount of Contract Capacity to be declared each year by
the Partnership and purchased each year by PECO, as defined in the PPA.
4. Projected average Summer Availability for the months of June through
September, as defined in the PPA.
5. Projected average Annual Availability, as defined in the PPA.
6. Annual capacity factors based on dispatch projections developed by RDI
through 2020, and the Partnership thereafter.
7. Projected number of Unit Starts, based on dispatch projections and
projections of the average duration of each Unit Startup developed by RDI.
8. Net plant heat rate assumed to average 11,088 Btu/kWh throughout the term of
the Bonds, including an allowance for degradation, as estimated by the
Partnership.
9. Based on estimates prepared by Blue Chip Economic Indicators.
10. Pursuant to the terms of the PPA. The annual reservation and energy payments
are specified each year in the PPA. The annual start-up payments are based
on an initial value of $11,000 in 2001, escalating at an annual rate of
3 percent thereafter.
11. Pursuant to PPA, and equal to $150,000 for each percentage point the Summer
Availability exceeds 97 percent if the Summer Availability Percentage for
each Contract Year exceeds 97 percent and the Peak Days Availability is
below 99 percent, and equal to $500,000 for each percentage point the Summer
Availability Percentage exceeds 97 percent if the Summer Availability
Percentage for each Contract Year exceeds 97 percent and the Peak Days
Availability exceeds 99 percent, up to a maximum of $1,500,000 each Contract
Year.
12. Pursuant to the PPA, and equal to a payment by the Partnership to PECO, if
the Summer Availability Percentage if less than 87 percent, of 3.34 percent
of the total reservation payments for that Contract Year for each percentage
point the Summer Availability Percentage is less than 97 percent.
13. Pursuant to the PPA, and equal to a payment by the Partnership to PECO, if
the Annual Availability Percentage is greater than 76.9 percent but less
than 97 percent, of 3.34 percent of the total reservation payments for that
Contract Year for each percentage point the Annual Availability Percentage
is below 97 percent. If the Annual Availability Percentage is below
76.9 percent, the Partnership shall pay PECO an amount equal to
66.8 percent of the total reservation payments for such Contract Year plus
0.432 percent of the total reservation payments for such Contract Year for
each percentage point the Annual Availability Percentage is below
76.9 percent.
14. Pursuant to the PPA, and equal to: (1) a payment to PECO by the Partnership
for the difference between the actual Summer Months Base Heat Rate and
11,300 Btu/kWh, if the Summer Months Base Heat Rate is greater than 11,300
Btu/ kWh; or (2) a payment from PECO to the Partnership for the difference
between 10,800 Btu/kWh and the actual Summer Months Base Heat Rate if the
actual Summer Months Base Heat Rate is less than 10,800 Btu/kWh. Payments
are equal to the applicable difference in heat rates multiplied by the Daily
Index Citation gas price.
15. All non-fuel operating expenses are as projected by the Partnership, and
assumed to increase at the general rate of inflation, except for certain
expenses under the LTSA and O&M Agreement, as described in the Report, and
property taxes and certain fees, which are based on a schedule provided by
the Partnership.
16. Includes operating contingency beginning in 2004 based on the assumption
that the cost of any extraordinary repairs will be covered by the EPC
Contractor and GE under their warranties pursuant to the EPC Contract and
the GE Turbine Contract, respectively.
17. Includes payments to GE International under the LTSA, non-turbine
maintenance costs, and preventative maintenance costs. LTSA payments include
monthly fixed charges and availability bonus or penalty payments per
percentage point the Annual Availability Percentage exceeds or is below a
guaranteed percentage during any calendar year, both subject to a maximum
annual amount. Payment rates are based on 2001 dollars and are assumed to
escalate at 3 percent per year through January 31, 2011 and at the rate of
general inflation thereafter.
18. Sum of the annual fixed management fee of $225,000 during the first Contract
Year, the incentive fee assumed to equal $100,000 the first Contract Year,
and the Operator Availability bonus or penalty, equal to $25,000 per
1 percent above or below a 97 percent Annual Availability Percentage
threshold. The fixed management fee is assumed to escalate at the
B-43
<PAGE>
general rate of inflation. The other expenses escalate each year at an
annual rate of 3.5 percent, beginning on January 1, 2001. Under the terms of
the O&M Agreement, the fixed management fee has been waived by the Operator
for 2003.
19. Includes Partnership management fee under the Partnership Agreement
beginning in 2010.
20. Based on the principal amount of the Bonds of $275,000,000 at an interest
rate as reported by the Initial Purchasers of 9.50 percent, with semi-annual
payments due each February 1 and August 1. Interest has been funded from
proceeds of the Bonds and from the operating revenues from the Initial Units
through June 1, 2002.
21. Average debt service coverage is equal to the sum of cash available for debt
service over the term of the Bonds divided by total debt service over the
term of the Bonds.
22. The Debt Service Reserve Account requirement is assumed to be satisfied with
a letter-of-credit. The Debt Service Reserve Account requirement is equal to
the scheduled principal and interest payments for the next scheduled payment
date over the term of the Bonds plus six months' interest on any draws on
the letter-of-credit, up to a maximum Debt Service Reserve Account
letter-of-credit amount of $16,000,000. For the purposes of estimating the
Debt Service Reserve Account requirement, the Partnership has assumed annual
draws on the letter-of-credit equal to the next scheduled semi-annual debt
service payment and an interest rate equal to the rate on the Bonds.
23. The Working Capital Line of Credit is assumed to be established in the
amount of $5,000,000, as estimated by the Partnership.
B-44
<PAGE>
EXHIBIT B-2
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY A--REDUCED AVAILABILITY
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2002(1) 2003 2004 2005 2006 2007 2008 2009
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Annual Availability under the PPA
(%)(5).............................. 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
Capacity Factor (%)(6)................ 2.0% 2.0% 3.0% 4.0% 5.0% 5.0% 5.0% 6.0%
Unit Starts per Year (7).............. 181 181 272 363 454 454 454 544
Energy Generation (MWh)............... 159,082 159,082 238,622 318,163 397,704 397,704 397,704 477,245
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 42.00 42.21 43.34 44.74 45.73 46.43 47.03 48.19
Unit Start Up Rates ($/Start)....... $ 11,330 11,670 12,020 12,381 12,752 13,135 13,529 13,934
Energy Charges ($/MWh).............. $ 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23
OPERATING REVENUES ($000)
Reservation Payments.................. $ 22,246 38,327 39,353 40,624 41,523 42,158 42,703 43,757
Unit Startup Charges.................. $ 1,921 1,979 3,057 4,198 5,405 5,567 5,734 7,088
Energy Payments....................... $ 27 29 43 60 80 84 87 110
Availability Incentive Adjustment
(11)................................ $ 0 0 0 0 0 0 0 0
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ (743) (1,280) (1,314) (1,357) (1,387) (1,408) (1,426) (1,461)
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 23,451 39,055 41,139 43,526 45,621 46,400 47,098 49,493
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 914 1,622 2,057 2,152 2,251 2,308 2,364 2,472
Capital Expenditures.................. $ 32 55 57 58 59 61 62 64
Major Maintenance (17)................ $ 1,439 2,265 3,283 4,358 5,495 5,657 5,822 7,095
Operator Fee, Incentive and Bonus
(18)................................ $ 187 80 338 347 356 366 376 387
Home Office Expenses (19)............. $ 422 742 761 780 799 819 840 861
Insurance............................. $ 224 394 404 414 424 435 446 457
Property and Other Taxes.............. $ 52 142 189 305 339 365 382 391
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 3,270 5,300 7,089 8,415 9,723 10,010 10,291 11,727
NET OPERATING REVENUES ($000)........... $ 20,181 33,755 34,049 35,111 35,898 36,390 36,807 37,766
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $275,000 275,000 275,000 275,000 274,714 274,026 273,052 271,391
Annual Principal.................... $ 0 0 0 286 688 974 1,661 2,349
Annual Interest..................... $ 15,240 26,125 26,125 26,125 26,081 26,016 25,907 25,733
Letter of Credit Fees................. $ 429 735 735 738 810 812 819 825
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 15,669 26,860 26,860 27,149 27,579 27,802 28,388 28,907
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.29 1.26 1.27 1.29 1.30 1.31 1.30 1.31
AVERAGE DEBT COVERAGE (21).............. 1.44
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 7,982 13,683 13,683 13,833 14,020 14,136 14,439 14,708
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2010 2011
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 97.0% 97.0%
Annual Availability under the PPA
(%)(5).............................. 96.0% 96.0%
Capacity Factor (%)(6)................ 5.0% 5.0%
Unit Starts per Year (7).............. 454 454
Energy Generation (MWh)............... 397,704 397,704
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 49.68 51.40
Unit Start Up Rates ($/Start)....... 14,353 14,783
Energy Charges ($/MWh).............. 0.24 0.25
OPERATING REVENUES ($000)
Reservation Payments.................. 45,109 46,671
Unit Startup Charges.................. 6,084 6,266
Energy Payments....................... 95 99
Availability Incentive Adjustment
(11)................................ 0 0
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... (1,507) (1,559)
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 49,782 51,478
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,486 2,546
Capital Expenditures.................. 66 67
Major Maintenance (17)................ 6,169 6,323
Operator Fee, Incentive and Bonus
(18)................................ 397 409
Home Office Expenses (19)............. 1,480 1,532
Insurance............................. 468 480
Property and Other Taxes.............. 429 416
------- -------
Total Operating Expenses.............. 11,495 11,773
NET OPERATING REVENUES ($000)........... 38,287 39,705
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 269,042 266,005
Annual Principal.................... 3,036 4,010
Annual Interest..................... 25,494 25,189
Letter of Credit Fees................. 893 900
------- -------
Total Debt Service.................... 29,423 30,099
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.30 1.32
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 14,943 15,293
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-45
<PAGE>
EXHIBIT B-2
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY A--REDUCED AVAILABILITY
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2012 2013 2014 2015 2016 2017 2018 2019
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Annual Availability under the PPA
(%)(5).............................. 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
Capacity Factor (%)(6)................ 5.0% 5.0% 4.0% 4.0% 3.0% 3.0% 3.0% 2.0%
Unit Starts per Year (7).............. 454 454 363 363 272 272 272 181
Energy Generation (MWh)............... 397,704 397,704 318,163 318,163 238,622 238,622 238,622 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 53.18 54.79 55.93 56.91 57.99 59.42 61.17 63.39
Unit Start Up Rates ($/Start)....... $ 15,227 15,683 16,154 16,638 17,138 17,652 18,181 18,727
Energy Charges ($/MWh).............. $ 0.26 0.27 0.29 0.30 0.31 0.33 0.34 0.36
OPERATING REVENUES ($000)
Reservation Payments.................. $ 48,287 49,749 50,784 51,674 52,655 53,953 55,542 57,558
Unit Startup Charges.................. $ 6,454 6,648 5,478 5,642 4,358 4,489 4,624 3,175
Energy Payments....................... $ 103 107 92 95 74 79 81 57
Availability Incentive Adjustment
(11)................................ $ 0 0 0 0 0 0 0 0
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ (1,613) (1,662) (1,696) (1,726) (1,759) (1,802) (1,855) (1,922)
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 53,232 54,843 54,658 55,686 55,328 56,719 58,392 58,868
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 2,612 2,676 2,687 2,754 2,764 2,837 2,907 2,917
Capital Expenditures.................. $ 69 71 72 74 76 78 80 82
Major Maintenance (17)................ $ 6,479 6,639 5,549 5,688 4,509 4,622 4,736 3,433
Operator Fee, Incentive and Bonus
(18)................................ $ 420 431 443 456 468 481 494 509
Home Office Expenses (19)............. $ 1,586 1,642 1,701 1,762 1,824 1,890 1,958 2,030
Insurance............................. $ 492 504 517 530 543 557 571 585
Property and Other Taxes.............. $ 497 532 569 693 735 803 851 900
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 12,154 12,496 11,538 11,957 10,919 11,268 11,597 10,456
NET OPERATING REVENUES ($000)........... $ 41,077 42,347 43,120 43,729 44,409 45,451 46,795 48,412
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $261,995 256,609 250,135 242,688 234,151 224,641 213,755 201,495
Annual Principal.................... $ 5,385 6,474 7,448 8,536 9,510 10,885 12,260 13,349
Annual Interest..................... $ 24,775 24,231 23,600 22,859 22,032 21,096 20,029 18,832
Letter of Credit Fees................. $ 901 933 933 933 965 965 965 965
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 31,062 31,638 31,981 32,329 32,508 32,946 33,255 33,146
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.32 1.34 1.35 1.35 1.37 1.38 1.41 1.46
AVERAGE DEBT COVERAGE (21).............. 1.44
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 15,797 16,000 16,000 16,000 16,000 16,000 16,000 16,000
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2020 2021
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 97.0% 97.0%
Annual Availability under the PPA
(%)(5).............................. 96.0% 96.0%
Capacity Factor (%)(6)................ 2.0% 2.0%
Unit Starts per Year (7).............. 181 181
Energy Generation (MWh)............... 159,082 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 62.90 61.10
Unit Start Up Rates ($/Start)....... 19,289 19,867
Energy Charges ($/MWh).............. 0.37 0.39
OPERATING REVENUES ($000)
Reservation Payments.................. 57,113 55,479
Unit Startup Charges.................. 3,270 3,368
Energy Payments....................... 59 62
Availability Incentive Adjustment
(11)................................ 0 0
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... (1,908) (1,853)
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 58,534 57,056
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,991 3,064
Capital Expenditures.................. 84 86
Major Maintenance (17)................ 3,517 3,604
Operator Fee, Incentive and Bonus
(18)................................ 522 536
Home Office Expenses (19)............. 2,103 2,180
Insurance............................. 600 615
Property and Other Taxes.............. 1,127 1,183
------- -------
Total Operating Expenses.............. 10,944 11,267
NET OPERATING REVENUES ($000)........... 47,590 45,789
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 188,146 174,109
Annual Principal.................... 14,036 14,724
Annual Interest..................... 17,547 16,198
Letter of Credit Fees................. 965 964
------- -------
Total Debt Service.................... 32,549 31,885
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.46 1.44
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 16,000 16,000
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-46
<PAGE>
EXHIBIT B-2
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY A--REDUCED AVAILABILITY
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030(L)
------------------------ -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2).................... 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity
(kW)(3).................... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the
PPA (%)(4)................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Annual Availability under the
PPA (%)(5)................. 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
Capacity Factor (%)(6)....... 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%
Unit Starts per Year (7)..... 181 181 181 181 181 181 181 181 0
Energy Generation (MWh)...... 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 0
Net Plant Heat Rate
(Btu/kWh)(8)............... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9)..... 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges
($/kW-yr)................ $ 60.67 60.86 62.71 65.29 67.01 69.03 70.57 71.55 72.00
Unit Start Up Rates
($/Start)................ $ 20,463 21,077 21,709 22,361 23,032 23,723 24,434 25,167 25,922
Energy Charges ($/MWh)..... $ 0.41 0.43 0.45 0.47 0.49 0.51 0.53 0.56 0.56
OPERATING REVENUES ($000)
Reservation Payments......... $ 55,088 55,261 56,941 59,283 60,845 62,679 64,078 64,967 5,448
Unit Startup Charges......... $ 3,470 3,574 3,681 3,791 3,905 4,022 4,143 4,267 0
Energy Payments.............. $ 65 68 72 75 78 81 84 89 0
Availability Incentive
Adjustment (11)............ $ 0 0 0 0 0 0 0 0 0
Summer Availability
Adjustment (12)............ $ 0 0 0 0 0 0 0 0 0
Annual Availability
Adjustment (13)............ $ (1,840) (1,846) (1,902) (1,980) (2,032) (2,093) (2,140) (2,170) (182)
Efficiency Adjustment (14)... $ 0 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues..... $ 56,783 57,058 58,792 61,169 62,796 64,689 66,165 67,153 5,266
OPERATING EXPENSES ($000)(15)
Fuel......................... $ 0 0 0 0 0 0 0 0 0
Operations (16).............. $ 3,141 3,220 3,300 3,384 3,467 3,555 3,643 3,734 306
Capital Expenditures......... $ 88 90 93 95 97 100 102 105 9
Major Maintenance (17)....... $ 3,692 3,782 3,876 3,970 4,068 4,167 4,269 4,374 153
Operator Fee, Incentive and
Bonus (18)................. $ 552 567 583 599 615 633 650 668 35
Home Office Expenses (19).... $ 2,261 2,344 2,431 2,522 2,616 2,713 2,815 2,922 253
Insurance.................... $ 630 646 662 678 695 713 731 749 64
Property and Other Taxes..... $ 1,609 1,587 1,566 1,545 1,524 1,504 1,484 1,465 117
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses..... $ 11,973 12,236 12,510 12,793 13,083 13,385 13,694 14,016 936
NET OPERATING REVENUES
($000)....................... $ 44,810 44,822 46,282 48,375 49,713 51,303 52,471 53,137 4,330
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance........ $159,385 143,688 126,901 109,427 91,266 72,130 50,760 26,812 2,062
Annual Principal........... $ 15,698 16,786 17,474 18,161 19,135 21,370 23,948 24,750 2,063
Annual Interest............ $ 14,782 13,258 11,647 9,971 8,229 6,379 4,267 1,959 98
Letter of Credit Fees........ $ 964 964 962 951 942 946 952 934 77
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service........... $ 31,444 31,009 30,083 29,084 28,307 28,695 29,167 27,643 2,237
TRANSFERS FROM DSRF............ $ 0 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE... 1.43 1.45 1.54 1.66 1.76 1.79 1.80 1.92 1.94
AVERAGE DEBT COVERAGE (21)..... 1.44
DEBT SERVICE RESERVE ACCOUNT
LOC (22)..................... $ 15,964 15,736 15,252 14,734 14,332 14,533 14,778 13,989 1,132
WORKING CAPITAL LOC (23)....... $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
</TABLE>
B-47
<PAGE>
FOOTNOTES TO EXHIBIT B-2
The footnotes to Exhibit B-2 are the same as the footnotes for Exhibit B-1,
except:
4. The projected average Summer Availability for the months of June through
September, as defined in the PPA, is assumed to be 1 percentage point lower
than in the Base Case due to an increase in the Facility forced outage rate
of 5 percentage points, and no liquidated damage payments are due from the
EPC Contractor.
5. The projected average Annual Availability, as defined in the PPA, is assumed
to be 1 percentage point lower than in the Base Case due to an increase in
the Facility forced outage rate of 5 percentage points, and no liquidated
damage payments are due from the EPC Contractor.
B-48
<PAGE>
EXHIBIT B-3
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY B--INCREASED HEAT RATE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2002(L) 2003 2004 2005 2006 2007 2008 2009
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0% 3.0% 4.0% 5.0% 5.0% 5.0% 6.0%
Unit Starts per Year (7).............. 181 181 272 363 454 454 454 544
Energy Generation (MWh)............... 159,082 159,082 238,622 318,163 397,704 397,704 397,704 477,245
Net Plant Heat Rate (Btu/kWh)(8)...... 11,642 11,642 11,642 11,642 11,642 11,642 11,642 11,642
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 42.00 42.21 43.34 44.74 45.73 46.43 47.03 48.19
Unit Start Up Rates ($/Start)....... $ 11,330 11,670 12,020 12,381 12,752 13,135 13,529 13,934
Energy Charges ($/MWh).............. $ 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23
OPERATING REVENUES ($000)
Reservation Payments.................. $ 22,246 38,327 39,353 40,624 41,523 42,158 42,703 43,757
Unit Startup Charges.................. $ 1,921 1,979 3,057 4,198 5,405 5,567 5,734 7,088
Energy Payments....................... $ 27 29 43 60 80 84 87 110
Availability Incentive Adjustment
(11)................................ $ 87 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 (311) (403) (430) (456) (586)
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 24,282 40,485 42,603 44,722 46,754 47,529 48,219 50,519
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 914 1,622 2,057 2,152 2,251 2,308 2,364 2,472
Capital Expenditures.................. $ 32 55 57 58 59 61 62 64
Major Maintenance (17)................ $ 1,559 2,477 3,502 4,583 5,727 5,895 6,068 7,348
Operator Fee, Incentive and Bonus
(18)................................ $ 202 107 366 376 386 397 408 420
Home Office Expenses (19)............. $ 422 742 761 780 799 819 840 861
Insurance............................. $ 224 394 404 414 424 435 446 457
Property and Other Taxes.............. $ 52 142 189 305 339 365 382 391
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 3,405 5,539 7,336 8,669 9,985 10,280 10,569 12,014
NET OPERATING REVENUES ($000)........... $ 20,877 34,945 35,267 36,053 36,770 37,249 37,649 38,506
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $275,000 275,000 275,000 275,000 274,714 274,026 273,052 271,391
Annual Principal.................... $ 0 0 0 286 688 974 1,661 2,349
Annual Interest..................... $ 15,240 26,125 26,125 26,125 26,081 26,016 25,907 25,733
Letter of Credit Fees................. $ 429 735 735 738 810 812 819 825
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 15,669 26,860 26,860 27,149 27,579 27,802 28,388 28,907
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.33 1.30 1.31 1.33 1.33 1.34 1.33 1.33
AVERAGE DEBT COVERAGE (21).............. 1.48
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 7,982 13,683 13,683 13,833 14,020 14,136 14,439 14,708
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2010 2011
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0%
Unit Starts per Year (7).............. 454 454
Energy Generation (MWh)............... 397,704 397,704
Net Plant Heat Rate (Btu/kWh)(8)...... 11,642 11,642
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 49.68 51.40
Unit Start Up Rates ($/Start)....... 14,353 14,783
Energy Charges ($/MWh).............. 0.24 0.25
OPERATING REVENUES ($000)
Reservation Payments.................. 45,109 46,671
Unit Startup Charges.................. 6,084 6,266
Energy Payments....................... 95 99
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ (502) (515)
------- -------
Total Operating Revenues.............. 50,936 52,672
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,486 2,546
Capital Expenditures.................. 66 67
Major Maintenance (17)................ 6,430 6,591
Operator Fee, Incentive and Bonus
(18)................................ 431 444
Home Office Expenses (19)............. 1,480 1,532
Insurance............................. 468 480
Property and Other Taxes.............. 429 416
------- -------
Total Operating Expenses.............. 11,790 12,077
NET OPERATING REVENUES ($000)........... 39,146 40,595
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 269,042 266,005
Annual Principal.................... 3,036 4,010
Annual Interest..................... 25,494 25,189
Letter of Credit Fees................. 893 900
------- -------
Total Debt Service.................... 29,423 30,099
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.33 1.35
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 14,943 15,293
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-49
<PAGE>
EXHIBIT B-3
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY B--INCREASED HEAT RATE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2012 2013 2014 2015 2016 2017 2018 2019
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0% 4.0% 4.0% 3.0% 3.0% 3.0% 2.0%
Unit Starts per Year (7).............. 454 454 363 363 272 272 272 181
Energy Generation (MWh)............... 397,704 397,704 318,163 318,163 238,622 238,622 238,622 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,642 11,642 11,642 11,642 11,642 11,642 11,642 11,642
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/KW-yr)....... $ 53.18 54.79 55.93 56.91 57.99 59.42 61.17 63.39
Unit Start Up Rates ($/Start)....... $ 15,227 15,683 16,154 16,638 17,138 17,652 18,181 18,727
Energy Charges ($/MWh).............. $ 0.26 0.27 0.29 0.30 0.31 0.33 0.34 0.36
OPERATING REVENUES ($000)
Reservation Payments.................. $ 48,287 49,749 50,784 51,674 52,655 53,953 55,542 57,558
Unit Startup Charges.................. $ 6,454 6,648 5,478 5,642 4,358 4,489 4,624 3,175
Energy Payments....................... $ 103 107 92 95 74 79 81 57
Availability Incentive Adjustment
(11)................................ $ 150 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ (527) (541) (443) (454) 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 54,467 56,114 56,061 57,107 57,237 58,671 60,397 60,940
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 2,612 2,676 2,687 2,754 2,764 2,837 2,907 2,917
Capital Expenditures.................. $ 69 71 72 74 76 78 80 82
Major Maintenance (17)................ $ 6,756 6,924 5,843 5,990 4,821 4,943 5,066 3,773
Operator Fee, Incentive and Bonus
(18)................................ $ 456 469 482 496 510 524 539 555
Home Office Expenses (19)............. $ 1,586 1,642 1,701 1,762 1,824 1,890 1,958 2,030
Insurance............................. $ 492 504 517 530 543 557 571 585
Property and Other Taxes.............. $ 497 532 569 693 735 803 851 900
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 12,467 12,819 11,871 12,300 11,273 11,632 11,973 10,843
NET OPERATING REVENUES ($000)........... $ 42,000 43,295 44,190 44,807 45,964 47,039 48,424 50,098
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $261,995 256,609 250,135 242,688 234,151 224,641 213,755 201,495
Annual Principal.................... $ 5,385 6,474 7,448 8,536 9,510 10,885 12,260 13,349
Annual Interest..................... $ 24,775 24,231 23,600 22,859 22,032 21,096 20,029 18,832
Letter of Credit Fees................. $ 901 933 933 933 965 965 965 965
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 31,062 31,638 31,981 32,329 32,508 32,946 33,255 33,146
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.35 1.37 1.38 1.39 1.41 1.43 1.46 L51
AVERAGE DEBT COVERAGE (21).............. 1.48
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 15,797 16,000 16,000 16,000 16,000 16,000 16,000 16,000
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2020 2021
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0%
Unit Starts per Year (7).............. 181 181
Energy Generation (MWh)............... 159,082 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,642 11,642
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/KW-yr)....... 62.90 61.10
Unit Start Up Rates ($/Start)....... 19,289 19,867
Energy Charges ($/MWh).............. 0.37 0.39
OPERATING REVENUES ($000)
Reservation Payments.................. 57,113 55,479
Unit Startup Charges.................. 3,270 3,368
Energy Payments....................... 59 62
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 60,592 59,059
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,991 3,064
Capital Expenditures.................. 84 86
Major Maintenance (17)................ 3,868 3,965
Operator Fee, Incentive and Bonus
(18)................................ 570 586
Home Office Expenses (19)............. 2,103 2,180
Insurance............................. 600 615
Property and Other Taxes.............. 1,127 1,183
------- -------
Total Operating Expenses.............. 11,342 11,679
NET OPERATING REVENUES ($000)........... 49,249 47,380
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 188,146 174,109
Annual Principal.................... 14,036 14,724
Annual Interest..................... 17,547 16,198
Letter of Credit Fees................. 965 964
------- -------
Total Debt Service.................... 32,549 31,885
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.51 1.49
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 16,000 16,000
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-50
<PAGE>
EXHIBIT B-3
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY B--INCREASED HEAT RATE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030(1)
------------------------ -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer installed Capacity
(kW)(2).................... 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity
(kW)(3).................... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the
PPA (%)(4)................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the
PPA (%)(5)................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)....... 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%
Unit Starts per Year (7)..... 181 181 181 181 181 181 181 181 0
Energy Generation (MWh)...... 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 0
Net Plant Heat Rate
(Btu/kWh)(8)............... 11,642 11,642 11,642 11,642 11,642 11,642 11,642 11,642 11,642
COMMODITY PRICES
General Inflation (%)(9)..... 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges
(S/kW-yr)................ $ 60.67 60.86 62.71 65.29 67.01 69.03 70.57 71.55 72.00
Unit Start Up Rates
($/Start)................ $ 20,463 21,077 21,709 22,361 23,032 23,723 24,434 25,167 25,922
Energy Charges ($/MWh)..... $ 0.41 0.43 0.45 0.47 0.49 0.51 0.53 0.56 0.56
OPERATING REVENUES ($000)
Reservation Payments......... $ 55,088 55,261 56,941 59,283 60,845 62,679 64,078 64,967 5,448
Unit Startup Charges......... $ 3,470 3,574 3,681 3,791 3,905 4,022 4,143 4,267 0
Energy Payments.............. $ 65 68 72 75 78 81 84 89 0
Availability Incentive
Adjustment (11)............ $ 150 150 150 150 150 150 150 150 12
Summer Availability
Adjustment (12)............ $ 0 0 0 0 0 0 0 0 0
Annual Availability
Adjustment (13)............ $ 0 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)... $ 0 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues..... $ 58,773 59,053 60,844 63,299 64,978 66,932 68,455 69,473 5,461
OPERATING EXPENSES ($000)(15)
Fuel......................... $ 0 0 0 0 0 0 0 0 0
Operations (16).............. $ 3,141 3,220 3,300 3,384 3,467 3,555 3,643 3,734 306
Capital Expenditures......... $ 88 90 93 95 97 100 102 105 9
Major Maintenance (17)....... $ 4,064 4,165 4,270 4,377 4,487 4,598 4,713 4,831 349
Operator Fee, Incentive and
Bonus (18)................. $ 603 620 638 656 674 694 713 734 63
Home Office Expenses (19).... $ 2,261 2,344 2,431 2,522 2,616 2,713 2,815 2,922 253
Insurance.................... $ 630 646 662 678 695 713 731 749 64
Property and Other Taxes..... $ 1,609 1,587 1,566 1,545 1,524 1,504 1,484 1,465 117
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses..... $ 12,396 12,672 12,960 13,257 13,560 13,878 14,201 14,540 1,161
NET OPERATING REVENUES ($000).. $ 46,377 46,381 47,884 50,042 51,418 53,055 54,254 54,933 4,299
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance........ $159,385 143,688 126,901 109,427 91,266 72,130 50,760 26,812 2,062
Annual Principal........... $ 15,698 16,786 17,474 18,161 19,135 21,370 23,948 24,750 2,063
Annual Interest............ $ 14,782 13,258 11,647 9,971 8,229 6,379 4,267 1,959 98
Letter of Credit Fees........ $ 964 964 962 951 942 946 952 934 77
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service........... $ 31,444 31,009 30,083 29,084 28,307 28,695 29,167 27,643 2,237
TRANSFERS FROM DSRF............ $ 0 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE... 1.47 1.50 1.59 1.72 1.82 1.85 1.86 1.99 1.92
AVERAGE DEBT COVERAGE (21)..... 1.48
DEBT SERVICE RESERVE ACCOUNT
LOC (22)..................... $ 15,964 15,736 15,252 14,734 14,332 14,533 14,778 13,989 1,132
WORKING CAPITAL LOC (23)....... $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
</TABLE>
B-51
<PAGE>
FOOTNOTES TO EXHIBIT B-3
The footnotes to Exhibit B-3 are the same as the footnotes for Exhibit B-1,
except:
8. Net Plant Heat Rates are assumed to be 5 percent higher than those assumed
in the Base Case and no liquidated damage payments are due from the EPC
Contractor.
B-52
<PAGE>
EXHIBIT B-4 TENASKA
GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY C--INCREASED OPERATING EXPENSES
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2002(1) 2003 2004 2005 2006 2007 2008 2009
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0% 3.0% 4.0% 5.0% 5.0% 5.0% 6.0%
Unit Starts per Year (7).............. 181 181 272 363 454 454 454 544
Energy Generation (MWh)............... 159,082 159,082 238,622 318,163 397,704 397,704 397,704 477,245
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 42.00 42.21 43.34 44.74 45.73 46.43 47.03 48.19
Unit Start Up Rates ($/Start)....... $ 11,330 11,670 12,020 12,381 12,752 13,135 13,529 13,934
Energy Charges ($/MWh).............. $ 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23
OPERATING REVENUES ($000)
Reservation Payments.................. $ 22,246 38,327 39,353 40,624 41,523 42,158 42,703 43,757
Unit Startup Charges.................. $ 1,921 1,979 3,057 4,198 5,405 5,567 5,734 7,088
Energy Payments....................... $ 27 29 43 60 80 84 87 110
Availability Incentive Adjustment
(11)................................ $ 87 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 24,282 40,485 42,603 45,032 47,158 47,959 48,674 51,105
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 1,003 1,785 2,262 2,367 2,475 2,538 2,599 2,718
Capital Expenditures.................. $ 35 61 63 64 65 67 68 70
Major Maintenance (17)................ $ 1,585 2,592 3,713 4,899 6,152 6,334 6,518 7,924
Operator Fee, Incentive and Bonus
(18)................................ $ 222 118 403 414 425 437 449 462
Home Office Expenses (19)............. $ 465 816 836 857 879 901 924 946
Insurance............................. $ 247 433 444 455 467 478 490 503
Property and Other Taxes.............. $ 57 156 208 336 373 402 420 430
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 3,613 5,960 7,929 9,391 10,836 11,156 11,469 13,053
NET OPERATING REVENUES ($000)........... $ 20,668 34,525 34,674 35,642 36,322 36,802 37,206 38,051
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $275,000 275,000 275,000 275,000 274,714 274,026 273,052 271,391
Annual Principal.................... $ 0 0 0 286 688 974 1,661 2,349
Annual Interest..................... $ 15,240 26,125 26,125 26,125 26,081 26,016 25,907 25,733
Letter of Credit Fees................. $ 429 735 735 738 810 812 819 825
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 15,669 26,860 26,860 27,149 27,579 27,802 28,388 28,907
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.32 1.29 1.29 1.31 1.32 1.32 1.31 1.32
AVERAGE DEBT COVERAGE (21).............. 1.45
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 7,982 13,683 13,683 13,833 14,020 14,136 14,439 14,708
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2010 2011
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0%
Unit Starts per Year (7).............. 454 454
Energy Generation (MWh)............... 397,704 397,704
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 49.68 51.40
Unit Start Up Rates ($/Start)....... 14,353 14,783
Energy Charges ($/MWh).............. 0.24 0.25
OPERATING REVENUES ($000)
Reservation Payments.................. 45,109 46,671
Unit Startup Charges.................. 6,084 6,266
Energy Payments....................... 95 99
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 51,438 53,186
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,733 2,802
Capital Expenditures.................. 73 74
Major Maintenance (17)................ 6,908 7,081
Operator Fee, Incentive and Bonus
(18)................................ 474 488
Home Office Expenses (19)............. 1,629 1,685
Insurance............................. 515 528
Property and Other Taxes.............. 472 458
------- -------
Total Operating Expenses.............. 12,804 13,116
NET OPERATING REVENUES ($000)........... 38,635 40,070
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 269,042 266,005
Annual Principal.................... 3,036 4,010
Annual Interest..................... 25,494 25,189
Letter of Credit Fees................. 893 900
------- -------
Total Debt Service.................... 29,423 30,099
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.31 1.33
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 14,943 15,293
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-53
<PAGE>
EXHIBIT B-4
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY C--INCREASED OPERATING EXPENSES
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2012 2013 2014 2015 2016 2017 2018 2019
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0% 4.0% 4.0% 3.0% 3.0% 3.0% 2.0%
Unit Starts per Year (7).............. 454 454 363 363 272 272 272 181
Energy Generation (MWh)............... 397,704 397,704 318,163 318,163 238,622 238,622 238,622 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 53.18 54.79 55.93 56.91 57.99 59.42 61.17 63.39
Unit Start Up Rates ($/Start)....... $ 15,227 15,683 16,154 16,638 17,138 17,652 18,181 18,727
Energy Charges ($/MWh).............. $ 0.26 0.27 0.29 0.30 0.31 0.33 0.34 0.36
OPERATING REVENUES ($000)
Reservation Payments.................. $ 48,287 49,749 50,784 51,674 52,655 53,953 55,542 57,558
Unit Startup Charges.................. $ 6,454 6,648 5,478 5,642 4,358 4,489 4,624 3,175
Energy Payments....................... $ 103 107 92 95 74 79 81 57
Availability Incentive Adjustment
(11)................................ $ 150 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 54,994 56,654 56,504 57,561 57,237 58,671 60,397 60,940
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 2,871 2,942 2,957 3,030 3,042 3,119 3,198 3,208
Capital Expenditures.................. $ 76 78 79 81 84 86 88 90
Major Maintenance (17)................ $ 7,257 7,439 6,245 6,401 5,112 5,240 5,371 3,945
Operator Fee, Incentive and Bonus
(18)................................ $ 502 516 530 546 561 576 593 611
Home Office Expenses (19)............. $ 1,745 1,807 1,871 1,938 2,007 2,079 2,154 2,232
Insurance............................. $ 541 555 569 583 598 612 628 643
Property and Other Taxes.............. $ 547 585 626 762 809 883 936 990
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 13,539 13,921 12,877 13,341 12,213 12,595 12,967 11,719
NET OPERATING REVENUES ($000)........... $ 41,455 42,733 43,627 44,221 45,024 46,076 47,430 49,221
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $261,995 256,609 250,135 242,688 234,151 224,641 213,755 201,495
Annual Principal.................... $ 5,385 6,474 7,448 8,536 9,510 10,885 12,260 13,349
Annual Interest..................... $ 24,775 24,231 23,600 22,859 22,032 21,096 20,029 18,832
Letter of Credit Fees................. $ 901 933 933 933 965 965 965 965
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 31,062 31,638 31,981 32,329 32,508 32,946 33,255 33,146
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.33 1.35 1.36 1.37 1.39 1.40 1.43 1.48
AVERAGE DEBT COVERAGE (21).............. 1.45
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 15,797 16,000 16,000 16,000 16,000 16,000 16,000 16,000
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2020 2021
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0%
Unit Starts per Year (7).............. 181 181
Energy Generation (MWh)............... 159,082 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 62.90 61.10
Unit Start Up Rates ($/Start)....... 19,289 19,867
Energy Charges ($/MWh).............. 0.37 0.39
OPERATING REVENUES ($000)
Reservation Payments.................. 57,113 55,479
Unit Startup Charges.................. 3,270 3,368
Energy Payments....................... 59 62
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 60,592 59,059
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 3,290 3,373
Capital Expenditures.................. 92 95
Major Maintenance (17)................ 4,043 4,144
Operator Fee, Incentive and Bonus
(18)................................ 627 645
Home Office Expenses (19)............. 2,314 2,399
Insurance............................. 660 676
Property and Other Taxes.............. 1,240 1,301
------- -------
Total Operating Expenses.............. 12,267 12,632
NET OPERATING REVENUES ($000)........... 48,325 46,427
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 188,146 174,109
Annual Principal.................... 14,036 14,724
Annual Interest..................... 17,547 16,198
Letter of Credit Fees................. 965 964
------- -------
Total Debt Service.................... 32,549 31,885
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.48 1,46
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 16,000 16,000
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-54
<PAGE>
EXHIBIT B-4
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY C--INCREASED OPERATING EXPENSES
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030(1)
------------------------ -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2).................... 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity
(kW)(3).................... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the
PPA (%)(4)................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the
PPA (%)(5)................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)....... 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%
Unit Starts per Year (7)..... 181 181 181 181 181 181 181 181 0
Energy Generation (MWh)...... 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 0
Net Plant Heat Rate
(Btu/kWh)(8)............... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9)..... 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges
($/kW-yr)................ $ 60.67 60.86 62.71 65.29 67.01 69.03 70.57 71.55 72.00
Unit Start Up Rates
($/Start)................ $ 20,463 21,077 21,709 22,361 23,032 23,723 24,434 25,167 25,922
Energy Charges ($/MWh)..... $ 0.41 0.43 0.45 0.47 0.49 0.51 0.53 0.56 0.56
OPERATING REVENUES ($000)
Reservation Payments......... $ 55,088 55,261 56,941 59,283 60,845 62,679 64,078 64,967 5,448
Unit Startup Charges......... $ 3,470 3,574 3,681 3,791 3,905 4,022 4,143 4,267 0
Energy Payments.............. $ 65 68 72 75 78 81 84 89 0
Availability Incentive
Adjustment (11)............ $ 150 150 150 150 150 150 150 150 12
Summer Availability
Adjustment (12)............ $ 0 0 0 0 0 0 0 0 0
Annual Availability
Adjustment (13)............ $ 0 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)... $ 0 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues..... $ 58,773 59,053 60,844 63,299 64,978 66,932 68,455 69,473 5,461
OPERATING EXPENSES ($000)(15)
Fuel......................... $ 0 0 0 0 0 0 0 0 0
Operations (16).............. $ 3,454 3,542 3,629 3,720 3,815 3,910 4,007 4,108 335
Capital Expenditures......... $ 97 99 102 105 107 110 112 116 10
Major Maintenance (17)....... $ 4,248 4,354 4,463 4,574 4,689 4,806 4,926 5,050 383
Operator Fee, Incentive and
Bonus (18)................. $ 663 682 702 722 741 763 784 807 69
Home Office Expenses (19).... $ 2,487 2,578 2,674 2,773 2,877 2,985 3,097 3,214 278
Insurance.................... $ 693 710 728 746 765 784 804 824 70
Property and Other Taxes..... $ 1,770 1,746 1,723 1,700 1,676 1,654 1,632 1,612 129
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses..... $ 13,412 13,711 14,022 14,340 14,670 15,013 15,363 15,730 1,274
NET OPERATING REVENUES
($000)....................... $45,3.61 45,343 46,822 48,959 50,308 51,920 53,092 53,743 4,187
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance........ $159,385 143,688 126,901 109,427 91,266 72,130 50,760 26,812 2,062
Annual Principal........... $ 15,698 16,786 17,474 18,161 19,135 21,370 23,948 24,750 2,063
Annual Interest............ $ 14,782 13,258 11,647 9,971 8,229 6,379 4,267 1,959 98
Letter of Credit Fees........ $ 964 964 962 951 942 946 952 934 77
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service........... $ 31,444 31,009 30,083 29,084 28,307 28,695 29,167 27,643 2,237
TRANSFERS FROM DSRF............ $ 0 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE... 1.44 1.46 1.56 1.68 1.78 1.81 1.82 1.94 1.87
AVERAGE DEBT COVERAGE (21)..... 1.45
DEBT SERVICE RESERVE ACCOUNT
LOC (22)..................... $ 15,964 15,736 15,252 14,734 14,332 14,533 14,778 13,989 1,132
WORKING CAPITAL LOC (23)....... $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
</TABLE>
B-55
<PAGE>
FOOTNOTES TO EXHIBIT B-4
The footnotes to Exhibit B-4 are the same as the footnotes for Exhibit B-1,
except:
15. Non-fuel related operating and maintenance costs assumed to be 10 percent
higher than that assumed in the Base Case.
B-56
<PAGE>
EXHIBIT B-5
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY D--INCREASED INFLATION RATE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2002(1) 2003 2004 2005 2006 2007 2008 2009
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97,0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0% 3.0% 4.0% 5.0% 5.0% 5.0% 6.0%
Unit Starts per Year (7).............. 181 181 272 363 454 454 454 544
Energy Generation (MWh)............... 159,082 159,082 238,622 318,163 397,704 397,704 397,704 477,245
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 42.00 42.21 43.34 44.74 45.73 46.43 47.03 48.19
Unit Start Up Rates ($/Start)....... $ 11,330 11,670 12,020 12,381 12,752 13,135 13,529 13,934
Energy Charges ($/MWh).............. $ 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23
OPERATING REVENUES ($000)
Reservation Payments.................. $ 22,246 38,327 39,353 40,624 41,523 42,158 42,703 43,757
Unit Startup Charges.................. $ 1,921 1,979 3,057 4,198 5,405 5,567 5,734 7,088
Energy Payments....................... $ 27 29 43 60 80 84 87 110
Availability Incentive Adjustment
(11)................................ $ 87 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 24,282 40,485 42,603 45,032 47,158 47,959 48,674 51,105
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 1,010 1,864 2,443 2,648 2,866 3,039 3,220 3,485
Capital Expenditures.................. $ 35 63 67 71 75 80 84 90
Major Maintenance (17)................ $ 1,597 2,569 3,619 4,730 5,906 6,109 6,320 7,641
Operator Fee, Incentive and Bonus
(18)................................ $ 217 107 412 434 457 482 507 535
Home Office Expenses (19)............. $ 459 833 883 936 992 1,052 1,115 1,182
Insurance............................. $ 248 451 478 506 537 569 603 639
Property and Other Taxes.............. $ 52 142 189 305 339 365 382 391
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 3,618 6,029 8,091 9,630 11,172 11,696 12,231 13,963
NET OPERATING REVENUES ($000)........... $ 20,664 34,455 34,512 35,402 35,986 36,262 36,444 37,142
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $275,000 275,000 275,000 275,000 274,714 274,026 273,052 271,391
Annual Principal.................... $ 0 0 0 286 688 974 1,661 2,349
Annual Interest..................... $ 15,240 26,125 26,125 26,125 26,081 26,016 25,907 25,733
Letter of Credit Fees................. $ 429 735 735 738 810 812 819 825
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 15,669 26,860 26,860 27,149 27,579 27,802 28,388 28,907
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.32 1.28 1.28 1.30 1.30 1.30 1.28 1.28
AVERAGE DEBT COVERAGE (21).............. 1.28
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 7,982 13,683 13,683 13,833 14,020 14,136 14,439 14,708
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2010 2011
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0%
Unit Starts per Year (7).............. 454 454
Energy Generation (MWh)............... 397,704 397,704
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 6.00 6.00
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 49.68 51.40
Unit Start Up Rates ($/Start)....... 14,353 14,783
Energy Charges ($/MWh).............. 0.24 0.25
OPERATING REVENUES ($000)
Reservation Payments.................. 45,109 46,671
Unit Startup Charges.................. 6,084 6,266
Energy Payments....................... 95 99
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 51,438 53,186
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 3,618 3,837
Capital Expenditures.................. 95 101
Major Maintenance (17)................ 6,765 7,171
Operator Fee, Incentive and Bonus
(18)................................ 563 594
Home Office Expenses (19)............. 1,852 1,957
Insurance............................. 678 718
Property and Other Taxes.............. 429 416
------- -------
Total Operating Expenses.............. 14,001 14,794
NET OPERATING REVENUES ($000)........... 37,438 38,392
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 269,042 266,005
Annual Principal.................... 3,036 4,010
Annual Interest..................... 25,494 25,189
Letter of Credit Fees................. 893 900
------- -------
Total Debt Service.................... 29,423 30,099
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.27 1.28
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 14,943 15,293
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-57
<PAGE>
EXHIBIT B-5
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY D--INCREASED INFLATION RATE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2012 2013 2014 2015 2016 2017 2018 2019
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0% 4.0% 4.0% 3.0% 3.0% 3.0% 2.0%
Unit Starts per Year (7).............. 454 454 363 363 272 272 272 181
Energy Generation (MWh)............... 397,704 397,704 318,163 318,163 238,622 238,622 238,622 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 53.18 54.79 55.93 56.91 57.99 59.42 61.17 63.39
Unit Start Up Rates ($/Start)....... $ 15,227 15,683 16,154 16,638 17,138 17,652 18,181 18,727
Energy Charges ($/MWh).............. $ 0.26 0.27 0.29 0.30 0.31 0.33 0.34 0.36
OPERATING REVENUES ($000)
Reservation Payments.................. $ 48,287 49,749 50,784 51,674 52,655 53,953 55,542 57,558
Unit Startup Charges.................. $ 6,454 6,648 5,478 5,642 4,358 4,489 4,624 3,175
Energy Payments....................... $ 103 107 92 95 74 79 81 57
Availability Incentive Adjustment
(11)................................ $ 150 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 54,994 56,654 56,504 57,561 57,237 58,671 60,397 60,940
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 4,066 4,312 4,472 4,741 4,918 5,211 5,526 5,725
Capital Expenditures.................. $ 107 113 120 127 135 143 151 160
Major Maintenance (17)................ $ 7,601 8,057 7,106 7,533 6,374 6,755 7,161 5,671
Operator Fee, Incentive and Bonus
(18)................................ $ 626 660 695 734 774 815 860 908
Home Office Expenses (19)............. $ 2,067 2,185 2,309 2,440 2,580 2,726 2,881 3,045
Insurance............................. $ 761 807 856 907 961 1,019 1,080 1,145
Property and Other Taxes.............. $ 497 532 569 693 735 803 851 900
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 15,725 16,665 16,127 17,175 16,476 17,472 18,510 17,554
NET OPERATING REVENUES ($000)........... $ 39,269 39,989 40,377 40,387 40,761 41,199 41,887 43,386
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $261,995 256,609 250,135 242,688 234,151 224,641 213,755 201,495
Annual Principal.................... $ 5,385 6,474 7,448 8,536 9,510 10,885 12,260 13,349
Annual Interest..................... $ 24,775 24,231 23,600 22,859 22,032 21,096 20,029 18,832
Letter of Credit Fees................. $ 901 933 933 933 965 965 965 965
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 31,062 31,638 31,981 32,329 32,508 32,946 33,255 33,146
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.26 1.26 1.26 1.25 1.25 1.25 1.26 1.31
AVERAGE DEBT COVERAGE (21).............. 1.28
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 15,797 16,000 16,000 16,000 16,000 16,000 16,000 16,000
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2020 2021
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0%
Unit Starts per Year (7).............. 181 181
Energy Generation (MWh)............... 159,082 159,082
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 6.00 6.00
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 62.90 61.10
Unit Start Up Rates ($/Start)....... 19,289 19,867
Energy Charges ($/MWh).............. 0.37 0.39
OPERATING REVENUES ($000)
Reservation Payments.................. 57,113 55,479
Unit Startup Charges.................. 3,270 3,368
Energy Payments....................... 59 62
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 60,592 59,059
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 6,070 6,434
Capital Expenditures.................. 170 180
Major Maintenance (17)................ 6,010 6,372
Operator Fee, Incentive and Bonus
(18)................................ 957 1,010
Home Office Expenses (19)............. 3,219 3,402
Insurance............................. 1,214 1,286
Property and Other Taxes.............. 1,127 1,183
------- -------
Total Operating Expenses.............. 18,767 19,867
NET OPERATING REVENUES ($000)........... 41,825 39,192
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 188,146 174,109
Annual Principal.................... 14,036 14,724
Annual Interest..................... 17,547 16,198
Letter of Credit Fees................. 965 964
------- -------
Total Debt Service.................... 32,549 31,885
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.28 1.23
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 16,000 16,000
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-58
<PAGE>
EXHIBIT B-5
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY D--INCREASED INFLATION RATE
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030(1)
------------------------ -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2).................... 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity
(kW)(3).................... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the
PPA (%)(4)................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the
PPA (%)(5)................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)....... 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%
Unit Starts per Year (7)..... 181 181 181 181 181 181 181 181 0
Energy Generation (MWh)...... 159,082 159,082 159,082 159,082 159,082 159,082 159,082 159,082 0
Net Plant Heat Rate
(Btu/kWh)(8)............... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9)..... 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00
Electricity Prices (10)
Reservation Charges
($/kW-yr)................ $ 60.67 60.86 62.71 65.29 67.01 69.03 70.57 71.55 72.00
Unit Start Up Rates
($/Start)................ $ 20,463 21,077 21,709 22,361 23,032 23,723 24,434 25,167 25,922
Energy Charges ($/MWh)..... $ 0.41 0.43 0.45 0.47 0.49 0.51 0.53 0.56 0.56
OPERATING REVENUES ($000)
Reservation Payments......... $ 55,088 55,261 56,941 59,283 60,845 62,679 64,078 64,967 5,448
Unit Startup Charges......... $ 3,470 3,574 3,681 3,791 3,905 4,022 4,143 4,267 0
Energy Payments.............. $ 65 68 72 75 78 81 84 89 0
Availability Incentive
Adjustment (11)............ $ 150 150 150 150 150 150 150 150 12
Summer Availability
Adjustment (12)............ $ 0 0 0 0 0 0 0 0 0
Annual Availability
Adjustment (13)............ $ 0 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)... $ 0 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues..... $ 58,773 59,053 60,844 63,299 64,978 66,932 68,455 69,473 5,461
OPERATING EXPENSES ($000)(15)
Fuel......................... $ 0 0 0 0 0 0 0 0 0
Operations (16).............. $ 6,821 7,231 7,665 8,125 8,610 9,129 9,674 10,256 865
Capital Expenditures......... $ 191 202 215 227 241 256 271 287 25
Major Maintenance (17)....... $ 6,753 7,158 7,589 8,044 8,527 9,037 9,580 10,155 772
Operator Fee, Incentive and
Bonus (18)................. $ 1,065 1,124 1,187 1,252 1,321 1,395 1,472 1,554 137
Home Office Expenses (19).... $ 3,596 3,801 4,017 4,246 4,489 4,745 5,016 5,303 468
Insurance.................... $ 1,364 1,445 1,532 1,624 1,722 1,825 1,934 2,050 181
Property and Other Taxes..... $ 1,609 1,587 1,566 1,545 1,524 1,504 1,484 1,465 117
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses..... $ 21,399 22,548 23,770 25,063 26,434 27,891 29,431 31,070 2,565
NET OPERATING REVENUES
($000)....................... $ 37,374 36,506 37,073 38,236 38,544 39,041 39,024 38,403 2,896
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance........ $159,385 143,688 126,901 109,427 91,266 72,130 50,760 26,812 2,062
Annual Principal........... $ 15,698 16,786 17,474 18,161 19,135 21,370 23,948 24,750 2,063
Annual Interest............ $ 14,782 13,258 11,647 9,971 8,229 6,379 4,267 1,959 98
Letter of Credit Fees........ $ 964 964 962 951 942 946 952 934 77
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service........... $ 31,444 31,009 30,083 29,084 28,307 28,695 29,167 27,643 2,237
TRANSFERS FROM DSRF............ $ 0 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE... 1.19 1.18 1.23 1.31 1.36 1.36 1.34 1.39 1.29
AVERAGE DEBT COVERAGE (21)..... 1.28
DEBT SERVICE RESERVE ACCOUNT
LOC (22)..................... $ 15,964 15,736 15,252 14,734 14,332 14,533 14,778 13,989 1,132
WORKING CAPITAL LOC (23)....... $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
</TABLE>
B-59
<PAGE>
FOOTNOTES TO EXHIBIT B-5
The footnotes to Exhibit B-5 are the same as the footnotes for Exhibit B-1,
except:
9. General inflation is assumed to escalate at a rate of 6.0 percent per year,
rather than 2.5 percent per year, as assumed in the Base Case.
B-60
<PAGE>
EXHIBIT B-6
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY E--REDUCED CONTRACT CAPACITY
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2002(1) 2003 2004 2005 2006 2007 2008 2009
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 875,000 875,000 875,000 875,000 875,000 875,000 875,000 875,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0% 3.0% 4.0% 5.0% 5.0% 5.0% 6.0%
Unit Starts per Year (7).............. 181 181 272 363 454 454 454 544
Energy Generation (MWh)............... 153,300 153,300 229,950 306,600 383,250 383,250 383,250 459,900
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 42.00 42.21 43.34 44.74 45.73 46.43 47.03 48.19
Unit Start Up Rates ($/Start)....... $ 11,330 11,670 12,020 12,381 12,752 13,135 13,529 13,934
Energy Charges ($/MWh).............. $ 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23
OPERATING REVENUES ($000)
Reservation Payments.................. $ 21,438 36,934 37,923 39,148 40,014 40,626 41,151 42,166
Unit Startup Charges.................. $ 1,921 1,979 3,057 4,198 5,405 5,567 5,734 7,088
Energy Payments....................... $ 26 28 41 58 77 80 84 106
Availability Incentive Adjustment
(11)................................ $ 87 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 23,473 39,091 41,171 43,554 45,646 46,423 47,119 49,510
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 914 1,622 2,057 2,152 2,251 2,308 2,364 2,472
Capital Expenditures.................. $ 32 55 57 58 59 61 62 64
Major Maintenance (17)................ $ 1,559 2,477 3,502 4,583 5,727 5,895 6,068 7,348
Operator Fee, Incentive and Bonus
(18)................................ $ 202 107 366 376 386 397 408 420
Home Office Expenses (19)............. $ 422 742 761 780 799 819 840 861
Insurance............................. $ 224 394 404 414 424 435 446 457
Property and Other Taxes.............. $ 52 142 189 305 339 365 382 391
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 3,405 5,539 7,336 8,669 9,985 10,280 10,569 12,014
NET OPERATING REVENUES ($000)........... $ 20,068 33,551 33,835 34,885 35,661 36,144 36,550 37,496
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $275,000 275,000 275,000 275,000 274,714 274,026 273,052 271,391
Annual Principal.................... $ 0 0 0 286 688 974 1,661 2,349
Annual Interest..................... $ 15,240 26,125 26,125 26,125 26,081 26,016 25,907 25,733
Letter of Credit Fees................. $ 429 735 735 738 810 812 819 825
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 15,669 26,860 26,860 27,149 27,579 27,802 28,388 28,907
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.28 1.25 1.26 1.28 1.29 1.30 1.29 1.30
AVERAGE DEBT COVERAGE (21).............. 1.42
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 7,982 13,683 13,683 13,833 14,020 14,136 14,439 14,708
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2010 2011
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 875,000 875,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0%
Unit Starts per Year (7).............. 454 454
Energy Generation (MWh)............... 383,250 383,250
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 49.68 51.40
Unit Start Up Rates ($/Start)....... 14,353 14,783
Energy Charges ($/MWh).............. 0.24 0.25
OPERATING REVENUES ($000)
Reservation Payments.................. 43,470 44,975
Unit Startup Charges.................. 6,084 6,266
Energy Payments....................... 92 96
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 49,796 51,487
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,486 2,546
Capital Expenditures.................. 66 67
Major Maintenance (17)................ 6,430 6,591
Operator Fee, Incentive and Bonus
(18)................................ 431 444
Home Office Expenses (19)............. 1,480 1,532
Insurance............................. 468 480
Property and Other Taxes.............. 429 416
------- -------
Total Operating Expenses.............. 11,790 12,077
NET OPERATING REVENUES ($000)........... 38,006 39,410
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 269,042 266,005
Annual Principal.................... 3,036 4,010
Annual Interest..................... 25,494 25,189
Letter of Credit Fees................. 893 900
------- -------
Total Debt Service.................... 29,423 30,099
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.29 1.31
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 14,943 15,293
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-61
<PAGE>
EXHIBIT B-6
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY E--REDUCED CONTRACT CAPACITY
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2012 2013 2014 2015 2016 2017 2018 2019
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 875,000 875,000 875,000 875,000 875,000 875,000 875,000 875,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 5.0% 5.0% 4.0% 4.0% 3.0% 3.0% 3.0% 2.0%
Unit Starts per Year (7).............. 454 454 363 363 272 272 272 181
Energy Generation (MWh)............... 383,250 383,250 306,600 306,600 229,950 229,950 229,950 153,300
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2,50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 53.18 54.79 55.93 56.91 57.99 59.42 61.17 63.39
Unit Start Up Rates ($/Start)....... $ 15,227 15,683 16,154 16,638 17,138 17,652 18,181 18,727
Energy Charges ($/MWh).............. $ 0.26 0.27 0.29 0.30 0.31 0.33 0.34 0.36
OPERATING REVENUES ($000)
Reservation Payments.................. $ 46,533 47,941 48,939 49,796 50,741 51,993 53,524 55,466
Unit Startup Charges.................. $ 6,454 6,648 5,478 5,642 4,358 4,489 4,624 3,175
Energy Payments....................... $ 100 103 89 92 71 76 78 55
Availability Incentive Adjustment
(11)................................ $ 150 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 53,237 54,842 54,656 55,680 55,320 56,708 58,376 58,846
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 2,612 2,676 2,687 2,754 2,764 2,837 2,907 2,917
Capital Expenditures.................. $ 69 71 72 74 76 78 80 82
Major Maintenance (17)................ $ 6,756 6,924 5,843 5,990 4,821 4,943 5,066 3,773
Operator Fee, Incentive and Bonus
(18)................................ $ 456 469 482 496 510 524 539 555
Home Office Expenses (19)............. $ 1,586 1,642 1,701 1,762 1,824 1,890 1,958 2,030
Insurance............................. $ 492 504 517 530 543 557 571 585
Property and Other Taxes.............. $ 497 532 569 693 735 803 851 900
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 12,467 12,819 11,871 12,300 11,273 11,632 11,973 10,843
NET OPERATING REVENUES ($000)........... $ 40,769 42,024 42,785 43,380 44,048 45,076 46,404 48,004
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $261,995 256,609 250,135 242,688 234,151 224,641 213,755 201,495
Annual Principal.................... $ 5,385 6,474 7,448 8,536 9,510 10,885 12,260 13,349
Annual Interest..................... $ 24,775 24,231 23,600 22,859 22,032 21,096 20,029 18,832
Letter of Credit Fees................. $ 901 933 933 933 965 965 965 965
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 31,062 31,638 31,981 32,329 32,508 32,946 33,255 33,146
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.31 1.33 1.34 1.34 1.35 1.37 1.40 1.45
AVERAGE DEBT COVERAGE (21).............. 1.42
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 15,797 16,000 16,000 16,000 16,000 16,000 16,000 16,000
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2020 2021
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 875,000 875,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 2.0% 2.0%
Unit Starts per Year (7).............. 181 181
Energy Generation (MWh)............... 153,300 153,300
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 62.90 61.10
Unit Start Up Rates ($/Start)....... 19,289 19,867
Energy Charges ($/MWh).............. 0.37 0.39
OPERATING REVENUES ($000)
Reservation Payments.................. 55,038 53,463
Unit Startup Charges.................. 3,270 3,368
Energy Payments....................... 57 60
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 58,515 57,041
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,991 3,064
Capital Expenditures.................. 84 86
Major Maintenance (17)................ 3,868 3,965
Operator Fee, Incentive and Bonus
(18)................................ 570 586
Home Office Expenses (19)............. 2,103 2,180
Insurance............................. 600 615
Property and Other Taxes.............. 1,127 1,183
------- -------
Total Operating Expenses.............. 11,342 11,679
NET OPERATING REVENUES ($000)........... 47,172 45,362
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 188,146 174,109
Annual Principal.................... 14,036 14,724
Annual Interest..................... 17,547 16,198
Letter of Credit Fees................. 965 964
------- -------
Total Debt Service.................... 32,549 31,885
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.45 1.42
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 16,000 16,000
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-62
<PAGE>
EXHIBIT B-6
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY E--REDUCED CONTRACT CAPACITY
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030(1)
------------------------ -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2).................... 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity
(kW)(3).................... 875,000 875,000 875,000 875,000 875,000 875,000 875,000 875,000 875,000
Summer Availability under the
PPA (%)(4)................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the
PPA (%)(5)................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)....... 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%
Unit Starts per Year (7)..... 181 181 181 181 181 181 181 181 0
Energy Generation (MWh)...... 153,300 153,300 153,300 153,300 153,300 153,300 153,300 153,300 0
Net Plant Heat Rate
(Btu/kWh)(8)............... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9)..... 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges
($/kW-yr)................ $ 60.67 60.86 62.71 65.29 67.01 69.03 70.57 71.55 72.00
Unit Start Up Rates
($/Start)................ $ 20,463 21,077 21,709 22,361 23,032 23,723 24,434 25,167 25,922
Energy Charges ($/MWh)..... $ 0.41 0.43 0.45 0.47 0.49 0.51 0.53 0.56 0.56
OPERATING REVENUES ($000)
Reservation Payments......... $ 53,086 53,253 54,871 57,129 58,634 60,401 61,749 62,606 5,250
Unit Startup Charges......... $ 3,470 3,574 3,681 3,791 3,905 4,022 4,143 4,267 0
Energy Payments.............. $ 63 66 69 72 75 78 81 86 0
Availability Incentive
Adjustment (11)............ $ 150 150 150 150 150 150 150 150 12
Summer Availability
Adjustment (12)............ $ 0 0 0 0 0 0 0 0 0
Annual Availability
Adjustment (13)............ $ 0 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)... $ 0 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues..... $ 56,769 57,043 58,771 61,142 62,764 64,651 66,123 67,109 5,263
OPERATING EXPENSES ($000)(15)
Fuel......................... $ 0 0 0 0 0 0 0 0 0
Operations (16).............. $ 3,141 3,220 3,300 3,384 3,467 3,555 3,643 3,734 306
Capital Expenditures......... $ 88 90 93 95 97 100 102 105 9
Major Maintenance (17)....... $ 4,064 4,165 4,270 4,377 4,487 4,598 4,713 4,831 349
Operator Fee, Incentive and
Bonus (18)................. $ 603 620 638 656 674 694 713 734 63
Home Office Expenses (19).... $ 2,261 2,344 2,431 2,522 2,616 2,713 2,815 2,922 253
Insurance.................... $ 630 646 662 678 695 713 731 749 64
Property and Other Taxes..... $ 1,609 1,587 1,566 1,545 1,524 1,504 1,484 1,465 117
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses..... $ 12,396 12,672 12,960 13,257 13,560 13,878 14,201 14,540 1,161
NET OPERATING REVENUES
($000)....................... $ 44,373 44,371 45,811 47,885 49,204 50,774 51,922 52,569 4,101
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance........ $159,385 143,688 126,901 109,427 91,266 72,130 50,760 26,812 2,062
Annual Principal........... $ 15,698 16,786 17,474 18,161 19,135 21,370 23,948 24,750 2,063
Annual Interest............ $ 14,782 13,258 11,647 9,971 8,229 6,379 4,267 1,959 98
Letter of Credit Fees........ $ 964 964 962 951 942 946 952 934 77
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service........... $ 31,444 31,009 30,083 29,084 28,307 28,695 29,167 27,643 2,237
TRANSFERS FROM DSRF............ $ 0 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE... 1.41 1.43 1.52 1.65 1.74 1.77 1.78 1.90 1.83
AVERAGE DEBT COVERAGE (21)..... 1.42
DEBT SERVICE RESERVE ACCOUNT
LOC (22)..................... $ 15,964 15,736 15,252 14,734 14,332 14,533 14,778 13,989 1,132
WORKING CAPITAL LOC (23)....... $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
</TABLE>
B-63
<PAGE>
FOOTNOTES TO EXHIBIT B-6
The footnotes to Exhibit B-6 are the same as the footnotes for Exhibit B-1,
except:
3. The projected levels of Contract Capacity to be declared each year by the
Partnership, and purchased each year by PECO, as defined in the PPA, are
assumed to equal the minimum amount of Contract Capacity allowed under the
PPA.
B-64
<PAGE>
EXHIBIT B-7
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY F--ZERO DISPATCH
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2002(L) 2003 2004 2005 2006 2007 2008 2009
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Unit Starts per Year (7).............. 0 0 0 0 0 0 0 0
Energy Generation (MWh)............... 0 0 0 0 0 0 0 0
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 42.00 42.21 43.34 44.74 45.73 46.43 47.03 48.19
Unit Start Up Rates ($/Start)....... $ 11,330 11,670 12,020 12,381 12,752 13,135 13,529 13,934
Energy Charges ($/MWh).............. $ 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23
OPERATING REVENUES ($000)
Reservation Payments.................. $ 22,246 38,327 39,353 40,624 41,523 42,158 42,703 43,757
Unit Startup Charges.................. $ 0 0 0 0 0 0 0 0
Energy Payments....................... $ 0 0 0 0 0 0 0 0
Availability Incentive Adjustment
(11)................................ $ 87 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 22,334 38,477 39,503 40,774 41,673 42,308 42,853 43,907
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 884 1,550 1,929 1,978 2,027 2,078 2,129 2,183
Capital Expenditures.................. $ 32 55 57 58 59 61 62 64
Major Maintenance (17)................ $ 1,189 2,096 2,158 2,219 2,282 2,347 2,413 2,481
Operator Fee, Incentive and Bonus
(18)................................ $ 202 107 366 376 386 397 408 420
Home Office Expenses (19)............. $ 422 742 761 780 799 819 840 861
Insurance............................. $ 224 394 404 414 424 435 446 457
Property and Other Taxes.............. $ 52 142 189 305 339 365 382 391
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 3,005 5,086 5,864 6,130 6,316 6,502 6,680 6,857
NET OPERATING REVENUES ($000)........... $ 19,329 33,391 33,639 34,644 35,357 35,806 36,173 37,050
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $275,000 275,000 275,000 275,000 274,714 274,026 273,052 271,391
Annual Principal.................... $ 0 0 0 286 688 974 1,661 2,349
Annual Interest..................... $ 15,240 26,125 26,125 26,125 26,081 26,016 25,907 25,733
Letter of Credit Fees................. $ 429 735 735 738 810 812 819 825
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 15,669 26,860 26,860 27,149 27,579 27,802 28,388 28,907
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.23 1.24 1.25 1.28 1.28 1.29 1.27 1.28
AVERAGE DEBT COVERAGE (21).............. 1.40
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 7,982 13,683 13,683 13,833 14,020 14,136 14,439 14,708
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2010 2011
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 0.0% 0.0%
Unit Starts per Year (7).............. 0 0
Energy Generation (MWh)............... 0 0
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 49.68 51.40
Unit Start Up Rates ($/Start)....... 14,353 14,783
Energy Charges ($/MWh).............. 0.24 0.25
OPERATING REVENUES ($000)
Reservation Payments.................. 45,109 46,671
Unit Startup Charges.................. 0 0
Energy Payments....................... 0 0
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 45,259 46,821
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,239 2,293
Capital Expenditures.................. 66 67
Major Maintenance (17)................ 2,553 2,617
Operator Fee, Incentive and Bonus
(18)................................ 431 444
Home Office Expenses (19)............. 1,480 1,532
Insurance............................. 468 480
Property and Other Taxes.............. 429 416
------- -------
Total Operating Expenses.............. 7,666 7,849
NET OPERATING REVENUES ($000)........... 37,593 38,972
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 269,042 266,005
Annual Principal.................... 3,036 4,010
Annual Interest..................... 25,494 25,189
Letter of Credit Fees................. 893 900
------- -------
Total Debt Service.................... 29,423 30,099
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.28 1.29
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 14,943 15,293
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-65
<PAGE>
EXHIBIT B-7
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY F--ZERO DISPATCH
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2012 2013 2014 2015 2016 2017 2018 2019
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PRA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Unit Stains per Year (7).............. 0 0 0 0 0 0 0 0
Energy Generation (MWh)............... 0 0 0 0 0 0 0 0
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 53.18 54.79 55.93 56.91 57.99 59.42 61.17 63.39
Unit Start Up Rates ($/Start)....... $ 15,227 15,683 16,154 16,638 17,138 17,652 18,181 18,727
Energy Charges ($/MWh).............. $ 0.26 0.27 0.29 0.30 0.31 0.33 0.34 0.36
OPERATING REVENUES ($000)
Reservation Payments.................. $ 48,287 49,749 50,784 51,674 52,655 53,953 55,542 57,558
Unit Startup Charges.................. $ 0 0 0 0 0 0 0 0
Energy Payments....................... $ 0 0 0 0 0 0 0 0
Availability Incentive Adjustment
(11)................................ $ 150 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 48,437 49,899 50,934 51,824 52,805 54,103 55,692 57,708
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 2,352 2,410 2,469 2,531 2,592 2,661 2,727 2,794
Capital Expenditures.................. $ 69 71 72 74 76 78 80 82
Major Maintenance (17)................ $ 2,682 2,749 2,817 2,889 2,960 3,035 3,111 3,188
Operator Fee, Incentive and Bonus
(18)................................ $ 456 469 482 496 510 524 539 555
Home Office Expenses (19)............. $ 1,586 1,642 1,701 1,762 1,824 1,890 1,958 2,030
Insurance............................. $ 492 504 517 530 543 557 571 585
Property and Other Taxes.............. $ 497 532 569 693 735 803 851 900
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 8,134 8,377 8,627 8,975 9,240 9,548 9,837 10,134
NET OPERATING REVENUES ($000)........... $ 40,303 41,522 42,307 42,849 43,565 44,555 45,855 47,574
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $261,995 256,609 250,135 242,688 234,151 224,641 213,755 201,495
Annual Principal.................... $ 5,385 6,474 7,448 8,536 9,510 10,885 12,260 13,349
Annual Interest..................... $ 24,775 24,231 23,600 22,859 22,032 21,096 20,029 18,832
Letter of Credit Fees................. $ 901 933 933 933 965 965 965 965
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 31,062 31,638 31,981 32,329 32,508 32,946 33,255 33,146
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.30 1.31 1.32 1.33 1.34 1.35 1.38 1.44
AVERAGE DEBT COVERAGE (21).............. 1.40
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 15,797 16,000 16,000 16,000 16,000 16,000 16,000 16,000
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2020 2021
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PRA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 0.0% 0.0%
Unit Stains per Year (7).............. 0 0
Energy Generation (MWh)............... 0 0
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 62.90 61.10
Unit Start Up Rates ($/Start)....... 19,289 19,867
Energy Charges ($/MWh).............. 0.37 0.39
OPERATING REVENUES ($000)
Reservation Payments.................. 57,113 55,479
Unit Startup Charges.................. 0 0
Energy Payments....................... 0 0
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 57,263 55,629
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,864 2,934
Capital Expenditures.................. 84 86
Major Maintenance (17)................ 3,268 3,350
Operator Fee, Incentive and Bonus
(18)................................ 570 586
Home Office Expenses (19)............. 2,103 2,180
Insurance............................. 600 615
Property and Other Taxes.............. 1,127 1,183
------- -------
Total Operating Expenses.............. 10,616 10,934
NET OPERATING REVENUES ($000)........... 46,647 44,695
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 188,146 174,109
Annual Principal.................... 14,036 14,724
Annual Interest..................... 17,547 16,198
Letter of Credit Fees................. 965 964
------- -------
Total Debt Service.................... 32,549 31,885
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.43 1.40
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 16,000 16,000
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-66
<PAGE>
EXHIBIT B-7
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY F--ZERO DISPATCH
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030(L)
------------------------ -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2).................... 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity
(kW)(3).................... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the
PPA (%)(4)................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the
PPA (%)(5)................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)....... 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Unit Starts per Year (7)..... 0 0 0 0 0 0 0 0 0
Energy Generation (MWh)...... 0 0 0 0 0 0 0 0 0
Net Plant Heat Rate
(Btu/kWh)(8)............... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9)..... 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges
($/kW-yr)................ $ 60.67 60.86 62.71 65.29 67.01 69.03 70.57 71.55 72.00
Unit Start Up Rates
($/Start)................ $ 20,463 21,077 21,709 22,361 23,032 23,723 24,434 25,167 25,922
Energy Charges ($/MWh)..... $ 0.41 0.43 0.45 0.47 0.49 0.51 0.53 0.56 0.56
OPERATING REVENUES ($000)
Reservation Payments......... $ 55,088 55,261 56,941 59,283 60,845 62,679 64,078 64,967 5,448
Unit Startup Charges......... $ 0 0 0 0 0 0 0 0 0
Energy Payments.............. $ 0 0 0 0 0 0 0 0 0
Availability Incentive
Adjustment (11)............ $ 150 150 150 150 150 150 150 150 12
Summer Availability
Adjustment (12)............ $ 0 0 0 0 0 0 0 0 0
Annual Availability
Adjustment (13)............ $ 0 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)... $ 0 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues..... $ 55,238 55,411 57,091 59,433 60,995 62,829 64,228 65,117 5,461
OPERATING EXPENSES ($000)(15)
Fuel......................... $ 0 0 0 0 0 0 0 0 0
Operations (16).............. $ 3,008 3,084 3,160 3,241 3,321 3,405 3,489 3,576 306
Capital Expenditures......... $ 88 90 93 95 97 100 102 105 9
Major Maintenance (17)....... $ 3,434 3,519 3,608 3,698 3,791 3,885 3,982 4,082 349
Operator Fee, Incentive and
Bonus (18)................. $ 603 620 638 656 674 694 713 734 63
Home Office Expenses (19).... $ 2,261 2,344 2,431 2,522 2,616 2,713 2,815 2,922 253
Insurance.................... $ 630 646 662 678 695 713 731 749 64
Property and Other Taxes..... $ 1,609 1,587 1,566 1,545 1,524 1,504 1,484 1,465 117
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses..... $ 11,633 11,890 12,158 12,435 12,718 13,014 13,316 13,633 1,161
NET OPERATING REVENUES
($000)....................... $ 43,605 43,521 44,933 46,998 48,277 49,815 50,912 51,484 4,299
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance........ $159,385 143,688 126,901 109,427 91,266 72,130 50,760 26,812 2,062
Annual Principal........... $ 15,698 16,786 17,474 18,161 19,135 21,370 23,948 24,750 2,063
Annual Interest............ $ 14,782 13,258 11,647 9,971 8,229 6,379 4,267 1,959 98
Letter of Credit Fees........ $ 964 964 962 951 942 946 952 934 77
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service........... $ 31,444 31,009 30,083 29,084 28,307 28,695 29,167 27,643 2,237
TRANSFERS FROM DSRF............ $ 0 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE... 1.39 1.40 1.49 1.62 1.71 1.74 1.75 1.86 1.92
AVERAGE DEBT COVERAGE (21)..... 1.40
DEBT SERVICE RESERVE ACCOUNT
LOC (22)..................... $ 15,964 15,736 15,252 14,734 14,332 14,533 14,778 13,989 1,132
WORKING CAPITAL LOC (23)....... $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
</TABLE>
B-67
<PAGE>
FOOTNOTES TO EXHIBIT B-7
The footnotes to Exhibit B-7 are the same as the footnotes for Exhibit B-1,
except:
6. The annual capacity factors are assumed to be zero each Contract Year.
B-68
<PAGE>
EXHIBIT B-8
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY G--INCREASED CAPACITY FACTORS
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2002(1) 2003 2004 2005 2006 2007 2008 2009
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 4.0% 4.0% 6.0% 8.0% 10.0% 10.0% 10.0% 12.0%
Unit Starts per Year (7).............. 363 363 544 726 907 907 907 1,089
Energy Generation (MWh)............... 318,163 318,163 477,245 636,326 795,408 795,408 795,408 954,490
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 42.00 42.21 43.34 44.74 45.73 46.43 47.03 48.19
Unit Start Up Rates ($/Start)....... $ 11,330 11,670 12,020 12,381 12,752 13,135 13,529 13,934
Energy Charges ($/MWh).............. $ 0.17 0.18 0.18 0.19 0.20 0.21 0.22 0.23
OPERATING REVENUES ($000)
Reservation Payments.................. $ 22,246 38,327 39,353 40,624 41,523 42,158 42,703 43,757
Unit Startup Charges.................. $ 3,842 3,957 6,114 8,396 10,810 11,135 11,469 14,175
Energy Payments....................... $ 54 57 86 121 159 167 175 220
Availability Incentive Adjustment
(11)................................ $ 87 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 26,230 42,491 45,703 49,291 52,642 53,610 54,497 58,302
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 945 1,694 2,185 2,327 2,474 2,537 2,598 2,761
Capital Expenditures.................. $ 32 55 57 58 59 61 62 64
Major Maintenance (17)................ $ 3,353 4,325 6,357 8,504 10,774 11,094 11,423 13,967
Operator Fee, Incentive and Bonus
(18)................................ $ 202 107 366 376 386 397 408 420
Home Office Expenses (19)............. $ 422 742 761 780 799 819 840 861
Insurance............................. $ 224 394 404 414 424 435 446 457
Property and Other Taxes.............. $ 52 142 189 305 339 365 382 391
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 5,229 7,459 10,318 12,764 15,256 15,708 16,159 18,921
NET OPERATING REVENUES ($000)........... $ 21,000 35,032 35,385 36,527 37,386 37,902 38,338 39,380
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $275,000 275,000 275,000 275,000 274,714 274,026 273,052 271,391
Annual Principal.................... $ 0 0 0 286 688 974 1,661 2,349
Annual Interest..................... $ 15,240 26,125 26,125 26,125 26,081 26,016 25,907 25,733
Letter of Credit Fees................. $ 429 735 735 738 810 812 819 825
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 15,669 26,860 26,860 27,149 27,579 27,802 28,388 28,907
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.34 1.30 1.32 1.35 1.36 1.36 1.35 1.36
AVERAGE DEBT COVERAGE (21).............. 1.50
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 7,982 13,683 13,683 13,833 14,020 14,136 14,439 14,708
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2010 2011
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 10.0% 10.0%
Unit Starts per Year (7).............. 907 907
Energy Generation (MWh)............... 795,408 795,408
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 49.68 51.40
Unit Start Up Rates ($/Start)....... 14,353 14,783
Energy Charges ($/MWh).............. 0.24 0.25
OPERATING REVENUES ($000)
Reservation Payments.................. 45,109 46,671
Unit Startup Charges.................. 12,167 12,532
Energy Payments....................... 191 199
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 57,617 59,552
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 2,733 2,800
Capital Expenditures.................. 66 67
Major Maintenance (17)................ 12,111 12,414
Operator Fee, Incentive and Bonus
(18)................................ 431 444
Home Office Expenses (19)............. 1,480 1,532
Insurance............................. 468 480
Property and Other Taxes.............. 429 416
------- -------
Total Operating Expenses.............. 17,718 18,153
NET OPERATING REVENUES ($000)........... 39,899 41,399
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 269,042 266,005
Annual Principal.................... 3,036 4,010
Annual Interest..................... 25,494 25,189
Letter of Credit Fees................. 893 900
------- -------
Total Debt Service.................... 29,423 30,099
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.36 1.38
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 14,943 15,293
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-69
<PAGE>
EXHIBIT B-8
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY G--INCREASED CAPACITY FACTORS
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2012 2013 2014 2015 2016 2017 2018 2019
------------------------ -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0%
Capacity Factor (%)(6)................ 10.0% 10.0% 8.0% 8.0% 6.0% 6.0% 6.0% 4.0%
Unit Starts per Year (7).............. 907 907 726 726 544 544 544 363
Energy Generation (MWh)............... 795,408 795,408 636,326 636,326 477,245 477,245 477,245 318,163
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... $ 53.18 54.79 55.93 56.91 57.99 59.42 61.17 63.39
Unit Start Up Rates ($/Start)....... $ 15,227 15,683 16,154 16,638 17,138 17,652 18,181 18,727
Energy Charges ($/MWh).............. $ 0.26 0.27 0.29 0.30 0.31 0.33 0.34 0.36
OPERATING REVENUES ($000)
Reservation Payments.................. $ 48,287 49,749 50,784 51,674 52,655 53,953 55,542 57,558
Unit Startup Charges.................. $ 12,908 13,295 10,955 11,284 8,717 8,978 9,248 6,350
Energy Payments....................... $ 207 215 185 191 148 157 162 115
Availability Incentive Adjustment
(11)................................ $ 150 150 150 150 150 150 150 150
Summer Availability Adjustment (12)... $ 0 0 0 0 0 0 0 0
Annual Availability Adjustment (13)... $ 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)............ $ 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues.............. $ 61,552 63,409 62,074 63,299 61,670 63,238 65,102 64,173
OPERATING EXPENSES ($000)(15)
Fuel.................................. $ 0 0 0 0 0 0 0 0
Operations (16)....................... $ 2,871 2,943 2,906 2,978 2,935 3,013 3,088 3,041
Capital Expenditures.................. $ 69 71 72 74 76 78 80 82
Major Maintenance (17)................ $ 12,724 13,042 10,859 11,132 8,774 8,994 9,219 6,611
Operator Fee, Incentive and Bonus
(18)................................ $ 456 469 482 496 510 524 539 555
Home Office Expenses (19)............. $ 1,586 1,642 1,701 1,762 1,824 1,890 1,958 2,030
Insurance............................. $ 492 504 517 530 543 557 571 585
Property and Other Taxes.............. $ 497 532 569 693 735 803 851 900
-------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses.............. $ 18,695 19,203 17,106 17,665 15,397 15,859 16,306 13,804
NET OPERATING REVENUES ($000)........... $ 42,856 44,206 44,967 45,634 46,273 47,379 48,796 50,369
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. $261,995 256,609 250,135 242,688 234,151 224,641 213,755 201,495
Annual Principal.................... $ 5,385 6,474 7,448 8,536 9,510 10,885 12,260 13,349
Annual Interest..................... $ 24,775 24,231 23,600 22,859 22,032 21,096 20,029 18,832
Letter of Credit Fees................. $ 901 933 933 933 965 965 965 965
-------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service.................... $ 31,062 31,638 31,981 32,329 32,508 32,946 33,255 33,146
TRANSFERS FROM DSRF..................... $ 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.38 1.40 1.41 1.41 1.42 1.44 1.47 1.52
AVERAGE DEBT COVERAGE (21).............. 1.50
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. $ 15,797 16,000 16,000 16,000 16,000 16,000 16,000 16,000
WORKING CAPITAL LOC (23)................ $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
<CAPTION>
YEAR ENDING DECEMBER 31, 2020 2021
------------------------ -------- --------
<S> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2)............................. 936,000 936,000
PPA Contract Capacity (kW)(3)......... 908,000 908,000
Summer Availability under the PPA
(%)(4).............................. 98.0% 98.0%
Annual Availability under the PPA
(%)(5).............................. 97.0% 97.0%
Capacity Factor (%)(6)................ 4.0% 4.0%
Unit Starts per Year (7).............. 363 363
Energy Generation (MWh)............... 318,163 318,163
Net Plant Heat Rate (Btu/kWh)(8)...... 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9).............. 2.50 2.50
Electricity Prices (10)
Reservation Charges ($/kW-yr)....... 62.90 61.10
Unit Start Up Rates ($/Start)....... 19,289 19,867
Energy Charges ($/MWh).............. 0.37 0.39
OPERATING REVENUES ($000)
Reservation Payments.................. 57,113 55,479
Unit Startup Charges.................. 6,541 6,737
Energy Payments....................... 118 124
Availability Incentive Adjustment
(11)................................ 150 150
Summer Availability Adjustment (12)... 0 0
Annual Availability Adjustment (13)... 0 0
Efficiency Adjustment (14)............ 0 0
------- -------
Total Operating Revenues.............. 63,922 62,490
OPERATING EXPENSES ($000)(15)
Fuel.................................. 0 0
Operations (16)....................... 3,117 3,193
Capital Expenditures.................. 84 86
Major Maintenance (17)................ 6,777 6,947
Operator Fee, Incentive and Bonus
(18)................................ 570 586
Home Office Expenses (19)............. 2,103 2,180
Insurance............................. 600 615
Property and Other Taxes.............. 1,127 1,183
------- -------
Total Operating Expenses.............. 14,378 14,790
NET OPERATING REVENUES ($000)........... 49,544 47,700
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance................. 188,146 174,109
Annual Principal.................... 14,036 14,724
Annual Interest..................... 17,547 16,198
Letter of Credit Fees................. 965 964
------- -------
Total Debt Service.................... 32,549 31,885
TRANSFERS FROM DSRF..................... 0 0
ANNUAL DEBT SERVICE COVERAGE............ 1.52 1.50
AVERAGE DEBT COVERAGE (21)..............
DEBT SERVICE RESERVE ACCOUNT
LOC (22).............................. 16,000 16,000
WORKING CAPITAL LOC (23)................ 5,000 5,000
</TABLE>
B-70
<PAGE>
EXHIBIT B-8
TENASKA GEORGIA FACILITY
PROJECTED OPERATING RESULTS
SENSITIVITY G--INCREASED CAPACITY FACTORS
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, 2022 2023 2024 2025 2026 2027 2028 2029 2030(L)
------------------------ -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PERFORMANCE
Net Summer Installed Capacity
(kW)(2).................... 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000 936,000
PPA Contract Capacity
(kW)(3).................... 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000 908,000
Summer Availability under the
PPA (%)(4)................. 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0% 98.0%
Annual Availability under the
PPA (%)(5)................. 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97.0% 97,0%
Capacity Factor (%)(6)....... 4.0% 4.0% 4.0% 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%
Unit Starts per Year (7)..... 363 363 363 363 363 363 363 363 0
Energy Generation (MWh)...... 318,163 318,163 318,163 318,163 318,163 318,163 318,163 318,163 0
Net Plant Heat Rate
(Btu/kWh)(8)............... 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088 11,088
COMMODITY PRICES
General Inflation (%)(9)..... 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50 2.50
Electricity Prices (10)
Reservation Charges
($/kW-yr)................ $ 60.67 60.86 62.71 65.29 67.01 69.03 70.57 71.55 72.00
Unit Start Up Rates
($/Start)................ $ 20,463 21,077 21,709 22,361 23,032 23,723 24,434 25,167 25,922
Energy Charges ($/MWh)..... $ 0.41 0.43 0.45 0.47 0.49 0.51 0.53 0.56 0.56
OPERATING REVENUES ($000)
Reservation Payments......... $ 55,088 55,261 56,941 59,283 60,845 62,679 64,078 64,967 5,448
Unit Startup Charges......... $ 6,939 7,147 7,362 7,582 7,810 8,044 8,286 8,534 0
Energy Payments.............. $ 130 137 143 150 156 162 169 178 0
Availability Incentive
Adjustment (11)............ $ 150 150 150 150 150 150 150 150 12
Summer Availability
Adjustment (12)............ $ 0 0 0 0 0 0 0 0 0
Annual Availability
Adjustment (13)............ so 0 0 0 0 0 0 0 0
Efficiency Adjustment (14)... $ 0 0 0 0 0 0 0 0 0
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues..... $ 62,307 62,695 64,596 67,165 68,961 71,035 72,683 73,829 5,461
OPERATING EXPENSES ($000)(15)
Fuel......................... $ 0 0 0 0 0 0 0 0 0
Operations (16).............. $ 3,274 3,356 3,439 3,527 3,614 3,706 3,797 3,892 306
Capital Expenditures......... $ 88 90 93 95 97 100 102 105 9
Major Maintenance (17)....... $ 7,120 7,298 7,481 7,668 7,860 8,056 8,257 8,464 349
Operator Fee, Incentive and
Bonus (18)................. $ 603 620 638 656 674 694 713 734 63
Home Office Expenses (19).... $ 2,261 2,344 2,431 2,522 2,616 2,713 2,815 2,922 253
Insurance.................... $ 630 646 662 678 695 713 731 749 64
Property and Other Taxes..... $ 1,609 1,587 1,566 1,545 1,524 1,504 1,484 1,465 117
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses..... $ 15,585 15,941 16,310 16,691 17,080 17,486 17,899 18,331 1,161
NET OPERATING REVENUES
($000)....................... $ 46,722 46,754 48,286 50,473 51,881 53,550 54,783 55,498 4,299
ANNUAL DEBT SERVICE ($000)(20)
Bonds
Outstanding Balance........ $159,385 143,688 126,901 109,427 91,266 72,130 50,760 26,812 2,062
Annual Principal........... $ 15,698 16,786 17,474 18,161 19,135 21,370 23,948 24,750 2,063
Annual Interest............ $ 14,782 13,258 11,647 9,971 8,229 6,379 4,267 1,959 98
Letter of Credit Fees........ $ 964 964 962 951 942 946 952 934 77
-------- ------- ------- ------- ------- ------- ------- ------- -------
Total Debt Service........... $ 31,444 31,009 30,083 29,084 28,307 28,695 29,167 27,643 2,237
TRANSFERS FROM DSRF............ $ 0 0 0 0 0 0 0 0 0
ANNUAL DEBT SERVICE COVERAGE... 1.49 1.51 1.61 1.74 1.83 1.87 1.88 2.01 1.92
AVERAGE DEBT COVERAGE (21)..... 1.50
DEBT SERVICE RESERVE ACCOUNT
LOC (22)..................... $ 15,964 15,736 15,252 14,734 14,332 14,533 14,778 13,989 1,132
WORKING CAPITAL LOC (23)....... $ 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
</TABLE>
B-71
<PAGE>
FOOTNOTES TO EXHIBIT B-8
The footnotes to Exhibit B-8 are the same as the footnotes for Exhibit B-1,
except:
6. The annual capacity factors are assumed to be twice those assumed in the
Base Case.
7. The projected number of Unit Starts each Contract Year are assumed to be
twice those assumed in the Base Case.
B-72
<PAGE>
APPENDIX C
SOUTHEAST U.S. POWER MARKET ANALYSIS
NOVEMBER 3, 1999
PREPARED BY:
Resource Data International, Inc.
1320 Pearl St., Suite 300
Boulder, CO 80302
(303) 444-7788
PREPARED FOR:
Tenaska Georgia Partners, L.P.
1044 N. 115th Street
Omaha, NE 68154-4446
<PAGE>
TABLE OF CONTENTS
<TABLE>
<S> <C>
Executive Summary........................................... 1
Summary of Findings....................................... 1
Introduction................................................ 4
Overview Of Study Methodology............................. 4
Report Outline............................................ 4
Methodology Overview........................................ 5
Energy Market Model....................................... 6
Capacity Price Model...................................... 7
Base Case Assumptions....................................... 9
Existing Supply........................................... 9
New Generation............................................ 13
Cost of New Generation Technologies....................... 15
Nuclear Generating Assumptions............................ 16
Demand Assumptions........................................ 17
Industry Restructuring in Georgia......................... 18
Inflation Assumptions..................................... 19
Transmission Capacity and Pricing......................... 19
Coal Price Forecast....................................... 19
Regional Ozone Transport Rule............................. 21
Gas Price Forecast........................................ 22
Electricity Price Escalation Rates Beyond 2020............ 24
Base Case Price Forecast.................................... 26
Comparison to Current Market Prices....................... 27
Energy Price Forecast..................................... 29
Capacity Price Forecast................................... 30
Tenaska Georgia Partners Operations....................... 32
Sensitivity Analysis........................................ 35
Energy Prices............................................. 37
Capacity Prices........................................... 40
Capacity Factors.......................................... 44
Appendix A: Gas Market Issues in the Southeast Region....... 46
Gas Supply................................................ 46
Gas Transportation........................................ 46
</TABLE>
i
<PAGE>
<TABLE>
<S> <C>
Gas Demand................................................ 47
Appendix B: Nuclear License Expiration Dates in Serc........ 49
Appendix C: Detailed Monthly Capacity Factors--Base Case.... 50
Appendix D: Hourly Profit Analysis.......................... 51
Appendix E: Fuel Switching Analysis......................... 52
Appendix F: High Start-up Cost Scenario..................... 54
Scenario Results.......................................... 54
Appendix G: Low Load Scenario............................... 58
Scenario Results.......................................... 58
Appendix H: Regional Ozone Transport Rule................... 63
</TABLE>
ii
<PAGE>
EXECUTIVE SUMMARY
Resource Data International, Inc. (RDI) has prepared this independent
assessment of the Southeast United States electricity market (covering the
states of Georgia, Florida, the Carolinas, Alabama, Tennessee, Mississippi,
Louisiana, Kentucky, and Virginia) and the economic competitiveness of the
Tenaska Georgia Power Project (Project or Tenaska Georgia Partners Project)
under development by Tenaska Georgia Partners, L.P. The market study provides an
assessment of the long-term market opportunities, including capacity and energy
prices expected to be received by generators in the region for the period 2000
through 2030.
PECO Energy has signed a purchase power agreement (PPA) with Tenaska Georgia
Partners to sell the output from this Project. Although the majority of this
report includes an analysis of power markets in the southeastern United States,
RDI's analysis was performed primarily to develop an economic dispatch profile
for the Project as well as to analyze the attractiveness of the PPA to PECO
Energy.
This report includes a prediction of market clearing prices and dispatch
profiles for the Project under the "Base" scenario and alternative scenarios.
The report also describes the key assumptions and the methodology used in
developing this assessment. Finally, the report addresses the attractiveness of
the project to both Tenaska and PECO Energy.
The base analytical tools utilized for this study were the Inter-Regional
Electric Market Model (IREMM) and an integrated capacity price model. IREMM is a
sophisticated production simulation model that simulates the Eastern
Interconnection bulk power supply system on an hourly basis for each year within
the time horizon of the forecast. The capacity price model is integrated with
IREMM and calculates the additional revenue required for maintenance of adequate
capacity reserves. Using these models, RDI forecasts the energy and capacity
price, and unit dispatch for the Project.
SUMMARY OF FINDINGS
The following represents the conclusions and key findings of RDI's
assessment of this project:
i. The Project represents a low cost, highly competitive and much needed
peaking resource for the growing Southeastern power market. The total
capacity of the project is equal to only one percent of the capacity
required in the Southeastern power market by the year 2020.
ii. The Project has many strong competitive advantages such as:
a. Direct access to additional power markets beyond Georgia via relatively
strong transmission links into the TVA, Virginia/Carolina, and Southwest
Power Pool markets.
b. State of the art generation technology which is ideal for serving peak
electricity loads.
c. Ready access to competitively priced gas supply from a diversified range
of sources through an extensive interstate gas pipeline transmission
system.
iii. As noted above, PECO Energy (PECO) has entered into a long term mutually
acceptably priced Power Purchase Agreement (PPA) with the Project. PECO is
very active in U.S. wholesale power markets nationally and also in the
Southeast U.S.
a. Due to recent price spikes and the curtailment of firm contract
deliveries, control or ownership of a physical asset in the Southeast has
become a source of strategic advantage to marketers such as PECO. Such an
asset allows the marketer to ensure delivery of firm power. This provides
both an advantage in marketing the power (as the purchaser is less likely
to enter into a contract with a seller that does not have control of
physical assets) and in avoiding liquidated damage payments in the event
of a transmission curtailment or other loss of power supplies.
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<PAGE>
b. The optionality embedded in peaking power plants plays an integral role
in the portfolio of power marketers like PECO.
iv. It is expected that PECO will operate the project only during summer peak
hours when electricity prices are highest. It is expected that the project
will achieve monthly summer capacity factors of 7 to 18%, averaging
approximately 4% on an annual basis during the 20 year forecast period.
Based on RDI's assumptions regarding price and electricity demand growth for
the period 2020-2030, RDI expects that the project's utilization will
continue to trend down slightly throughout that period.
v. The technical capability of the Project to start up and shut down quickly
should allow PECO to select operating hours in which revenues and
profitability can be maximized.
vi. The cost of capacity and energy to PECO Energy under the PPA remains below
the market price forecast under both RDI's base and downside cases,
confirming the economic attractiveness of the PPA to PECO.
C-2
<PAGE>
INTRODUCTION
Resource Data International, Inc. (RDI) has prepared this independent
assessment of the Southeast United States electricity market (covering the
states of Georgia, Florida, the Carolinas, Alabama, Tennessee, Mississippi,
Louisiana, Kentucky, and Virginia) and the economic competitiveness of the
Tenaska Georgia Power Project (Project or Tenaska Georgia Partners Project)
under development by Tenaska Georgia Partners, L.P. The market study provides an
assessment of the long-term market opportunities, including capacity and energy
prices expected to be received by generators in the region for the period 2000
through 2030.
PECO Energy has signed a purchase power agreement (PPA) with Tenaska Georgia
Partners to sell the output from this Project. RDI's market analysis was
performed primarily to develop an economic dispatch profile for the Project as
well as to analyze the attractiveness of the power purchase contract to PECO
Energy.
OVERVIEW OF STUDY METHODOLOGY
The base analytical tools utilized for this study were the Inter-Regional
Electric Market Model (IREMM) and an integrated capacity price model. IREMM is a
sophisticated production simulation model that simulates the Eastern
Interconnection bulk power supply system on an hourly basis for each year within
the time horizon of the forecast. The capacity price model is integrated with
IREMM and calculates the additional revenue required for maintenance of adequate
capacity reserves. Using these models, Resource Data International (RDI)
forecasts the economy energy price, unit dispatch, and capacity price for the
southeastern United States (U.S.). A forecast was developed for multiple
scenarios in order to understand market dynamics and project risks.
REPORT OUTLINE
This study is organized into several sections. The previous section
summarizes the study's key findings. The next section describes the methodology
and models used for the study. The fourth section describes the base case
assumptions. The fifth section describes the base case results. The sixth and
final section provides an analysis of the results from alternative scenarios.
Supporting analyses and additional sensitivities are provided in several
Appendices.
METHODOLOGY OVERVIEW
In general, there are three different pricing models that are prominently
used to describe competitive wholesale markets. These models are as follows:
- RESERVE REQUIREMENT MODEL: In this model, a reserve requirement is imposed
on each load serving entity (LSE) in proportion to its load. To meet this
requirement, the load serving entity must enter into contracts with
generators or procure its obligation through a "capacity exchange" that is
operated by a central clearing house, such as an Independent System
Operator (ISO). In such a model, a generator will receive two separate
payment streams. The first stream is an energy price that is determined by
the hourly interaction of supply and demand in the spot market. The second
stream is the capacity price that is determined by the separately run
capacity auction. This stream could be determined on a monthly, seasonal,
or annual basis. Such a market is currently operating in the
Pennsylvania-New Jersey-Maryland Interconnection (PJM), the New York Power
Pool (NYPP), and the New England Power Pool (NEPOOL).
- EXPLICIT CAPACITY ADDER MODEL: This model is similar to the reserve
requirement model in that market rules dictate that capacity will be
priced separately. One difference between these models is that, in an
explicit capacity adder model, retail suppliers do not have an obligation
to secure capacity. Also, the "capacity premium" is calculated on an
hourly basis rather than on a monthly
C-3
<PAGE>
or annual basis. The explicit capacity adder model is currently employed
in the United Kingdom (U.K.) electricity market. In this model, all
generators submit bids to a central clearing exchange, specifying how much
power they are willing to commit at a given price during the next
24 hours. Generators have the potential to earn revenues from two
different payment streams. The first payment stream is received for actual
kilowatt-hour sales into a central power exchange (or spot market). This
price is determined by the bid of the highest cost unit selected to supply
power during each hour. This price is commonly referred to as the system
marginal price. The second payment stream is commonly referred to as the
capacity payment. This additional payment is equal to the value of lost
load multiplied by the loss of load probability. It is paid to all
generators available during the hour. The value of lost load is determined
administratively by the central pool. The loss of load probability is a
function of the forecast demand and the amount of generation available to
meet that demand.
- ENERGY ONLY MODEL: In this model, the hourly price of electricity is
determined purely through the interaction of supply and demand without the
interference of administratively determined installed reserve requirements
or a separate capacity payment. In the other two model structures, the
hourly price in the spot market is always set by the highest cost unit (on
a variable cost basis) dispatched to meet demand (assuming no participant
can exert market power). The key distinction of the energy only model is
that during some peak hours of demand, the price would instead be set by
the marginal cost of an outage to customers. If regulators could estimate
precisely the value of lost load on an hourly basis and customers could
curtail demand, the energy only model market would result in pricing that
is very similar to the explicit capacity adder model. Moreover, if a
regulator precisely predicted the reserve requirement found in the energy
only model, the reserve requirement and energy only models would achieve
similar annual prices for electricity.
In theory, each of these model structures result in similar prices on an
annual basis. Also, a mix of these market structures can exist. For instance, in
an energy only market bilateral transactions will exist between generators and
marketers where capacity and energy may be priced separately.
ENERGY MARKET MODEL
RDI employs an analytical approach that is based on the reserve requirement
model. First, RDI simulates the interaction of the energy market using IREMM.
This model performs many of the functions typically associated with electric
power production simulation programs such as marginal cost dispatching and
maintenance scheduling.
IREMM's methodology relies on the following concepts:
INCREMENTAL PRODUCTION COST The incremental cost of production is the cost
of producing an additional MWh of energy. To minimize costs, an efficient
dispatch center will dispatch its lowest cost generating units first. In the
bulk power market, a profit-maximizing company will produce energy as long as
its incremental cost of production is less than the additional revenue obtained
from the sale of that energy. Thus, if it can sell energy externally for more
than its incremental cost of production, the company will continue to produce
after its own load has been met. On the other hand, if the company can buy the
energy it needs to meet its load for less than the cost of its own generation,
the company will maximize profit by making the purchase.
LIMITS OF MARKET POWER To the extent that the selling company believes it
has market power, it may elect to withhold surplus power from the market until
the purchase price is maximized. In such a situation, the seller would receive a
higher price, but may sell less energy. Thus, the seller faces the risk that
profits may not be maximized. If a seller with perceived market power withholds
energy to wait for a higher price, it will lose potential customers if, in the
meantime, customers successfully find lower prices from alternative suppliers.
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<PAGE>
SUPPLY AND DEMAND Initially, units are dispatched to meet each individual
company's internal load. Once these loads are served with their available
resources, the quantities of surplus energy available for sale and the
quantities of displaceable energy can be calculated at various price levels.
From these prices and quantities, IREMM develops supply and demand curves for
each company. Energy supply and demand are balanced on an hourly basis.
MARKET CLEARING PRICES The basic premise of IREMM is that market forces
exist and determine prevailing bulk power prices. Together with the cost of
transmitting energy between any two companies, the interactions of the supply
and demand functions determine the market clearing prices. These market prices
represent a spatial equilibrium where supply and demand are satisfied
simultaneously. Market clearing prices emerge as each system attempts to
maximize its "gains," defined as the sum of profits on sales and savings on
purchases.
Important outputs from the IREMM model that are used in this analysis
include:
- Hourly energy market prices for the Southern Company region, where Tenaska
Georgia Partner's proposed project will be located,
- Unit specific capacity factors for Tenaska Georgia Partner's project,
- Calculations of reserve margins for the Southeast Electric Reliability
Council (SERC), and
- Calculations of the amount of new capacity added to the grid in each year
in SERC.
CAPACITY PRICE MODEL
During the next step of the modeling process, RDI incorporates the results
from IREMM into a capacity price-forecasting model. The resulting capacity price
is calculated as: the amount of additional revenue required to keep enough
generation available to meet demand plus the reserve requirement. Each power
plant in a region is ranked according to the plant's operating profit--taking
into account only spot market revenues and variable operating costs. Consider a
hypothetical low cost coal plant. Such a plant is likely to achieve a
contribution margin as high as $50 per kW-yr (energy market revenues less
variable fuel and O&M). Accordingly, this plant covers its cash operating costs
from energy market revenues alone. Assuming perfect competitive conditions, its
bid into the capacity market will be close to zero.
Next, consider a combustion turbine. This plant will achieve only a small
contribution margin in the energy market since it only runs economically a few
hours of the year because of its higher operating cost. When it does run, it is
normally the price setting unit, receiving only its short-run marginal costs.
Therefore, it must recover the rest of its cash costs from the capacity market
if it is going to continue to be financially viable. It is this break-even
figure that determines the bid price of each generator in the capacity market.
The capacity price model makes two additional calculations. First, the model
calculates the break-even costs (including annualized investment costs and
return on equity) for new generating technologies. If the break even price for a
new plant is lower than the market clearing price of capacity, then the model
adds new capacity to the grid and the energy market model is run again. The type
of capacity added in each year is determined by the overall profitability of
competing generation technologies. Second, the model determines which plants
cannot recover their cash costs from the market. Typically, these plants are
retired.
Any new retirements or capacity additions resulting from the capacity price
model are put back into the IREMM model, and the model is re-run. This process
is continued until a converged solution is reached.
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<PAGE>
The IREMM and capacity price model are used in this study to analyze the
period from 2000 to 2020. Beyond 2020, escalation rates were developed to
forecast electricity prices through 2030. The assumptions driving the escalation
rates are described below in the Assumptions section of the report.
To summarize, the overall modeling approach accounts for the factors that
affect all markets: supply, demand, transport capability, and ownership
concentration. Ultimately, the model ensures that prices reach a level that
enables all generators within the required reserve margin to recover their cash
operating costs(1). New capacity is built only if and when it is profitable to
do so. Selecting the mix of capacity additions that result in the lowest overall
prices while still maintaining generator profitability minimizes overall costs.
------------------------
(1) After a power plant is built, cash operating costs include fuel, operation
and maintenance expenses, and capital replacement costs that are required to
keep the plant operating and available. Before a power plant is built, cash
costs include these costs as well as investment costs and a return on
capital.
C-6
<PAGE>
BASE CASE ASSUMPTIONS
This section provides a detailed accounting of the factors driving the base
case forecast.
For this analysis, RDI modeled the entire Eastern Interconnection. This
report, however, focuses primarily on the SERC which includes states located in
the southeast United States.
EXISTING SUPPLY
The supply curves constructed by RDI for this analysis were built on a unit
by unit basis. The unit data used are based on the annual EIA-411 reports
supplied to the Department of Energy via the regional councils of the North
American Electric Reliability Council (NERC), and from RDI's proprietary
databases. RDI also verified the EIA-411 report by utilizing integrated resource
plans and RDI's internal databases. Key assumptions relating to generating units
were as follows:
- UNIT RATINGS The EIA-411 report was used to determine the summer and
winter capacity ratings of each unit on the grid.
- PRIMARY AND ALTERNATE FUEL TYPES For non-coal burning plants, RDI
determined each type of fuel that can be used at a generating unit from
EIA-411 reports. Each month the relative price of alternate fuels is
compared to the primary fuel and the least expensive fuel is selected.
Coal fired plants are treated separately and are discussed later in the
report.
- AVAILABILITY The availability statistics for all non-nuclear units were
obtained from aggregate NERC/GADS statistics by prime mover type. The
equivalent availability factor (EAF)(2) and the equivalent forced outage
rate(3) (EFOR) were used to calculate the scheduled outage factor (SOF) to
determine the maintenance period for each unit. Average 1996 availability
factors and forced outage rates are shown in Table 1. Availability
statistics for nuclear units are based on an engineering and statistical
analysis performed by RDI.
TABLE 1: 1998 AVERAGE AVAILABILITY STATISTICS
<TABLE>
<CAPTION>
EAF EFOR
-------- --------
<S> <C> <C>
STEAM TURBINES.............................................. 82% 7.0%
GAS TURBINES................................................ 83% 4.9%
</TABLE>
- HEAT RATES Heat rate information was obtained from RDI's POWERdat
information system, based on a combination of EIA-411 and EIA-860
information.
- NON-FUEL VARIABLE O&M: Variable O&M costs affect the dispatch price of
individual units. Variable O&M calculations vary across utilities. It is
RDI's opinion that this variation occurs primarily because utilities have
never had profit incentives that motivate them to fully understand their
cost structure. A few utilities do not include a variable O&M adder in
dispatch decisions. One RDI client assumes that 20% of its total non-fuel
O&M is variable. Another client uses a variable O&M of $1 per MWh at one
coal-fired power plant and $2 per MWh at another coal fired power plant
because the second plant must pay the local water utility for its water
supplies. This same client dispatches its gas turbine assuming a variable
O&M of $3 per MWh. For this analysis, RDI assumes a variable O&M of $1.2
per MWh for all steam turbines(4) and $10 per MWh for all gas turbines.
This assumption is discussed in greater detail in the new technologies
section of the report. The higher O&M cost for a gas turbine is intended
to reflect
------------------------
(2) EAF is the percentage of hours in the year that a unit is available to
operate.
(3) EFOR is the percentage of hours in the year in which a plant will incur an
unplanned outage.
(4) This estimate is based upon analysis performed by an engineering
consulting firm in a previous RDI project.
C-7
<PAGE>
the additional start-up costs such units typically incur. Units with
scrubbers are assigned an additional $1 per MWh charge based on
information reported in the EIA-767 form by utilities.
- FIXED O&M: Fixed O&M calculations for individual plants were based on data
filed with the Energy Information Administration. For each plant and prime
mover type, the fixed O&M was calculated as follows:
Fixed O&M = Total Non-Fuel O&M less (Assumed Variable O&M
($/MWh) X Generation (MWh))
If power plant rents were greater than 20% of total non-fuel O&M, then
power plant rents were subtracted from total non-fuel O&M for purposes of
calculating fixed O&M. In many instances, sale-leaseback expenses are
reported as an operating cost associated with the plant. Because these
expenses would have to be paid whether or not the plant is shutdown, it is
not appropriate to consider these expenses when analyzing a plant's cash
costs. Also, since there can be significant year to year swings in O&M
expenses due to major overhauls or other major non-recurring costs, RDI
averaged fixed O&M expenses from 1995 through 1997.
The above approach was used to estimate fixed O&M expenses for all utility
owned generation. However, actual power plant O&M cost information is not
publicly available for non-utility owned plants. For non-utility coal
units, it is assumed that fixed O&M expenses equal $15 per kW. Based on
previous work for independent power companies, RDI believes this is a
reasonable assumption. For NUG units that have contracts guaranteeing a
fixed price for their output, it was not necessary to make any assumptions
regarding fixed O&M.
- REPLACEMENT CAPITAL COSTS: Since generating assets are assumed to maintain
operations over the forecast horizon (unless it is uneconomic to do so),
it is also assumed that replacement capital would have to be invested to
keep the plant in service. It is also necessary to include replacement
capital costs in the model because many utilities account for operating
expenses as capital expenses to increase their ratebase. The cost of
replacement capital in this analysis is based on the historic information
and trends shown in Figure 1. It is largely consistent with replacement
cost information presented in numerous utility Integrated Resource Plans
as well.
FIGURE 1: UTILITY ANNUAL CAPITAL ADDITIONS ($/KW-YR)
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
COST OF CAPITAL ADDITIONS
<S> <C> <C> <C> <C>
STEAM NUCLEAR HYDRO OTHER
1988 6.5 10.75 3
1989 7 36.5 8.75 2
1990 7.5 35 9 3
1991 9 28.5 9 7
1992 9.5 25 10 4.5
1993 10 25.5 9.5 4.5
1994 15 22.5 9.5 3.5
1995 10 20 8 8
</TABLE>
C-8
<PAGE>
OVERVIEW OF SOUTHEAST Supply The southeast U.S. is one of the fastest
growing electricity markets in the country. Electric power supply in the region
is dominated by five utilities (see Figure 2). Together these five utilities
account for 77% of the 150,000 MW in this market. Within the Southeast ownership
is even more concentrated. In Alabama and Georgia, two companies control 75% of
the generating assets.
FIGURE 2: SOUTHEAST MARKET SHARE (% OF TOTAL CAPACITY)
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
SOUC 20%
<S> <C>
TVA 20%
ENTR 20%
DUPC 12%
DOMRES 10%
CPLC 7%
OTHER 16%
</TABLE>
In 1997, 55.8% of the electricity in the region was generated by coal
plants, 32.6% by nuclear plants, and 4.9% by hydro plants. The remaining 6.8%
was generated with gas or oil. Less than 4% of the electricity in the region is
supplied by non-utility generators. Most of the non-utility capacity is
concentrated in the Carolinas and Virginia and supplies power under long-term
contracts that do not expire until after 2005.
Currently the southeast U.S. is dominated by baseload capacity with nuclear
and coal supplying the majority of the electricity in the region. Unlike many
other regions of the country, the performance of nuclear plants has been well
above industry norms, typically achieving capacity factors higher than 85%. RDI
considers it unlikely that any nuclear plants in this region will be retired
before their licenses expire. It is important to note that much of the excess
coal-fired capacity in the region has also been diminished by load growth. Over
the past five years, coal-fired capacity factors have increased from 60% to
almost 70%. At this capacity factor level, most excess coal-fired capacity
exists only during the off-peak hours.
C-9
<PAGE>
FIGURE 3: SERC CAPACITY FACTORS
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
CAPACITY FACTORS PRIMARY FUEL
<S> <C> <C> <C> <C>
COAL OIL-L/GAS URAN WATER
1994 59.09 20.14 82.83 24.52
1995 62.29 22.73 87.51 20.01
1996 63.41 17.34 87.41 21.88
1997 65.88 16.03 87.33 20.92
1998 67.76 18.50 92.23 23.01
</TABLE>
NEW GENERATION
Except for those announced merchant plant or utility projects that RDI
considers likely to be seen to completion, future capacity additions are added
only as they are economically justified. RDI considers a project likely to be
seen to completion if it has signed a purchase power agreement for its output,
if construction has already begun, or if it has secured financing. There are
also a few projects that RDI considers likely due to knowledge obtained from
sources close to the development process.
There is currently a substantial amount of building activity among competing
suppliers in the Southeast. Table 2 shows RDI's base case forecast of merchant
plant additions.
Enron Capital & Trade Resources (Enron) is developing three projects in
Mississippi. In New Albany (Union County) Enron is building a 390 MW combustion
turbine plant consisting of six 65 MW turbines. The New Albany plant will be
ready for the 1999 summer peaking season. In Caledonia (Lowndes County), just
north of Columbus, Enron will bring a 475 MW combustion turbine plant online in
June 1999 as well(5). In Fulton (Itawamba County) a 260 MW combustion turbine
unit is schedule to come online in the summer of 2000. In Tennessee Enron is
pursuing a plant near Brownsville (Haywood County). This 475 MW unit will be
ready in June of 2000. These projects will most likely be used to meet Enron's
supply obligations with the Tennessee Valley Authority.
Alabama Power is constructing a cogeneration facility in Theodore (Mobile
County), Alabama. The plant will supply 207 MW of electricity to meet Alabama's
reserve margin requirements and steam to Degussa Corp. and Phenolchemie. The
Theodore cogeneration plant will begin operation in June of 2001. In Rockingham
County, North Carolina, Dynegy Power is developing an 800 MW combustion turbine
plant which has a start-up date of June 2000. The Southeastern Electric
Development Company
------------------------
(5) Enron's projects that were scheduled to begin operation in the summer of
1999 have actually begun operation. These facilities did not begin
operation until after the study had commenced.
C-10
<PAGE>
intends to construct a 100 MW combustion turbine in Lee County, Alabama, which
is expected to supply power by January 2001.
Sonat Energy Services and Calpine Corp. are developing a combustion turbine
project in Cataula (Harris County) north of Columbus, Georgia. This 680 MW unit
is expected to begin operation in June of 2000. In Thomaston (Upson County),
Georgia, Sonat Energy Services broke ground on March 25, 1999 for the
construction of a 680 MW combustion turbine plant consisting of four turbines.
The Thomaston plant will be operational in June of 2000, when the sales contract
with Georgia Power goes into effect.
Outside of SERC, in the SPP region, we have included two new plants. The
first is a combined cycle power plant developed by LS Power in Batesville
(Panola County), Mississippi. This 837 MW plant will start up in January of
2000. Also in Mississippi is the "Red Hills" steam plant project, which
Tractabel Power is developing near Chester (Choctaw county) and which is
expected to be producing electricity in December 2000. This coal-fired plant has
a purchase power agreement with the Tennessee Valley Authority
Two power projects pursued by Carolina Power and Light (CP&L) in North
Carolina, one near Cleveland (Rowan county) and another in Hamlet (Richmond
county) were not considered in the base case since the go-or-no-go decision for
these plants will not be made until the fall of 1999 according to a spokesperson
for CP&L.
TABLE 2: ASSUMED MERCHANT PLANT ADDITIONS IN SERC
<TABLE>
<CAPTION>
SIZE AND ON-LINE
NAME DEVELOPER TECHNOLOGY DATE
---- ----------------------------------- ------------- --------
<S> <C> <C> <C>
New Albany, MS.................... Enron Capital & Trade Resources 390 MW CT Jun-99
Caledonia, MS..................... Enron Capital & Trade Resources 475 MW CT Jun-99
Fulton, MS........................ Enron Capital & Trade Resouces 260 MW CT Jun-00
Brownsville, TN................... Enron Capital & Trade Resources 475 MW CT Jun-00
Theodore, AL...................... Alabama Power 207 MW CG Jun-01
Rockingham, NC.................... Dynegy Power 800 MW CT Jun-01
Lee County, AL.................... Southeast Elec Dev 100 MW CT Jun-01
Cataula, GA....................... Sonat Energy Services/Calpine Corp. 680 MW CT Jun-01
Thomaston, GA..................... Sonat Energy Services 680 MW CT Jun-00
----------------------------------- ----------- ------
Total Capacity.................... 4,067 MW
</TABLE>
C-11
<PAGE>
The projects listed in Table 2 represent the projects that at the time this
report commenced were deemed most likely to be brought on-line by RDI(6). RDI's
base case forecast presented in this report projects that 80,700 MW of new
capacity will be needed in the region over the forecast horizon. To the extent
that any one of the projects listed in Table 2 is not brought on-line as
anticipated, the need for capacity in the region will likely be filled by
another project.
COST OF NEW GENERATION TECHNOLOGIES
The cost of new generation technologies has been determined through RDI's
work with other developers and a review of publicly available documents. These
assumptions are shown in Table 3. In an effort to decrease heat rates and
increase efficiency, combustion turbine (CT) technology has made substantial
technological progress in the last five years. Improvements in performance have
come at the price of higher O&M costs due to technical problems with the new
technology. The industry is currently in a consolidation phase, in which these
technologies will likely mature. Since turbine technology is already highly
sophisticated, RDI does not expect major improvements in heat rates or
efficiencies in the future. Our base case assumption is that the heat rates of
turbines will improve by 5% by 2010. The most substantial technological
improvements in the economics of CT's will most likely result from lower fixed
and variable O&M costs due to better materials and design. The reduction of
start-up costs is one possible area for improvements. However, existing units
will also likely benefit from the same improvements when these units are
upgraded with new technology during scheduled overhauls of the turbines.
The variable O&M for combustion turbines is based upon a combination of
information supplied by Tenaska Georgia Partners and RDI analysis. Tenaska
Georgia Partner's indicated that their start-up cost will be approximately
$10,000 per start-up. RDI's analysis (described later in the report) indicates
that the plant will operate at full output levels for an average of
approximately 6.5 hours during each start-up. Spreading the start-up costs
across the average output during each start-up results in an average cost of
approximately $10 per MWh.
TABLE 3: COST OF NEW TECHNOLOGIES
<TABLE>
<CAPTION>
COMBINED CYCLE COMBUSTION TURBINE COAL PLANT
--------------- ------------------ ----------
<S> <C> <C> <C>
Construction Period......................... 2 Years 1 Years 3 Years
Initial capital costs ($/KW)................ 525 325 900
Variable O&M ($/MWH)........................ 1.5 10* 1.5
Fixed O&M ($/KW-YR)......................... 15 5 20
Availability factor......................... 92% 95% 88%
Heat rate................................... 6,900 10,900 9,000
</TABLE>
------------------------
* Variable O&M for combustion turbines consists primarily of start-up costs.
Other financial assumptions are as follows:
Debt Financing: 60%
Cost of Debt: 8%
Cost of Equity: 15%
Marginal Income Tax Rate: 37%
Depreciation Schedule: MACRS
------------------------
(6) Since commencement of the report, Sonat has abandoned the development of
its Cataula project.
C-12
<PAGE>
NUCLEAR GENERATING ASSUMPTIONS
Beginning in the year 2010, operating licenses for nuclear plants in the
U.S. will expire. The Nuclear Regulatory Commission (NRC) will have to consider
whether or not to extend any of the 40-year operating licenses of the reactors.
Baltimore Gas and Electric (BG&E) is the first nuclear operator to pursue a
license extension for its Calvert Cliffs nuclear station and the re-licensing
process is being carefully watched by other nuclear operators. It is estimated
that for as little as $10-50 per kW a nuclear plant can be upgraded to operate
20 years beyond its current 40-year licensing period. The construction of other
baseload capacity could not even be conceived at this price. Because of these
economics and possible political decisions related to the Kyoto Protocol(7),
there will be substantial pressure on the NRC to re-license nuclear plants in
the coming years.
Figure 4 shows the decline of total nuclear generating capacity in SERC, if
all nuclear plants in the area were to retire at the end of their license
periods. If all plants closed at the end of their license periods, from 2010
through 2030 an average of 1,200 MW per year of base load capacity would have to
be replaced by other generating facilities. However, three of the nuclear
operators in SERC are already considering applying for an extension of their
operating licenses. Southern Nuclear Operating Corp. is aggressively pursuing
the renewal of its operating licenses for Hatch units 1 and 2. Duke Energy is
considering extending the life of its three Oconee units, whose operating
licenses will expire in 2013 and 2014. And finally, Virginia Power is
considering the same step for its two reactors in Surry, where operating
licenses expire in 2012 and 2013, as well for its North Anna stations, where the
licenses are now scheduled to run out in 2018 and 2020. If these operators are
successful in their efforts, then 7,550 MW or 30% of the region's nuclear
(baseload) generating capacity would remain in service over the forecast
horizon. A list of all regional nuclear units and their license expirations is
included in Appendix B.
For the base case scenario, RDI assumes that none of the 26 GW of nuclear
capacity in SERC will retire during the forecast horizon (through 2020). Because
of the enormous financial upside of keeping a nuclear plant running, RDI expects
that all nuclear operators in SERC will follow the example of Southern, Duke,
and Virginia Power and will file for an extension of their operating licenses.
RDI expects that the NRC will grant operating life extensions for all plants
except for nuclear units which have had serious problems. None of these
"problem" plants are located in SERC.
------------------------
(7) The Kyoto Protocol, if implemented in its current form, would require the
U.S. to significantly reduce its carbon dioxide emissions. Nuclear
generation technologies are one of the few electric generation technologies
that emit no carbon dioxide.
C-13
<PAGE>
FIGURE 4: TOTAL NUCLEAR GENERATING CAPACITY IN SERC IF UNITS RETIRE WHEN
THEIR LICENSES EXPIRE
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
2008 25.78
<S> <C>
2009 25.78
2010 25.10
2011 25.10
2012 24.29
2013 21.80
2014 18.22
2015 18.22
2016 16.29
2017 15.46
2018 13.76
2019 13.76
2020 11.74
2021 8.64
2022 7.70
2023 6.57
2024 5.44
2025 5.44
2026 3.45
2027 2.29
2028 2.29
2029 1.12
2030 1.12
2031 1.12
2032 1.12
2033 1.12
2034 1.12
2035 -
2036 -
</TABLE>
DEMAND ASSUMPTIONS
The load growth scenario for this study was developed from RDI's own demand
forecast and the FERC 714. The FERC 714 report contains hourly load information.
This information is utilized to simulate hourly chronological demand in IREMM.
Both population and economic growth set the stage for strong electric sales
growth in recent history. In the first half of the 1990s, actual electricity
sales increased at an average rate of 2.9% per year. Weather-normalized sales
growth is estimated at 3.25% annually.
RDI believes that a combination of both strong population and economic
growth will maintain a weather-normalized electricity growth rate of up to 2.25%
annually through 2005 (see Figure 5). After 2005, this growth rate slows
significantly, approaching 1.5% by 2009. Overall, electricity demand in the
region is expected to grow faster than the national average.
A small amount of the demand in each region represents interruptible demand.
RDI includes this demand in its forecast of peak demand. To model this demand,
RDI includes the interruptible demand as a peaking resource. That is, we
represent it as actual capacity with a very high marginal cost so that this
resource would be dispatched during the highest peak demand conditions.
C-14
<PAGE>
FIGURE 5: AVERAGE ANNUAL DEMAND GROWTH
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
TIME PERIOD AVERAGE ANNUAL GROWTH RATE
<S> <C>
1999-2005 2.3%
2005-2010 1.5%
2010-2015 2.0%
2015-2020 2.0%
</TABLE>
INDUSTRY RESTRUCTURING IN GEORGIA
Georgia is moving toward deregulation at a more conservative pace than other
states. Georgia is a member of the twenty-three-state coalition called the "Low
Cost Electricity States". In December of 1998, these states presented Congress
with an initiative requesting the ability to determine whether electricity
deregulation was appropriate on a state-by-state basis without a federal
mandate.
Pending any federal restructuring mandate, the Georgia Legislature passed an
initiative to study the impacts of competition in January 1998. The Georgia
Public Service Commission staff is conducting the study. Nevertheless, all
indications are that Georgia is still several years from independently
considering legislation that would open their electricity markets to direct
access.
INFLATION ASSUMPTIONS
It is anticipated that reduced government deficits and continued and
sustained low interest rates will be the primary precursors to continued low
inflation over the forecast horizon. RDI assumes that inflation will average
2.5% per year over the forecast horizon.
TRANSMISSION CAPACITY AND PRICING
The transmission system of Georgia has relatively strong transmission links
into the TVA, Virginia/ Carolina, and the Southwest Power Pool markets. This
provides the project with access to major electricity markets beyond Georgia.
Only one major transmission constraint affects the ability to market power from
a project in Georgia. This transmission constraint is the interconnection
between Georgia and Florida (3,600 MW of transfer capability).
Most other interconnections are very strong and do not frequently become
constrained. In fact, RDI analysis of historic daily electricity prices reveals
that the Entergy and Cinergy hubs are the two most closely correlated hubs in
the country. The correlation coefficient for these two hubs during the past year
was 94%.
C-15
<PAGE>
We also assume that transmission tariffs will be set at $2.50 per MWh for
non-firm transactions based on analysis of Open Access Same Time Information
System (OASIS) data.
COAL PRICE FORECAST
Coal and gas prices, in conjunction with capacity supply and demand
balances, are the driving factors that determine market clearing prices in
electricity markets. For this analysis, RDI developed plant specific coal price
forecasts. These forecasts reflect RDI's analysis of coal supply and demand,
Clean Air Act Compliance strategies, contract expiration dates, and the impact
of railroad mergers. Overall, RDI believes that the following factors will push
average coal prices lower (in 1999 dollars):
- Average coal mine productivity in the West will increase as longwall
mining technology is improved in Colorado and Utah, and as surface mining
operations in Wyoming install larger scale haulage, more efficient
overburden coal stripping equipment, and improved mine planning and
maintenance efficiency.
- Numerous coal contracts will expire or "rollover" during the next fifteen
years. As these contracts are replaced or renegotiated, coal consumers
will likely receive price reductions resulting from productivity
improvements and general oversupply conditions. New contracts being
entered into are of substantially shorter duration, almost always less
than five years. The elimination of long-term contracts will result in a
more volatile, commodity-like pricing environment where the primary factor
determining sales success is price.
- Premium quality, eastern low-sulfur coal will see supply constraints in
the forecast period due to reserve depletion and additional mining
regulations. However, declining demand for this product due to declining
export coal markets, and the continued encroachment of lower cost western
coals will prevent run-ups in the price of eastern coal.
- Restructuring of electricity markets will put increasing pressure on coal
suppliers to reduce contract prices and offer innovative pricing schemes.
Of all of the regions of the U.S., RDI expects that SERC coal-fired power
plants will experience the greatest nominal price growth in the country
(although prices will still decline in constant dollars). One factor
contributing to this price growth is the higher cost of low sulfur coals
required to meet Phase 2 emission standards. A second factor relates to the fact
that utilities in the Southeast must pay much higher coal transportation costs
than utilities in other regions of the country. Since transportation costs are
expected to escalate more rapidly than coal mining costs, plants with a large
transportation component in their delivered fuel costs will experience higher
price growth. Figure 6 shows RDI's average delivered coal price for select
markets that affect this analysis.
C-16
<PAGE>
FIGURE 6: FORECAST DELIVERED COAL PRICES (CONSTANT 1999 $/MMBTU)
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
FORECAST DELIVERED COAL PRICES (1999 $/MMBTU)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
AEP 1.16 1.16 1.16 1.16 1.16 1.12 1.08 1.08 1.06 1.05 1.04 1.03
APS 1.04 1.08 1.01 1.01 0.99 0.97 0.96 0.95 0.93 0.92 0.91 0.91
CAPCO 1.21 1.20 1.18 1.16 1.17 1.17 1.16 1.15 1.14 1.13 1.12 1.12
ECARSR 1.07 1.07 1.05 1.05 1.04 1.03 1.02 1.00 0.99 0.97 0.97 0.96
STHRN 1.18 1.16 1.15 1.14 1.13 1.12 1.11 1.11 1.10 1.09 1.09 1.08
TVA 0.98 0.97 0.96 0.95 0.95 0.94 0.93 0.92 0.91 0.90 0.90 0.89
VACAR 0.98 0.97 0.96 0.95 0.95 0.94 0.93 0.92 0.91 0.90 0.90 0.89
</TABLE>
SULFUR ALLOWANCE PRICES Another factor affecting coal plant variable costs
is the cost of sulfur allowances. In general, these costs do not have a
substantial impact on electricity prices. However, they do play a role in
determining individual plant dispatch. They also influence off-peak prices.
RDI's base case forecast is shown in Figure 7. At $100 per ton, the sulfur
allowance causes an increase of approximately $1 per MWh in dispatch prices,
depending upon the sulfur quality of the coal consumed at the plant. Over the
forecast horizon, we expect allowance prices to continue to increase in value.
This increase is driven primarily by Phase II compliance strategies, increased
coal generation due to general load growth, and increased coal generation caused
by the retirement of nuclear plants in some regions of the country.
After 2009 RDI projects a sharp increase in allowance prices. This increase
results from implementation of Phase III of the Clean Air Act Amendments. Phase
III of the Clean Air Act calls for substantial reductions of sulfur emissions,
driving up the price of an allowance.
C-17
<PAGE>
FIGURE 7: SULFUR ALLOWANCE FORECAST (1999 $)
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
SO2 ALLOWANCE PRICES IN 1999 DOLLARS
<S> <C>
NOMINAL 1999$
1999 193
2000 251
2001 226
2002 238
2003 245
2004 232
2005 234
2006 235
2007 248
2008 250
2009 252
2010 280
2011 283
2012 288
2013 288
2014 296
2015 296
</TABLE>
REGIONAL OZONE TRANSPORT RULE
The Environmental Protection Agency (EPA) is currently pursuing the
implementation of new environmental regulations that seek to reduce the
formation of ozone during the summer months. EPA originally proposed that these
rules would go into effect in May of 2003. However, the United States Court of
Appeals for the District of Columbia Circuit recently remanded the rules to
EPA(8). EPA has appealed this court decision. If EPA does not win its appeal,
there is a possibility that the implementation of these new regulations could be
delayed and that the rules themselves could also change. In this analysis, RDI
has assumed that these new rules will go into effect in May of 2003 as
originally proposed. With May 1, 2003 as the start date for compliance
regardless of court rulings related to specific rules, there is little to no
time for affected sources to await the outcome of pending litigation--orders for
emission control equipment must be placed soon. Many of RDI's own clients are
currently pursuing implementation plans assuming that they must comply by 2003.
A more detailed history and background on the regional ozone transport rules is
provided in Appendix H.
RDI assumed in this analysis that companies will install NO(x) control
equipment to reduce their emissions to levels that are consistent with the
predetermined state budgets described in Appendix H. In making these
assumptions, RDI ran an optimization model for each state that determines the
least cost control plan given all of the NO(x) reduction opportunities in the
state. Typically, these compliance options result in coal plants incurring
additional costs of $20 to $80 per kW in 2002 or 2003. Furthermore, the variable
operating costs of all plants that install additional control equipment were
escalated during the May to September time frame in each year after 2002 to
reflect the additional costs of operating the NO(x) reduction equipment.
Depending on the level of emissions reductions required at a plant, these costs
range from $1 to $2.50 per MWh.
------------------------
(8) American Trucking Association, Inc. et al, Petitioners vs. the United
States Environmental Protection Agency, Respondent, et. al., Intervenors,
United States Court of Appeals for the District of Columbia Circuit (No.
97-1440).
C-18
<PAGE>
It is important to note that RDI did not model the implications of a NO(x)
allowance trading scheme. If an allowance trading regime were implemented, it
would be advantageous to Tenaska Georgia Partner's project. Such a scheme would
tend to increase the marginal cost of coal-fired generation by $2 to $5 per MWh,
depending upon NO(x) allowance prices and the NO(x) emission rate of the coal
fired plant. Because it emits less NO(x) per megawatt hour of output, a new
combustion turbine would not face as steep an increase in marginal costs.
GAS PRICE FORECAST
In this section we present the key findings of RDI's gas price forecast for
the Southeast. A detailed discussion of the underlying assumptions can be found
in Appendix A.
- Table 4 shows RDI's base case gas price forecast. In general, Henry Hub
prices are expected to increase from $2.06 per mmBtu in 2000 to $2.18 per
mmBtu in 2004 in 1999 dollars. After 2004, prices stay relatively constant
until the 2007 to 2010 period when upward pressure on gas acquisition
costs and substantial new gas demand from combined-cycle power plants
throughout North America begin to force prices up at a rate of 2 to 3% per
year. The basis differential between the Georgia region and Henry Hub is
expected to increase from $0.19 per mmBtu in 2000 to $0.26 per mmBtu in
2010 as excess pipeline capacity becomes more fully utilized.
- Gas supply prices in the region are tied to the fortunes of producers in
the Gulf of Mexico. Recent forecasts show a wide range of variation in
expected supply from the gulf. RDI forecasts Gulf offshore supplies to
reach 7 trillion cubic feet (Tcf) by 2010, from current levels of
approximately 5 Tcf.
- Deregulation of the gas market has created a great deal of short-term
price volatility, but the 10 year trend at Henry Hub has remained within
the $1.50 to $2.50 per mmBtu price range. RDI does not expect the level of
volatility to diminish as short-term imbalances between gas supply and
demand will continue to occur. It is RDI's expectation that the long-term
supply price trend will not surpass $2.50 at Henry Hub during the forecast
horizon. Forecast gas prices are escalated at the rate of inflation after
2010.
- The price sensitivity of the electric generation and industrial sectors is
one factor that keeps a ceiling on the price of gas. As long as
alternative fuel options are available to these customers at a reasonable
cost fuel switching will put downward pressure on gas prices.
- This forecast reflects the fact that large gas transmission additions from
Canada will alter the dynamics of the U.S. market. The Alliance expansion
in late 2000 is expected to unlock low cost supplies from Alberta. This
will drive down delivered gas prices in the Midwest and push Gulf Coast
supplies back, decreasing basis differentials between Illinois and the
Gulf. The expansion of Maritimes & Northeast into the New England area
could put further downward pressure on gas prices. This phenomenon is
responsible for the Henry Hub forecast price of $2.06 per mmBtu in 2000.
- Regional pipeline expansions will also play a role in market pricing.
Additions from the Midwest to the Northeast are expected to cause slightly
lower utilization on Transcontinental Pipeline (Transco) flows into the
Northeast. Still, growing gas demand in the Southeast will keep pipe
utilization high in the winter months. RDI forecasts that current capacity
on Transco will be insufficient to meet seasonal load by 2006 at which
time additional expansion from Alabama to Georgia will be necessary.
However, Transco has already taken several steps to alleviate any
potential pipeline capacity shortages. First, Transco has pursued
development of a project referred to as Southcoast. This pipeline
expansion project, scheduled to be completed in 2001, would increase
pipeline capacity by 600 MMcfd in the Alabama and Georgia region. This
capacity expansion alone would create enough new pipeline capacity to
satisfy demand through
C-19
<PAGE>
the next decade. Another project, referred to as Cumberland, would
increase Transco's pipeline capacity by another 200 MMcfd in Northern
Georgia.
TABLE 4: NATURAL GAS PRICE FORECASTS, HENRY HUB AND SOUTHERN REGIONS
(1999 $)
<TABLE>
<CAPTION>
HENRY HENRY TO HENRY TO HENRY TO
YEAR HUB STHRN TVA VACAR STHRN TVA VACAR
---- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
2000.................................. $2.06 $2.25 $2.32 $2.39 $0.19 $0.26 $0.33
2001.................................. $2.15 $2.33 $2.39 $2.45 $0.18 $0.24 $0.30
2002.................................. $2.12 $2.31 $2.37 $2.43 $0.19 $0.25 $0.31
2003.................................. $2.16 $2.37 $2.44 $2.50 $0.21 $0.27 $0.34
2004.................................. $2.18 $2.41 $2.47 $2.52 $0.23 $0.29 $0.35
2005.................................. $2.19 $2.41 $2.48 $2.55 $0.22 $0.29 $0.36
2006.................................. $2.20 $2.44 $2.51 $2.57 $0.24 $0.31 $0.38
2007.................................. $2.26 $2.51 $2.58 $2.65 $0.24 $0.32 $0.39
2008.................................. $2.32 $2.58 $2.65 $2.72 $0.26 $0.33 $0.40
2009.................................. $2.35 $2.67 $2.71 $2.74 $0.33 $0.36 $0.40
2010.................................. $2.41 $2.66 $2.75 $2.83 $0.26 $0.34 $0.42
</TABLE>
Note: Except for the Henry Hub price forecast, prices reflect prices for gas
delivered to the burner-tip of the power plant. Prices after 2010 are escalated
at the rate of inflation.
ELECTRICITY PRICE ESCALATION RATES BEYOND 2020
After 2020, RDI applied escalation rates to projected prices through 2030.
It is RDI's opinion that the escalation rate on a long-term forecast should be
based on an analysis of the factors that drive the long run marginal cost. In
the case of electricity markets, the long run marginal cost is driven by fuel
costs, the conversion efficiency of a new plant, the capital cost of
constructing a new combined cycle facility, and the operating and maintenance
expense of a new plant.
FUEL COSTS In our analysis we have made the assumption that beyond 2010 gas
prices will escalate at the rate of inflation. We believe that this assumption
should also hold beyond the 2020 time frame. The fuel cost of a new combined
cycle facility is also influenced by the conversion efficiency of a plant,
typically referred to as the heat rate. Over the past decade turbine efficiency
has made dramatic improvements. For instance, according to data filed with the
Energy Information Administration, one plant that began operation in 1993
achieved a heat rate of 8,000 btu/kWh last year. Two plants that came on-line in
1996 and 1997 achieved heat rates of 7,100 btu/kWh--an improvement of 11%. This
analysis assumes that plants built in 2000 will have an average heat rate of
6,900. We further assume that by 2010 technological improvements will result in
heat rates that decrease to 6,300 btu/kWh.
Future improvements in heat rates beyond 6,300 btu/kWh are extremely
unlikely. An analysis conducted by P.J. Dechamps found that the theoretical
maximum efficiency that could ever be achieved by a combined cycle facility is
58.33%(9)--which translates into a heat rate of 5,850 btu/kWh. His analysis
assumed that such a plant could only achieve this efficiency under idealized
conditions. In practice, an actual plant never operates in idealized conditions
and typically achieves a heat rate that is 5% higher than the idealized heat
rate. Based on that study, the maximum efficiency that combined cycle plants
could achieve is 6,140 btu/kWh. RDI therefore concludes that our 2010 heat rate
assumptions should remain in place for the 2020 to 2030 time frame. This
assumption is just 3% higher than the actual maximum efficiency determined by
the P.J. Dechamps study. Moreover, the increased capital and operating costs
that might be required to achieve this level of efficiency are likely to
outweigh the fuel cost reductions caused by the slight improvement in
efficiency.
------------------------
(9) P.J. Dechamps, TRANSACTIONS OF THE ASME, Vol. 120, April 1998
C-20
<PAGE>
Therefore, with constant heat rates and gas prices increasing at the rate of
inflation, we conclude that a reasonable escalation rate for the fuel price of a
new plant should be the rate of inflation (2.5%).
CAPITAL AND OPERATING COSTS This analysis assumes that the cost of
constructing a new combined cycle plant in a greenfield site will decrease from
$525 per kW in 1999 to $430 per kW in 2020 (in constant dollars). This change in
cost is predicated on the assumption that the cost of a new power plant will
increase at a rate of 1.5% per year, rather than at the rate of inflation. We do
not have any justification for assuming that turbine prices can decrease in
constant dollar terms indefinitely and feel that our assumptions between 2000
and 2020 are already fairly aggressive. This is especially true when
consideration is given to the fact that we have assumed the efficiencies of
plants will improve AND the cost of constructing new facilities will also
decrease. We therefore recommend that for the 2020 to 2030 time frame it is
assumed that both capital costs and operation and maintenance costs are assumed
to increase at the rate of inflation.
Given our assumptions regarding fuel prices, we estimate that fuel costs
comprise 58% of the cost of a new combined cycle plant, operating and
maintenance costs comprise another 12%, and capital expenses comprise the
remaining 30%. Since each of these factors is assumed to increase at the cost of
inflation (2.5%), the weighted average escalation rate of the cost of a new
combined cycle facility is also 2.5%, or the rate of inflation. This escalation
rate is therefore applied to the price forecast for the 2022 to 2030 time
period.
C-21
<PAGE>
BASE CASE PRICE FORECAST
Table 5 shows RDI's base case annual electricity price forecast for the
Southern Companies market--the market area in which the Tenaska Georgia
Partner's project will be built.
Energy prices are summarized according to the parameters established by the
contract for the output of power from the Tenaska Georgia Partners' plant. That
is, "Summer" months are June through September. "Contract" hours refer to the
peak hours of the day as defined by the contract--6 am to 10 p.m. Capacity
prices are presented in this table as an average year round price. A methodology
for allocating capacity prices to certain hours of the year is discussed below.
The defining characteristic of the Southeast electricity market is a
shortage of capacity. In other words, electricity prices in the region already
reflect the long-run marginal cost of adding new capacity to the grid. Over the
forecast horizon, therefore, electricity prices are driven primarily by the
factors that determine the long run marginal cost of electricity. The first of
these factors is gas prices. From the period 2000 to 2010 the major factor
driving annual price growth of approximately 4% (in nominal dollars) is
increasing gas prices. In particular, gas prices drive the growth in energy
price projections. The price growth caused by projected increases in gas prices
is diminished, however, by projected reductions in the construction cost of new
generating facilities. This factor causes capacity prices to decline in real
dollar terms. One other factor that pushes prices up slightly during the first
decade of the forecast is the cost of complying with new NO(x)regulations. These
regulations are to be implemented in 2003. The cost of operating the equipment
that reduces NO(x) emissions contributes slightly to the 7% increase in energy
prices in 2003.
After 2010, electricity prices rise at a rate slightly less than the rate of
inflation. Declining prices in real dollar terms are driven by two factors.
First, RDI's gas price forecast assumes that gas prices will escalate at the
rate of inflation after 2010. Second, RDI has also assumed that all capacity
additions after 2010 would have more advanced technologies than those added in
the earlier years of the forecast. The presence of these more efficient units
(both peaking and baseload) has a dampening effect on prices during all hours in
the later years of the forecast as these units penetrate the grid.
TABLE 5: BASE CASE ELECTRICITY PRICE FORECAST
(NOMINAL $ UNLESS STATED)
<TABLE>
<CAPTION>
BASE CASE ENERGY PRICES ($/MWH)
-----------------------------------------------------------------
WINTER MONTHS SUMMER MONTHS
------------------- ------------------- TOTAL
HOURS OF DAY ANNUAL CAPACITY TOTAL PRICE
----------------------------------------- YR ROUND PRICE PRICE PRICE $/MWH
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION $/KW-YR $/MWH (1999 $)
---- -------- -------- -------- -------- -------- ---------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000........ 24.02 17.99 22.31 18.49 21.55 -- 46.46 30.39 29.65
2001........ 24.81 18.32 23.44 18.90 22.38 3.9% 47.26 31.37 29.86
2002........ 25.69 18.54 24.57 19.49 23.26 3.9% 47.97 32.39 30.07
2003........ 28.00 19.79 26.19 20.24 24.84 6.8% 48.69 34.10 30.90
2004........ 28.89 20.06 27.69 21.01 25.93 4.4% 49.82 35.41 31.30
2005........ 30.22 20.45 29.26 21.86 27.19 4.8% 50.56 36.81 31.74
2006........ 31.59 21.22 30.45 22.55 28.29 4.0% 52.11 38.20 32.14
2007........ 32.74 21.80 32.15 23.54 29.61 4.7% 52.38 39.57 32.48
2008........ 33.69 22.41 33.53 24.61 30.75 3.9% 53.65 40.96 32.80
2009........ 35.66 23.54 35.02 25.76 32.25 4.9% 55.04 42.72 33.38
2010........ 36.46 24.15 36.38 26.80 33.35 3.4% 55.13 43.84 33.41
<CAPTION>
REAL
ANNUAL
PRICE
YEAR ESCALATION
---- ----------
<S> <C>
2000........ --
2001........ 0.7%
2002........ 0.7%
2003........ 2.5%
2004........ 1.2%
2005........ 1.2%
2006........ 1.1%
2007........ 0.9%
2008........ 0.8%
2009........ 1.4%
2010........ 0.1%
</TABLE>
C-22
<PAGE>
<TABLE>
<CAPTION>
BASE CASE ENERGY PRICES ($/MWH)
-----------------------------------------------------------------
WINTER MONTHS SUMMER MONTHS
------------------- ------------------- TOTAL
HOURS OF DAY ANNUAL CAPACITY TOTAL PRICE
----------------------------------------- YR ROUND PRICE PRICE PRICE $/MWH
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION $/KW-YR $/MWH (1999 $)
---- -------- -------- -------- -------- -------- ---------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2011........ 37.27 24.71 37.12 27.46 34.07 2.2% 55.84 44.70 33.23
2012........ 38.37 25.45 37.56 28.15 34.74 2.0% 57.27 45.64 33.11
2013........ 38.83 25.92 38.32 28.86 35.40 1.9% 58.20 46.47 32.89
2014........ 39.64 26.71 38.91 29.59 36.08 1.9% 58.85 47.28 32.64
2015........ 40.97 27.63 39.92 30.37 37.12 2.9% 59.61 48.46 32.64
2016........ 41.49 28.10 40.84 31.09 37.86 2.0% 60.38 49.35 32.43
2017........ 42.36 28.80 41.70 31.96 38.71 2.2% 61.46 50.40 32.32
2018........ 43.49 29.65 42.43 32.68 39.54 2.2% 62.26 51.39 32.15
2019........ 44.17 30.30 43.47 33.43 40.40 2.2% 63.17 52.42 31.99
2020........ 45.07 31.19 44.32 34.37 41.28 2.2% 64.30 53.52 31.86
2021........ 45.42 32.21 43.79 34.81 41.30 0.1% 65.08 53.68 31.18
2022........ 46.55 33.02 44.88 35.68 42.33 2.5% 66.71 55.03 31.18
2023........ 47.72 33.84 46.01 36.57 43.39 2.5% 68.38 56.40 31.18
2024........ 48.91 34.69 47.16 37.48 44.48 2.5% 70.09 57.81 31.18
2025........ 50.13 35.55 48.34 38.42 45.59 2.5% 71.84 59.26 31.18
2026........ 51.38 36.44 49.54 39.38 46.73 2.5% 73.63 60.74 31.18
2027........ 52.67 37.35 50.78 40.37 47.90 2.5% 75.47 62.26 31.18
2028........ 53.99 38.29 52.05 41.37 49.10 2.5% 77.36 63.81 31.18
2029........ 55.34 39.25 53.35 42.41 50.32 2.5% 79.29 65.41 31.18
2030........ 56.72 40.23 54.69 43.47 51.58 2.5% 81.28 67.04 31.18
<CAPTION>
REAL
ANNUAL
PRICE
YEAR ESCALATION
---- ----------
<S> <C>
2011........ -0.4%
2012........ -0.3%
2013........ -0.5%
2014........ -0.5%
2015........ 0.0%
2016........ -0.4%
2017........ -0.2%
2018........ -0.3%
2019........ -0.3%
2020........ -0.2%
2021........ -1.3%
2022........ 0.0%
2023........ 0.0%
2024........ 0.0%
2025........ 0.0%
2026........ 0.0%
2027........ 0.0%
2028........ 0.0%
2029........ 0.0%
2030........ 0.0%
</TABLE>
------------------------
* Assumes a 60% load factor based on SERC summer load factor for 1999 as
reported in EIA-411
COMPARISON TO CURRENT MARKET PRICES
RDI's price forecast for the year 2000 is slightly lower than historic
wholesale prices in the region. According to price information collected by
Megawatt Daily, the average round the clock price at the Southern hub in 1998
was $33 per MWh or approximately 10% higher than RDI's base case forecast for
the year 2000.
Comparison to the current forward curve is more difficult because there is
not yet a liquid forward curve (i.e. heavily traded futures contract) in the
southeast U.S. However, based on the best available information, it appears that
RDI's forecast is substantially below the forward price curve as well. The two
most liquid trading hubs that are close to Georgia are Entergy and TVA. The
Entergy hub in late April was trading at $47 per MWh for delivery during the
next year. The TVA hub was trading at $52 per MWh for delivery during the next
year. Again, this price is substantially higher than RDI's comparable forecast
price of $35 per MWh for peak prices during 2000.
The current forward price curve appears to capture uncertainty related to
last summer's price spikes in the Midwest. It is RDI's belief that those price
spikes were driven by a confluence of events. Those specific events are unlikely
to occur simultaneously in the future. First, in ECAR and MAIN nearly 23% of the
capacity in the region was unavailable during June. Moreover, during the week of
the price spikes, almost 4,000 MW of nuclear capacity was forced off line.
Second, temperatures reached abnormally high levels and loads were substantially
higher than anticipated. Third, problems in one area of the transmission system
quickly became problems in other market areas as tight supply/ demand conditions
limited the ability of utilities to shift generation to meet load. These shifts
began to cause overloads on the transmission system, which resulted in the need
for line loading relief. RDI's forecast does not reflect the uncertainty created
by last years price spikes because RDI's forecast does
C-23
<PAGE>
not consider low probability events. However, it is important to note that while
the specific conditions that caused the Midwest price spikes are not likely to
occur simultaneously in the future, over the life of the project the market will
periodically encounter conditions that will result in temporary price spikes.
CONVERTING RDI'S FORECAST TO COMPARABLE FORWARD PRICES RDI forecasts
wholesale market prices as two separate components--energy and capacity. These
two components, when added together, comprise the total value of electricity.
The energy price represents the spot price of non-firm power. The capacity price
represents the premium that must be paid to assure firm supply or to acquire
electricity supply during times of shortages.
Energy prices are projected in terms of dollars per megawatt hour. Capacity
prices are projected first in dollars per kilowatt year, then allocated to a
specified number of hours to obtain values in dollars per megawatt hour. For
example, a capacity price of $52 per kW-yr, when allocated over 100% of the
8,760 hours in a year is equivalent to $5.90 per MWh. If the average energy
price over the year is $20.00 per MWh, then the average price of firm power over
the year is $25.90 per MWh. This is the value of firm baseload power.
On an hourly basis, capacity has a value of zero in the vast majority of
hours. These include all hours in non-peak months, weekends, and off-peak hours
of every day. Even some prices during on-peak hours of peak months will have a
capacity value of zero. Capacity has a non-zero value in only 10% or fewer of
the hours of the year. A capacity price of $52 per kW-yr, when allocated over
10% of the hours in a year, is equivalent to $59 per MWh. If energy prices are,
say, $5.00 per MWh higher on average during peaking hours than the all-hours
average, then the total price of firm peaking power is $84 per MWh
($20 + $5 + $59).
Total firm prices show a sharply pronounced seasonal profile. One place to
observe this is in futures prices. Futures prices typically reflect little value
for capacity during nine of the 12 forward months. The fundamental concept
underlying capacity prices is reliability. Capacity prices are highest in hours,
days, and months when the risk of curtailment owing to a generating capacity
shortfall is highest. Studies of hourly loss-of-load-probability (LOLP) show
that almost all of the hours with non-zero LOLP are concentrated in only two or
three months of the year.
Figure 8 shows RDI's base case forecast using a methodology approximating
the forward curve observed on a NYMEX contract. The annual value of capacity was
assumed to be allocated 5% to May, 15% to June, 30% to July, 30% to August, 15%
to September, and 5% to October. This assumption was based on observed
historical spot market prices and current futures prices, in the absence of a
LOLP study specific to this region. Again, current prices for summer delivery
are greater than $100 per MWh, compared to RDI's price projections of $70 per
MWh.
C-24
<PAGE>
FIGURE 8: YEAR 2000 MONTHLY FORECAST FOR ON-PEAK PRICES (NOMINAL $/MWH)
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
YEAR 2000 MONTHLY TOTAL ON-PEAK PRICES (CAPACITY & ENERGY)
<S> <C> <C>
Monthly Energy Capacity
Jan 22.33 -
Feb 21.04 -
Mar 21.12 -
Apr 24.50 -
May 21.26 7.54
Jun 22.78 22.61
Jul 23.57 45.22
Aug 24.38 45.22
Sep 21.85 22.61
Oct 24.81 7.54
Nov 23.37 -
Dec 20.74 -
</TABLE>
ENERGY PRICE FORECAST
Figure 9 summarizes energy prices by time of day and by contract period, as
described above.
FIGURE 9: AVERAGE ANNUAL PRICES BY TIME PERIOD (NOMINAL $ PER MWH)
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
ENERGY PRICES IN $/MWH
<S> <C> <C> <C> <C>
YEAR SUMMER CONT SUMMER OFF WINTER CONT WINTER OFF
2000 24.02 17.99 22.31 18.49
2001 24.81 18.32 23.44 18.90
2002 25.69 18.54 24.57 19.49
2003 28.00 19.79 26.19 20.24
2004 28.89 20.06 27.69 21.01
2005 30.22 20.45 29.26 21.86
2006 31.59 21.22 30.45 22.55
2007 32.74 21.80 32.15 23.54
2008 33.69 22.41 33.53 24.61
2009 35.66 23.54 35.02 25.76
2010 36.46 24.15 36.38 26.80
2011 37.27 24.71 37.12 27.46
2012 38.37 25.45 37.56 28.15
2013 38.83 25.92 38.32 28.86
2014 39.64 26.71 38.91 29.59
2015 40.97 27.63 39.92 30.37
2016 41.49 28.10 40.84 31.09
2017 42.36 28.80 41.70 31.96
2018 43.49 29.65 42.43 32.68
2019 44.17 30.30 43.47 33.43
2020 45.07 31.19 44.32 34.37
2021 45.42 32.21 43.79 34.81
2022 46.55 33.02 44.88 35.68
2023 47.72 33.84 46.01 36.57
2024 48.91 34.69 47.16 37.48
2025 50.13 35.55 48.34 38.42
2026 51.38 36.44 49.54 39.38
2027 52.67 37.35 50.78 40.37
2028 53.99 38.29 52.05 41.37
2029 55.34 39.25 53.35 42.41
2030 56.72 40.23 54.69 43.47
</TABLE>
The movement of energy prices over the forecast period is driven by four
market dynamics. First, increasing gas prices push energy prices higher. Second,
general demand growth increases the need to run higher cost
resources--particularly in the early years of the forecast. Third, the Clean Air
Act
C-25
<PAGE>
requirements for NO(x) emission standards are assumed to take effect in 2003.
This contributes to a 7% increase in average energy prices in 2003. Finally, new
gas fired peaking capacity in the region displaces the existing less efficient
fossil generation dampening price growth.
CAPACITY PRICE FORECAST
SUPPLY/DEMAND BALANCE Over the past decade electricity demand has grown
rapidly in the southeast U.S. This rapid demand growth, however, has not been
met by an equal amount of supply growth, resulting in a tightening of markets.
If substantial amounts of new capacity are not built soon, the region will
suffer shortages and much higher electricity prices than currently forecast by
RDI. Even with RDI's projections for merchant plant additions, reserve margins
in the region are likely to fall to 13% by 2000. Another 3,816 MW of new
capacity additions beyond RDI's merchant plant projections of 5,000 MW will be
required in 2001 to maintain a 15% reserve margin. It is this shortage of
capacity that pushes RDI's capacity price projections to a level that supports
the profitable additions of new capacity.
It should also be noted that it is currently more profitable to build a
combustion turbine than it is to build a combined cycle plant in the Southeast.
While the region as a whole requires significant capacity additions, it does not
require baseload resources. Currently more than 80% of the capacity in the
region consists of coal-fired, nuclear, or hydro baseload facilities. Of the
peaking capacity, a majority is concentrated in Southern Mississippi and is
owned by Entergy. The fact that the region as a whole has a load factor of
60%(10) indicates there is too much baseload capacity. As a result, a combined
cycle plant is currently not competitive in the region.
------------------------
(10) Load factor is a measure of the peak demand in a region to the hourly
average demand throughout the year.
C-26
<PAGE>
FIGURE 10: PERCENTAGE OF BASELOAD VS. PEAKING CAPACITY IN SERC
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
BASELOAD CAPACITY 20%
<S> <C>
PEAKING CAPACITY 80%
</TABLE>
CAPACITY ADDITIONS Table 6 contains a summary of capacity additions for the
base case. These numbers include the new capacity explicitly added by RDI as
discussed in the Base Case Assumptions section (Merchant Plant Additions), the
Tenaska Georgia Partners project, and incremental capacity added by IREMM. Over
the next decade more than 35,000 MW of new capacity additions are likely to be
required in the region. Another 15,000 to 30,000 MW will also be required in
neighboring regions. If this new capacity is not added, prices may rise
substantially higher than forecast by RDI. However, it is RDI's expectation that
developers will respond to the price signals sent by the market and that these
new capacity additions will be made.
TABLE 6: FORECAST CAPACITY ADDITIONS IN SERC (MW)
<TABLE>
<CAPTION>
CURRENT CAPACITY
VINTAGE CURRENT ADVANCED ADVANCED TOTAL PRICE
YEAR CT'S VINTAGE CC'S CT'S CC'S ADDITIONS $/KW-YR
---- --------- ------------ -------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
2000............................. 3,760 -- -- -- 3,760 46.46
2001............................. 3,220 1,350 -- -- 4,570 47.26
2002............................. 1,851 599 -- -- 2,450 47.97
2003............................. 2,971 1,272 -- -- 4,243 48.69
2004............................. 3,581 1,534 -- -- 5,115 49.82
2005............................. 2,956 1,266 -- -- 4,222 50.56
2006............................. 1,707 731 -- -- 2,438 52.11
2007............................. 2,084 893 -- -- 2,977 52.38
2008............................. 796 1,859 -- -- 2,655 53.65
2009............................. 745 1,741 -- -- 2,486 55.04
2010............................. 1,151 2,687 -- -- 3,838 55.13
2011............................. -- -- 430 3,880 4,310 55.84
2012............................. -- -- 418 3,779 4,197 57.27
2013............................. -- -- 321 2,905 3,226 58.20
2014............................. -- -- 265 2,389 2,654 58.85
2015............................. -- -- 880 2,055 2,935 59.61
2016............................. -- -- 1,132 2,643 3,775 60.38
2017............................. -- -- 1,154 2,695 3,849 61.46
2018............................. -- -- 1,150 2,685 3,835 62.26
2019............................. -- -- 1,174 2,741 3,915 63.17
2020............................. -- -- 1,198 2,797 3,995 64.30
2021............................. -- -- 1,576 3,679 5,255 65.08
------ ------ ----- ------ ------ -----
TOTAL............................ 24,822 13,932 9,698 32,248 80,700
</TABLE>
C-27
<PAGE>
TENASKA GEORGIA PARTNERS OPERATIONS
MONTHLY CAPACITY FACTORS Forecast monthly utilization is summarized in
Table 7. Detailed monthly capacity factors are included in Appendix C. RDI's
base case forecast shows July and August capacity factors ranging from 7% to
18%. In 2003, the first full year that all 900 MW are on-line, the plant
achieves capacity factors of 8% and 9% in July and August, respectively. By the
middle years of the forecast (2007-2012) the plant is achieving capacity factors
of 10% to 18% in the summer months and is also being dispatched in off-peak
months. The plant's utilization is reduced somewhat in the later years of the
forecast, due to the addition of advanced peaking capacity technologies after
2010 and significant new combined cycle plant additions.
TABLE 7: FORECAST MONTHLY CAPACITY FACTORS FOR THE TENASKA GEORGIA PROJECT
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003..................... 0% 1% 0% 0% 1% 5% 8% 9% 3%
2005..................... 1% 1% 1% 0% 3% 11% 13% 14% 4%
2010..................... 2% 1% 1% 0% 4% 11% 15% 18% 6%
2015..................... 1% 1% 1% 0% 3% 8% 12% 14% 6%
2020..................... 0% 0% 0% 0% 2% 4% 9% 7% 2%
--- --- --- --- --- --- --- --- ---
AVG 2000-2021............ 1% 1% 1% 0% 3% 8% 11% 13% 4%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003..................... 0% 0% 0% 2%
2005..................... 3% 0% 1% 4%
2010..................... 3% 2% 2% 5%
2015..................... 1% 0% 0% 4%
2020..................... 0% 0% 0% 2%
--- --- --- ---
AVG 2000-2021............ 2% 1% 1% 4%
</TABLE>
In the early years of the forecast, the project competes in peak hours with
existing peaking technologies and new combustion turbines of the same vintage.
These include both the other merchant capacity explicitly added to the model and
expansion units added implicitly by IREMM. For the most part, current vintage
combustion turbines compete favorably against the peaking units that currently
operate in the market. However, after 2010, the project (and other combustion
turbines) must also compete against peaking units with advanced technology.
Because the advanced combustion turbines have improved heat rates, they will
move ahead of the project and other current vintage combustion turbines in the
dispatch order. This causes the projected capacity factors after 2010 to
decrease.
C-28
<PAGE>
Figure 11 shows the forecast of annual capacity factors for new combustion
turbines of both current vintage and advanced technologies in SERC.
FIGURE 11: FORECAST ANNUAL CAPACITY FACTOR FOR A NEW CT IN SERC
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
AVERAGE ANNUAL CAPACITY FACTORS FOR NEW COMBUSTION TURBINES
<S> <C> <C> <C>
CURRENT VINTAGE ADVANCED TECH AVERAGE
2001 1%
2002 1%
2003 2%
2004 2%
2005 3%
2006 3%
2007 3%
2008 3%
2009 4%
2010 4%
2011 4% 8% 4%
2012 4% 8% 4%
2013 3% 7% 3%
2014 3% 6% 3%
2015 3% 6% 3%
2016 2% 6% 3%
2017 2% 6% 3%
2018 2% 5% 3%
2019 2% 5% 3%
2020 2% 5% 3%
2021 1% 4% 2%
</TABLE>
The forecast capacity factors are similar to the capacity factors achieved
by relatively recent gas turbine additions. For instance, over the past three
years the annual capacity factor at the Lincoln Combustion Turbines owned by
Duke Power (construction was finished in 1996) has ranged from 1.4% to 5%. The
5% capacity factor was achieved in 1998 when more than 20% of the capacity in
the region was out of service and temperatures reached record levels. RDI's
capacity factors are lower than 5% due to two reasons. First, RDI's forecast is
based upon normalized weather conditions so it does not reflect the abnormal
temperatures of recent years. Second, substantial new capacity additions reduce
capacity factors for all peaking power plants in the early years of the
forecast.
START-UP PROFILE Table 8 summarizes plant start-up data for the Tenaska
Georgia Partners' project. These figures represent the number of times any unit
at the facility is called upon by the model in the subject month. The plant is
called on during most weekdays in the months of June, July and August through
2010. Start-ups in all months are reduced somewhat in the later years of the
forecast.
C-29
<PAGE>
TABLE 8: PROJECTED MONTHLY START-UPS FOR SELECT YEARS--
TENASKA GEORGIA PARTNER'S PROJECT
START-UPS BY MONTH
<TABLE>
<CAPTION>
YR JAN FEB MAR APR MAY JUN JUL AUG SEP
-- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003..................... -- 1 1 -- 3 9 11 15 5
2005..................... 3 2 3 -- 5 13 15 17 7
2010..................... 3 2 3 -- 6 15 17 20 9
2015..................... 2 2 2 -- 5 12 14 17 9
2020..................... -- -- -- -- 5 9 11 10 4
<CAPTION>
YR OCT NOV DEC TOTAL
-- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003..................... -- -- 1 46
2005..................... 5 1 2 73
2010..................... 6 7 3 91
2015..................... 2 2 2 69
2020..................... 1 -- -- 40
</TABLE>
AVERAGE DURATION OF START-UPS
<TABLE>
<CAPTION>
YR JAN FEB MAR APR MAY JUN JUL AUG SEP
-- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003..................... -- 5.0 4.0 -- 5.0 5.4 6.9 6.4 5.8
2005..................... 4.0 4.5 4.0 -- 5.0 7.0 7.3 6.9 6.7
2010..................... 5.0 4.5 4.0 -- 5.8 6.7 7.5 7.7 6.1
2015..................... 3.0 4.0 4.0 -- 5.4 6.8 7.5 7.3 5.8
2020..................... -- -- -- -- 3.8 5.1 6.5 6.4 5.3
<CAPTION>
YR OCT NOV DEC TOTAL
-- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003..................... -- -- 4.0 6.0
2005..................... 6.4 4.0 4.5 6.4
2010..................... 6.2 3.3 4.3 6.4
2015..................... 6.5 3.0 4.0 6.4
2020..................... 7.0 -- -- 5.7
</TABLE>
The average run time per start-up is over six hours in almost all years
analyzed and approaches 6.5 hours in the middle years of the forecast. In summer
months, the average run time for each start-up is higher than the average annual
value. For peaking units, the number of start-ups in any month is a function of
both the level of demand in the region and the amount of capacity available to
meet that demand. Thus, the model may call upon a peaking unit in non-peaking
months if other resources are off-line for maintenance. However, in the years
examined, the run times in those months are shorter in duration.
C-30
<PAGE>
SENSITIVITY ANALYSIS
The base case scenario provides an estimate of the most likely future energy
and capacity prices. However, prices are subject to change as fundamental market
forces change. Two of the key forces affecting the price forecast are future
fuel prices and the overall supply/demand balance in the region. To gauge the
sensitivity of the base case forecast to changes in market dynamics, RDI
considered three main additional scenarios and one scenario which was designed
solely to gauge the impact of technological improvements on capacity prices. The
additional scenarios were:
- LOW GAS PRICES--gas prices 20% lower than the base case.
- 12% REQUIRED RESERVE MARGIN--There is a great amount of uncertainty
concerning the level of required reserves in a deregulated market. In the
base case, it was assumed that a 15% reserve margin would be maintained in
the Southeast. In the sensitivity analysis, RDI reduced the level of
required reserves to 12%.
- OVERBUILD--assumes that an additional 9,000 MW (7,500 MW CT/1,500 MW CC)
of merchant capacity will be added to the grid by June 2001. RDI assumed
in the base case that 5,000 MW of new merchant capacity will be built by
2002. This figure includes the Tenaska Georgia Partners' project. There is
currently another 6,000 MW of merchant capacity that has been proposed for
the Southeast that RDI did not include in its model. Much of the capacity
not included by RDI in the base case either faces significant development
hurdles or is in the very early stages of development. However, in this
scenario we assumed that all of this 6,000 MW of capacity is built. RDI
also assumed that developers will bring an additional 3,000 MW of capacity
on-line by 2001. Therefore, in total, this scenario assumes that 14,000 MW
of capacity will be built by 2002. To put this number into perspective,
during the past decade only 15,000 MW of new capacity was added to SERC's
grid.
- TECHNOLOGICAL IMPROVEMENT--assumes that the cost of building new capacity
decreases 2% in each of the first 10 years of the forecast and 1% for the
remainder of the forecast. The base case assumes a constant 1%
improvement. Energy prices remain the same as in the base case. The
results of this scenario are only discussed in the section on capacity
prices below.
C-31
<PAGE>
Table 9 summarizes price results by scenario. More detail is provided in the
discussion below.
TABLE 9: PRICE RESULTS--SENSITIVITY ANALYSIS (NOMINAL $)
<TABLE>
<CAPTION>
LOW FUEL OVERBUILD 12% RESERVE
----------------------------------------- ------------------------------------------ -------------------
ENERGY ENERGY ENERGY
$/ CAPACITY TOTAL $/ % CHG $/ CAPACITY TOTAL $/ % CHG $/ CAPACITY
YEAR MWH $/KW-YR MWH* BASE MWH $/KW-YR MWH* BASE MWH $/KW-YR
---- -------- -------- -------- -------- ------ ---------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000........... 20.41 46.46 29.25 (3.8)% 21.52 26.58 26.57 (12.6)% 21.62 46.36
2001........... 20.93 47.26 29.93 (4.6)% 22.30 15.38 25.22 (19.6)% 22.62 47.05
2002........... 21.63 47.77 30.72 (5.2) 23.18 18.33 26.67 (17.6)% 23.54 47.67
2003........... 22.88 48.59 32.13 (5.8)% 24.96 48.59 34.21 0.3 % 25.13 48.49
2004........... 23.67 49.92 33.17 (6.3)% 26.06 49.52 35.48 0.2 % 26.24 49.42
2005........... 24.61 50.36 34.19 (7.1)% 27.31 50.46 36.91 (0.3)% 27.49 50.76
2006........... 25.48 51.31 35.24 (7.8)% 28.43 51.81 38.29 0.2 % 28.45 51.31
2007........... 26.51 52.68 36.53 (7.7)% 29.81 51.98 39.70 0.3 % 29.58 52.18
2008........... 27.33 53.75 37.55 (8.3)% 30.92 52.75 40.95 0.0 % 30.78 53.35
2009........... 28.43 54.24 38.75 (9.3)% 32.38 54.24 42.70 (0.1)% 32.35 54.34
2010........... 29.27 55.83 39.89 (9.0)% 33.55 54.63 43.94 0.2 % 33.24 54.93
2011........... 29.75 56.34 40.47 (9.5)% 34.24 55.74 44.84 0.3 % 33.98 55.54
2012........... 30.19 57.67 41.16 (9.8)% 34.89 56.87 46.71 0.1 % 34.66 57.37
2013........... 30.60 57.90 41.62 (10.4)% 35.58 57.80 46.58 0.2 % 35.33 58.20
2014........... 31.13 58.75 42.31 (10.5)% 36.27 58.65 47.43 0.3 % 36.04 58.75
2015........... 31.90 59.41 42.30 (10.9)% 37.30 59.21 48.57 0.2 % 36.94 59.51
2016........... 32.41 60.58 43.94 (11.0)% 38.01 60.26 49.47 0.3 % 37.50 60.08
2017........... 33.06 61.36 44.74 (11.2)% 38.88 61.16 50.51 0.2 % 38.32 61.16
2018........... 33.74 62.06 45.54 (11.4)% 39.74 62.06 61.55 0.3 % 39.16 61.86
2019........... 34.35 63.27 46.39 (11.5)% 40.60 63.07 52.60 0.3 % 40.00 63.07
2020........... 35.00 64.40 47.26 (11.7)% 41.48 64.00 53.65 0.3 % 40.82 64.00
2021........... 34.92 65.16 47.32 (11.9)% 41.49 54.74 53.80 0.2 % 40.85 64.78
2022........... 36.79 66.79 48.50 (11.9)% 42.52 66.36 55.15 0.2 % 41.87 66.36
2023........... 35.69 68.46 49.71 (11.9)% 43.59 68.02 56.53 0.2 % 42.92 68.02
2024........... 37.61 70.17 50.96 (11.9)% 44.68 69.72 57.94 0.2 % 43.99 69.72
2025........... 38.55 71.93 52.23 (11.9)% 45.79 71.46 59.39 0.2 % 45.09 71.46
2026........... 39.51 73.72 53.54 (11.9)% 45.94 73.25 60.87 0.2 % 46.21 73.25
2027........... 40.50 75.57 54.88 (11.9)% 46.11 75.08 62.40 0.2 % 47.37 75.08
2028........... 41.51 77.46 56.25 (11.9)% 49.31 76.96 63.96 0.2 % 48.55 76.96
2029........... 42.55 79.39 57.65 (11.9)% 50.55 78.88 65.55 0.2 % 49.77 78.88
2030........... 43.61 81.38 59.10 (11.9)% 51.81 80.85 67.19 0.2 % 51.01 80.85
<CAPTION>
12% RESERVE
-------------------
TOTAL $/ % CHG
YEAR MWH* BASE
---- -------- --------
<S> <C> <C>
2000........... 30.44 0.2 %
2001........... 31.58 0.6 %
2002........... 32.61 0.7 %
2003........... 34.36 0.7 %
2004........... 35.64 0.7 %
2005........... 37.15 0.9 %
2006........... 38.21 0.0 %
2007........... 39.51 (0.2)%
2008........... 40.93 (0.1)%
2009........... 42.69 (0.1)%
2010........... 43.69 (0.3)%
2011........... 44.55 (0.3)%
2012........... 45.57 (0.1)%
2013........... 46.41 (0.1)%
2014........... 47.22 (0.1)%
2015........... 48.26 (0.4)%
2016........... 48.93 (0.8)%
2017........... 49.96 (0.9)%
2018........... 50.93 (0.6)%
2019........... 52.00 (0.8)%
2020........... 52.99 (1.0)%
2021........... 53.17 (1.0)%
2022........... 54.49 (1.0)%
2023........... 55.66 (1.0)%
2024........... 57.25 (1.0)%
2025........... 58.68 (1.0)%
2026........... 60.15 (1.0)%
2027........... 61.65 (1.0)%
2028........... 63.20 (1.0)%
2029........... 64.78 (1.0)%
2030........... 86.40 (1.0)%
</TABLE>
------------------------------
* Assumes a 60% load factor based on SEPC summer load factor for 1999 as
reported in BA-411.
ENERGY PRICES
In general this analysis indicates that energy prices are not sensitive to
changes in reserve margins, or to an overbuild scenario. As shown in Table 10
energy prices significantly depart from the base case forecast only in the low
fuel scenario. During many hours of the year, gas-fired generation sets the
price of energy. During these hours, any reduction in gas prices, therefore,
reduces energy prices. This reduction in energy prices is due to the role that
gas-fired generation plays in setting electricity prices during many hours of
the year.
C-32
<PAGE>
TABLE 10: ENERGY PRICE RESULTS--SENSITIVITY ANALYSES (NOMINAL $/MWH)
<TABLE>
<CAPTION>
BASE CASE LOW FUEL OVERBUILD 12% RESERVE
---------------------- --------------------------------- --------------------------------- ---------
YR ROUND ANNUAL YR ROUND ANNUAL % YR ROUND ANNUAL % YR ROUND
AVE PRICE AVE PRICE CHG AVE PRICE CHG AVE
YEAR $/MWH ESCALATION $/MWH ESCALATION BASE $/MWH ESCALATION BASE $/MWH
---- --------- ---------- --------- ---------- -------- --------- ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000........... 21.56 -- 20.41 -- 5.3 % 21.52 -- (0.2)% 21.02
2001........... 22.38 3.8% 20.93 2.6 % (6.5)% 22.30 3.6% (0.4)% 22.62
2002........... 23.26 3.9% 21.83 3.3 % (7.0)% 23.18 4.0% (0.3)% 23.54
2003........... 24.84 6.8% 22.88 5.8 % (7.9)% 24.95 7.7% 0.5 % 25.13
2004........... 25.93 4.4% 23.67 3.4 % (0.7)% 26.06 4.4% 0.5 % 26.24
2005........... 27.19 4.8% 24.61 3.9 % (9.5)% 27.31 4.8% 0.4 % 27.49
2006........... 28.29 4.0% 25.46 3.5 % (9.9)% 28.43 4.1% 0.5 % 28.45
2007........... 29.61 4.7% 26.51 4.1 % (10.5)% 29.81 4.8% 0.7 % 29.58
2008........... 30.75 3.9% 27.33 3.1 % (11.1)% 30.92 3.7% 0.6 % 30.78
2009........... 32.25 4.9% 28.43 4.1 % (11.8)% 32.36 4.7% 0.4 % 32.35
2010........... 33.30 3.4% 20.27 2.9 % (12.2)% 35.55 3.6% 0.6 % 33.24
2011........... 34.01 2.2% 29.75 1.6 % (12.7)% 34.24 2.1% 0.5 % 33.50
2012........... 34.74 2.0% 30.19 1.5 % (15.1)% 34.89 1.0% 0.4 % 34.66
2013........... 35.40 1.9% 30.60 1.4 % (13.5)% 35.50 2.0% 0.5 % 35.33
2014........... 36.08 1.9% 31.13 1.7 % (13.7)% 36.27 1.9% 0.5 % 36.04
2015........... 37.12 2.9% 31.90 2.5 % (14.1)% 37.30 2.8% 0.5 % 36.94
2016........... 37.86 2.0% 32.41 1.6 % (14.4)% 38.01 1.9% 0.4 % 37.50
2017........... 38.71 2.2% 33.06 2.0 % (14.6)% 38.88 2.3% 0.4 % 38.32
2018........... 39.54 2.2% 33.74 2.0 % (14.7)% 39.74 2.2% 0.5 % 39.16
2019........... 40.40 2.2% 34.35 1.8 % (15.0)% 40.60 2.2% 0.5 % 40.00
2020........... 41.28 2.2% 35.00 1.9 % (15.2)% 41.48 2.1% 0.5 % 40.82
2021........... 41.30 0.1% 34.92 (0.2)% 15.4 % 41.49 0.0% 0.4 % 40.85
<CAPTION>
12% RESERVE
---------------------
ANNUAL %
PRICE CHG
YEAR ESCALATION BASE
---- ---------- --------
<S> <C> <C>
2000........... -- 0.3 %
2001........... 4.6% 1.1 %
2002........... 4.1% 1.2 %
2003........... 6.8% 1.2 %
2004........... 4.4% 1.2 %
2005........... 4.8% 1.1 %
2006........... 3.5% 0.6 %
2007........... 4.0% (0.1)%
2008........... 4.1% 0.1 %
2009........... 5.1% 0.3 %
2010........... 2.7% (0.3)%
2011........... 2.2% (0.3)%
2012........... 2.0% (0.2)%
2013........... 2.0% (0.2)%
2014........... 2.0% (0.1)%
2015........... 2.5% (0.5)%
2016........... 1.5% (0.9)%
2017........... 2.2% (1.0)%
2018........... 2.2% (1.0)%
2019........... 2.1% (1.0)%
2020........... 2.0% (1.1)%
2021........... 0.1% (1.1)%
</TABLE>
In the low fuel scenario, a 20% reduction in gas prices results in energy
prices that are 5 to 10% below the base case results in the early years of the
forecast because decreased fuel costs for the marginal units results in
decreased market clearing prices. As shown in Table 11, energy prices are 10 to
15% below the price results for the base case in the later years of the
forecast. There is a greater differential in the later years of the forecast
because gas-fired units are on the margin in more hours during those years.
C-33
<PAGE>
TABLE 11: ENERGY PRICE RESULTS LOW--FUEL SCENARIO (NOMINAL $/MWH)
<TABLE>
<CAPTION>
LOW FUEL ENERGY PRICES ($/MWH)
-----------------------------------------
SUMMER MONTHS WINTER MONTHS
------------------- -------------------
HOURS OF DAY ANNUAL %
------------------- YR ROUND PRICE CHG
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION BASE
---- -------- -------- -------- -------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
2000............................... 22.34 17.60 20.95 18.15 20.41 -- (5.3)%
2001............................... 22.88 17.76 21.67 18.37 20.93 2.6 % (6.5)%
2002............................... 23.59 18.03 22.54 18.83 21.63 3.3 % (7.0)%
2003............................... 25.43 19.39 23.74 19.46 22.88 5.8 % (7.0)%
2004............................... 26.07 19.51 24.86 19.95 23.67 3.4 % (8.7)%
2005............................... 27.13 19.75 26.03 20.50 24.61 3.9 % (9.5)%
2006............................... 28.25 20.32 26.98 21.04 25.48 3.5 % (9.9)%
2007............................... 29.20 20.67 28.38 21.63 26.51 4.1 % (10.5)%
2008............................... 30.13 20.95 29.34 22.22 27.33 3.1 % (11.1)%
2009............................... 31.63 21.72 30.47 22.95 28.43 4.1 % (11.8)%
2010............................... 32.32 22.07 31.59 23.53 29.27 2.9 % (12.2)%
2011............................... 32.91 22.38 32.06 23.99 29.75 1.6 % (12.7)%
2012............................... 33.71 22.92 32.33 24.33 30.19 1.5 % (13.1)%
2013............................... 33.92 23.10 32.87 24.81 30.60 1.4 % (13.5)%
2014............................... 34.51 23.62 33.37 25.35 31.13 1.7 % (13.7)%
2015............................... 35.56 24.30 34.11 25.88 31.90 2.5 % (14.1)%
2016............................... 35.87 24.50 34.79 26.39 32.41 1.6 % (14.4)%
2017............................... 36.60 25.23 35.44 26.92 33.06 2.0 % (14.6)%
2018............................... 37.55 25.92 36.04 27.44 33.74 2.0 % (14.7)%
2019............................... 38.01 26.18 36.85 27.91 34.35 1.8 % (15.0)%
2020............................... 38.66 26.71 37.50 28.65 35.00 1.9 % (15.2)%
2021............................... 38.83 27.34 37.01 28.88 34.92 (0.2)% (15.4)%
2022............................... 39.81 28.02 37.94 29.60 35.79 2.5 % (15.4)%
2023............................... 40.81 28.72 36.88 30.34 36.69 2.5 % (15.4)%
2024............................... 41.83 29.44 39.86 31.10 37.61 2.5 % (15.4)%
2025............................... 42.87 30.18 40.85 31.88 38.55 2.5 % (15.4)%
2026............................... 43.94 30.93 41.87 32.68 39.51 2.5 % (15.4)%
2027............................... 45.04 31.70 42.92 33.49 40.50 2.5 % (15.4)%
2028............................... 46.17 32.50 43.99 43.33 41.51 2.5 % (15.4)%
2029............................... 47.32 33.31 45.09 35.19 42.55 2.5 % (15.4)%
2030............................... 46.50 34.14 46.22 36.07 43.61 2.5 % (15.4)%
</TABLE>
Table 12 and Table 13 summarize energy price results from the overbuild and
12% reserve margin scenarios. Energy prices in these scenarios closely track
those from the base case. This is due to the fact that although the supply and
demand balance of capacity in the region has been changed, load in almost all
hours of the year is met with resources with identical characteristics to those
in the base case. As a result, the marginal price of producing electricity in a
given hour is close to that in the base case.
C-34
<PAGE>
TABLE 12: ENERGY PRICE RESULTS--OVERBUILD SCENARIO (NOMINAL $/MWH)
<TABLE>
<CAPTION>
OVERBUILD ENERGY PRICES ($/MWH)
-----------------------------------------
SUMMER MONTHS WINTER MONTHS
------------------- -------------------
HOURS OF DAY ANNUAL %
------------------- YR ROUND PRICE CHG
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION BASE
---- -------- -------- -------- -------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
2000................................ 23.89 17.99 22.30 18.49 21.52 -- (0.2)%
2001................................ 24.33 18.25 23.50 18.92 22.30 3.6% (0.4)%
2002................................ 25.37 18.49 24.59 19.47 23.18 4.0% (0.3)%
2003................................ 27.89 19.76 26.50 20.29 24.96 7.7% 0.5 %
2004................................ 28.90 20.05 27.95 21.04 26.06 4.4% 0.5 %
2005................................ 30.26 20.46 29.47 21.92 27.31 4.8% 0.4 %
2006................................ 31.61 21.20 30.73 22.62 28.43 4.1% 0.5 %
2007................................ 32.82 21.77 32.51 23.62 29.81 4.8% 0.7 %
2008................................ 33.79 22.39 33.83 24.67 30.92 3.7% 0.6 %
2009................................ 35.68 23.51 35.26 25.84 32.38 4.7% 0.4 %
2010................................ 36.62 24.12 36.70 26.88 33.55 3.6% 0.6 %
2011................................ 37.41 24.70 37.38 27.54 34.24 2.1% 0.5 %
2012................................ 38.39 25.44 37.82 26.22 34.69 1.9% 0.4 %
2013................................ 38.94 25.92 38.65 28.90 35.58 2.0% 0.5 %
2014................................ 39.72 26.69 39.25 29.61 36.27 1.9% 0.5 %
2015................................ 41.10 27.61 40.23 30.42 37.30 2.8% 0.5 %
2016................................ 41.58 28.10 41.10 31.11 38.01 1.9% 0.4 %
2017................................ 42.41 28.79 42.04 31.95 38.88 2.4% 0.4 %
2018................................ 43.62 29.54 42.78 32.70 39.74 2.2% 0.5 %
2019................................ 44.31 30.31 43.81 33.45 40.60 2.2% 0.5 %
2020................................ 45.13 31.21 44.70 34.34 41.48 2.1% 0.5 %
2021................................ 45.56 32.21 44.09 34.85 41.49 0.0% 0.4 %
2022................................ 46.70 33.01 45.19 35.72 42.52 2.5% 0.4 %
2023................................ 47.87 33.84 46.32 36.62 43.59 2.5% 0.4 %
2024................................ 49.07 34.69 47.48 37.53 44.68 2.5% 0.4 %
2025................................ 50.29 35.55 48.67 38.47 45.79 2.5% 0.4 %
2026................................ 51.55 36.44 49.88 39.43 46.94 2.5% 0.4 %
2027................................ 52.84 37.35 51.13 40.42 48.11 2.5% 0.4 %
2028................................ 54.16 38.29 52.41 41.43 49.31 2.5% 0.4 %
2029................................ 55.51 39.24 53.72 42.46 50.55 2.5% 0.4 %
2030................................ 56.90 40.22 55.06 43.52 51.81 2.5% 0.4 %
</TABLE>
C-35
<PAGE>
TABLE 13: ENERGY PRICE RESULTS--12% RESERVE MARGIN SCENARIO (NOMINAL $/MWH)
<TABLE>
<CAPTION>
12% RESERVE ENERGY PRICES ($/MWH)
----------------------------------------------------
SUMMER MONTHS WINTER MONTHS
------------------- -------------------
HOURS OF DAY ANNUAL %
----------------------------------------- YR ROUND PRICE CHG
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION BASE
---- -------- -------- -------- -------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
2000................................ 24.02 17.98 22.30 18.50 21.62 * 0.3 %
2001................................ 25.12 18.34 23.75 18.94 22.62 4.6% 1.1 %
2002................................ 26.07 18.60 24.92 19.53 23.54 4.1% 1.2 %
2003................................ 28.35 19.81 26.60 20.27 25.13 6.8% 1.2 %
2004................................ 29.29 20.11 28.05 21.08 26.24 4.4% 1.2 %
2005................................ 30.54 20.49 29.67 21.98 27.49 4.8% 1.1 %
2006................................ 31.81 21.27 30.64 22.58 28.45 3.5% 0.6 %
2007................................ 32.74 21.79 32.11 23.55 29.58 4.0% (0.1)%
2008................................ 33.78 22.43 33.51 24.63 30.78 4.1% 0.1 %
2009................................ 35.86 23.53 35.08 25.76 32.35 5.1% 0.3 %
2010................................ 36.45 24.02 36.24 26.63 33.24 2.7% (0.3)%
2011................................ 37.28 24.65 36.97 27.35 33.98 2.2% (0.3)%
2012................................ 38.33 25.36 37.46 28.03 34.66 2.0% (0.2)%
2013................................ 38.82 25.88 38.25 28.75 36.33 2.0% (0.2)%
2014................................ 39.60 26.69 38.87 29.47 36.04 2.0% (0.1)%
2015................................ 40.81 27.57 39.66 30.24 35.94 2.5% (0.5)%
2016................................ 41.17 26.00 40.32 30.87 37.50 1.5% (0.9)%
2017................................ 42.00 28.67 41.18 31.73 38.32 2.2% (1.0)%
2018................................ 43.15 29.48 41.91 32.41 39.16 2.2% (1.0)%
2019................................ 43.78 30.16 42.85 33.23 40.00 2.1% (1.0)%
2020................................ 44.61 31.12 43.71 34.15 40.82 2.0% (1.1)%
2021................................ 44.96 32.11 43.13 34.68 40.85 0.1% (1.1)%
2022................................ 46.08 32.91 44.21 35.55 41.87 2.5% (1.1)%
2023................................ 47.23 33.73 45.32 36.44 42.92 2.5% (1.1)%
2024................................ 48.41 34.58 46.45 37.35 43.99 2.5% (1.1)%
2025................................ 49.62 35.44 47.61 38.28 45.09 2.5% (1.1)%
2026................................ 50.87 36.33 48.80 39.24 46.21 2.5% (1.1)%
2027................................ 52.14 37.24 50.02 40.22 47.37 2.5% (1.1)%
2028................................ 53.44 38.17 51.27 41.22 48.55 2.5% (1.1)%
2029................................ 54.78 39.12 52.55 42.25 49.77 2.5% (1.1)%
2030................................ 56.15 40.10 53.87 43.31 51.01 2.5% (1.1)%
</TABLE>
CAPACITY PRICES
Capacity price results from the sensitivity scenarios are summarized in
Table 14 and Figure 12. Capacity prices are sensitive to fluctuations in the
cost of building new technologies, future demand growth, and the amount of new
capacity that enters the market. Because SERC requires significant new capacity
additions, only very large changes in the supply/demand balance and
technological improvements lowering the cost of new capacity result in
significant deviations from the base case capacity price forecast.
C-36
<PAGE>
TABLE 14: CAPACITY PRICE RESULTS--SENSITIVITY ANALYSES (NOMINAL $/KW-YR)
<TABLE>
<CAPTION>
CAPACITY PRICE $ KW-YR % CHG FROM BASE
---------------------------------------------------- ----------------------------------------------------
BASE LOW 12% OVER TECH BASE LOW 12% OVER TECH
YEAR CASE FUEL RESERVE BUILD IMPROVE CASE FUEL RESERVE BUILD IMPROVE
---- -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000................. 46.46 46.46 46.36 26.58 46.46 -- 0.0 % (0.2)% (42.8)% 0.0 %
2001................. 47.26 47.26 47.06 15.38 46.79 -- 0.0 % (0.4)% (67.5)% (1.0)%
2002................. 47.97 47.77 47.67 18.33 47.02 -- (0.4)% (0.6)% (61.8)% (2.0)%
2003................. 48.69 48.59 48.49 48.59 47.26 -- (0.2)% (0.4)% (0.2)% (2.9)%
2004................. 49.82 49.92 49.42 49.52 47.89 -- 0.2 % (0.8)% (0.6)% (3.9)%
2005................. 50.56 50.36 50.76 50.46 48.12 -- (0.4)% 0.4 % (0.2)% (4.8)%
2006................. 52.11 51.31 51.31 51.81 49.16 -- (1.5)% (1.5)% (0.6)% (5.7)%
2007................. 52.38 52.68 52.18 51.98 48.90 -- 0.6 % (0.4)% (0.8)% (6.6)%
2008................. 53.65 53.75 53.35 52.75 49.64 -- 0.2 % (0.6)% (1.7)% (7.5)%
2009................. 55.04 54.24 54.34 54.24 50.48 -- (1.5)% (1.3)% (1.5)% (8.3)%
2010................. 55.13 55.83 54.93 54.63 50.02 -- 1.3 % (0.4)% (0.9)% (9.3)%
2011................. 55.84 56.34 55.54 55.74 50.66 -- 0.9 % (0.5)% (0.2)% (9.3)%
2012................. 57.27 57.67 57.37 56.87 51.95 -- 0.7 % 0.2 % (0.7)% (9.3)%
2013................. 58.20 57.90 58.20 57.80 52.80 -- (0.5)% 0.0 % (0.7)% (9.3)%
2014................. 58.85 58.75 58.75 58.65 53.39 -- (0.2)% (0.2)% (0.3)% (9.3)%
2015................. 59.61 59.41 59.51 59.21 54.07 -- (0.3)% (0.2)% (0.7)% (9.3)%
2016................. 60.38 60.58 60.08 60.28 54.77 -- 0.3 % (0.5)% (0.2)% (9.3)%
2017................. 61.46 61.36 61.16 61.16 55.76 -- (0.2)% (0.5)% (0.5)% (9.3)%
2018................. 62.26 62.06 61.86 62.06 56.48 -- (0.3)% (0.6)% (0.3)% (9.3)%
2019................. 63.17 63.27 63.07 63.07 57.31 -- 0.2 % (0.2)% (0.2)% (9.3)%
2020................. 64.30 64.40 64.00 64.00 58.33 -- 0.2 % (0.5)% (0.5)% (9.3)%
2021................. 65.08 65.16 64.78 64.74 59.04 -- 0.1 % (0.5)% (0.5)% (9.3)%
2022................. 66.71 66.79 66.40 66.36 60.52 -- 0.1 % (0.5)% (0.5)% (9.3)%
2023................. 68.38 68.46 68.06 68.02 62.03 -- 0.1 % (0.5)% (0.5)% (9.3)%
2024................. 70.09 70.17 69.76 69.72 63.58 -- 0.1 % (0.5)% (0.5)% (9.3)%
2025................. 71.84 71.93 71.51 71.46 65.17 -- 0.1 % (0.5)% (0.5)% (9.3)%
2026................. 73.63 73.72 73.29 73.25 66.80 -- 0.1 % (0.5)% (0.5)% (9.3)%
2027................. 75.47 75.57 75.13 75.08 68.47 -- 0.1 % (0.5)% (0.5)% (9.3)%
2028................. 77.36 77.46 77.00 76.96 70.18 -- 0.1 % (0.5)% (0.5)% (9.3)%
2029................. 79.29 79.39 78.93 78.88 71.93 -- 0.1 % (0.5)% (0.5)% (9.3)%
2030................. 81.28 81.38 80.90 80.85 73.73 -- 0.1 % (0.5)% (0.5)% (9.3)%
</TABLE>
------------------------
* Assumes a 60% load factor based on SERC summer load factor for 1999 as
reported in EIA-411
As a result of the region's tight capacity situation, the only significant
sensitivities in the capacity price forecasts are seen in the overbuild scenario
and in the technological improvement scenario. In the overbuild scenario,
capacity prices drop over 60% from the base case in the early years of the
forecast. In the technological improvements scenario, capacity prices gradually
deviate from the base case forecast by an additional 1% per year in each of the
first 10 years of the forecast.
C-37
<PAGE>
FIGURE 12: CAPACITY PRICE RESULTS--SENSITIVITY ANALYSES
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
CAPACITY PRICES ($/KW-YR)
<S> <C> <C> <C> <C> <C>
BASE CASE LOW FUEL 12% RESERVE OVERBUILD TECH IMPROVE
2000 46.46 46.46 46.36 26.58 46.46
2001 47.26 47.26 47.06 15.38 46.79
2002 47.97 47.77 47.67 18.33 47.02
2003 48.69 48.59 48.49 48.59 47.26
2004 49.82 49.92 49.42 49.52 47.89
2005 50.56 50.36 50.76 50.46 48.12
2006 52.11 51.31 51.31 51.81 49.16
2007 52.38 52.68 52.18 51.98 48.90
2008 53.65 53.75 53.35 52.75 49.64
2009 55.04 54.24 54.34 54.24 50.48
2010 55.13 55.83 54.93 54.63 50.02
2011 55.84 56.34 55.54 55.74 50.66
2012 57.27 57.67 57.37 56.87 51.95
2013 58.20 57.90 58.20 57.80 52.80
2014 58.85 58.75 58.75 58.65 53.39
2015 59.61 59.41 59.51 59.21 54.07
2016 60.38 60.58 60.08 60.28 54.77
2017 61.46 61.36 61.16 61.16 55.76
2018 62.26 62.06 61.86 62.06 56.48
2019 63.17 63.27 63.07 63.07 57.31
2020 64.30 64.40 64.00 64.00 58.33
2021 65.08 65.16 64.78 64.74 59.04
2022 66.71 66.79 66.40 66.36 60.52
2023 68.38 68.46 68.06 68.02 62.03
2024 70.09 70.17 69.76 69.72 63.58
2025 71.84 71.93 71.51 71.46 65.17
2026 73.63 73.72 73.29 73.25 66.80
2027 75.47 75.57 75.13 75.08 68.47
2028 77.36 77.46 77.00 76.96 70.18
2029 79.29 79.39 78.93 78.88 71.93
2030 81.28 81.38 80.90 80.85 73.73
</TABLE>
The overbuild scenario merely accelerates the addition of capacity that is
forecast in the base case. This is best illustrated by a comparison between
capacity additions in the base case and capacity additions in the overbuild
scenario as shown in Table 15.
TABLE 15: CAPACITY ADDITIONS--BASE CASE VS. OVERBUILD SCENARIO
<TABLE>
<CAPTION>
BASE CASE CUMMULATIVE RESERVE OVERBUILD CUMMULATIVE RESERVE
YEAR ADDITIONS* ADDITIONS MARGIN ADDITIONS* ADDITIONS MARGIN
---- ---------- ----------- -------- ---------- ----------- --------
<S> <C> <C> <C> <C> <C> <C>
2000............................. 3,760 3,760 13% 7,510** 7,510 16%
2001............................. 4,570 8,330 15% 6,007** 13,517 19%
2002............................. 2,450 10,780 15% 450 13,967 17%
2003............................. 4,243 15,023 15% 1,060 15,027 15%
2004............................. 5,115 20,138 15% 5,118 20,145 15%
2005............................. 4,222 24,360 15% 4,226 24,371 15%
</TABLE>
------------------------
* Includes Merchant plants explicity added and incremental capacity added by
IREMM
** Also includes capacity added for Overbuild scenario
Table 15 shows that cumulative capacity additions in the overbuild scenario
are well ahead of those in the base case by the end of 2001. In the overbuild
scenario, the reserve margin rises to 19% by 2001. As a result, it becomes
uneconomic to build new capacity. Due to over capacity conditions, capacity
additions in the overbuild scenario slow in 2002 and 2003. By the end of 2003,
cumulative capacity additions match those of the base case. As a result, market
prices recover by 2003 as demand increases and the reserve margin falls back to
15%. From 2003 onward, the overbuild scenario results closely track base case
results. Moreover, it bears mentioning that assuming an additional 9,000 MW of
capacity will come on line before June 2001 is, in RDI's view, a very aggressive
assumption.
The overbuild scenario indicates that one of the primary risks to the
profitability of a new peaking unit is aggressive overbuilding in a region.
Employing the capacity price allocation methodology described above, total
on-peak prices in 2000 would be significantly lower in the overbuild scenario
C-38
<PAGE>
than in the base case. Figure 13 shows that the total price for August 2000 is
forecast to reach 39.37 $/ MWh in the overbuild scenario. RDI's total price
forecast for August 2000 in the base case approaches 70 $/MWh. This implies that
if the market were to overbuild capacity in the early years of the forecast,
price volatility would be dampened--limiting the opportunity for operators of
peaking units to capitalize on price spikes in a few hours of the year. Still,
if over building did occur, the market would likely react to the over-saturation
by not adding capacity until 2003 when the capacity market is brought back into
equilibrium. It is even possible that the market might not react until price
spikes occur, signaling the need for new demand. In such a case, prices could
spike higher than forecast by RDI in 2003 or 2004.
FIGURE 13: TOTAL PRICE OF FIRM POWER--OVERBUILD SCENARIO (2000)
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
TOTAL PRICE OF FIRM POWER (CAPACITY & ENERGY) $/MWH
<S> <C> <C>
ENERGY CAPACITY
JAN 21.85 -
FEB 20.53 -
MAR 20.51 -
APR 24.64 -
MAY 22.83 1.85
JUN 25.54 5.54
JUL 26.51 11.08
AUG 28.29 11.08
SEP 24.00 5.54
OCT 26.02 1.85
NOV 23.62 -
DEC 20.45 -
</TABLE>
It is RDI's opinion that over the next several years it is not likely that
there will be an overbuilding of capacity in the Southeast U.S. To date only
5,000 MW of new announced capacity additions appear likely to be built by 2002.
To maintain a level of capacity reserves that will prevent very sharp price
spikes in the market, at least another 5,000 MW of new capacity will need to be
developed, permitted, financed, and constructed by 2002. Overbuilding would
require even more new capacity additions. With new power plant development in
other regions of the country creating a significant demand for turbines,
developers will likely find it both expensive and difficult to acquire enough
turbines to meet this level of demand in such a short-time frame.
Beyond 2002, there is a chance that over the course of 30 years the region
may sometimes experience over-capacity. During these periods the value of firm
capacity may be diminished as shown in the over-build sensitivity analysis.
However, we also believe that price dips will be followed by price spikes as
shortages are likely to occur as well. Over the duration of the 30-year
contract, average future electricity prices should approximate the long run
marginal cost of electricity.
It is also important to note that two dynamics in the Southeast electricity
market are likely to diminish the potential for over-building. The first dynamic
is related to ownership concentration in the region. One of the keys to
commodity pricing is the asset ownership concentration in a region. High
concentration of asset ownership should provide pricing discipline in the
Southeast U.S. The top five companies in the Southeast control 70% of the
generating capacity. Within Alabama and Georgia, 75% of the generation assets
are controlled by only two companies. In the event of an overbuild scenario,
C-39
<PAGE>
these large companies will have significant economic incentives to temporarily
close a portion of their generation facilities to increase the value of their
other facilities that remain open. Such a high concentration of ownership is
likely to moderate the downward price impacts of an overbuild scenario. A second
dynamic is the rapid demand growth in the region. Robust demand growth serves to
mitigate the potential for over-building because excess supplies can more
quickly be absorbed by the market.
The second primary risk to combustion turbine profitability is demonstrated
in the technological improvement scenario. While the impact of technological
improvements is initially small, it is cumulative and becomes quite significant
by the middle years of the forecast. Due to the on-going nature of its effect on
capacity prices, the technological improvement scenario would reduce capacity
prices and consequently the profitability of the Tenaska Georgia Partner's
project.
CAPACITY FACTORS
The sensitivity analyses also provide insight on how changes in these
assumptions affect the Tenaska Georgia Partners project's utilization. Capacity
factors of peaking turbines will be most sensitive to changes in the
supply/demand balance in the region, the type of capacity added to the grid, and
improvements in peaking technology.
Figure 14 shows forecast capacity factors for the month of August in select
years of the forecast. Except in the overbuild scenario, the project's
utilization closely tracks base case results. Capacity factors in the overbuild
scenario are lower than the base case because there is a surplus of capacity
resulting from the overbuild. Capacity factors remain lower than the base case
throughout the forecast period because 1,500 additional megawatts of baseload
capacity is added in the early years of the overbuild scenario that is not added
in the base case. The additional baseload capacity moves all peaking capacity
back on the supply curve throughout the forecast period. Lower capacity factors
in the overbuild scenario indicate that the Tenaska Georgia Partner's project
would operate during substantially less hours if additional combined cycle
capacity is added to the region.
FIGURE 14: FORECAST AUGUST CAPACITY FACTORS--TENASKA GEORGIA PARTNER'S
PROJECT (SELECT YEARS)
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
AUGUST CAPACITY FACTORS
<S> <C> <C> <C> <C>
Base Case Low Fuel Overbuild 12% Reserve
2003 9% 9% 8% 11%
2005 14% 13% 7% 15%
2010 18% 16% 13% 17%
2015 14% 14% 5% 14%
2020 7% 8% 4% 8%
</TABLE>
Detailed monthly capacity factor results for all scenarios are included in
Appendix C.
C-40
<PAGE>
APPENDIX A:
GAS MARKET ISSUES IN THE SOUTHEAST REGION
This appendix examines gas supply, demand, and transportation issues in the
southeast region.
GAS SUPPLY
The southeast U.S. is primarily dependent on gas supplies from the Gulf
region, both onshore and offshore. The onshore regions of Louisiana,
Mississippi, and Alabama are mature production areas. New exploration in the
region will be required to maintain current production levels. The primary area
of interest from a supply expansion perspective is the Gulf of Mexico offshore.
The offshore region currently accounts for almost one-quarter of the
nation's gas supply with production above 5 Tcf per year. Recently, many
industry experts have begun to raise concerns about the rate at which producing
wells on the shelf of the Gulf of Mexico decline. Shelf production is currently
represents approximately 80% of total Gulf production. Decline rates are
expected to reach 45% by 2001, resulting in the need for substantial amounts of
drilling to replace existing production. Given the economics of the region, more
drilling is likely to translate into higher commodity prices. RDI forecasts that
over 1,300 well completions per year will have to occur in 2000 to satisfy
demand. By 2010, 1,700 well completions per year will be required.
It is RDI's view that the gas industry will be able to sustain the increased
gas production levels that will be required in the Gulf region. It is likely
that the deep-water and Eastern (Mobile Bay, Destin) areas of the Gulf will
sustain the majority of gas supply growth over the long term. RDI projects
annual production from the gulf to reach 7 Tcf (19 Bcfd) by 2010. Even though
drilling costs are expected to decline through 2010 as a result of technological
innovation, the increased depth of drilling and complexity of the formations
explored drives RDI's gas price forecast upward after 2006.
One other supply issue of concern is gas processing capacity in the
southeast. Processing facilities are currently near full utilization. Therefore
growth in gas supply from the Gulf will have to be met with increases in
processing capacity, tending to increase prices.
GAS TRANSPORTATION
The Southeast region currently has limited pipeline capacity. RDI estimates
that about 3.5 Bcfd can enter Transco pipeline at the Georgia border. Average
utilization is around 85% at this crossing point, which indicates that overall
capacity is fairly tight into Georgia on Transco. RDI's modeling indicates that
summertime utilization falls into the 65% range. RDI expects that capacity
utilization will tighten through 2006 at which time expansions will be
necessary. However, Transco has already taken several steps to alleviate any
potential pipeline capacity shortages. First, Transco has pursued development of
a project referred to as Southcoast. This pipeline expansion project, scheduled
to be completed in 2001, would increase pipeline capacity by 600 MMcfd in the
Alabama and Georgia region. This capacity expansion alone would create enough
new pipeline capacity to satisfy demand through the next decade. Another
project, referred to as Cumberland, would increase Transco's pipeline capacity
by another 200 MMcfd in Northern Georgia.
Other pipeline expansions are also forecast during the 2000 to 2010 period.
Several major expansions are forecast for Florida Gas Transmission (FGT) at
Mobile Bay, Alabama. One other major project includes a new pipeline called
Palmetto which is proposed for the Carolinas.
One controversial project included in the RDI forecast is an expansion from
the offshore Gulf to Florida. RDI's forecast includes a 600 MMcfd expansion from
the Gulf as an alternative to continued expansions of FGT. In March 1999
Williams' Buccaneer project was joined by a competing project sponsored by
Coastal called Gulfstream. The State of Florida is very protective of its
coastal waters, and either one of these projects would have to pass stringent
environmental reviews. The state has
C-A-1
<PAGE>
adamantly opposed offshore pipes on the coast of Florida in the past. On the
other hand, the economic rationale for building the system is strong. As gas
drilling operations move further east from the Mobile Bay area into the Destin
Dome region at the tip of the Florida panhandle and as gas demand for electric
generation surges in Florida, an offshore pipeline into Florida linking these
areas of supply and demand has compelling economic logic.
One other gas transportation issues of note is that final FERC decisions on
short term capacity are still lingering. It is possible that a FERC decision
could result in auctions that might free up pipe capacity as portions of firm
transportation contracts are offered back to the market for short time periods.
GAS DEMAND
Gas demand in the Southeast is anchored by strong industrial gas demand.
Weather conditions in the region are generally mild so swings in residential and
commercial demand are minimal. Electric sector gas demand currently plays a very
small role in the region, but growth in this sector will generate the bulk of
new demand. Although electric generation will be extremely important to demand
growth, the high levels of population and economic growth will also contribute
to future demand growth.
Figure APP-1 shows projected gas demand by year and sector for the State of
Georgia. Electric generation demand is expected to increase at an annual average
rate of 160% per year as demand for this sector grows from a value very close to
zero. By 2010 annual demand is expected to reach 500 Bcf. Residential and
commercial demand is forecast to increase at a rate of 2.3% per year. RDI
expects total U.S. annual gas consumption to reach 30 Tcf in 2011, of which
electric generation demand will be about 9 Tcf, inclusive of grid connected
cogeneration.
One final factor affecting markets in Georgia is the introduction of
competition for gas supply at the residential customer level. By the end of the
year Atlanta Gas Light will have completely exited the merchant function. So far
customer response to choice has been mild, but now customers will have to choose
a supplier or be assigned to a marketer. This arrangement has given rise to a
number of unique marketing ploys. For example Columbia Gas Marketing is using
Amway distributors. Unbundling is not expected to change demand dramatically,
but it should cause an increase in the number of gas marketers holding pipe
capacity into Georgia. Potentially, this could increase the liquidity of the
secondary market for transmission capacity.
FIGURE APP-1: NATURAL GAS DEMAND FORECAST FOR GEORGIA
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
NATURAL GAS DEMAND IN BILLIONS OF CUBIC FEET
<S> <C> <C> <C>
BCF ELECTRIC GENERATION INDUSTRIAL RESIDENTIAL-COMMERCIAL
1998 9 175 192
1999 4 177 203
2000 28 177 210
2001 38 180 213
2002 52 180 218
2003 70 182 222
2004 91 181 227
2005 106 183 232
2006 119 185 238
2007 135 190 242
2008 155 191 244
2009 172 191 247
2010 203 196 249
</TABLE>
C-A-2
<PAGE>
APPENDIX B:
NUCLEAR LICENSE EXPIRATION DATES IS SERC
<TABLE>
<CAPTION>
OPERATING
CAPACITY LICENSE
OPERATOR PLANT STATE M/W EXP. DATE
-------- --------------------------- -------- -------- ------------------
<S> <C> <C> <C> <C> <C>
CP&L................................. Brunswick 1 NC 813 September 8, 2016
CP&L................................. Brunswick 2 NC 810 December 27, 2014
CP&L................................. Harris 1 NC 860 October 24, 2026
CP&L................................. Robinson 2 SC 683 July 31, 2010
Duke................................. Catawba 1 SC 1,129 December 6, 2024
Duke................................. Catawba 2 SC 1,129 February 24, 2026
Duke................................. McGuire 1 NC 1,129 June 12, 2021
Duke................................. McGuire 2 NC 1,129 March 3, 2023
Duke................................. Oconee 1 SC 846 February 6, 2013
Duke................................. Oconee 2 SC 846 October 6, 2013
Duke................................. Oconee 3 SC 846 July 19, 2014
SCANA................................ Summer 1 SC 942 August 6, 2022
Southern............................. Edwin I. Hatch 1 GA 813 August 6, 2014
Southern............................. Edwin I. Hatch 2 GA 813 June 13, 2018
Southern............................. Joseph M. Farley 1 AL 824 June 25, 2017
Southern............................. Joseph M. Farley 2 AL 854 March 31, 2021
Southern............................. Vogtie 1 GA 1,164 January 16, 2027
Southern............................. Vogtie 2 GA 1,164 February 9, 2029
TVA.................................. Browns Ferry 2 AL 1,116 June 28, 2014
TVA.................................. Browns Ferry 3 AL 1,110 July 2, 2016
TVA.................................. Sequoyah 1 TN 1,119 September 17, 2020
TVA.................................. Sequoyah 2 TN 1,119 September 15, 2021
TVA.................................. Watts Par 1 TN 1,122 November 9, 2035
Virginia Power....................... North Anna 1 VA 893 April 1, 2018
Virginia Power....................... North Anna 2 VA 897 August 21, 2020
Virginia Power....................... Surry 1 VA 801 May 25, 2012
Virginia Power....................... Surry 2 VA 801 January 29, 2013
</TABLE>
C-B-1
<PAGE>
APPENDIX C:
DETAILED MONTHLY CAPACITY FACTORS--BASE CASE
<TABLE>
<CAPTION>
TENASKA GEORGIA POWER PARTNERS
MONTHLY PLANT GENERATION (GWH)
------------------------------
JAN FEB MAR APR MAY JUN JUL AUG
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
2001................................. -- -- -- -- -- 9 17 21
2002................................. -- 3 1 -- 5 11 41 42
2003................................. -- 5 1 -- 8 31 57 63
2004................................. 2 6 -- -- 18 38 62 78
2005................................. 9 7 8 -- 22 70 86 91
2006................................. 9 6 10 5 24 73 90 110
2007................................. 12 6 6 -- 24 78 93 111
2008................................. 10 10 11 -- 27 75 93 112
2009................................. 12 8 11 4 26 78 94 118
2010................................. 11 6 9 -- 25 72 98 120
2011................................. 11 10 10 1 24 68 89 105
2012................................. 10 8 8 2 24 72 96 114
2013................................. 8 7 8 -- 24 60 88 104
2014................................. 7 5 8 2 20 51 78 87
2015................................. 5 4 4 -- 22 51 79 92
2016................................. 5 5 2 -- 18 54 79 82
2017................................. 5 5 5 -- 18 33 80 68
2018................................. -- -- -- -- 16 35 72 73
2019................................. -- -- -- -- 15 30 67 65
2020................................. -- -- -- -- 14 27 57 49
2021................................. -- -- -- -- 2 20 47 40
<CAPTION>
TENASKA GEORGIA POWER PARTNERS
MONTHLY PLANT GENERATION (GWH)
SEP OCT NOV DEC TOTAL
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
2001................................. 4 -- -- 3 54
2002................................. 12 3 -- 6 124
2003................................. 18 -- -- 3 186
2004................................. 16 6 -- 8 234
2005................................. 29 19 3 6 349
2006................................. 41 17 2 6 393
2007................................. 39 23 15 12 419
2008................................. 40 18 16 9 421
2009................................. 49 36 9 8 453
2010................................. 40 20 15 11 428
2011................................. 45 21 13 11 408
2012................................. 49 24 6 7 420
2013................................. 33 15 13 6 366
2014................................. 31 19 5 6 319
2015................................. 36 5 2 3 303
2016................................. 22 4 -- 2 273
2017................................. 20 6 -- 5 245
2018................................. 28 2 -- -- 226
2019................................. 15 2 -- -- 194
2020................................. 13 2 -- -- 162
2021................................. 4 -- -- -- 113
</TABLE>
<TABLE>
<CAPTION>
MONTHLY CAPACITY FACTORS
------------------------
JAN FEB MAR APR MAY JUN JUL AUG SEP
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2001...................... 0% 0% 0% 0% 0% 3% 5% 6% 1%
2002...................... 0% 1% 0% 0% 1% 2% 6% 6% 2%
2003...................... 0% 1% 0% 0% 1% 5% 8% 9% 3%
2004...................... 0% 1% 0% 0% 3% 6% 9% 12% 2%
2005...................... 1% 1% 1% 0% 3% 11% 13% 14% 4%
2006...................... 1% 1% 1% 1% 4% 11% 13% 16% 6%
2007...................... 2% 1% 1% 0% 4% 12% 14% 17% 6%
2008...................... 1% 2% 2% 0% 4% 12% 14% 17% 6%
2009...................... 2% 1% 2% 1% 4% 12% 14% 18% 8%
2010...................... 2% 1% 1% 0% 4% 11% 15% 18% 6%
2011...................... 2% 2% 1% 0% 4% 10% 13% 16% 7%
2012...................... 1% 1% 1% 0% 4% 11% 14% 17% 8%
2013...................... 1% 1% 1% 0% 4% 9% 13% 16% 5%
2014...................... 1% 1% 1% 0% 3% 8% 12% 13% 5%
2015...................... 1% 1% 1% 0% 3% 8% 12% 14% 6%
2016...................... 1% 1% 0% 0% 3% 8% 12% 12% 3%
2017...................... 1% 1% 1% 0% 3% 5% 12% 10% 3%
2018...................... 0% 0% 0% 0% 2% 5% 11% 11% 4%
2019...................... 0% 0% 0% 0% 2% 5% 10% 10% 2%
2020...................... 0% 0% 0% 0% 2% 4% 9% 7% 2%
2021...................... 0% 0% 0% 0% 0% 3% 7% 6% 1%
--- --- --- --- --- --- --- --- ---
AVERAGE................... 1% 1% 1% 0% 3% 8% 11% 13% 4%
<CAPTION>
MONTHLY CAPACITY FACTORS
OCT NOV DEC AVG
-------- -------- -------- --------
<S> <C> <C> <C> <C>
2001...................... 0% 0% 1% 2%
2002...................... 0% 0% 1% 2%
2003...................... 0% 0% 0% 2%
2004...................... 1% 0% 1% 3%
2005...................... 3% 0% 1% 4%
2006...................... 3% 0% 1% 5%
2007...................... 3% 2% 2% 5%
2008...................... 3% 2% 1% 5%
2009...................... 5% 1% 1% 6%
2010...................... 3% 2% 2% 5%
2011...................... 3% 2% 2% 5%
2012...................... 4% 1% 1% 5%
2013...................... 2% 2% 1% 5%
2014...................... 3% 1% 1% 4%
2015...................... 1% 0% 0% 4%
2016...................... 1% 0% 0% 3%
2017...................... 1% 0% 1% 3%
2018...................... 0% 0% 0% 3%
2019...................... 0% 0% 0% 2%
2020...................... 0% 0% 0% 2%
2021...................... 0% 0% 0% 1%
--- --- --- ---
AVERAGE................... 2% 1% 1% 4%
</TABLE>
* Assumes 450 MW on line in June, 2001 and 450 MW on line in June, 2002
C-C-1
<PAGE>
SUMMARY
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003...................... 0% 1% 0% 0% 1% 5% 8% 9% 3%
2005...................... 1% 1% 1% 0% 3% 11% 13% 14% 4%
2010...................... 2% 1% 1% 0% 4% 11% 15% 18% 6%
2015...................... 1% 1% 1% 0% 3% 8% 12% 14% 6%
2020...................... 0% 0% 0% 0% 2% 4% 9% 7% 2%
--- --- --- --- --- --- --- --- ---
AVG 2000-2021............. 1% 1% 1% 0% 3% 8% 11% 13% 4%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003...................... 0% 0% 0% 2%
2005...................... 3% 0% 1% 4%
2010...................... 3% 2% 2% 5%
2015...................... 1% 0% 0% 4%
2020...................... 0% 0% 0% 2%
--- --- --- ---
AVG 2000-2021............. 2% 1% 1% 4%
</TABLE>
REVISED START-UPS
<TABLE>
<CAPTION>
YR JAN FEB MAR APR MAY JUN JUL AUG SEP
-- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003..................... 0% 1% 0% 0% 1% 5% 8% 9% 3%
2005..................... 1% 1% 1% 0% 3% 11% 13% 14% 4%
<CAPTION>
YR OCT NOV DEC TOTAL
-- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003..................... 0% 0% 0% 2.4%
2005..................... 3% 0% 1% 4.4%
</TABLE>
C-C-2
<PAGE>
APPENDIX C:
DETAILED MONTHLY CAPACITY FACTORS--LOW FUEL SCENARIO
<TABLE>
<CAPTION>
TENASKA GEORGIA POWER PARTNERS
MONTHLY PLANT GENERATION (GWH)
------------------------------
YEAR JAN FEB MAR APR MAY JUN JUL AUG
---- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
2001................................. -- -- -- -- -- 9 20 25
2002................................. -- 3 -- -- 6 22 50 42
2003................................. -- 6 -- -- 11 35 58 63
2004................................. 4 6 2 -- 17 52 70 86
2005................................. 8 8 10 -- 20 60 81 87
2006................................. 11 9 10 7 23 60 86 105
2007................................. 13 6 10 3 23 79 98 110
2008................................. 9 6 9 2 24 76 93 111
2009................................. 9 9 9 1 25 74 97 117
2010................................. 14 9 7 2 24 80 95 109
2011................................. 13 10 9 4 24 78 92 109
2012................................. 9 9 8 5 24 70 93 110
2013................................. 6 7 6 2 24 66 85 100
2014................................. 7 6 7 1 22 56 82 97
2015................................. 6 6 4 -- 24 52 82 95
2016................................. 4 5 1 -- 18 53 75 84
2017................................. 3 2 3 -- 18 38 66 68
2018................................. 5 2 1 -- 18 47 72 81
2019................................. 3 -- -- -- 18 27 58 64
2020................................. -- -- -- -- 14 22 56 52
2021................................. -- -- -- -- 4 14 47 40
<CAPTION>
TENASKA GEORGIA POWER PARTNERS
MONTHLY PLANT GENERATION (GWH)
YEAR SEP OCT NOV DEC TOTAL
---- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
2001................................. 5 -- -- 3 62
2002................................. 12 1 -- 5 141
2003................................. 22 1 -- 6 202
2004................................. 19 5 -- 6 267
2005................................. 26 6 9 11 326
2006................................. 39 8 3 8 369
2007................................. 37 26 15 11 431
2008................................. 46 26 13 9 424
2009................................. 51 19 1 8 420
2010................................. 43 28 18 7 436
2011................................. 46 33 8 6 432
2012................................. 50 25 3 9 415
2013................................. 38 20 7 8 369
2014................................. 39 18 1 6 342
2015................................. 37 12 -- 6 324
2016................................. 28 4 -- 6 278
2017................................. 21 8 -- 2 229
2018................................. 35 3 -- 3 267
2019................................. 12 2 -- 3 187
2020................................. 14 2 -- -- 160
2021................................. 2 -- -- -- 107
</TABLE>
<TABLE>
<CAPTION>
MONTHLY CAPACITY FACTORS
------------------------
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2001...................... 0% 0% 0% 0% 0% 3% 6% 7% 2%
2002...................... 0% 1% 0% 0% 2% 3% 7% 6% 2%
2003...................... 0% 1% 0% 0% 2% 5% 9% 9% 3%
2004...................... 1% 1% 0% 0% 3% 8% 10% 13% 3%
2005...................... 1% 1% 1% 0% 3% 9% 12% 13% 4%
2006...................... 2% 1% 1% 1% 3% 9% 13% 16% 6%
2007...................... 2% 1% 1% 0% 3% 12% 15% 16% 6%
2008...................... 1% 1% 1% 0% 4% 12% 14% 17% 7%
2009...................... 1% 1% 1% 0% 4% 11% 14% 17% 8%
2010...................... 2% 1% 1% 0% 4% 12% 14% 16% 7%
2011...................... 2% 2% 1% 1% 4% 12% 14% 16% 7%
2012...................... 1% 1% 1% 1% 4% 11% 14% 16% 8%
2013...................... 1% 1% 1% 0% 4% 10% 13% 15% 6%
2014...................... 1% 1% 1% 0% 3% 9% 12% 14% 6%
2015...................... 1% 1% 1% 0% 4% 8% 12% 14% 6%
2016...................... 1% 1% 0% 0% 3% 8% 11% 13% 4%
2017...................... 0% 0% 0% 0% 3% 6% 10% 10% 3%
2018...................... 1% 0% 0% 0% 3% 7% 11% 12% 5%
2019...................... 0% 0% 0% 0% 3% 4% 9% 10% 2%
2020...................... 0% 0% 0% 0% 2% 3% 8% 8% 2%
2021...................... 0% 0% 0% 0% 1% 2% 7% 6% 0%
--- --- --- --- --- --- --- --- ---
AVERAGE................... 1% 1% 1% 0% 3% 8% 11% 13% 5%
<CAPTION>
MONTHLY CAPACITY FACTORS
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2001...................... 0% 0% 1% 3%
2002...................... 0% 0% 1% 2%
2003...................... 0% 0% 1% 3%
2004...................... 1% 0% 1% 3%
2005...................... 1% 1% 2% 4%
2006...................... 1% 0% 1% 5%
2007...................... 4% 2% 2% 5%
2008...................... 4% 2% 1% 5%
2009...................... 3% 0% 1% 5%
2010...................... 4% 3% 1% 6%
2011...................... 5% 1% 1% 5%
2012...................... 4% 0% 1% 5%
2013...................... 3% 1% 1% 5%
2014...................... 3% 0% 1% 4%
2015...................... 2% 0% 1% 4%
2016...................... 1% 0% 1% 4%
2017...................... 1% 0% 0% 3%
2018...................... 0% 0% 0% 3%
2019...................... 0% 0% 0% 2%
2020...................... 0% 0% 0% 2%
2021...................... 0% 0% 0% 1%
--- --- --- ---
AVERAGE................... 2% 1% 1% 4%
</TABLE>
C-C-3
<PAGE>
SUMMARY
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003...................... 0% 1% 0% 0% 2% 5% 9% 9% 3%
2005...................... 1% 1% 1% 0% 3% 9% 12% 13% 4%
2010...................... 2% 1% 1% 0% 4% 12% 14% 16% 7%
2015...................... 1% 1% 1% 0% 4% 8% 12% 14% 6%
2020...................... 0% 0% 0% 0% 2% 3% 8% 8% 2%
--- --- --- --- --- --- --- --- ---
AVG....................... 1% 1% 1% 0% 3% 8% 11% 13% 5%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003...................... 0% 0% 1% 3%
2005...................... 1% 1% 2% 4%
2010...................... 4% 3% 1% 6%
2015...................... 2% 0% 1% 4%
2020...................... 0% 0% 0% 2%
--- --- --- ---
AVG....................... 2% 1% 1% 4%
</TABLE>
C-C-4
<PAGE>
APPENDIX C:
DETAILED MONTHLY CAPACITY FACTORS--OVERBUILD SCENARIO
<TABLE>
<CAPTION>
TENASKA GEORGIA POWER PARTNERS
MONTHLY PLANT GENERATION (GWH)
------------------------------
YEAR JAN FEB MAR APR MAY JUN JUL AUG
---- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
2001................................. -- -- -- -- -- 2 8 13
2002................................. 1 3 -- -- 6 12 42 46
2003................................. -- 8 -- -- 10 22 36 54
2004................................. 3 8 -- -- 22 -- 49 46
2005................................. 7 2 6 -- 13 42 23 44
2006................................. 8 6 6 3 10 33 52 100
2007................................. -- 12 -- 3 5 16 37 63
2008................................. 8 9 -- -- 9 4 23 40
2009................................. 7 7 -- 5 10 65 91 107
2010................................. 3 8 8 -- 15 49 74 88
2011................................. -- 2 3 2 28 18 62 62
2012................................. 6 6 6 6 20 39 39 75
2013................................. 7 5 9 1 16 44 75 86
2014................................. 7 4 -- -- -- -- 16 17
2015................................. 3 -- -- -- 12 12 25 31
2016................................. 1 1 3 -- -- 1 55 57
2017................................. -- 6 4 -- 14 31 52 63
2018................................. 2 -- 3 -- 10 20 27 24
2019................................. -- 2 -- -- 8 15 37 37
2020................................. -- 4 1 -- 9 15 30 29
2021................................. -- -- -- -- 7 23 74 61
<CAPTION>
TENASKA GEORGIA POWER PARTNERS
MONTHLY PLANT GENERATION (GWH)
YEAR SEP OCT NOV DEC TOTAL
---- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
2001................................. 3 -- -- 2 28
2002................................. 17 6 -- 6 139
2003................................. 6 4 7 8 155
2004................................. 19 -- 8 10 165
2005................................. 11 12 -- 6 166
2006................................. 10 21 1 10 260
2007................................. 24 24 -- 6 190
2008................................. 9 5 13 10 130
2009................................. -- 21 1 6 320
2010................................. 19 14 18 13 309
2011................................. 43 10 4 10 244
2012................................. 30 16 6 10 259
2013................................. 30 13 12 -- 298
2014................................. 6 -- 2 6 58
2015................................. 8 -- -- -- 91
2016................................. 24 5 -- 1 148
2017................................. 25 9 -- 2 206
2018................................. 7 3 -- 2 98
2019................................. 9 2 -- -- 110
2020................................. 8 2 -- -- 98
2021................................. 5 -- -- -- 170
</TABLE>
<TABLE>
<CAPTION>
MONTHLY CAPACITY FACTORS
------------------------
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2001...................... 0% 0% 0% 0% 0% 1% 2% 4% 1%
2002...................... 0% 1% 0% 0% 2% 2% 6% 7% 3%
2003...................... 0% 1% 0% 0% 1% 3% 5% 8% 1%
2004...................... 0% 1% 0% 0% 3% 0% 7% 7% 3%
2005...................... 1% 0% 1% 0% 2% 6% 3% 7% 2%
2006...................... 1% 1% 1% 0% 1% 5% 8% 15% 2%
2007...................... 0% 2% 0% 0% 1% 2% 6% 9% 4%
2008...................... 1% 1% 0% 0% 1% 1% 3% 6% 1%
2009...................... 1% 1% 0% 1% 1% 10% 14% 16% 0%
2010...................... 0% 1% 1% 0% 2% 8% 11% 13% 3%
2011...................... 0% 0% 0% 0% 4% 3% 9% 9% 7%
2012...................... 1% 1% 1% 1% 3% 6% 6% 11% 5%
2013...................... 1% 1% 1% 0% 2% 7% 11% 13% 5%
2014...................... 1% 1% 0% 0% 0% 0% 2% 3% 1%
2015...................... 0% 0% 0% 0% 2% 2% 4% 5% 1%
2016...................... 0% 0% 0% 0% 0% 0% 8% 9% 4%
2017...................... 0% 1% 1% 0% 2% 5% 8% 9% 4%
2018...................... 0% 0% 0% 0% 1% 3% 4% 4% 1%
2019...................... 0% 0% 0% 0% 1% 2% 6% 6% 1%
2020...................... 0% 1% 0% 0% 1% 2% 4% 4% 1%
2021...................... 0% 0% 0% 0% 1% 4% 11% 9% 1%
--- --- --- --- --- --- --- --- ---
AVERAGE................... 0% 1% 0% 0% 2% 3% 7% 8% 2%
<CAPTION>
MONTHLY CAPACITY FACTORS
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2001...................... 0% 0% 1% 1%
2002...................... 1% 0% 1% 2%
2003...................... 1% 1% 1% 2%
2004...................... 0% 1% 1% 2%
2005...................... 2% 0% 1% 2%
2006...................... 3% 0% 1% 3%
2007...................... 4% 0% 1% 2%
2008...................... 1% 2% 1% 2%
2009...................... 3% 0% 1% 4%
2010...................... 2% 3% 2% 4%
2011...................... 1% 1% 1% 3%
2012...................... 2% 1% 1% 3%
2013...................... 2% 2% 0% 4%
2014...................... 0% 0% 1% 1%
2015...................... 0% 0% 0% 1%
2016...................... 1% 0% 0% 2%
2017...................... 1% 0% 0% 3%
2018...................... 0% 0% 0% 1%
2019...................... 0% 0% 0% 1%
2020...................... 0% 0% 0% 1%
2021...................... 0% 0% 0% 2%
--- --- --- ---
AVERAGE................... 1% 1% 1% 2%
</TABLE>
C-C-5
<PAGE>
SUMMARY
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003...................... 0% 1% 0% 0% 1% 3% 5% 8% 1%
2005...................... 1% 0% 1% 0% 2% 6% 3% 7% 2%
2010...................... 0% 1% 1% 0% 2% 8% 11% 13% 3%
2015...................... 0% 0% 0% 0% 2% 2% 4% 5% 1%
2020...................... 0% 1% 0% 0% 1% 2% 4% 4% 1%
--- --- --- --- --- --- --- --- ---
AVG 2000-2021............. 0% 1% 0% 0% 2% 3% 7% 8% 2%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003...................... 1% 1% 1% 2%
2005...................... 2% 0% 1% 2%
2010...................... 2% 3% 2% 4%
2015...................... 0% 0% 0% 1%
2020...................... 0% 0% 0% 1%
--- --- --- ---
AVG 2000-2021............. 1% 1% 1% 2%
</TABLE>
C-C-6
<PAGE>
APPENDIX C:
DETAILED MONTHLY CAPACITY FACTOR--12% RESERVE SCENARIO
<TABLE>
<CAPTION>
TENASKA GEORGIA POWER PARTNERS
MONTHLY PLANT GENERATION (GWH)
------------------------------
JAN FEB MAR APR MAY JUN JUL AUG
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
2001................................. -- -- -- -- -- 10 17 24
2002................................. 1 3 2 -- 5 17 42 49
2003................................. 3 6 3 -- 14 38 60 74
2004................................. 3 7 2 -- 21 42 68 85
2005................................. 11 14 12 2 25 76 88 100
2006................................. 10 10 10 8 25 73 91 115
2007................................. 12 6 9 -- 26 77 92 111
2008................................. 11 10 11 2 27 73 94 111
2009................................. 12 8 13 2 26 78 97 118
2010................................. 14 9 12 -- 30 72 93 112
2011................................. 11 9 12 2 27 69 85 100
2012................................. 7 8 8 2 24 69 95 113
2013................................. 8 6 8 -- 25 59 86 102
2014................................. 11 6 11 -- 20 53 77 86
2015................................. 5 6 6 -- 24 49 78 93
2016................................. 5 5 5 1 19 53 78 80
2017................................. 2 5 5 -- 18 34 74 69
2018................................. -- 3 1 -- 18 32 72 74
2019................................. -- 6 -- -- 14 29 65 64
2020................................. -- -- -- -- 13 29 58 56
2021................................. -- -- -- -- -- 20 48 40
<CAPTION>
TENASKA GEORGIA POWER PARTNERS
MONTHLY PLANT GENERATION (GWH)
SEP OCT NOV DEC TOTAL
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
2001................................. 4 -- -- 3 58
2002................................. 16 6 -- 6 147
2003................................. 24 7 2 6 237
2004................................. 24 10 3 9 274
2005................................. 34 27 18 10 417
2006................................. 44 19 5 7 417
2007................................. 41 20 13 12 419
2008................................. 42 18 21 9 429
2009................................. 52 41 13 12 472
2010................................. 43 28 22 9 444
2011................................. 44 18 12 9 398
2012................................. 46 19 6 7 404
2013................................. 31 13 14 6 358
2014................................. 35 17 5 6 327
2015................................. 34 6 2 5 308
2016................................. 25 4 -- 3 278
2017................................. 19 6 1 5 238
2018................................. 28 2 -- -- 230
2019................................. 16 2 -- 2 198
2020................................. 13 3 -- 1 173
2021................................. 4 -- -- -- 112
</TABLE>
<TABLE>
<CAPTION>
MONTHLY CAPACITY FACTORS
------------------------------------------------------------------------------------------------
JAN FEB MAR APR MAY JUN JUL AUG SEP
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2001...................... 0% 0% 0% 0% 0% 3% 5% 7% 1%
2002...................... 0% 1% 1% 0% 1% 3% 6% 7% 2%
2003...................... 0% 1% 0% 0% 2% 6% 9% 11% 4%
2004...................... 0% 1% 0% 0% 3% 6% 10% 13% 4%
2005...................... 2% 2% 2% 0% 4% 12% 13% 15% 5%
2006...................... 1% 2% 1% 1% 4% 11% 14% 17% 7%
2007...................... 2% 1% 1% 0% 4% 12% 14% 17% 6%
2008...................... 2% 2% 2% 0% 4% 11% 14% 17% 6%
2009...................... 2% 1% 2% 0% 4% 12% 14% 18% 8%
2010...................... 2% 1% 2% 0% 4% 11% 14% 17% 7%
2011...................... 2% 1% 2% 0% 4% 11% 13% 15% 7%
2012...................... 1% 1% 1% 0% 4% 11% 14% 17% 7%
2013...................... 1% 1% 1% 0% 4% 9% 13% 15% 5%
2014...................... 2% 1% 2% 0% 3% 8% 11% 13% 5%
2015...................... 1% 1% 1% 0% 4% 8% 12% 14% 5%
2016...................... 1% 1% 1% 0% 3% 8% 12% 12% 4%
2017...................... 0% 1% 1% 0% 3% 5% 11% 10% 3%
2018...................... 0% 0% 0% 0% 3% 5% 11% 11% 4%
2019...................... 0% 1% 0% 0% 2% 4% 10% 10% 2%
2020...................... 0% 0% 0% 0% 2% 4% 9% 8% 2%
2021...................... 0% 0% 0% 0% 0% 3% 7% 6% 1%
--- --- --- --- --- --- --- --- ---
AVERAGE................... 1% 1% 1% 0% 3% 8% 11% 13% 5%
<CAPTION>
MONTHLY CAPACITY FACTORS
------------------------------
OCT NOV DEC AVG
-------- -------- -------- --------
<S> <C> <C> <C> <C>
2001...................... 0% 0% 1% 3%
2002...................... 1% 0% 1% 2%
2003...................... 1% 0% 1% 3%
2004...................... 1% 0% 1% 3%
2005...................... 4% 3% 1% 5%
2006...................... 3% 1% 1% 5%
2007...................... 3% 2% 2% 5%
2008...................... 3% 3% 1% 5%
2009...................... 6% 2% 2% 6%
2010...................... 4% 3% 1% 6%
2011...................... 3% 2% 1% 5%
2012...................... 3% 1% 1% 5%
2013...................... 2% 2% 1% 5%
2014...................... 3% 1% 1% 4%
2015...................... 1% 0% 1% 4%
2016...................... 1% 0% 0% 4%
2017...................... 1% 0% 1% 3%
2018...................... 0% 0% 0% 3%
2019...................... 0% 0% 0% 3%
2020...................... 0% 0% 0% 2%
2021...................... 0% 0% 0% 1%
--- --- --- ---
AVERAGE................... 2% 1% 1% 4%
</TABLE>
C-C-7
<PAGE>
SUMMARY
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003...................... 0% 1% 0% 0% 2% 6% 9% 11% 4%
2005...................... 2% 2% 2% 0% 4% 12% 13% 15% 5%
2010...................... 2% 1% 2% 0% 4% 11% 14% 17% 7%
2015...................... 1% 1% 1% 0% 4% 8% 12% 14% 5%
2020...................... 0% 0% 0% 0% 2% 4% 9% 8% 2%
AVG 2000-2021............. 1% 1% 1% 0% 3% 8% 11% 13% 5%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003...................... 1% 0% 1% 3%
2005...................... 4% 3% 1% 5%
2010...................... 4% 3% 1% 6%
2015...................... 1% 0% 1% 4%
2020...................... 0% 0% 0% 2%
AVG 2000-2021............. 2% 1% 1% 4%
</TABLE>
DIFFERENCE
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003................... 0% 0% 0% 0% 1% 1% (1)% (1)% 1%
2005................... 0% 0% 1% 0% 0% (1)% (1)% 0% 1%
2010................... 0% 0% 0% 0% 0% (1)% (1)% (2)% 0%
2015................... 0% 1% 0% 0% 0% 0% (1)% 0% 0%
2020................... 0% 0% 0% 0% 0% 1% 1% 1% 1%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003................... 0% 0% 0% 0%
2005................... (1)% 0% 1% 0%
2010................... 0% 0% 0% 0%
2015................... 1% 0% 0% 0%
2020................... 0% 0% 0% 0%
</TABLE>
C-C-8
<PAGE>
APPENDIX D:
HOURLY PROFIT ANALYSIS
RDI performed an analysis of the average profits achieved by the Tenaska
Georgia Partner's project in select years of the forecast. The analysis was
performed for the years 2003 (the first full year in which the entire plant is
on line), 2005, 2010, 2015 and 2020. In each of these years, RDI compared the
market price recorded by IREMM to the dispatch cost of the plant in each hour
for which any unit at the plant was called upon to run. This analysis was used
to derive profits achieved from the energy market. To determine total
contributions to fixed costs, RDI further included revenues received from the
capacity market.
Table APP-2 summarizes the results of the hourly profit analysis on an
annual basis. Tables showing the results of the analysis summarized on a monthly
basis are attached within the following pages of Appendix D. In the monthly
tables, the annual capacity price is allocated to each month according to the
methodology described in the report above(11). That is, the annual price was
allocated only to the following months: May (5%); June (15%); July (30%); August
(30%); September (15%); and October (5%).
APP-2: HOURLY PROFIT ANALYSIS--ANNUAL SUMMARY
<TABLE>
<CAPTION>
TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT.
------------------------------ ------------------- ------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
YEAR GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003.................. 186 8,051 43.19 39.83 626 3.36 48.69 43,819 44,445
2005.................. 349 15,259 43.70 42.53 411 1.18 50.56 45,504 45,915
2010.................. 428 22,401 52.31 51.65 280 0.65 55.13 49,621 49,901
2015.................. 303 17,837 58.83 58.19 195 0.64 59.61 53.646 53,841
2020.................. 162 10,738 66.23 65.62 99 0.61 64.30 57,868 57,967
</TABLE>
APPENDIX D: HOURLY PROFIT ANALYSIS - 2003
BASE CASE SCENARIO
<TABLE>
<CAPTION>
TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT.
------------------------------ ------------------- ------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2003 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN................... -- -- -- 42.68 -- -- -- -- --
FEB................... 5 225 46.41 41.78 22 4.63 -- -- 22
MAR................... 1 36 42.08 40.68 1 1.40 -- -- 1
APR................... -- -- -- 39.78 -- -- -- -- --
MAY................... 8 343 40.39 39.48 8 0.91 2.43 2,191 2,199
JUN................... 31 1,248 40.24 39.48 24 0.76 7.30 6,573 6,596
JUL................... 57 2,405 42.40 39.78 149 2.62 14.61 13,146 13,294
AUG................... 63 2,864 45.57 39.78 364 5.79 14.61 13,146 13,510
SEP................... 18 777 42.35 39.78 47 2.57 7.30 6,573 6,620
OCT................... -- -- -- 40.08 -- -- 2.43 2,191 2,191
NOV................... -- -- -- 41.48 -- -- -- -- --
DEC................... 3 152 46.48 43.18 11 3.30 -- -- 11
--- ------ ----- ----- --- ---- ----- ------ ------
2003 TOTAL............ 186 8,051 43.19 39.83 626 3.36 48.69 43,819 44,445
</TABLE>
------------------------
(11) Pages 27-29.
C-D-1
<PAGE>
APPENDIX D: HOURLY PROFIT ANALYSIS - 2005
BASE CASE SCENARIO
<TABLE>
<CAPTION>
TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT.
------------------------------ ------------------- ------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2005 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN................... 9 418 46.07 45.40 6 0.67 -- -- 6
FEB................... 7 306 46.08 44.50 10 1.58 -- -- 10
MAR................... 8 356 44.08 43.30 6 0.78 -- -- 6
APR................... -- -- -- 42.40 -- -- -- -- --
MAY................... 22 922 42.76 42.00 16 0.76 2.53 2,275 2,292
JUN................... 70 2,961 42.09 42.00 6 0.09 7.58 6,826 6,832
JUL................... 86 3,736 43.37 42.40 83 0.97 15.17 13,651 13,735
AUG................... 91 4,076 44.84 42.40 222 2.44 15.17 13,651 13,873
SEP................... 29 1,247 43.74 42.40 38 1.34 7.58 6,826 6,864
OCT................... 19 815 42.89 42.70 4 0.19 2.53 2,275 2,279
NOV................... 3 128 44.63 44.20 1 0.43 -- -- 1
DEC................... 6 294 48.84 46.00 17 2.84 -- -- 17
--- ------ ----- ----- --- ---- ----- ------ ------
2005 TOTAL............ 349 15,259 43.70 42.53 411 1.18 50.56 45,504 45,915
</TABLE>
APPENDIX D: HOURLY PROFIT ANALYSIS - 2010
BASE CASE SCENARIO
<TABLE>
<CAPTION>
TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT.
------------------------------ ------------------- ------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2010 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN................... 11 635 55.73 55.18 6 0.55 -- -- 6
FEB................... 6 361 58.29 53.98 27 4.31 -- -- 27
MAR................... 9 467 52.86 52.48 3 0.38 -- -- 3
APR................... -- -- -- 51.38 -- -- -- -- --
MAY................... 25 1,301 51.35 50.98 9 0.37 2.76 2,481 2,490
JUN................... 72 3,701 51.05 50.98 5 0.07 8.27 7,443 7,448
JUL................... 98 5,084 51.88 51.38 49 0.50 16.54 14,886 14,935
AUG................... 120 6,305 52.42 51.38 125 1.04 16.54 14,886 15,011
SEP................... 40 2,081 52.01 51.38 25 0.63 8.27 7,443 7,469
OCT................... 20 1,043 51.78 51.68 2 0.10 2.76 2,481 2,483
NOV................... 15 799 53.97 53.58 6 0.39 -- -- 6
DEC................... 11 624 57.99 55.88 23 2.11 -- -- 23
--- ------ ----- ----- --- ---- ----- ------ ------
2010 TOTAL............ 428 22,401 52.31 51.65 280 0.65 55.13 49,621 49,901
</TABLE>
C-D-2
<PAGE>
APPENDIX D: HOURLY PROFIT ANALYSIS - 2015
BASE CASE SCENARIO
<TABLE>
<CAPTION>
TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT.
------------------------------ ------------------- ------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2015 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN................... 5 309 62.94 62.39 3 0.55 -- -- 3
FEB................... 4 235 62.50 61.09 5 1.41 -- -- 5
MAR................... 4 265 59.71 59.39 1 0.32 -- -- 1
APR................... -- -- -- 58.09 -- -- -- -- --
MAY................... 22 1,281 58.22 57.69 12 0.53 2.98 2,682 2,694
JUN................... 51 2,935 57.69 57.69 0 0.00 8.94 8,047 8,047
JUL................... 79 4,647 58.82 58.09 58 0.73 17.88 16,094 16,152
AUG................... 92 5,459 59.07 58.09 90 0.98 17.88 16,094 16,184
SEP................... 36 2,108 58.55 58.09 17 0.46 8.94 8,047 8,063
OCT................... 5 297 58.76 58.49 1 0.27 2.98 2,682 2,684
NOV................... 2 122 61.02 60.69 1 0.33 -- -- 1
DEC................... 3 179 65.91 63.29 7 2.62 -- -- 7
--- ------ ----- ----- --- ---- ----- ------ ------
2015 TOTAL............ 303 17,837 58.83 58.19 195 0.64 59.61 53,646 53,841
</TABLE>
APPENDIX D: HOURLY PROFIT ANALYSIS - 2020
BASE CASE SCENARIO
<TABLE>
<CAPTION>
TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT.
------------------------------ ------------------- ------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2020 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN................... -- -- -- 70.64 -- -- -- -- --
FEB................... -- -- -- 69.14 -- -- -- -- --
MAR................... -- -- -- 67.24 -- -- -- -- --
APR................... -- -- -- 65.74 -- -- -- -- --
MAY................... 14 915 65.38 65.24 2 0.14 3.21 2,893 2,895
JUN................... 27 1,734 65.27 65.24 1 0.03 9.64 8,680 8,681
JUL................... 57 3,818 66.53 65.74 46 0.79 19.29 17,360 17,406
AUG................... 49 3,270 66.67 65.74 45 0.93 19.29 17,360 17,406
SEP................... 13 862 66.07 65.74 4 0.33 9.64 8,680 8,684
OCT................... 2 138 66.64 66.24 1 0.40 3.21 2,893 2,894
NOV................... -- -- -- 68.64 -- -- -- -- --
DEC................... -- -- -- 71.54 -- -- -- -- --
--- ------ ----- ----- --- ---- ----- ------ ------
2020 TOTAL............ 162 10,738 66.23 65.62 99 0.61 64.30 57,868 57,967
</TABLE>
C-D-3
<PAGE>
APPENDIX E:
FUEL SWITCHING ANALYSIS
Pursuant to this report, RDI examined how the Tenaska Georgia Partners
project's profitability would be affected if it were forced to switch to fuel
oil during peak gas demand periods due to a lack of availability of natural gas.
This analysis was performed for the select years: 2003 (the first full year in
which the entire plant is on line), 2005, 2010, 2015 and 2020.
METHODOLOGY RDI analyzed peak periods of gas pipeline capacity in the
southeast. This analysis determined that if the Tenaska Georgia Partners project
would be forced to switch to fuel oil due to gas pipeline capacity constraints,
that interruption would most likely to occur in the months of January and
February. RDI made two further assumptions:
- the project would be forced to burn fuel oil for the entire month; and
- the project would be a price taker in the market.
RDI employed the same methodology described in Appendix D to determine the
effect of fuel switching on the project's profitability in the select years.
This analysis took into account two scenarios. First, RDI examined a scenario
where the plant would not be dispatched if it became uneconomic due to fuel
switching. The second scenario assumed that the plant would be dispatched as if
it had not switched fuels (i.e. the plant would be dispatched as it would in the
base case even if it became uneconomic due to fuel switching.)
RESULTS The results of the fuel switching analysis are summarized on an
annual basis below in Table APP-3 and on a monthly basis in the tables attached
to this Appendix.
The fuel switching analysis indicates that if the Tenaska Georgia Partners
project were forced to switch to fuel oil in the months of January and February,
it would never be economically dispatched in the years examined. This is due to
the significantly higher fuel oil forecast for the region.
However, in both scenarios considered, fuel switching has only a minor
impact on the overall profitability of the project. First, the months of January
and February are months in which the plant does not achieve high capacity
factors in the base case forecast. So, in the scenario in which the plant is not
dispatched, the revenues foregone from the energy market are relatively small.
If the plant is required to run despite being uneconomic, the losses sustained
in January and February are largely offset by energy market profits achieved in
later months, and by contributions to fixed costs from the capacity market.
Moreover, RDI's profitability analysis (outlined in Appendix D) demonstrates
that the project's profitability is largely dependent on its revenue
contributions from the capacity market. Fuel switching will not impact revenue
from the capacity market unless the plant is not able to generate. As shown in
Table APP-3, total contributions to fixed costs are not impacted by more than
one percent in any year analyzed in both fuel-switching scenarios.
TABLE APP--3 FUEL SWITCHING ANALYSIS--ANNUAL SUMMARY
<TABLE>
<CAPTION>
FUEL SWITCHING SCENARIO
BASE CASE ASSUMING NO DISPATCH
----------------------------------------------------- -----------------------------------------
ENERGY PROFIT CONT. ENERGY PROFIT CONT. %
------------------- FIXED ------------------- FIXED CHG
AVE COSTS AVG COSTS FROM
YEAR ($000) /MWH ($000) ($000) $/MWH ($000) BASE
---- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
2003................. 626 3.36 44,445 603 3.24 44,422 -0.1%
2005................. 411 1.18 45,915 395 1.13 45,898 0.0%
2010................. 280 0.65 49,901 247 0.58 49,868 -0.1%
2015................. 195 0.64 53,841 187 0.62 53,833 0.0%
2020................. 99 0.61 57,967 99 0.61 57,967 0.0%
<CAPTION>
FUEL SWITCHING SCENARIO
ASSUMING PLANT DISPATCHED
--------------------- -----------------------------------------
ENERGY PROFIT CONT. %
------------------- FIXED CHG
AVG COSTS FROM
YEAR ($000) $/MWH ($000) BASE
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003................. 548 2.94 44,367 -0.2%
2005................. 157 0.45 45,661 -0.6%
2010................. (13) (0.03) 49,608 -0.5%
2015................. (16) (0.05) 53,630 -0.4%
2020................. 99 0.61 57,967 0.0%
</TABLE>
C-E-1
<PAGE>
APPENDIX E: FUEL SWITCHING ANALYSIS - 2003
<TABLE>
<CAPTION>
BASE CASE SCENARIO
------------------------------------------------------------------------------------------ TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT
------------------------------ ------------------- --------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2003 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- ----------- -------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. -- -- -- 42.68 -- -- -- -- --
FEB.................. 5 225 46.41 41.78 22 4.63 -- -- 22
MAR.................. 1 36 42.08 40.68 1 1.40 -- -- 1
APR.................. -- -- -- 39.78 -- -- -- -- --
MAY.................. 8 343 40.39 39.48 8 0.91 2.43 2,191 2,199
JUN.................. 31 1,248 40.24 39.48 24 0.76 7.30 6,573 6,596
JUL.................. 57 2,405 42.40 39.78 149 2.62 14.61 13,146 13,294
AUG.................. 63 2,864 45.57 39.78 364 5.79 14.61 13,146 13,510
SEP.................. 18 777 42.35 39.78 47 2.57 7.30 6,573 6,620
OCT.................. -- -- -- 40.08 -- -- 2.43 2,191 2,191
NOV.................. -- -- -- 41.48 -- -- -- -- --
DEC.................. 3 152 46.48 43.18 11 3.30 -- -- 11
--- ------ ----- ----- --- ---- ----- ------ ------
2003 TOTAL........... 186 8,051 43.19 39.83 626 3.36 48.69 43,819 44,445
<CAPTION>
FUEL SWITCHING SCENARIO--ASSUMINGOPLANT DISPATCHED CONT.
ENERGY REVENUE ENERGY PROFIT
------------------------------ ------------------- CAPACITY FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2003 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- ----------- -------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. -- -- -- 42.68 -- -- -- -- --
FEB.................. 5 225 46.41 41.78 22 4.63 -- -- 22
MAR.................. 1 36 42.08 40.68 1 1.40 -- -- 1
APR.................. -- -- -- 39.78 -- -- -- -- --
MAY.................. 8 343 40.39 39.48 8 0.91 2.43 2,191 2,199
JUN.................. 31 1,248 40.24 39.48 24 0.76 7.30 6,573 6,596
JUL.................. 57 2,405 42.40 39.78 149 2.62 14.61 13,146 13,294
AUG.................. 63 2,864 45.57 39.78 364 5.79 14.61 13,146 13,510
SEP.................. 18 777 42.35 39.78 47 2.57 7.30 6,573 6,620
OCT.................. -- -- -- 40.08 -- -- 2.43 2,191 2,191
NOV.................. -- -- -- 41.48 -- -- -- -- --
DEC.................. 3 152 46.48 43.18 11 3.30 -- -- 11
--- ------ ----- ----- --- ---- ----- ------ ------
2003 TOTAL........... 186 8,051 43.19 39.83 626 3.36 48.69 43,819 44,445
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. -- -- -- 57.84 -- -- -- -- --
FEB.................. -- -- -- 57.84 -- -- -- -- --
MAR.................. 1 36 42.08 40.68 1 1.40 -- -- 1
APR.................. -- -- -- 39.78 -- -- -- -- --
MAY.................. 8 343 40.39 39.48 8 0.91 2.43 2,191 2,199
JUN.................. 31 1,248 40.24 39.48 24 0.76 7.30 6,573 6,596
JUL.................. 57 2,405 42.40 39.78 149 2.62 14.61 13,146 13,294
AUG.................. 63 2,864 45.57 39.78 364 5.79 14.61 13,146 13,510
SEP.................. 18 777 42.35 39.78 47 2.57 7.30 6,573 6,620
OCT.................. -- -- -- 40.08 -- -- 2.43 2,191 2,191
NOV.................. -- -- -- 41.48 -- -- -- -- --
DEC.................. 3 152 46.48 43.18 11 3.30 -- -- 11
--- ----- ----- ----- ------ ------ ----- ------ ------
2003 TOTAL........... 182 7,826 43.10 39.78 603 3.24 48.69 43,819 44,422
JAN.................. -- -- -- 57.84 -- -- -- -- --
FEB.................. 5 225 46.41 57.84 (55) (11.43) -- -- (55)
MAR.................. 1 36 42.08 40.68 1 1.40 -- -- 1
APR.................. -- -- -- 39.78 -- -- -- -- --
MAY.................. 8 343 40.39 39.48 8 0.91 2.43 2,191 2,199
JUN.................. 31 1,248 40.24 39.48 24 0.76 7.30 6,573 6,596
JUL.................. 57 2,405 42.40 39.78 149 2.62 14.61 13,146 13,294
AUG.................. 63 2,864 45.57 39.78 364 5.79 14.61 13,146 13,510
SEP.................. 18 777 42.35 39.78 47 2.57 7.30 6,573 6,620
OCT.................. -- -- -- 40.08 -- -- 2.43 2,191 2,191
NOV.................. -- -- -- 41.48 -- -- -- -- --
DEC.................. 3 152 46.48 43.18 11 3.30 -- -- 11
--- ----- ----- ----- ------ ------ ----- ------ ------
2003 TOTAL........... 186 8,051 43.19 40.25 548 2.94 48.69 43,819 44,367
</TABLE>
C-E-2
<PAGE>
APPENDIX E: FUEL SWITCHING ANALYSIS - 2005
<TABLE>
<CAPTION>
BASE CASE SCENARIO
-------------------------------------------------------------------------------------- TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT
------------------------------ ------------------- -------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2005 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- -------- -------- -------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN................... 9 418 46.07 45.40 6 0.67 -- -- 6
FEB................... 7 306 46.08 44.50 10 1.58 -- -- 10
MAR................... 8 356 44.08 43.30 6 0.78 -- -- 6
APR................... -- -- -- 42.40 -- -- -- -- --
MAY................... 22 922 42.76 42.00 16 0.76 2.53 2,275 2,292
JUN................... 70 2,961 42.09 42.00 6 0.09 7.58 6,826 6,832
JUL................... 86 3,736 43.37 42.40 83 0.97 15.17 13,651 13,735
AUG................... 91 4,076 44.84 42.40 222 2.44 15.17 13,651 13,873
SEP................... 29 1,247 43.74 42.40 38 1.34 7.58 6,826 6,864
OCT................... 19 815 42.89 42.70 4 0.19 2.53 2,275 2,279
NOV................... 3 128 44.63 44.20 1 0.43 -- -- 1
DEC................... 6 294 48.84 46.00 17 2.84 -- -- 17
--- ------ ----- ----- --- ---- ----- ------ ------
2005 TOTAL............ 349 15,259 43.70 42.53 411 1.18 50.56 45,504 45,915
<CAPTION>
FUEL SWITCHING SCENARIO--ASSUMINGOPLANT DISPATCHED CONT.
ENERGY REVENUE ENERGY PROFIT
------------------------------ ------------------- CAPACITY FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2005 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- -------- -------- -------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN................... 9 418 46.07 45.40 6 0.67 -- -- 6
FEB................... 7 306 46.08 44.50 10 1.58 -- -- 10
MAR................... 8 356 44.08 43.30 6 0.78 -- -- 6
APR................... -- -- -- 42.40 -- -- -- -- --
MAY................... 22 922 42.76 42.00 16 0.76 2.53 2,275 2,292
JUN................... 70 2,961 42.09 42.00 6 0.09 7.58 6,826 6,832
JUL................... 86 3,736 43.37 42.40 83 0.97 15.17 13,651 13,735
AUG................... 91 4,076 44.84 42.40 222 2.44 15.17 13,651 13,873
SEP................... 29 1,247 43.74 42.40 38 1.34 7.58 6,826 6,864
OCT................... 19 815 42.89 42.70 4 0.19 2.53 2,275 2,279
NOV................... 3 128 44.63 44.20 1 0.43 -- -- 1
DEC................... 6 294 48.84 46.00 17 2.84 -- -- 17
--- ------ ----- ----- --- ---- ----- ------ ------
2005 TOTAL 349 15,259 43.70 42.53 411 1.18 50.56 45,504 45,915
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN................... -- -- -- 61.20 -- -- -- -- --
FEB................... -- -- -- 61.20 -- -- -- -- --
MAR................... 8 356 44.08 43.30 6 0.78 -- -- 6
APR................... -- -- -- 42.40 -- -- -- -- --
MAY................... 22 922 42.76 42.00 16 0.76 2.53 2,275 2,292
JUN................... 70 2,961 42.09 42.00 6 0.09 7.58 6,826 6,832
JUL................... 86 3,736 43.37 42.40 83 0.97 15.17 13,651 13,735
AUG................... 91 4,076 44.84 42.40 222 2.44 15.17 13,651 13,873
SEP................... 29 1,247 43.74 42.40 38 1.34 7.58 6,826 6,864
OCT................... 19 815 42.89 42.70 4 0.19 2.53 2,275 2,279
NOV................... 3 128 44.63 44.20 1 0.43 -- -- 1
DEC................... 6 294 48.84 46.00 17 2.84 -- -- 17
--- ------ ----- ----- ---- ------ ----- ------ ------
2005 TOTAL............ 333 14,535 43.59 42.41 395 1.13 50.56 45,504 45,898
JAN................... 9 418 46.07 61.20 (137) (15.12) -- -- (137)
FEB................... 7 306 46.08 61.20 (100) (15.12) -- -- (100)
MAR................... 8 356 44.08 43.30 6 0.78 -- -- 6
APR................... -- -- -- 42.40 -- -- -- -- --
MAY................... 22 922 42.76 42.00 16 0.76 2.53 2,275 2,292
JUN................... 70 2,961 42.09 42.00 6 0.09 7.58 6,826 6,832
JUL................... 86 3,736 43.37 42.40 83 0.97 15.17 13,651 13,735
AUG................... 91 4,076 44.84 42.40 222 2.44 15.17 13,651 13,873
SEP................... 29 1,247 43.74 42.40 38 1.34 7.58 6,826 6,864
OCT................... 19 815 42.89 42.70 4 0.19 2.53 2,275 2,279
NOV................... 3 128 44.63 44.20 1 0.43 -- -- 1
DEC................... 6 294 48.84 46.00 17 2.84 -- -- 17
--- ------ ----- ----- ---- ------ ----- ------ ------
2005 TOTAL 349 15,259 43.70 43.25 157 0.45 50.56 45,504 45,661
</TABLE>
C-E-3
<PAGE>
APPENDIX E: FUEL SWITCHING ANALYSIS - 2010
<TABLE>
<CAPTION>
BASE CASE SCENARIO
------------------------------------------------------------------------------------------ TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT
------------------------------ ------------------- --------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2010 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- ----------- -------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. 11 635 55.73 55.18 6 0.55 -- -- 6
FEB.................. 6 361 58.29 53.98 27 4.31 -- -- 27
MAR.................. 9 467 52.86 52.48 3 0.38 -- -- 3
APR.................. -- -- -- 51.38 -- -- -- -- --
MAY.................. 25 1,301 51.35 50.98 9 0.37 2.76 2,481 2,490
JUN.................. 72 3,701 51.05 50.98 5 0.07 8.27 7,443 7,448
JUL.................. 98 5,084 51.88 51.38 49 0.50 16.54 14,886 14,935
AUG.................. 120 6,305 52.42 51.38 125 1.04 16.54 14,886 15,011
SEP.................. 40 2,081 52.01 51.38 25 0.63 8.27 7,443 7,469
OCT.................. 20 1,043 51.78 51.68 2 0.10 2.76 2,481 2,483
NOV.................. 15 799 53.97 53.58 6 0.39 -- -- 6
DEC.................. 11 624 57.99 55.88 23 2.11 -- -- 23
--- ------ ----- ----- --- ---- ----- ------ ------
2010 TOTAL 428 22,401 52.31 51.65 280 0.65 55.13 49,621 49,901
<CAPTION>
FUEL SWITCHING SCENARIO--ASSUMINGOPLANT DISPATCHED CONT.
ENERGY REVENUE ENERGY PROFIT
------------------------------ ------------------- CAPACITY FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2010 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- ----------- -------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. 11 635 55.73 55.18 6 0.55 -- -- 6
FEB.................. 6 361 58.29 53.98 27 4.31 -- -- 27
MAR.................. 9 467 52.86 52.48 3 0.38 -- -- 3
APR.................. -- -- -- 51.38 -- -- -- -- --
MAY.................. 25 1,301 51.35 50.98 9 0.37 2.76 2,481 2,490
JUN.................. 72 3,701 51.05 50.98 5 0.07 8.27 7,443 7,448
JUL.................. 98 5,084 51.88 51.38 49 0.50 16.54 14,886 14,935
AUG.................. 120 6,305 52.42 51.38 125 1.04 16.54 14,886 15,011
SEP.................. 40 2,081 52.01 51.38 25 0.63 8.27 7,443 7,469
OCT.................. 20 1,043 51.78 51.68 2 0.10 2.76 2,481 2,483
NOV.................. 15 799 53.97 53.58 6 0.39 -- -- 6
DEC.................. 11 624 57.99 55.88 23 2.11 -- -- 23
--- ------ ----- ----- --- ---- ----- ------ ------
2010 TOTAL........... 428 22,401 52.31 51.65 280 0.65 55.13 49,621 49,901
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. -- -- -- 71.44 -- -- -- -- --
FEB.................. -- -- -- 71.44 -- -- -- -- --
MAR.................. 9 467 52.86 52.48 3 0.38 -- -- 3
APR.................. -- -- -- 51.38 -- -- -- -- --
MAY.................. 25 1,301 51.35 50.98 9 0.37 2.76 2,481 2,490
JUN.................. 72 3,701 51.05 50.98 5 0.07 8.27 7,443 7,448
JUL.................. 98 5,084 51.88 51.38 49 0.50 16.54 14,886 14,935
AUG.................. 120 6,305 52.42 51.38 125 1.04 16.54 14,886 15,011
SEP.................. 40 2,081 52.01 51.38 25 0.63 8.27 7,443 7,469
OCT.................. 20 1,043 51.78 51.68 2 0.10 2.76 2,481 2,483
NOV.................. 15 799 53.97 53.58 6 0.39 -- -- 6
DEC.................. 11 624 57.99 55.88 23 2.11 -- -- 23
--- ------ ----- ----- ---- ------ ----- ------ ------
2010 TOTAL 411 21,406 52.12 51.52 247 0.58 55.13 49,621 49,868
JAN.................. 11 635 55.73 71.44 (179) (15.72) -- -- (179)
FEB.................. 6 361 58.29 71.44 (81) (13.16) -- -- (81)
MAR.................. 9 467 52.86 52.48 3 0.38 -- -- 3
APR.................. -- -- -- 51.38 -- -- -- -- --
MAY.................. 25 1,301 51.35 50.98 9 0.37 2.76 2,481 2,490
JUN.................. 72 3,701 51.05 50.98 5 0.07 8.27 7,443 7,448
JUL.................. 98 5,084 51.88 51.38 49 0.50 16.54 14,886 14,935
AUG.................. 120 6,305 52.42 51.38 125 1.04 16.54 14,886 15,011
SEP.................. 40 2,081 52.01 51.38 25 0.63 8.27 7,443 7,469
OCT.................. 20 1,043 51.78 51.68 2 0.10 2.76 2,481 2,483
NOV.................. 15 799 53.97 53.58 6 0.39 -- -- 6
DEC.................. 11 624 57.99 55.88 23 2.11 -- -- 23
--- ------ ----- ----- ---- ------ ----- ------ ------
2010 TOTAL........... 428 22,401 52.31 52.34 (13) (0.03) 55.13 49,621 49,608
</TABLE>
C-E-4
<PAGE>
APPENDIX E: FUEL SWITCHING ANALYSIS - 2015
<TABLE>
<CAPTION>
BASE CASE SCENARIO
------------------------------------------------------------------------------------------ TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT
------------------------------ ------------------- --------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2015 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- ----------- -------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. 5 309 62.94 62.39 2.7 0.55 -- -- 3
FEB.................. 4 235 62.50 61.09 5.3 1.41 -- -- 5
MAR.................. 4 265 59.71 59.39 1.4 0.32 -- -- 1
APR.................. -- -- -- 58.09 -- -- -- -- --
MAY.................. 22 1,281 58.22 57.69 11.6 0.53 2.98 2,682 2,694
JUN.................. 51 2,935 57.69 57.69 0.2 0.00 8.94 8,047 8,047
JUL.................. 79 4,647 58.82 58.09 58.0 0.73 17.88 16,094 16,152
AUG.................. 92 5,459 59.07 58.09 90.1 0.98 17.88 16,094 16,184
SEP.................. 36 2,108 58.55 58.09 16.5 0.46 8.94 8,047 8,063
OCT.................. 5 297 58.76 58.49 1.3 0.27 2.98 2,682 2,684
NOV.................. 2 122 61.02 60.69 0.7 0.33 -- -- 1
DEC.................. 3 179 65.91 63.29 7.1 2.62 -- -- 7
--- ------ ----- ----- ----- ---- ----- ------ ------
2015 TOTAL........... 303 17,837 58.83 58.19 195.0 0.64 59.61 53,646 53,841
<CAPTION>
FUEL SWITCHING SCENARIO--ASSUMINGOPLANT DISPATCHED CONT.
ENERGY REVENUE ENERGY PROFIT
------------------------------ ------------------- CAPACITY FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2015 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- ----------- -------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. 5 309 62.94 62.39 2.7 0.55 -- -- 3
FEB.................. 4 235 62.50 61.09 5.3 1.41 -- -- 5
MAR.................. 4 265 59.71 59.39 1.4 0.32 -- -- 1
APR.................. -- -- -- 58.09 -- -- -- -- --
MAY.................. 22 1,281 58.22 57.69 11.6 0.53 2.98 2,682 2,694
JUN.................. 51 2,935 57.69 57.69 0.2 0.00 8.94 8,047 8,047
JUL.................. 79 4,647 58.82 58.09 58.0 0.73 17.88 16,094 16,152
AUG.................. 92 5,459 59.07 58.09 90.1 0.98 17.88 16,094 16,184
SEP.................. 36 2,108 58.55 58.09 16.5 0.46 8.94 8,047 8,063
OCT.................. 5 297 58.76 58.49 1.3 0.27 2.98 2,682 2,684
NOV.................. 2 122 61.02 60.69 0.7 0.33 -- -- 1
DEC.................. 3 179 65.91 63.29 7.1 2.62 -- -- 7
--- ------ ----- ----- ----- ---- ----- ------ ------
2015 TOTAL........... 303 17,837 58.83 58.19 195.0 0.64 59.61 53,646 53,841
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. -- -- -- 86.22 -- -- -- -- --
FEB.................. -- -- -- 86.22 -- -- -- -- --
MAR.................. 4 265 59.71 59.39 1.4 0.32 -- -- 1
APR.................. -- -- -- 58.09 -- -- -- -- --
MAY.................. 22 1,281 58.22 57.69 11.6 0.53 2.98 2,682 2,694
JUN.................. 51 2,935 57.69 57.69 0.2 0.00 8.94 8,047 8,047
JUL.................. 79 4,647 58.82 58.09 58.0 0.73 17.88 16,094 16,152
AUG.................. 92 5,459 59.07 58.09 90.1 0.98 17.88 16,094 16,184
SEP.................. 36 2,108 58.55 58.09 16.5 0.46 8.94 8,047 8,063
OCT.................. 5 297 58.76 58.49 1.3 0.27 2.98 2,682 2,684
NOV.................. 2 122 61.02 60.69 0.7 0.33 -- -- 1
DEC.................. 3 179 65.91 63.29 7.1 2.62 -- -- 7
--- ------ ----- ----- ------ ------ ----- ------ ------
2015 TOTAL........... 295 17,293 58.72 58.08 187.0 0.62 59.61 53,646 53,833
JAN.................. 5 309 62.94 86.22 (114.2) (23.27) -- -- (114)
FEB.................. 4 235 62.50 86.22 (89.0) (23.72) -- -- (89)
MAR.................. 4 265 59.71 59.39 1.4 0.32 -- -- 1
APR.................. -- -- -- 58.09 -- -- -- -- --
MAY.................. 22 1,281 58.22 57.69 11.6 0.53 2.98 2,682 2,694
JUN.................. 51 2,935 57.69 57.69 0.2 0.00 8.94 8,047 8,047
JUL.................. 79 4,647 58.82 58.09 58.0 0.73 17.88 16,094 16,152
AUG.................. 92 5,459 59.07 58.09 90.1 0.98 17.88 16,094 16,184
SEP.................. 36 2,108 58.55 58.09 16.5 0.46 8.94 8,047 8,063
OCT.................. 5 297 58.76 58.49 1.3 0.27 2.98 2,682 2,684
NOV.................. 2 122 61.02 60.69 0.7 0.33 -- -- 1
DEC.................. 3 179 65.91 63.29 7.1 2.62 -- -- 7
--- ------ ----- ----- ------ ------ ----- ------ ------
2015 TOTAL........... 303 17,837 58.83 58.89 (16.2) (0.05) 59.61 53,646 53,630
</TABLE>
C-E-5
<PAGE>
APPENDIX E: FUEL SWITCHING ANALYSIS - 2020
<TABLE>
<CAPTION>
BASE CASE SCENARIO
------------------------------------------------------------------------------------------ TOTAL
ENERGY REVENUE ENERGY PROFIT CAPACITY CONT
------------------------------ ------------------- --------------------- FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2020 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- ----------- -------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. -- -- -- 70.64 -- -- -- -- --
FEB.................. -- -- -- 69.14 -- -- -- -- --
MAR.................. -- -- -- 67.24 -- -- -- -- --
APR.................. -- -- -- 65.74 -- -- -- -- --
MAY.................. 14 915 65.38 65.24 2.0 0.14 3.21 2,893 2,895
JUN.................. 27 1,734 65.27 65.24 0.8 0.03 9.64 8,680 8,681
JUL.................. 57 3,818 66.53 65.74 45.6 0.79 19.29 17,360 17,406
AUG.................. 49 3,270 66.67 65.74 45.5 0.93 19.29 17,360 17,406
SEP.................. 13 862 66.07 65.74 4.3 0.33 9.64 8,680 8,684
OCT.................. 2 138 66.64 66.24 0.8 0.40 3.21 2,893 2,894
NOV.................. -- -- -- 68.64 -- -- -- -- --
DEC.................. -- -- -- 71.54 -- -- -- -- --
--- ------ ----- ----- ---- ---- ----- ------ ------
2020 TOTAL........... 162 10,738 66.23 65.62 99.0 0.61 64.30 57,868 57,967
<CAPTION>
FUEL SWITCHING SCENARIO--ASSUMINGOPLANT DISPATCHED CONT.
ENERGY REVENUE ENERGY PROFIT
------------------------------ ------------------- CAPACITY FIXED
GEN AVG DISPATCH AVG PRICE REV COSTS
2020 GWH ($ 000) $/MWH $/MWH ($ 000) $/MWH $/KW-MTH ($ 000) ($ 000)
---- -------- -------- -------- ----------- -------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. -- -- -- 70.64 -- -- -- -- --
FEB.................. -- -- -- 69.14 -- -- -- -- --
MAR.................. -- -- -- 67.24 -- -- -- -- --
APR.................. -- -- -- 65.74 -- -- -- -- --
MAY.................. 14 915 65.38 65.24 2.0 0.14 3.21 2,893 2,895
JUN.................. 27 1,734 65.27 65.24 0.8 0.03 9.64 8,680 8,681
JUL.................. 57 3,818 66.53 65.74 45.6 0.79 19.29 17,360 17,406
AUG.................. 49 3,270 66.67 65.74 45.5 0.93 19.29 17,360 17,406
SEP.................. 13 862 66.07 65.74 4.3 0.33 9.64 8,680 8,684
OCT.................. 2 138 66.64 66.24 0.8 0.40 3.21 2,893 2,894
NOV.................. -- -- -- 68.64 -- -- -- -- --
DEC.................. -- -- -- 71.54 -- -- -- -- --
--- ------ ----- ----- ---- ---- ----- ------ ------
2020 TOTAL........... 162 10,738 66.23 65.62 99.0 0.61 64.30 57,868 57,967
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
JAN.................. -- -- -- 99.48 -- -- -- -- --
FEB.................. -- -- -- 99.48 -- -- -- -- --
MAR.................. -- -- -- 67.24 -- -- -- -- --
APR.................. -- -- -- 65.74 -- -- -- -- --
MAY.................. 14 915 65.38 65.24 2.0 0.14 3.21 2,893 2,895
JUN.................. 27 1,734 65.27 65.24 0.8 0.03 9.64 8,680 8,681
JUL.................. 57 3,818 66.53 65.74 45.6 0.79 19.29 17,360 17,406
AUG.................. 49 3,270 66.67 65.74 45.5 0.93 19.29 17,360 17,406
SEP.................. 13 862 66.07 65.74 4.3 0.33 9.64 8,680 8,684
OCT.................. 2 138 66.64 66.24 0.8 0.40 3.21 2,893 2,894
NOV.................. -- -- -- 68.64 -- -- -- -- --
DEC.................. -- -- -- 71.54 -- -- -- -- --
--- ------ ----- ----- ---- ------ ----- ------ ------
2020 TOTAL........... 162 10,738 66.23 65.62 99.0 0.61 64.30 57,868 57,967
JAN.................. -- -- -- 99.48 -- -- -- -- --
FEB.................. -- -- -- 99.48 -- -- -- -- --
MAR.................. -- -- -- 67.24 -- -- -- -- --
APR.................. -- -- -- 65.74 -- -- -- -- --
MAY.................. 14 915 65.38 65.24 2.0 0.14 3.21 2,893 2,895
JUN.................. 27 1,734 65.27 65.24 0.8 0.03 9.64 8,680 8,681
JUL.................. 57 3,818 66.53 65.74 45.6 0.79 19.29 17,360 17,406
AUG.................. 49 3,270 66.67 65.74 45.5 0.93 19.29 17,360 17,406
SEP.................. 13 862 66.07 65.74 4.3 0.33 9.64 8,680 8,684
OCT.................. 2 138 66.64 66.24 0.8 0.40 3.21 2,893 2,894
NOV.................. -- -- -- 68.64 -- -- -- -- --
DEC.................. -- -- -- 71.54 -- -- -- -- --
--- ------ ----- ----- ---- ------ ----- ------ ------
2020 TOTAL........... 162 10,738 66.23 65.62 99.0 0.61 64.30 57,868 57,967
</TABLE>
C-E-6
<PAGE>
APPENDIX F:
HIGH START-UP COST SCENARIO
As a supplement to this report, RDI examined the sensitivities of market
prices and the project's capacity factors to changes in start-up costs. For this
scenario, variable O&M (the bulk of which consists of start-up costs) for all
new combustion turbines was increased to 15 $/MWh. In the base case, variable
O&M for new combustion turbines (including the Tenaska Georgia Partners project)
was assumed to be 10 $/MWh.
Summary tables showing detailed price and capacity factor results are
attached to this Appendix.
SCENARIO RESULTS
ENERGY PRICES Energy price results for the high start-up cost scenario are
summarized in Table APP-4. Energy prices gradually deviate from the base case in
the early years of the forecast as peaking units set prices in more hours of the
year. By 2007, prices in the high start-up case are 4% higher than in the base
case and remain approximately 4% higher for the rest of the forecast period.
TABLE APP-4 ENERGY PRICE RESULTS--HIGH START-UP COST SCENARIO (NOMINAL $)
<TABLE>
<CAPTION>
HIGH START-UP COST ENERGY PRICES ($/MWH)
-----------------------------------------------------
SUMMER MONTHS WINTER MONTHS
------------------- -------------------
HOURS OF DAY ANNUAL %
------------------- YR ROUND PRICE CHG
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION BASE
---- -------- -------- -------- -------- --------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
2000........................................... 24.50 17.98 22.46 18.47 21.73 -- 0.8%
2001........................................... 25.32 18.30 23.68 18.88 22.61 4.1% 1.0%
2002........................................... 26.45 18.51 25.04 19.44 23.65 4.6% 1.7%
2003........................................... 28.98 19.78 26.83 20.22 25.37 7.3% 2.1%
2004........................................... 30.03 20.04 28.62 20.98 26.64 5.0% 2.7%
2005........................................... 31.69 20.42 30.41 21.83 28.08 5.4% 3.3%
2006........................................... 33.25 21.15 31.82 22.52 29.31 4.4% 3.6%
2007........................................... 34.54 21.74 33.83 23.50 30.82 5.1% 4.1%
2008........................................... 35.65 22.33 35.20 24.59 31.99 3.8% 4.0%
2009........................................... 37.78 23.43 36.68 25.74 33.53 4.8% 4.0%
2010........................................... 38.64 24.11 38.25 26.85 34.75 3.6% 4.2%
2011........................................... 39.51 24.67 38.92 27.40 35.43 2.0% 4.0%
2012........................................... 40.57 25.38 39.32 28.14 36.09 1.8% 3.9%
2013........................................... 41.06 25.87 40.14 28.91 36.79 1.9% 3.9%
2014........................................... 41.91 26.69 40.77 29.72 37.52 2.0% 4.0%
2015........................................... 43.41 27.58 41.77 30.39 38.57 2.8% 3.9%
2016........................................... 43.89 28.05 42.69 31.10 39.30 1.9% 3.8%
2017........................................... 44.92 28.78 43.68 31.98 40.25 2.4% 4.0%
2018........................................... 46.14 29.56 44.38 32.79 41.10 2.1% 3.9%
2019........................................... 46.82 30.24 45.52 33.50 42.01 2.2% 4.0%
2020........................................... 47.81 31.15 46.39 34.49 42.93 2.2% 4.0%
2021........................................... 48.03 32.23 45.45 34.86 42.71 -0.5% 3.4%
2022........................................... 49.23 33.03 46.58 35.73 43.78 2.5% 3.4%
2023........................................... 50.46 33.86 47.75 36.62 44.88 2.5% 3.4%
2024........................................... 51.73 34.71 48.94 37.54 46.00 2.5% 3.4%
2025........................................... 53.02 35.57 50.16 38.47 47.15 2.5% 3.4%
2026........................................... 54.35 36.46 51.42 39.44 48.33 2.5% 3.4%
2027........................................... 55.70 37.38 52.70 40.42 49.53 2.5% 3.4%
2028........................................... 57.10 38.31 54.02 41.43 50.77 2.5% 3.4%
2029........................................... 58.52 39.27 55.37 42.47 52.04 2.5% 3.4%
2030........................................... 59.99 40.25 56.76 43.53 53.34 2.5% 3.4%
</TABLE>
------------------------------
* Assumes a 60% load factor
C-F-1
<PAGE>
CAPACITY PRICES Capacity price results for the high start-up cost scenario
are shown in Figure App-2. Capacity prices in the high start-up cost scenario
are two to four percent lower (approximately .30 $/MWh assuming a 60% load
factor) than capacity prices in the base case in the later years of the forecast
because higher average energy prices translate to greater contributions to fixed
costs for new combustion turbines.
FIGURE APP-2 CAPACITY PRICE RESULTS--HIGH START-UP COST SCENARIO
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
CAPACITY PRICES IN $/KW-YR
<S> <C> <C>
BASE HIGH START-UP
2000 46.46 46.36
2001 47.26 47.26
2002 47.97 47.97
2003 48.69 48.49
2004 49.82 49.52
2005 50.56 50.46
2006 52.11 51.11
2007 52.38 52.08
2008 53.65 52.85
2009 55.04 53.74
2010 55.13 54.63
2011 55.84 54.44
2012 57.27 55.27
2013 58.2 56.10
2014 58.85 57.05
2015 59.61 57.71
2016 60.38 58.78
2017 61.46 59.76
2018 62.26 60.56
2019 63.17 61.57
2020 64.3 62.50
2021 65.08 63.64
2022 66.71 66.36
2023 68.38 68.02
2024 70.09 69.72
2025 71.84 71.46
2026 73.63 73.25
2027 75.47 75.08
2028 77.36 76.96
2029 79.29 78.88
2030 81.28 80.85
</TABLE>
CAPACITY FACTORS Table APP-5 summarizes forecast monthly capacity factors
for select years of the forecast. As shown in Figure APP-3, the higher dispatch
costs associated with greater start-up costs would have only a minimal impact on
the project's summer capacity factors. A detailed table showing monthly capacity
factors for each year of the forecast accompanies this Appendix.
TABLE APP-5 MONTHLY CAPACITY FACTORS--SELECT YEARS
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT
---- -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003................. 0% 1% 0% 0% 1% 5% 8% 9% 3% 0%
2005................. 1% 1% 1% 0% 3% 9% 11% 13% 4% 3%
2010................. 2% 1% 2% 0% 4% 11% 14% 16% 6% 4%
2015................. 1% 1% 1% 0% 3% 8% 13% 14% 5% 1%
2020................. 0% 0% 0% 0% 2% 4% 8% 8% 2% 0%
--- --- --- --- --- --- --- --- --- ---
Avg 2000-2021........ 1% 1% 1% 0% 3% 8% 11% 12% 4% 2%
<CAPTION>
YEAR NOV DEC AVG
---- -------- -------- --------
<S> <C> <C> <C>
2003................. 0% 1% 1%
2005................. 0% 1% 3%
2010................. 3% 1% 5%
2015................. 0% 1% 4%
2020................. 0% 0% 3%
--- --- ---
Avg 2000-2021........ 1% 1% 4%
</TABLE>
FIGURE APP-3 MONTHLY CAPACITY FACTORS--SELECT YEARS
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
AUGUST CAPACITY FACTORS - SELECT YEARS
<S> <C> <C>
BASE CASE HIGH START-UP
2003 9% 9%
2005 14% 13%
2010 18% 16%
2015 14% 14%
2020 7% 8%
</TABLE>
C-F-2
<PAGE>
APPENDIX F:
DETAILED MONTHLY CAPACITY FACTORS--
HIGH START-UP COST SCENARIO
MONTHLY PLANT GENERATION (GWH)
TENASKA GEORGIA POWER PARTNERS
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2001..................... -- -- -- -- -- 6 16 22 5
2002..................... -- 3 -- -- 3 10 41 37 11
2003..................... -- 6 2 -- 7 34 51 57 19
2004..................... 5 6 2 -- 11 52 55 67 15
2005..................... 6 9 6 -- 18 59 76 89 23
2006..................... 6 6 7 5 22 64 81 101 36
2007..................... 12 9 6 -- 28 76 91 105 38
2008..................... 11 9 9 1 28 73 91 107 42
2009..................... 11 11 12 6 24 69 92 109 45
2010..................... 14 8 11 -- 26 73 95 110 40
2011..................... 12 8 8 2 27 70 89 105 47
2012..................... 6 8 11 4 24 70 96 114 46
2013..................... 9 7 7 -- 21 56 81 93 32
2014..................... 6 4 6 2 19 46 74 82 32
2015..................... 6 5 8 -- 23 53 86 95 35
2016..................... 4 6 2 -- 18 43 77 81 24
2017..................... 6 5 5 -- 18 44 79 75 30
2018..................... 2 -- 2 -- 13 33 80 81 30
2019..................... 2 -- -- -- 15 39 68 71 17
2020..................... 2 -- -- -- 14 29 55 53 11
2021..................... -- -- -- -- 5 26 46 40 3
<CAPTION>
YEAR OCT NOV DEC TOTAL
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2001..................... -- -- 1 50
2002..................... -- -- 4 109
2003..................... -- -- 8 184
2004..................... 1 1 7 222
2005..................... 18 3 6 313
2006..................... 14 2 6 350
2007..................... 23 14 7 409
2008..................... 14 18 10 413
2009..................... 38 8 7 432
2010..................... 24 20 6 427
2011..................... 22 3 8 401
2012..................... 27 9 8 423
2013..................... 11 12 6 335
2014..................... 17 2 6 296
2015..................... 9 1 5 326
2016..................... 5 -- 6 266
2017..................... 7 -- 5 274
2018..................... 2 -- 2 245
2019..................... 2 -- 2 216
2020..................... 2 -- 1 167
2021..................... -- -- -- 120
</TABLE>
C-F-3
<PAGE>
MONTHLY CAPACITY FACTORS
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2001....................... 0% 0% 0% 0% 0% 2% 5% 7% 2%
2002....................... 0% 1% 0% 0% 1% 2% 6% 6% 2%
2003....................... 0% 1% 0% 0% 1% 5% 8% 9% 3%
2004....................... 1% 1% 0% 0% 2% 8% 8% 10% 2%
2005....................... 1% 1% 1% 0% 3% 9% 11% 13% 4%
2006....................... 1% 1% 1% 1% 3% 10% 12% 15% 6%
2007....................... 2% 1% 1% 0% 4% 12% 14% 16% 6%
2008....................... 2% 1% 1% 0% 4% 11% 14% 16% 6%
2009....................... 2% 2% 2% 1% 4% 11% 14% 16% 7%
2010....................... 2% 1% 2% 0% 4% 11% 14% 16% 6%
2011....................... 2% 1% 1% 0% 4% 11% 13% 16% 7%
2012....................... 1% 1% 2% 1% 4% 11% 14% 17% 7%
2013....................... 1% 1% 1% 0% 3% 9% 12% 14% 5%
2014....................... 1% 1% 1% 0% 3% 7% 11% 12% 5%
2015....................... 1% 1% 1% 0% 3% 8% 13% 14% 5%
2016....................... 1% 1% 0% 0% 3% 7% 11% 12% 4%
2017....................... 1% 1% 1% 0% 3% 7% 12% 11% 5%
2018....................... 0% 0% 0% 0% 2% 5% 12% 12% 5%
2019....................... 0% 0% 0% 0% 2% 6% 10% 11% 3%
2020....................... 0% 0% 0% 0% 2% 4% 8% 8% 2%
2021....................... 0% 0% 0% 0% 1% 4% 7% 6% 0%
-- -- -- -- -- -- -- -- --
Average.................... 1% 1% 1% 0% 3% 8% 11% 12% 4%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2001....................... 0% 0% 0% 2%
2002....................... 0% 0% 1% 2%
2003....................... 0% 0% 1% 2%
2004....................... 0% 0% 1% 3%
2005....................... 3% 0% 1% 4%
2006....................... 2% 0% 1% 4%
2007....................... 3% 2% 1% 5%
2008....................... 2% 3% 1% 5%
2009....................... 6% 1% 1% 5%
2010....................... 4% 3% 1% 5%
2011....................... 3% 0% 1% 5%
2012....................... 4% 1% 1% 5%
2013....................... 2% 2% 1% 4%
2014....................... 3% 0% 1% 4%
2015....................... 1% 0% 1% 4%
2016....................... 1% 0% 1% 3%
2017....................... 1% 0% 1% 3%
2018....................... 0% 0% 0% 3%
2019....................... 0% 0% 0% 3%
2020....................... 0% 0% 0% 2%
2021....................... 0% 0% 0% 2%
-- -- -- --
Average.................... 2% 1% 1% 4%
</TABLE>
SUMMARY
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003....................... 0% 1% 0% 0% 1% 5% 8% 9% 3%
2005....................... 1% 1% 1% 0% 3% 9% 11% 13% 4%
2010....................... 2% 1% 2% 0% 4% 11% 14% 16% 6%
2015....................... 1% 1% 1% 0% 3% 8% 13% 14% 5%
2020....................... 0% 0% 0% 0% 2% 4% 8% 8% 2%
-- -- -- -- -- -- -- -- --
Avg 2000-2021.............. 1% 1% 1% 0% 3% 8% 11% 12% 4%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003....................... 0% 0% 1% 2%
2005....................... 3% 0% 1% 4%
2010....................... 4% 3% 1% 5%
2015....................... 1% 0% 1% 4%
2020....................... 0% 0% 0% 2%
-- -- -- --
Avg 2000-2021.............. 2% 1% 1% 4%
</TABLE>
C-F-4
<PAGE>
APPENDIX F:
TENASKA GEORGIA POWER PROJECT--
HIGH START-UP COST PRICE FORECAST RESULTS
<TABLE>
<CAPTION>
HIGH START-UP COST ENERGY PRICES ($/MWH)
----------------------------------------------------
SUMMER MONTHS WINTER MONTHS
------------------- -------------------
HOURS OF DAY ANNUAL % CAPACITY %
------------------- YR ROUND PRICE CHG PRICE CHG
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION BASE $/KW-YR BASE
---- -------- -------- -------- -------- -------- ---------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000 24.50 17.98 22.46 18.47 21.73 -- 0.8% 46.36 -0.2%
2001 25.32 18.30 23.68 18.88 22.61 4.1% 1.0% 47.26 0.0%
2002 26.45 18.51 25.04 19.44 23.65 4.6% 1.7% 47.97 0.0%
2003 28.98 19.78 26.83 20.22 25.37 7.3% 2.1% 48.49 -0.4%
2004 30.03 20.04 28.62 20.98 26.64 5.0% 2.7% 49.52 -0.6%
2005 31.69 20.42 30.41 21.83 28.08 5.4% 3.3% 50.46 -0.2%
2006 33.25 21.15 31.82 22.52 29.31 4.4% 3.6% 51.11 -1.9%
2007 34.54 21.74 33.83 23.50 30.82 5.1% 4.1% 52.08 -0.6%
2008 35.65 22.33 35.20 24.59 31.99 3.8% 4.0% 52.85 -1.5%
2009 37.78 23.43 36.68 25.74 33.53 4.8% 4.0% 53.74 -2.4%
2010 38.64 24.11 38.25 26.85 34.75 3.6% 4.2% 54.63 -0.9%
2011 39.51 24.67 38.92 27.40 35.43 2.0% 4.0% 54.44 -2.5%
2012 40.57 25.38 39.32 28.14 36.09 1.8% 3.9% 55.27 -3.5%
2013 41.06 25.87 40.14 28.91 36.79 1.9% 3.9% 56.10 -3.6%
2014 41.91 26.69 40.77 29.72 37.52 2.0% 4.0% 57.05 -3.1%
2015 43.41 27.58 41.77 30.39 38.57 2.8% 3.9% 57.71 -3.2%
2016 43.89 28.05 42.69 31.10 39.30 1.9% 3.8% 58.78 -2.6%
2017 44.92 28.78 43.68 31.98 40.25 2.4% 4.0% 59.76 -2.8%
2018 46.14 29.56 44.38 32.79 41.10 2.1% 3.9% 60.56 -2.7%
2019 46.82 30.24 45.52 33.50 42.01 2.2% 4.0% 61.57 -2.5%
2020 47.81 31.15 46.39 34.49 42.93 2.2% 4.0% 62.50 -2.8%
2021 48.03 32.23 45.45 34.86 42.71 -0.5% 3.4% 63.64 -2.2%
2022 49.23 33.03 46.58 35.73 43.78 2.5% 3.4% 66.36 -0.5%
2023 50.46 33.86 47.75 36.62 44.88 2.5% 3.4% 68.02 -0.5%
2024 51.73 34.71 48.94 37.54 46.00 2.5% 3.4% 69.72 -0.5%
2025 53.02 35.57 50.16 38.47 47.15 2.5% 3.4% 71.46 -0.5%
2026 54.35 36.46 51.42 39.44 48.33 2.5% 3.4% 73.25 -0.5%
2027 55.70 37.38 52.70 40.42 49.53 2.5% 3.4% 75.08 -0.5%
2028 57.10 38.31 54.02 41.43 50.77 2.5% 3.4% 76.96 -0.5%
2029 58.52 39.27 55.37 42.47 52.04 2.5% 3.4% 78.88 -0.5%
2030 59.99 40.25 56.76 43.53 53.34 2.5% 3.4% 80.85 -0.5%
<CAPTION>
TOTAL REAL
TOTAL PRICE ANNUAL %
PRICE $/MWH* PRICE CHG
YEAR $/MWH* (1999$) ESCALATION BASE
---- -------- -------- ---------- --------
<S> <C> <C> <C> <C>
2000 30.55 29.81 -- 0.5%
2001 31.60 30.08 0.9% 0.7%
2002 32.77 30.43 1.2% 1.2%
2003 34.59 31.34 3.0% 1.4%
2004 36.06 31.87 1.7% 1.8%
2005 37.68 32.49 1.9% 2.4%
2006 39.04 32.84 1.1% 2.2%
2007 40.72 33.42 1.8% 2.9%
2008 42.04 33.67 0.7% 2.6%
2009 43.75 34.18 1.5% 2.4%
2010 45.14 34.41 0.7% 3.0%
2011 45.79 34.05 -1.0% 2.4%
2012 46.60 33.81 -0.7% 2.1%
2013 47.46 33.59 -0.6% 2.1%
2014 48.38 33.40 -0.6% 2.3%
2015 49.54 33.37 -0.1% 2.2%
2016 50.48 33.18 -0.6% 2.3%
2017 51.62 33.10 -0.2% 2.4%
2018 52.62 32.92 -0.5% 2.4%
2019 53.72 32.78 -0.4% 2.5%
2020 54.82 32.64 -0.4% 2.4%
2021 54.82 31.84 -2.4% 2.1%
2022 56.41 31.97 0.4% 2.5%
2023 57.82 31.97 0.0% 2.5%
2024 59.26 31.97 0.0% 2.5%
2025 60.74 31.97 0.0% 2.5%
2026 62.26 31.97 0.0% 2.5%
2027 63.82 31.97 0.0% 2.5%
2028 65.41 31.97 0.0% 2.5%
2029 67.05 31.97 0.0% 2.5%
2030 68.73 31.97 0.0% 2.5%
</TABLE>
------------------------
* Assumes a 60% load factor
C-F-5
<PAGE>
APPENDIX G:
LOW LOAD SCENARIO
As a supplement to this report, RDI examined the sensitivities of market
prices and the project's capacity factors to a regional decrease in demand. For
this scenario, a uniform demand growth rate of 1.5% was assumed throughout the
forecast period. Load growth assumptions in the base case are presented in
Figure 5. A comparison to assumed demand growth in the base case is presented in
Figure App-4.
FIGURE APP-4: LOAD GROWTH ASSUMPTIONS--BASE CASE VS. LOW LOAD SCENARIO
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
PEAK DEMAND IN BASE CASE V. LOW LOAD SCENARIO (GW)
<S> <C> <C>
BASE LOW LOAD
2000 39.42 39.42
2001 40.16 40.01
2002 40.85 40.61
2003 42.35 41.22
2004 44.27 41.84
2005 45.47 42.47
2006 46.25 43.11
2007 46.66 43.75
2008 47.18 44.41
2009 48.25 45.07
2010 49.75 45.75
2011 51.56 46.44
2012 53.19 47.13
2013 53.92 47.84
2014 54.46 48.56
2015 54.86 49.29
2016 55.79 50.03
2017 56.74 50.78
2018 57.71 51.54
2019 58.69 52.31
2020 59.68 53.10
</TABLE>
Summary tables showing detailed price and capacity factor results are
attached to this Appendix.
SCENARIO RESULTS
ENERGY PRICES Energy price results for the low load scenario are summarized
in Table App-6. Energy prices are approximately 3% lower than the base case
forecast from 2005-2012 because the decrease in demand diminishes the need for
higher cost resources. From 2013-2021, energy prices are approximately 2% than
base case prices.
C-G-1
<PAGE>
TABLE APP-6 ENERGY PRICE RESULTS--LOW LOAD SCENARIO (NOMINAL $)
<TABLE>
<CAPTION>
LOW LOAD ENERGY PRICES ($/MWH)
----------------------------------------------------
SUMMER MONTHS WINTER MONTHS
------------------- -------------------
HOURS OF DAY ANNUAL %
------------------- YR ROUND PRICE CHG
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION BASE
---- -------- -------- -------- -------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
2000......................................... 23.98 17.98 22.34 18.47 21.55 -- 0.0%
2001......................................... 24.70 18.28 23.42 18.87 22.34 3.6% -0.2%
2002......................................... 25.64 18.51 24.51 19.41 23.20 3.9% -0.2%
2003......................................... 27.62 19.70 25.85 20.07 24.55 5.8% -1.2%
2004......................................... 28.22 19.89 26.93 20.65 25.33 3.2% -2.3%
2005......................................... 29.36 20.22 28.27 21.39 26.41 4.3% -2.9%
2006......................................... 30.80 20.94 29.40 22.03 27.47 4.0% -2.9%
2007......................................... 32.02 21.45 31.13 22.93 28.80 4.8% -2.7%
2008......................................... 33.09 22.00 32.47 23.86 29.92 3.9% -2.7%
2009......................................... 34.95 23.11 33.87 24.91 31.34 4.7% -2.8%
2010......................................... 35.77 23.74 35.24 25.96 32.44 3.5% -2.7%
2011......................................... 36.52 24.32 36.02 26.64 33.18 2.3% -2.6%
2012......................................... 37.50 25.09 36.52 27.26 33.84 2.0% -2.6%
2013......................................... 38.00 25.52 37.32 28.06 34.53 2.1% -2.4%
2014......................................... 38.77 26.31 37.97 28.86 35.26 2.1% -2.3%
2015......................................... 40.20 27.22 38.97 29.62 36.30 3.0% -2.2%
2016......................................... 40.65 27.63 39.98 30.42 37.08 2.1% -2.1%
2017......................................... 41.62 28.46 40.90 31.28 37.99 2.5% -1.9%
2018......................................... 42.85 29.31 41.71 32.05 38.90 2.4% -1.6%
2019......................................... 43.49 29.91 42.79 32.90 39.78 2.3% -1.5%
2020......................................... 44.45 30.88 43.74 33.72 40.71 2.3% -1.4%
2021......................................... 44.76 31.70 43.11 34.18 40.65 -0.1% -1.6%
2022......................................... 45.88 32.49 44.18 35.03 41.67 2.5% -1.6%
2023......................................... 47.02 33.31 45.29 35.91 42.71 2.5% -1.6%
2024......................................... 48.20 34.14 46.42 36.81 43.78 2.5% -1.6%
2025......................................... 49.40 34.99 47.58 37.73 44.87 2.5% -1.6%
2026......................................... 50.64 35.87 48.77 38.67 45.99 2.5% -1.6%
2027......................................... 51.90 36.76 49.99 39.64 47.14 2.5% -1.6%
2028......................................... 53.20 37.68 51.24 40.63 48.32 2.5% -1.6%
2029......................................... 54.53 38.62 52.52 41.64 49.53 2.5% -1.6%
2030......................................... 55.90 39.59 53.83 42.69 50.77 2.5% -1.6%
</TABLE>
CAPACITY SUPPLY AND DEMAND The largest effect the low load scenario has on
the market is that 25% less new capacity will be required over the forecast
horizon. A comparison of capacity additions in the low load scenario to those in
the base case is presented in Table App-7.
C-G-2
<PAGE>
TABLE APP-7: CAPACITY ADDITIONS--BASE CASE VS. LOW LOAD SCENARIO
<TABLE>
<CAPTION>
CAP ADDITIONS (MW) CAPACITY PRICES $/KW-YR
----------------------------------------- ------------------------------------
CHG FROM % %
BASE LOW BASE CHG BASE LOW CHG
YEAR CASE LOAD (MW) BASE CASE LOAD BASE
---- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
2000.................................. 3,760 3,760 -- 0.0% 46.46 46.26 -0.4%
2001.................................. 4,570 3,782 788 -17.2% 47.26 47.26 0.0%
2002.................................. 2,450 1,717 733 -29.9% 47.97 47.77 -0.4%
2003.................................. 2,243 2,224 2,019 -17.6% 48.69 48.39 -0.6%
2004.................................. 5,115 2,336 2,779 -54.3% 49.82 49.42 -0.8%
2005.................................. 4,222 2,476 1,746 -41.4% 50.56 50.16 -0.8%
2006.................................. 2,438 2,335 103 -4.2% 52.11 51.01 -2.1%
2007.................................. 2,977 2,660 317 -10.6% 52.36 51.78 -1.1%
2008.................................. 2,655 2,368 287 -10.8% 53.65 52.75 -1.7%
2009.................................. 2,486 2,450 36 -1.4% 53.04 53.64 -2.5%
2010.................................. 3,828 2,439 1,399 -36.5% 55.13 52.09 -5.5%
2011.................................. 4,310 2,624 1,686 -39.1% 55.84 54.34 -2.7%
2012.................................. 4,197 2,894 1,303 -31.0% 57.25 55.07 -3.8%
2013.................................. 3,226 3,088 138 -4.3% 58.20 56.10 -3.6%
2014.................................. 2,654 2,885 (231) 8.7% 58.85 56.95 -3.2%
2015.................................. 2,935 2,714 221 -7.5% 59.61 57.81 -3.0%
2016.................................. 3,775 2,754 1,021 -27.0% 60.38 58.88 -2.5%
2017.................................. 3,849 2,793 1,056 -27.4% 61.46 59.76 -2.8%
2018.................................. 3,835 2,746 1,089 -28.4% 62.26 60.56 -2.7%
2019.................................. 3,915 2,786 1,129 -28.8% 63.17 61.57 -2.5%
2020.................................. 3,995 2,829 1,166 -29.2% 64.30 62.60 -2.8%
2021.................................. 5,255 4,054 1,201 -22.0% 65.08 63.04 -2.2%
------ ------ ------ ------ ----- ----- ----
Total................................. 80,700 60,714 19,986 -24.8%
</TABLE>
Even with lower growth projections, the results of the low load scenario
continue to indicate a strong need for capacity in the region. For this reason,
capacity prices in the low load scenario are only two to four percent lower than
the base case in the later years of the forecast (approximately
.30$/MWh assuming a 60% load factor). This supports the proposition that
regional capacity prices are only likely to be affected by very large changes in
the regional supply and demand balance. Capacity price results for the high
start-up cost scenario are shown in Figure App-5.
FIGURE APP-5 CAPACITY PRICE RESULTS--LOW LOAD SCENARIO
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
CAPACITY PRICES IN $/KW-YR
<S> <C> <C>
BASE LOW LOAD
2000 46.46 46.26
2001 47.26 47.26
2002 47.97 47.77
2003 48.69 48.39
2004 49.82 49.42
2005 50.56 50.16
2006 52.11 51.01
2007 52.38 51.78
2008 53.65 52.75
2009 55.04 53.64
2010 55.13 52.09
2011 55.84 54.34
2012 57.27 55.07
2013 58.2 56.10
2014 58.85 56.95
2015 59.61 57.81
2016 60.38 58.88
2017 61.46 59.76
2018 62.26 60.56
2019 63.17 61.57
2020 64.3 62.50
2021 65.08 63.64
</TABLE>
C-G-3
<PAGE>
CAPACITY FACTORS Table App-8 summarizes forecast monthly capacity factors
for select years of the forecast. As shown in Figure App-6. A detailed table
showing monthly capacity factors for each year of the forecast accompanies this
Appendix. Capacity factors are lower in the low load scenario than in the base
case because decreased demand reduces the amount the market relies on peaking
capacity.
TABLE APP-8 MONTHLY CAPACITY FACTORS--SELECT YEARS
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003....................... 0% 1% 0% 0% 2% 4% 7% 8% 2%
2005....................... 1% 1% 1% 0% 2% 7% 10% 9% 2%
2010....................... 0% 1% 1% 0% 3% 9% 11% 14% 2%
2015....................... 0% 1% 0% 0% 2% 4% 9% 9% 3%
2020....................... 0% 0% 0% 0% 1% 3% 6% 5% 0%
Avg 2000-2021.............. 0% 1% 0% 0% 2% 5% 0% 9% 2%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003....................... 0% 0% 1% 2%
2005....................... 0% 0% 1% 2%
2010....................... 0% 1% 1% 4%
2015....................... 0% 0% 1% 2%
2020....................... 0% 0% 0% 2%
Avg 2000-2021.............. 0% 0% 1% 3%
</TABLE>
FIGURE APP-6: MONTHLY CAPACITY FACTORS--SELECT YEARS
EDGAR REPRESENTATION OF DATA POINTS USED IN PRINTED GRAPHIC
<TABLE>
<CAPTION>
AUGUST CAPACITY FACTORS - SELECT YEARS
<S> <C> <C>
BASE CASE LOW LOAD
2003 9% 8%
2005 14% 9%
2010 18% 14%
2015 14% 9%
2020 7% 5%
</TABLE>
C-G-4
<PAGE>
APPENDIX G:
DETAILED MONTHLY CAPACITY FACTORS--
LOW LOAD SCENARIO
MONTHLY PLANT GENERATION (GWH)
TENASKA GEORGIA POWER PARTNERS
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2001...................... -- -- -- -- -- 7 17 21 4
2002...................... -- 3 1 -- 3 11 39 42 12
2003...................... -- 6 1 -- 11 27 50 51 14
2004...................... -- 6 -- -- 12 19 49 55 8
2005...................... 4 6 4 -- 16 47 64 60 15
2006...................... 1 6 4 -- 18 50 66 79 25
2007...................... 7 6 2 -- 20 53 77 87 22
2008...................... 6 6 8 -- 21 57 79 88 23
2009...................... 6 6 4 -- 20 58 74 91 32
2010...................... 2 6 4 -- 20 56 75 94 13
2011...................... 3 6 2 -- 19 46 63 65 20
2012...................... 2 6 2 -- 20 46 72 85 25
2013...................... 3 3 -- -- 17 38 69 71 8
2014...................... 2 6 -- -- 14 31 57 55 8
2015...................... -- 6 -- -- 15 28 61 62 18
2016...................... 1 -- -- -- 12 32 57 57 9
2017...................... 1 4 -- -- 11 20 56 41 6
2018...................... -- -- -- -- 10 23 51 52 12
2019...................... -- 3 -- -- 10 20 49 45 3
2020...................... -- -- -- -- 4 17 42 33 3
2021...................... -- -- -- -- -- 15 40 18 --
<CAPTION>
YEAR OCT NOV DEC TOTAL
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2001...................... -- -- 3 52
2002...................... 3 -- 6 120
2003...................... 1 -- 6 167
2004...................... 2 -- 7 158
2005...................... 2 2 6 226
2006...................... 1 -- 6 256
2007...................... 1 4 11 290
2008...................... 6 6 6 306
2009...................... 9 -- 6 306
2010...................... 2 4 10 286
2011...................... 2 4 6 236
2012...................... 2 -- 6 266
2013...................... 1 3 6 219
2014...................... 3 2 6 184
2015...................... -- -- 4 194
2016...................... -- -- 3 171
2017...................... -- -- 6 145
2018...................... -- -- -- 148
2019...................... -- -- 3 133
2020...................... -- -- -- 99
2021...................... -- -- -- 73
</TABLE>
C-G-5
<PAGE>
MONTHLY CAPACITY FACTORS
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2001........................... 0% 0% 0% 0% 0% 2% 5% 6% 1%
2002........................... 0% 1% 0% 0% 1% 2% 6% 6% 2%
2003........................... 0% 1% 0% 0% 2% 4% 7% 8% 2%
2004........................... 0% 1% 0% 0% 2% 3% 7% 8% 1%
2005........................... 1% 1% 1% 0% 2% 7% 10% 9% 2%
2006........................... 0% 1% 1% 0% 3% 8% 10% 12% 4%
2007........................... 1% 1% 0% 0% 3% 8% 11% 13% 3%
2008........................... 1% 1% 1% 0% 3% 9% 12% 13% 4%
2009........................... 1% 1% 1% 0% 3% 9% 11% 14% 5%
2010........................... 0% 1% 1% 0% 3% 9% 11% 14% 2%
2011........................... 0% 1% 0% 0% 3% 7% 9% 10% 3%
2012........................... 0% 1% 0% 0% 3% 7% 11% 13% 4%
2013........................... 0% 0% 0% 0% 3% 6% 10% 11% 1%
2014........................... 0% 1% 0% 0% 2% 5% 9% 8% 1%
2015........................... 0% 1% 0% 0% 2% 4% 9% 9% 3%
2016........................... 0% 0% 0% 0% 2% 5% 9% 9% 1%
2017........................... 0% 1% 0% 0% 2% 3% 8% 6% 1%
2018........................... 0% 0% 0% 0% 1% 4% 8% 8% 2%
2019........................... 0% 0% 0% 0% 1% 3% 7% 7% 0%
2020........................... 0% 0% 0% 0% 1% 3% 6% 5% 0%
2021........................... 0% 0% 0% 0% 0% 2% 6% 3% 0%
-- -- -- -- -- -- --- --- --
Average........................ 0% 1% 0% 0% 2% 5% 9% 9% 2%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2001........................... 0% 0% 1% 2%
2002........................... 0% 0% 1% 2%
2003........................... 0% 0% 1% 2%
2004........................... 0% 0% 1% 2%
2005........................... 0% 0% 1% 2%
2006........................... 0% 0% 1% 3%
2007........................... 0% 1% 2% 3%
2008........................... 1% 1% 1% 4%
2009........................... 1% 0% 1% 4%
2010........................... 0% 1% 1% 4%
2011........................... 0% 1% 1% 4%
2012........................... 0% 0% 1% 3%
2013........................... 0% 0% 1% 3%
2014........................... 0% 0% 1% 3%
2015........................... 0% 0% 1% 2%
2016........................... 0% 0% 0% 2%
2017........................... 0% 0% 1% 2%
2018........................... 0% 0% 0% 2%
2019........................... 0% 0% 0% 2%
2020........................... 0% 0% 0% 2%
2021........................... 0% 0% 0% 1%
-- -- -- --
Average........................ 0% 0% 1% 3%
</TABLE>
SUMMARY
<TABLE>
<CAPTION>
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP
---- -------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2003........................... 0% 1% 0% 0% 2% 4% 7% 8% 2%
2005........................... 1% 1% 1% 0% 2% 7% 10% 9% 2%
2010........................... 0% 1% 1% 0% 3% 9% 11% 14% 2%
2015........................... 0% 1% 0% 0% 2% 4% 9% 9% 3%
2020........................... 0% 0% 0% 0% 1% 3% 6% 5% 0%
-- -- -- -- -- -- --- --- --
Avg 2000-2021.................. 0% 1% 0% 0% 2% 5% 9% 9% 2%
<CAPTION>
YEAR OCT NOV DEC AVG
---- -------- -------- -------- --------
<S> <C> <C> <C> <C>
2003........................... 0% 0% 1% 2%
2005........................... 0% 0% 1% 2%
2010........................... 0% 1% 1% 4%
2015........................... 0% 0% 1% 2%
2020........................... 0% 0% 0% 2%
-- -- -- --
Avg 2000-2021.................. 0% 0% 1% 3%
</TABLE>
C-G-6
<PAGE>
APPENDIX G:
TENASKA GEORGIA POWER PROJECT--
LOW LOAD PRICE FORECAST RESULTS
<TABLE>
<CAPTION>
LOW LOAD ENERGY PRICES ($/MWH)
----------------------------------------------------
SUMMER MONTHS WINTER MONTHS
------------------- -------------------
HOURS OF DAY ANNUAL % CAPACITY %
------------------- YR ROUND PRICE CHG PRICE CHG
YEAR CONTRACT OFF CONTRACT OFF AVG ESCALATION BASE $/KW-YR BASE
---- -------- -------- -------- -------- -------- ---------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2000........ 23.98 17.98 22.34 18.47 21.55 -- 0.0% 46.26 -0.4%
2001........ 24.70 18.28 23.42 18.87 22.34 3.6% -0.2% 47.26 0.0%
2002........ 25.64 18.51 24.51 19.41 23.20 3.9% -0.2% 47.77 -0.4%
2003........ 27.62 19.70 25.85 20.07 24.55 5.8% -1.2% 48.39 -0.6%
2004........ 28.22 19.89 26.93 20.65 25.33 3.2% -2.3% 49.42 -0.8%
2005........ 29.36 20.22 28.27 21.39 26.41 4.3% -2.9% 50.16 -0.8%
2006........ 30.80 20.94 29.40 22.03 27.47 4.0% -2.9% 51.01 -2.1%
2007........ 32.02 21.45 31.13 22.93 28.80 4.8% -2.7% 51.78 -1.1%
2008........ 33.09 22.00 32.47 23.86 29.92 3.9% -2.7% 52.75 -1.7%
2009........ 34.95 23.11 33.87 24.91 31.34 4.7% -2.8% 53.64 -2.5%
2010........ 35.77 23.74 35.24 25.96 32.44 3.5% -2.7% 52.09 -5.5%
2011........ 36.52 24.32 36.02 26.64 33.18 2.3% -2.6% 54.34 -2.7%
2012........ 37.50 25.09 36.52 27.26 33.84 2.0% -2.6% 55.07 -3.8%
2013........ 38.00 25.52 37.32 28.06 34.53 2.1% -2.4% 56.10 -3.6%
2014........ 38.77 26.31 37.97 28.86 35.26 2.1% -2.3% 56.95 -3.2%
2015........ 40.20 27.22 38.97 29.62 36.30 3.0% -2.2% 57.81 -3.0%
2016........ 40.65 27.63 39.98 30.42 37.08 2.1% -2.1% 58.88 -2.5%
2017........ 41.62 28.46 40.90 31.28 37.99 2.5% -1.9% 59.76 -2.8%
2018........ 42.85 29.31 41.71 32.05 38.90 2.4% -1.6% 60.56 -2.7%
2019........ 43.49 29.91 42.79 32.90 39.78 2.3% -1.5% 61.57 -2.5%
2020........ 44.45 30.88 43.74 33.72 40.71 2.3% -1.4% 62.50 -2.8%
2021........ 44.76 31.70 43.11 34.18 40.65 -0.1% -1.6% 63.64 -2.2%
2022........ 45.88 32.49 44.18 35.03 41.67 2.5% -1.6% 66.36 -0.5%
2023........ 47.02 33.31 45.29 35.91 42.71 2.5% -1.6% 68.02 -0.5%
2024........ 48.20 34.14 46.42 36.81 43.78 2.5% -1.6% 69.72 -0.5%
2025........ 49.40 34.99 47.58 37.73 44.87 2.5% -1.6% 71.46 -0.5%
2026........ 50.64 35.87 48.77 38.67 45.99 2.5% -1.6% 73.25 -0.5%
2027........ 51.90 36.76 49.99 39.64 47.14 2.5% -1.6% 75.08 -0.5%
2028........ 53.20 37.68 51.24 40.63 48.32 2.5% -1.6% 76.96 -0.5%
2029........ 54.53 38.62 52.52 41.64 49.53 2.5% -1.6% 78.88 -0.5%
2030........ 55.90 39.59 53.83 42.69 50.77 2.5% -1.6% 80.85 -0.5%
<CAPTION>
TOTAL REAL
TOTAL PRICE ANNUAL %
PRICE $/MWH* PRICE CHG
YEAR $/MWH* (1999$) ESCALATION BASE
---- -------- -------- ---------- --------
<S> <C> <C> <C> <C>
2000........ 30.36 29.62 -- -0.1%
2001........ 31.33 29.82 0.7% -0.1%
2002........ 32.29 29.99 0.6% -0.3%
2003........ 33.75 30.58 2.0% -1.0%
2004........ 34.73 30.70 0.4% -1.9%
2005........ 35.95 31.00 1.0% -2.3%
2006........ 37.18 31.28 0.9% -2.7%
2007........ 38.65 31.73 1.4% -2.3%
2008........ 39.96 32.00 0.9% -2.4%
2009........ 41.54 32.45 1.4% -2.8%
2010........ 42.36 32.28 -0.5% -3.4%
2011........ 43.52 32.36 0.2% -2.6%
2012........ 44.32 32.15 -0.7% -2.9%
2013........ 45.21 31.99 -0.5% -2.7%
2014........ 46.09 31.82 -0.5% -2.5%
2015........ 47.30 31.86 0.1% -2.4%
2016........ 48.28 31.73 -0.4% -2.2%
2017........ 49.36 31.65 -0.3% -2.1%
2018........ 50.42 31.54 -0.3% -1.9%
2019........ 51.49 31.43 -0.4% -1.8%
2020........ 52.60 31.32 -0.3% -1.7%
2021........ 52.76 30.65 -2.1% -1.7%
2022........ 54.29 30.77 0.4% -1.3%
2023........ 55.65 30.77 0.0% -1.3%
2024........ 57.04 30.77 0.0% -1.3%
2025........ 58.47 30.77 0.0% -1.3%
2026........ 59.93 30.77 0.0% -1.3%
2027........ 61.43 30.77 0.0% -1.3%
2028........ 62.96 30.77 0.0% -1.3%
2029........ 64.54 30.77 0.0% -1.3%
2030........ 66.15 30.77 0.0% -1.3%
</TABLE>
------------------------
* Assumes a 60% load factor
C-G-7
<PAGE>
APPENDIX H:
REGIONAL OZONE TRANSPORT RULE
In September 1998, the EPA finalized the regional ozone transport rule.
Similar to the goal of the Ozone Transport Commission's (OTC) nitrous oxide
(NO(X)) program, which began May 1, 1999, this rulemaking establishes summertime
NO(X) emissions budgets for twenty-two states and the District of Columbia.
Included within this program are all of the states participating in the OTC
trading program except for Maine, New Hampshire, and Vermont. Unlike the
state-driven OTC program, however, the NO(X) State Implementation Plant (SIP)
call marks the first time the EPA has REQUIRED states to reduce the emissions of
ozone precursors to assist with ozone mitigation in other downwind states.
The process for evaluating ozone transport over an area extending past the
Northeast Ozone Transport Region began in March 1995 with the establishment of
the Ozone Transport Assessment Group (OTAG). This workgroup was composed of the
thirty-seven eastern most states and the District of Columbia as well as the EPA
and other interested stakeholders including industry and environmental groups.
The goal of this workgroup was "to identify and recommend a strategy to reduce
transported ozone and its precursors, which, in combination with other measures,
will enable attainment and maintenance of the ozone standard in the OTAG region.
A number of criteria were to be considered in selecting a strategy, including
but not limited to, "cost-effectiveness, feasibility, and impacts on ozone
levels."(12) OTAG completed its work and issued recommendations in June 1997.
Despite reaching conclusions by majority vote, the group remained sharply
divided over the findings and recommendations. Overall, the OTAG membership
concluded that ozone and its precursors could travel over long distances and
recognized transport of 150, 300, and as far as 500 miles, in some cases. The
group made broad recommendations for future atmospheric modeling and specific
recommendations for several sectors. For the utility sector, OTAG concluded that
EPA should require utility NO(X) controls that fall into the range between
existing reductions planned under the Clean Air Act Amendments of 1990 (CAAA90)
and the less stringent of 85% reduction or
0.15 lb/mmBtu, and that EPA should assist states with complying with the
existing National Ambient Air Quality Standards (NAAQS).
Once OTAG completed its work, EPA immediately began the process of
developing the ozone transport rule resulting in a proposal that was released in
November 1997 and the final rule in September 1998. In this rulemaking, EPA
found, based on OTAG air quality modeling as well as additional modeling
performed by EPA, that NO(X) emissions from sources in the 23 jurisdictions
significantly contribute to non-attainment of the ozone NAAQS in one or more
downwind states throughout the eastern U.S. EPA cites section 110(a)(2)(D) of
the CAAA90 as the authority to control NO(X) emissions in states that are found
to be significant contributors to transport. Section 110(a)(2)(D) authorizes EPA
to require these states to develop adequate emission control programs to prevent
their emissions from significantly contributing to non-attainment, or
interfering with maintenance, in one or more downwind states.
The rule requires that the affected states adopt adequate control programs
to meet the prescribed NO(X) emissions budgets and to submit these regulations
to EPA for review by September 1999(13). The control programs are to then be
implemented by May 1, 2003. Although EPA established a summertime emission
budget for each state under this rulemaking, EPA does not have the authority to
mandate the specific controls or the specific sources that the states should
regulate to achieve the budgets. Each state has the flexibility to develop its
own control strategy. However, the economics of
------------------------
(12) Ozone Transport Assessment Group, Executive Report; July 1997
(13) The United States Court of Appeal recently remanded the rules regarding
the state's filings of State Implimentation plans. This ruling is currently
under appeal, but if the appeal is not successful the implementation of the
program could be delayed.
C-H-1
<PAGE>
pollution control and the politics associated with regulating certain types of
sources, such as automobiles, suggest that states are likely to get most of the
required reductions from electric generating units and from other large
stationary sources used by industrial sectors.
EPA developed individual state emissions budgets for this rulemaking by
determining the amount of NO(X) emissions that each state would have after
applying what EPA determined to be "highly cost-effective controls." To perform
the budget calculation, EPA projected the 1995/1996 baseline emissions data for
each state out to the year 2007. For fossil fuel fired electricity generating
units greater than 25 MW, EPA multiplied the 2007 projected heat input by a
0.15 lb/mmBtu emissions rate to determine this sector's budget contribution to
the overall state budget. See Table App-9. EPA also assumed emissions reductions
for three other source categories: large industrial boilers and turbines
(greater than 250 mmBtu/hr), stationary combustion engines, and cement kilns.
EPA calculated a flat percentage reduction from the 2007 projected emissions to
establish the budget contribution for these categories. The reductions are 60%,
90%, and 30%, respectively. To establish the remainder of the state budgets, EPA
calculated the projected 2007 emissions for all other source categories, which
includes projections for reductions required by other parts of the CAAA90 but
does not assume any additional controls.
TABLE APP-9: REGIONAL OZONE TRANSPORT RULE EMISSION BUDGETS
<TABLE>
<CAPTION>
BUDGET CONTRIBUTION FOR
STATE ELECTRIC GENERATING UNITS
----- -------------------------
<S> <C>
Alabama................................................ 29,051
Connecticut............................................ 2,583
Delaware............................................... 3,523
District of Columbia................................... 207
Georgia................................................ 30,255
Illinois............................................... 32,045
Indiana................................................ 49,020
Kentucky............................................... 36,753
Maryland............................................... 14,807
Massachusetts.......................................... 15,033
Michigan............................................... 28,165
Missouri............................................... 23,923
New Jersey............................................. 10,863
New York............................................... 30,273
North Carolina......................................... 31,394
Ohio................................................... 49,468
Pennsylvania........................................... 52,000
Rhode Island........................................... 1,118
South Carolina......................................... 16,290
Tennesses.............................................. 25,386
Virginia............................................... 18,258
West Virginia.......................................... 26,439
Wisconsin.............................................. 17,972
</TABLE>
Although EPA does not have the authority under Title I to mandate that
states control certain sources, EPA did strongly recommend a specific control
strategy. Very similar to the OTC NO(X) trading program, EPA recommended that
states implement a regional emission trading program designed for large electric
generating units and industrial sources. To facilitate the establishment of the
trading program, EPA adopted a model trading rule as a part of the regional
ozone transport rule. The model rule is very close in purpose and design to the
model rule used in the OTC trading program. States
C-H-2
<PAGE>
that wish to participate in the regional trading program need to adopt a state
regulation that is consistent with the model rule.
The regional ozone transport rule is being legally challenged by a variety
of states, companies, and associations representing companies. At the same time,
a number of states, companies, and environmental groups are intervening in the
litigation on behalf of EPA. (See Table App-10 for a list of litigating
parties.) Although cases were filed in several courts throughout the region
affected by the rule, it is likely that all of the cases will be transferred to
the D.C. Circuit court. The deadline has now expired for the filing of
additional cases and intervention. Based on the current schedule, oral arguments
for the case will probably be heard in the fall of 1999. Although a variety of
issues are included in the litigation, the case centers around two key issues.
The first is whether EPA has the legal authority under Section 110(a)(2)(D) of
the CAAA90 to mandate that the affected states meet the specific emissions
budgets. And if EPA does have the authority, the second issue is whether the
levels of control are more stringent than necessary to significantly mitigate
the transport of ozone between states outside of the Northeast Ozone Transport
Region. EPA appears to be on track to continue with implementation of the
regional ozone transport ruling as originally adopted, unless the court were to
force a delay in the schedule.
TABLE APP-10: SELECTIVE LIST OF PARTIES IN THE REGIONAL OZONE TRANSPORT RULE
LITIGATION
<TABLE>
<CAPTION>
PETITIONERS INTERVENORS IN SUPPORT OF EPA
----------- -------------------------------------
<S> <C>
Alabama.................................................. Connecticut
Indiana.................................................. Maine
Kansas................................................... Massachusetts
Michigan................................................. New Hampshire
North Carolina........................................... New York
Ohio..................................................... Pennsylvania
South Carolina........................................... Rhode Island
West Virginia............................................ Vermont
Midwest and Southeast Utilities.......................... East and Northeast Electric Utilities
Interstate Natural Gas Assoc. of America................. Natural Resource Defense Council
United Mine Workers of America........................... New England Council
Virginia Chamber of Commerce.............................
</TABLE>
C-H-3
<PAGE>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
3.1+ Amended and Restated Partnership Agreement of Tenaska
Georgia Partners, L.P., dated as of October 29, 1999,
between Tenaska Georgia, Inc. and Tenaska Georgia I, L.P.
4.1+ Indenture of Trust, dated as of November 1, 1999, among the
partnership, the Trustee and the Depositary Bank.
4.2+ Collateral Agency and Intercreditor Agreement, dated as of
November 1, 1999, among the partnership, the Trustee, the
Development Authority Trustee, the Collateral Agent, the
Debt Service Reserve Letter of Credit Provider, the Power
Purchase Agreement Letter of Credit Provider and the
Depositary Bank.
4.3+ Form of bonds, dated November 10, 1999, evidencing 9.50%
Senior Secured Bonds of the partnership due 2030 in the
principal amount of $275,000,000.
4.4+ Assignment and Security Agreement, dated as of November 1,
1999, between the partnership and the Collateral Agent.
4.5+ General Partner Pledge and Security Agreement, dated as of
November 1, 1999, between Tenaska Georgia, Inc. and the
Collateral Agent.
4.6+ Limited Partner Pledge and Security Agreement, dated as of
November 1, 1999, between Tenaska Georgia I, L.P. and the
Collateral Agent.
4.7+ Exchange and Registration Rights Agreement, dated as of
November 10, 1999, between the partnership and the initial
purchasers of the old bonds.
4.8+ Leasehold Deed to Secure Debt, Assignment of Rents and
Leases and Security Agreement dated as of November 10, 1999
by the partnership to the Collateral Agent.
4.9+ Consent and Agreement, dated as of November 10, 1999, among
the Power Purchaser, the Collateral Agent and the
partnership.
4.10+ Consent and Agreement, dated as of November 10, 1999, among
the Georgia Power Company, the Collateral Agent and the
partnership.
4.11+ Consent and Agreement, dated as of November 10, 1999, among
the Zachry Construction Corporation, the Collateral Agent
and the partnership (with respect to the EPC Contract).
4.12+ Consent and Agreement, dated as of November 10, 1999, among
H.B. Zachry Company, the Collateral Agent and the
partnership.
4.13+ Consent and Agreement, dated as of November 10, 1999, among
Tenaska Operations, Inc., the Collateral Agent and the
partnership (with respect to the Operations & Maintenance
Agreement).
4.14+ Consent and Agreement, dated as of November 10, 1999, among
Heard County Water Authority, the Collateral Agent and the
partnership.
</TABLE>
II-1
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
4.15+ Consent and Agreement, dated as of November 10, 1999, among
Transcontinental Gas Pipe Line Corporation, the Collateral
Agent and the partnership.
4.16+ Consent and Agreement, dated as of November 10, 1999, among
General Electric Company, the Collateral Agent and the
partnership.
4.17+ Consent to Assignment, dated as of November 10, 1999, among
Willbros Engineers, Inc., the Collateral Agent and the
partnership.
4.18+ Consent to Assignment, dated as of November 10, 1999, among
Willbros Group, Inc., the Collateral Agent and the
partnership.
4.19+ Indenture of Trust, dated as of November 1, 1999, between
The Development Authority of Heard County, Georgia ("DAHC")
and The Chase Manhattan Bank, as Trustee.
4.20+ Development Authority Bonds, dated November 10, 1999,
evidencing $275,000,000 Taxable Industrial Development
Revenue Bonds, Series 1999, issued by the Development
Authority under the Development Authority Indenture.
4.21+ Lease Agreement, dated as of November 1, 1999, between the
partnership and The Development Authority of Heard County,
Georgia.
4.22+ Deed to Secure Debt, Security Agreement and Assignment of
Rents and Leases, dated as of November 1, 1999 by DAHC in
favor of the DAHC Trustee.
4.23+ Guaranty Agreement, dated as of November 1, 1999, between
the partnership and the DAHC Trustee for DAHC Bonds.
4.24+ Debt Service Reserve Letter of Credit and Reimbursement
Agreement, dated as of November 10, 1999, among the
partnership, the DSR LOC Provider and the Banks named
therein.
4.25+ Equity Contribution Agreement, dated as of November 1, 1999,
among the partnership, the Contributing Partners and the
Collateral Agent.
4.26+ Agreement as to Certain Undertakings, Common
Representations, Warranties, Covenants and Other Terms,
dated as of November 1, 1999, among the partnership, the
Trustee, the DSR LOC Agent, the Power Purchase Agreement LOC
Agent and the Collateral Agent.
4.27+ Power Purchase Agreement Letter of Credit.
4.28+ Tenaska Georgia I, L.P. Letter of Credit.
4.29+ Tenaska Georgia, Inc. Letter of Credit.
5.1+ Opinion of Winthrop, Stimson, Putnam & Roberts regarding the
legality of the new bonds.
8.1+ Opinion of Winthrop, Stimson, Putnam & Roberts regarding tax
matters.
10.1+ H.B. Zachry Company Guaranty of Obligation dated as of
October 22, 1999 made by H.B. Zachry Company in favor of the
partnership
10.2+ EPC Contractor Performance Bond and Payment Bond
10.3*+ Power Purchase Agreement, dated August 24, 1999, between the
partnership and the Power Purchaser.
</TABLE>
II-2
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
10.4* Engineering, Procurement and Construction Agreement, dated
as of September 15, 1999 (the "EPC Contract"), as amended,
between the partnership (as assignee of Tenaska Georgia I,
L.P.) and the EPC Contractor.
10.4.1+ First Amendment, dated as of October 8, 1999, to the
Engineering, Procurement and Construction Agreement between
the partnership (as assignee of Tenaska Georgia I, L.P.) and
the EPC Contractor.
10.4.2+ Option 5--Substation Switchyard, exercised by the
partnership on October 20, 1999.
10.4.3+ Agreement for Assignment and Assumption of EPC Contract to
the partnership, dated November 10, 1999, between Tenaska
Georgia I, L.P. and the partnership.
10.5+ Guaranty of Obligation, dated as of September 23, 1999,
between Willbros Group, Inc. and the partnership.
10.6+ Operations and Maintenance Agreement, dated as of September
10, 1999, as amended, between the partnership and Tenaska
Operations, Inc.
10.6.1+ Amendment, dated as of October 26, 1999, to the Operations
and Maintenance Agreement, between the partnership and
Tenaska Operations, Inc.
10.6.2+ Second Amendment, dated as of November 4, 1999, to the
Operations and Maintenance Agreement, between the
partnership and Tenaska Operations, Inc.
10.7+ Interconnection Agreement, dated as of October 19, 1999,
between the partnership and Georgia Power Company.
10.8*+ Fixed Price Engineering, Procurement and Construction
Services Agreement, dated September 23, 1999 (the "Pipeline
EPC Contract"), between the partnership and Willbros
Engineers, Inc.
10.9+ Interconnect, Reimbursement and Operating Agreement, dated
as of August 18, 1999, between the partnership and the
Transcontinental Gas Pipe Line Corporation.
10.10+ Water Purchase Agreement, dated February 25, 1999, between
the partnership and the Heard County Water Authority.
10.11* Contract for Purchase, dated as of August 27, 1999, between
General Electric and the partnership, as assignee of Tenaska
Georgia I, L.P.
10.11.1+ Agreement for Assignment and Assumption of Turbine Contract
to the partnership, dated as of November 10, 1999, between
Tenaska Georgia I, L.P. and the partnership.
10.11.2+ Agreement for Assignment and Assumption of Turbine Contract
to the partnership, dated as of November 10, 1999, between
Zachry Construction Corporation and the partnership.
10.12+ Ground Lease, dated as of November 10, 1999 between the
partnership and Tenaska Georgia, Inc.
10.13+ Short Form Ground Lease Agreement, dated November 10, 1999
between the partnership and Tenaska Georgia, Inc.
10.14+ Access and Utility Easement Agreement, dated November 10,
1999 between the partnership and Tenaska Georgia, Inc.
10.15+ Electric Substation Site Option Agreement, dated November
10, 1999 between the partnership and Tenaska Georgia, Inc.
</TABLE>
II-3
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
10.16+ Natural Gas Pipeline Right-of-Way, dated November 2, 1999
between the partnership and Great Northern Nekoosa
Corporation.
10.17+ Perpetual Right-of-Way and Easement Agreement, dated
November 1, 1999 between the partnership and Charles
Goodson.
10.18+ Perpetual Right-of-Way and Easement Agreement, dated
November 1, 1999 between the partnership and Tenaska
Georgia, Inc.
10.19+ Construction Easement Agreement, dated October 8, 1999
between the partnership and Inland Paperboard and Packaging,
Inc.
10.20+ Easement Agreement, dated November 2, 1999 among the
partnership, Susan Lynn Payne and Robert Charles Payne.
10.21+ Non-Interference and Cross Indemnity Agreement, dated as of
November 10, 1999 between Tenaska Georgia, Inc. and the
partnership.
10.22+ Power Purchase Agreement Letter of Credit and the
Reimbursement Agreement, dated as of November 10, 1999,
among the partnership, the Power Purchase Agreement LOC
Provider and the Banks named therein.
10.23+ Agreement Regarding Ad Valorem Taxation, dated as of July
30, 1999, among the partnership, the Board of Commissioners
of Heard County, and the Board of Tax Assessors of Heard
County.
10.24* Long Term Parts & Long Term Service Contract, dated June 24,
1999, between General Electric International, Inc. and the
partnership, as assignee of Tenaska, Inc.
10.24.1+ Agreement for Assignment and Assumption of LTSA to Tenaska
Georgia I, dated November 10, 1999, between Tenaska, Inc.
and Tenaska Georgia I, L.P.
10.24.2+ Agreement for Assignment and Assumption of LTSA to Tenaska
Georgia, dated November 10, 1999, between Tenaska Georgia I,
L.P. and the partnership.
12.1+ Statement regarding ratio of earnings to fixed charges.
23.1.1+ Consent of Winthrop, Stimson, Putnam & Roberts (included in
Exhibit 5.1 to this Registration Statement).
23.1.2+ Consent of Winthrop, Stimson, Putnam & Roberts (included in
Exhibit 8.1 to this Registration Statement).
23.2 Consent of Arthur Andersen LLP.
23.3+ Consent of R.W. Beck, Inc.
23.4+ Consent of Resource Data International, Inc.
23.5+ Consent of EMCON.
24.1+ Power-of-Attorney (contained on the signature page of this
Registration Statement).
25.1+ Statement of Eligibility and Qualification on Form T-1 of
The Chase Manhattan Bank.
27.1+ Financial Data Schedule.
99.1+ Form of Letter of Transmittal.
99.2+ Form of Letter to Clients.
</TABLE>
II-4
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
99.3+ Form of Letter to Registered Holders and DTC Participants.
99.4+ Form of Notice of Guaranteed Delivery.
99.5+ Form of Instruction to Registered Holders.
</TABLE>
+ Previously filed.
* Portions of this exhibit have been omitted and filed separately with the
SEC, pursuant to a confidential treatment request.
(b) Financial Statement Schedules
Financial statement schedules are not included as the required information
is inapplicable or is presented in the financial statements or the notes
thereto.
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 set forth in the
registration statement. Notwithstanding the foregoing, any increase or
decrease in volume of securities offered (if the total dollar value of
securities 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 set forth in the "Calculation of Registration Fee" table in the
effective registration statement; and
(iii) To include any material information with respect to the plan of
distribution not previously disclosed in the registration statement or any
material change to such information in the registration statement.
PROVIDED, HOWEVER, that paragraphs (a)(1)(i) and (a)(1)(ii) do not apply if
the registration statement is on Form S-3, Form S-8, or Form F-3, and the
information required to be included in a post-effective amendment by those
paragraphs is contained in periodic reports filed by the registrant pursuant to
section 13 or section 15(d) of the Securities Exchange Act of 1934 that are
incorporated by reference in the registration statement.
(2) That, for the purpose of determining any liability under the Securities
Act of 1933, each such post-effective amendment shall be deemed to be a new
registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any
of the securities being registered which remain unsold at the termination of the
offering.
(b) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the registrant, pursuant to the foregoing
II-5
<PAGE>
provisions, or otherwise, the registrant has been advised that in the opinion of
the SEC such indemnification is against public policy as expressed in the
Securities Act of 1933 and is, therefore, unenforceable. In the event that a
claim for indemnification against such liabilities (other than the payment by
the registrant of expenses incurred or paid by a director, officer or
controlling person of the registrant in the successful defense of any action,
suit or proceeding) is asserted by any such director, officer or controlling
person in connection with the securities being registered, the registrant will,
unless in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question of whether
or not such indemnification is against public policy as expressed in the
Securities Act of 1933 and will be governed by the final adjudication of such
issue.
(c) The undersigned registrant hereby undertakes to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Item 4, 10(b), 11 or 13 of this form, within one business day of receipt of such
request, and to send the incorporated documents by first class mail or other
equally prompt means. This includes information contained in documents filed
subsequent to the effective date of the registration statement through the date
of responding to the request.
(d) The undersigned registrant hereby undertakes to supply by means of a
post-effective amendment all information concerning a transaction, and the
company being acquired involved therein, that was not the subject of and
included in the registration statement when it became effective.
II-6
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this Amendment No. 3 to the registration statement to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of
Omaha, State of Nebraska on the 25th day of July, 2000.
<TABLE>
<S> <C> <C>
TENASKA GEORGIA PARTNERS, L.P.
a Delaware limited partnership
By: Tenaska Georgia, Inc.
a Delaware corporation, as General Partner
of
Tenaska Georgia Partners, L.P.
By: /s/ MICHAEL F. LAWLER
-----------------------------------------
Michael F. Lawler
VICE PRESIDENT OF FINANCE AND TREASURER
</TABLE>
Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 3 to the registration statement has been signed by the following persons in
the capacities and on the dates indicated.
<TABLE>
<C> <C> <S>
By: *
----------------------------------------
Name: Howard L. Hawks
Title: Director--Tenaska Georgia, Inc.
Date: July 25, 2000
By: *
----------------------------------------
Name: Thomas E. Hendricks
Title: Director--Tenaska Georgia, Inc.
Date: July 25, 2000
By: *
----------------------------------------
Name: Ronald N. Quinn
Title: Director--Tenaska Georgia, Inc.
Date: July 25, 2000
By: *
----------------------------------------
Name: John T. Reed
Title: Director--Tenaska Georgia, Inc.
Date: July 25, 2000
</TABLE>
* Signed by Michael F. Lawler pursuant to the Power of Attorney dated
January 31, 2000
By: /s/ MICHAEL F. LAWLER
-------------------------------------------
Michael F. Lawler
VICE PRESIDENT OF FINANCE AND TREASURER
II-7
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
3.1+ Amended and Restated Partnership Agreement of Tenaska
Georgia Partners, L.P., dated as of October 29, 1999,
between Tenaska Georgia, Inc. and Tenaska Georgia I, L.P.
4.1+ Indenture of Trust, dated as of November 1, 1999, among the
partnership, the Trustee and the Depositary Bank.
4.2+ Collateral Agency and Intercreditor Agreement, dated as of
November 1, 1999, among the partnership, the Trustee, the
Development Authority Trustee, the Collateral Agent, the
Debt Service Reserve Letter of Credit Provider, the Power
Purchase Agreement Letter of Credit Provider and the
Depositary Bank.
4.3+ Form of bonds, dated November 10, 1999, evidencing 9.50%
Senior Secured Bonds of the partnership due 2030 in the
principal amount of $275,000,000.
4.4+ Assignment and Security Agreement, dated as of November 1,
1999, between the partnership and the Collateral Agent.
4.5+ General Partner Pledge and Security Agreement, dated as of
November 1, 1999, between Tenaska Georgia, Inc. and the
Collateral Agent.
4.6+ Limited Partner Pledge and Security Agreement, dated as of
November 1, 1999, between Tenaska Georgia I, L.P. and the
Collateral Agent.
4.7+ Exchange and Registration Rights Agreement, dated as of
November 10, 1999, between the partnership and the initial
purchasers of the old bonds.
4.8+ Leasehold Deed to Secure Debt, Assignment of Rents and
Leases and Security Agreement dated as of November 10, 1999
by the partnership to the Collateral Agent.
4.9+ Consent and Agreement, dated as of November 10, 1999, among
the Power Purchaser, the Collateral Agent and the
partnership.
4.10+ Consent and Agreement, dated as of November 10, 1999, among
the Georgia Power Company, the Collateral Agent and the
partnership.
4.11+ Consent and Agreement, dated as of November 10, 1999, among
the Zachry Construction Corporation, the Collateral Agent
and the partnership (with respect to the EPC Contract).
4.12+ Consent and Agreement, dated as of November 10, 1999, among
H.B. Zachry Company, the Collateral Agent and the
partnership.
4.13+ Consent and Agreement, dated as of November 10, 1999, among
Tenaska Operations, Inc., the Collateral Agent and the
partnership (with respect to the Operations & Maintenance
Agreement).
4.14+ Consent and Agreement, dated as of November 10, 1999, among
Heard County Water Authority, the Collateral Agent and the
partnership.
4.15+ Consent and Agreement, dated as of November 10, 1999, among
Transcontinental Gas Pipe Line Corporation, the Collateral
Agent and the partnership.
4.16+ Consent and Agreement, dated as of November 10, 1999, among
General Electric Company, the Collateral Agent and the
partnership.
4.17+ Consent to Assignment, dated as of November 10, 1999, among
Willbros Engineers, Inc., the Collateral Agent and the
partnership.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
4.18+ Consent to Assignment, dated as of November 10, 1999, among
Willbros Group, Inc., the Collateral Agent and the
partnership.
4.19+ Indenture of Trust, dated as of November 1, 1999, between
The Development Authority of Heard County, Georgia ("DAHC")
and The Chase Manhattan Bank, as Trustee.
4.20+ Development Authority Bonds, dated November 10, 1999,
evidencing $275,000,000 Taxable Industrial Development
Revenue Bonds, Series 1999, issued by the Development
Authority under the Development Authority Indenture.
4.21+ Lease Agreement, dated as of November 1, 1999, between the
partnership and The Development Authority of Heard County,
Georgia.
4.22+ Deed to Secure Debt, Security Agreement and Assignment of
Rents and Leases, dated as of November 1, 1999 by DAHC in
favor of the DAHC Trustee.
4.23+ Guaranty Agreement, dated as of November 1, 1999, between
the partnership and the DAHC Trustee for DAHC Bonds.
4.24+ Debt Service Reserve Letter of Credit and Reimbursement
Agreement, dated as of November 10, 1999, among the
partnership, the DSR LOC Provider and the Banks named
therein.
4.25+ Equity Contribution Agreement, dated as of November 1, 1999,
among the partnership, the Contributing Partners and the
Collateral Agent.
4.26+ Agreement as to Certain Undertakings, Common
Representations, Warranties, Covenants and Other Terms,
dated as of November 1, 1999, among the partnership, the
Trustee, the DSR LOC Agent, the Power Purchase Agreement LOC
Agent and the Collateral Agent.
4.27+ Power Purchase Agreement Letter of Credit.
4.28+ Tenaska Georgia I, L.P. Letter of Credit.
4.29+ Tenaska Georgia, Inc. Letter of Credit.
5.1+ Opinion of Winthrop, Stimson, Putnam & Roberts regarding the
legality of the new bonds.
8.1+ Opinion of Winthrop, Stimson, Putnam & Roberts regarding tax
matters.
10.1+ H.B. Zachry Company Guaranty of Obligation dated as of
October 22, 1999 made by H.B. Zachry Company in favor of the
partnership
10.2+ EPC Contractor Performance Bond and Payment Bond
10.3*+ Power Purchase Agreement, dated August 24, 1999, between the
partnership and the Power Purchaser.
10.4* Engineering, Procurement and Construction Agreement, dated
as of September 15, 1999 (the "EPC Contract"), as amended,
between the partnership (as assignee of Tenaska Georgia I,
L.P.) and the EPC Contractor.
10.4.1+ First Amendment, dated as of October 8, 1999, to the
Engineering, Procurement and Construction Agreement between
the partnership (as assignee of Tenaska Georgia I, L.P.) and
the EPC Contractor.
10.4.2+ Option 5--Substation Switchyard, exercised by the
partnership on October 20, 1999.
10.4.3+ Agreement for Assignment and Assumption of EPC Contract to
the partnership, dated November 10, 1999, between Tenaska
Georgia I, L.P. and the partnership.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
10.5+ Guaranty of Obligation, dated as of September 23, 1999,
between Willbros Group, Inc. and the partnership.
10.6+ Operations and Maintenance Agreement, dated as of September
10, 1999, as amended, between the partnership and Tenaska
Operations, Inc.
10.6.1+ Amendment, dated as of October 26, 1999, to the Operations
and Maintenance Agreement, between the partnership and
Tenaska Operations, Inc.
10.6.2+ Second Amendment, dated as of November 4, 1999, to the
Operations and Maintenance Agreement, between the
partnership and Tenaska Operations, Inc.
10.7+ Interconnection Agreement, dated as of October 19, 1999,
between the partnership and Georgia Power Company.
10.8*+ Fixed Price Engineering, Procurement and Construction
Services Agreement, dated September 23, 1999 (the "Pipeline
EPC Contract"), between the partnership and Willbros
Engineers, Inc.
10.9+ Interconnect, Reimbursement and Operating Agreement, dated
as of August 18, 1999, between the partnership and the
Transcontinental Gas Pipe Line Corporation.
10.10+ Water Purchase Agreement, dated February 25, 1999, between
the partnership and the Heard County Water Authority.
10.11* Contract for Purchase, dated as of August 27, 1999, between
General Electric and the partnership, as assignee of Tenaska
Georgia I, L.P.
10.11.1+ Agreement for Assignment and Assumption of Turbine Contract
to the partnership, dated as of November 10, 1999, between
Tenaska Georgia I, L.P. and the partnership.
10.11.2+ Agreement for Assignment and Assumption of Turbine Contract
to the partnership, dated as of November 10, 1999, between
Zachry Construction Corporation and the partnership.
10.12+ Ground Lease, dated as of November 10, 1999 between the
partnership and Tenaska Georgia, Inc.
10.13+ Short Form Ground Lease Agreement, dated November 10, 1999
between the partnership and Tenaska Georgia, Inc.
10.14+ Access and Utility Easement Agreement, dated November 10,
1999 between the partnership and Tenaska Georgia, Inc.
10.15+ Electric Substation Site Option Agreement, dated November
10, 1999 between the partnership and Tenaska Georgia, Inc.
10.16+ Natural Gas Pipeline Right-of-Way, dated November 2, 1999
between the partnership and Great Northern Nekoosa
Corporation.
10.17+ Perpetual Right-of-Way and Easement Agreement, dated
November 1, 1999 between the partnership and Charles
Goodson.
10.18+ Perpetual Right-of-Way and Easement Agreement, dated
November 1, 1999 between the partnership and Tenaska
Georgia, Inc.
10.19+ Construction Easement Agreement, dated October 8, 1999
between the partnership and Inland Paperboard and Packaging,
Inc.
10.20+ Easement Agreement, dated November 2, 1999 among the
partnership, Susan Lynn Payne and Robert Charles Payne.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- ------------------------------------------------------------
<S> <C>
10.21+ Non-Interference and Cross Indemnity Agreement, dated as of
November 10, 1999 between Tenaska Georgia, Inc. and the
partnership.
10.22+ Power Purchase Agreement Letter of Credit and the
Reimbursement Agreement, dated as of November 10, 1999,
among the partnership, the Power Purchase Agreement LOC
Provider and the Banks named therein.
10.23+ Agreement Regarding Ad Valorem Taxation, dated as of July
30, 1999, among the partnership, the Board of Commissioners
of Heard County, and the Board of Tax Assessors of Heard
County.
10.24* Long Term Parts & Long Term Service Contract, dated June 24,
1999, between General Electric International, Inc. and the
partnership, as assignee of Tenaska, Inc.
10.24.1+ Agreement for Assignment and Assumption of LTSA to Tenaska
Georgia I, dated November 10, 1999, between Tenaska, Inc.
and Tenaska Georgia I, L.P.
10.24.2+ Agreement for Assignment and Assumption of LTSA to Tenaska
Georgia, dated November 10, 1999, between Tenaska Georgia I,
L.P. and the partnership.
12.1+ Statement regarding ratio of earnings to fixed charges.
23.1.1+ Consent of Winthrop, Stimson, Putnam & Roberts (included in
Exhibit 5.1 to this Registration Statement).
23.1.2+ Consent of Winthrop, Stimson, Putnam & Roberts (included in
Exhibit 8.1 to this Registration Statement).
23.2 Consent of Arthur Andersen LLP.
23.3+ Consent of R.W. Beck, Inc.
23.4+ Consent of Resource Data International, Inc.
23.5+ Consent of EMCON.
24.1+ Power-of-Attorney (contained on the signature page of this
Registration Statement).
25.1+ Statement of Eligibility and Qualification on Form T-1 of
The Chase Manhattan Bank.
27.1+ 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.
99.5+ Form of Instruction to Registered Holders.
</TABLE>
+ Previously filed.
* Portions of this exhibit have been omitted and filed separately with the
SEC, pursuant to a confidential treatment request.
